FERC Form

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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.


AOCI						Accumulated Other Comprehensive Income.
APCo						Appalachian Power Company, an AEP electric utility subsidiary.

ARO						Asset Retirement Obligations.

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.
FGD						Flue Gas Desulfurization or scrubbers.
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.
IRA						On August 16, 2022 President Biden signed into law legislation commonly referred to as the “Inflation Reduction Act” (IRA).
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.
MMBtu						Million British Thermal Units.
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.

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 965,000 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 non-current 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 rather than regulatory liabilities.
·			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


		2022		2021
For the Years Ended December 31,
Cash was Paid (Received) for:
	Interest (Net of Capitalized Amounts)	$	214.9	$	207.5
	Income Taxes (Net of Refunds)	(88.2)		32.7
Noncash Acquisitions Under Finance Leases		1.6		1.7
As of December 31,
Construction Expenditures Included in Current and Accrued Liabilities		164.6		139.1

AEP System Tax Allocation

APCo joins in the filing of a consolidated federal income tax return. Historically, the allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocated the benefit of current tax loss of the parent company (Parent Company Loss Benefit) to APCo through a reduction of current tax expense. In the first quarter of 2022, APCo changed accounting for the Parent Company Loss Benefit from a reduction of current tax expense to an allocation through equity. The impact of this change was immaterial to APCo’s financial statements. The consolidated NOL of the AEP System is allocated to each company in the consolidated group with taxable loss. 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.

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.

Renewable Energy Credits

In regulated jurisdictions, APCo records renewable energy credits (RECs) at cost. APCo follows the inventory model for these RECs. RECs expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. RECs with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of RECs are reported in the Operating Activities section of the statements of cash flows. RECs that are consumed to meet applicable state renewable portfolio standards are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of RECs affects the determination of deferred fuel and REC costs and the amortization of regulatory assets for certain jurisdictions.

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 written down to its then current estimated fair value, with the change charged to expense, and the asset is removed from plant-in-service or CWIP. 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.

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 their 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.

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 purchased electricity, 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”. An estimated annual true-up is recorded by APCo in the fourth quarter of each calendar year and a final annual true-up is 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. APCo includes realized gains and losses on marketing and risk management transactions are included in revenue or expense based on the transaction’s facts and circumstances. The unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).

Certain qualifying marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge). In the event APCo designates a cash flow hedge, the cash flow hedge’s gain or loss is initially recorded as a component of AOCI. When the forecasted transaction is realized and affects net income, APCo subsequently reclassifies the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their statements of income. See “Accounting for Cash Flow Hedging Strategies” section of Note 9 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 utility is able to utilize the ITC on a stand-alone basis.

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	30	%
Fixed Income	54	%
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, 2022 and 2021, the fair value of securities on loan as part of the program was $83 million and $137 million, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned as of December 31, 2022 and 2021.

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, 2022 through February 23, 2023, the date that AEP’s Form 10-K was issued, and has updated such evaluation for disclosure purposes through April 12, 2023. 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, 2022 and 2021. 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, 2022		Interest Rate		Costs		Status		Total
	(in millions)
Balance in AOCI as of December 31, 2021		$	7.5	$	1.2	$	15.7	$	24.4
Change in Fair Value Recognized in AOCI		—		—		(24.1)		(24.1)
Amount of (Gain) Loss Reclassified from AOCI
Interest on Long-Term Debt (a)		(1.0)		—		—		(1.0)
Amortization of Prior Service Cost (Credit)		—		(5.4)		—		(5.4)
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(1.0)		(5.4)		—		(6.4)
Income Tax (Expense) Benefit		(0.2)		(1.1)		—		(1.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.8)		(4.3)		—		(5.1)
Net Current Period Other Comprehensive Income (Loss)		(0.8)		(4.3)		(24.1)		(29.2)
Balance in AOCI as of December 31, 2022		$	6.7	$	(3.1)	$	(8.4)	$	(4.8)


			Pension and OPEB
			Amortization		Changes in
	Cash Flow Hedges -		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

(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 statutory 140 basis point band (8.5% bottom, 9.2% midpoint, 9.9% top). APCo appealed this order and a similar order on reconsideration to the Virginia Supreme Court in March 2021, alleging the Virginia SCC erred in finding that costs associated with asset impairments related to APCo early retirement determinations for certain generation facilities should not be attributed to the 2017-2019 test periods under review and deemed fully recovered in the period recorded. In August 2022, the Virginia Supreme Court agreed with this portion of APCo’s appeal and remanded this issue regarding the retired coal-fired plants back to the Virginia SCC for further proceedings. In September 2022, as a result of the Virginia Supreme Court ruling, APCo expensed the remaining $25 million closed coal plant regulatory asset that was previously ordered by the Virginia SCC and recorded a $37 million regulatory asset for previously incurred costs that APCo is expecting to recover as a result of earning below its 2017-2019 authorized ROE band.

In response to the Virginia Supreme Court’s August 2022 opinion, the Virginia SCC initiated remand proceedings and, in December 2022, issued an order that: (a) approved APCo’s requested $37 million regulatory asset related to previously incurred costs as a result of APCo earning below its 2017-2019 authorized ROE band, (b) authorized a $28 million annual increase in APCo Virginia base rates effective October 2022 and (c) approved a rider to recover approximately $48 million related to this APCo Virginia base rate increase for the period January 2021 through September 2022. APCo’s 2022 financial statements reflect the impact of the Virginia SCC’s December 2022 order.

2020-2022 Virginia Triennial Review

In March 2023, APCo submitted its required Virginia earnings test calculation to the Virginia SCC for the 2020-2022 Triennial Review period. For Triennial Review periods in which a Virginia utility earns below its authorized ROE band, the utility may file to recover expenses incurred, up to the bottom of the authorized ROE band, related to major storms, the early retirement of fossil fuel generating assets and certain projects necessary to comply with state and federal environmental legislation. As of December 31, 2022, APCo has deferred approximately $38 million related to previously incurred costs as a result of the current estimate that APCo will earn below the bottom of its authorized ROE band during the 2020-2022 Triennial Review period. If it is determined that APCo has earned above the bottom of its authorized ROE band for the 2020-2022 Triennial Review period it could reduce future net income and cash flows and impact financial condition.

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. In August 2021, the Virginia SCC issued an order approving recovery of CCR-related operation and maintenance expenses and investments at the Amos and Mountaineer Plants through an active rider. The order also denied APCo’s request to recover the cost of ELG investments and denied recovery of previously incurred ELG costs, but did not preclude APCo from

refiling for approval. 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 March 2022, APCo refiled for approval to recover the Virginia jurisdictional share of ELG investments at the Amos and Mountaineer Plants. The Virginia SCC issued a November 2022 order approving this request.

2021 and 2022 ENEC (Expanded Net Energy Cost) Filings

In April 2021, APCo and WPCo (the Companies) requested a $73 million annual increase in ENEC rates based on a cumulative combined $55 million ENEC under-recovery as of February 28, 2021 and a combined $18 million increase in projected ENEC costs for the period September 2021 through August 2022. In September 2021, the WVPSC issued an order approving a $7 million overall increase in ENEC rates, including an approval for recovery of the Companies’ cumulative $55 million ENEC under-recovery balance and a $48 million reduction in projected costs for the period September 2021 through August 2022. Subsequently, the Companies submitted a request for reconsideration of this order, identifying flaws in the WVPSC’s calculation of forecasted future year fuel expense and purchased power costs.

In March 2022, the WVPSC issued an order granting the Companies’ request for reconsideration, in part, and approving $31 million in projected costs for the period September 2021 through August 2022. The order also reopened the 2021 ENEC case to require the Companies to explain the significant growth in the reported under-recovery of ENEC costs and to provide various other information including revised projected costs for the period March 2022 through August 2022. Also, in March 2022, the Companies filed testimony providing the information requested in the WVPSC’s order and requested a $155 million annual increase in ENEC rates effective May 1, 2022. In May 2022, the WVPSC issued an order approving a $93 million overall increase to ENEC rates to recover projected annual ENEC costs. However, the WVPSC stated that actual and projected ENEC costs are still subject to a prudency review.

In April 2022, the Companies submitted their 2022 annual ENEC filing with the WVPSC requesting a $297 million annual increase in ENEC revenues, inclusive of the previously requested $155 million increase, effective September 1, 2022.

In September 2022, following an agreed upon delay in the proceedings of the Companies’ 2022 ENEC case, certain intervenors submitted testimony recommending disallowances of at least $83 million to the Companies’ historical period ENEC under-recovery balance along with proposals to either securitize the Companies’ remaining ENEC balance or defer recovery of this balance beyond the traditional one-year period. West Virginia Staff recommended a $13 million increase in ENEC rates pending the outcome of the ENEC prudency review. In February 2023, the WVPSC issued an order stating that the commission will not grant additional rate increases for fuel costs until the WVPSC staff completes its prudency review. As of December 31, 2022, the Companies’ cumulative ENEC under-recovery was $520 million. If any deferred ENEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

June 2022 West Virginia Storm Costs

In June 2022, the West Virginia service territories of APCo and WPCo (the Companies) were impacted by strong winds from multiple storms resulting in system damages and power outages. As of December 31, 2022, the Companies incurred and deferred an estimated $17 million in incremental distribution operation and maintenance expenses related to service restoration efforts. The Companies will seek recovery of these deferrals in future filings. If any of the storm restoration costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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:	2022		2021
	(in millions)
Regulatory assets pending final regulatory approval:

Regulatory Assets Currently Earning a Return
COVID-19 - Virginia	$	7.0	$	6.8
Total Regulatory Assets Currently Earning a Return	7.0		6.8
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs - West Virginia	72.6		53.7
2020-2022 Virginia Triennial Under-Earnings	37.9		15.1
Plant Retirement Costs - Asset Retirement Obligation Costs	25.9		25.9
Other Regulatory Assets Pending Final Regulatory Approval	1.2		3.6
Total Regulatory Assets Currently Not Earning a Return	137.6		98.3

Total Regulatory Assets Pending Final Regulatory Approval	144.6		105.1

Regulatory assets approved for recovery:

Regulatory Assets Currently Earning a Return
Long-term Under-recovered Fuel Costs - Virginia	223.3		—		2 years
Under-recovered Fuel Costs - Virginia	180.7		127.2		1 year
Plant Retirement Costs - Unrecovered Plant	—		30.9
Other Regulatory Assets Approved for Recovery	0.4		0.4		various
Total Regulatory Assets Currently Earning a Return	404.4		158.5
Regulatory Assets Currently Not Earning a Return
Income Tax Assets (a)	375.4		327.9
Plant Retirement Costs - Asset Retirement Obligation Costs	303.1		293.1		15 years
Under-recovered Fuel Costs - Virginia	292.4		74.1		1 year
Pension and OPEB Funded Status	108.3		62.7		12 years
2017-2019 Virginia Triennial Under-Earnings	30.1		—		2 years
Virginia Transmission Rate Adjustment	18.7		37.2		2 years
Virginia Clean Economy Act	16.7		—		2 years
Peak Demand Reduction/Energy Efficiency	15.8		17.8		4 years
Postemployment Benefits	13.7		13.3		3 years
Vegetation Management Program - West Virginia	13.7		11.9		2 years
Environmental Compliance Costs	4.3		13.7		2 years
Other Regulatory Assets Approved for Recovery	15.8		14.2		various
Total Regulatory Assets Currently Not Earning a Return	1,208.0		865.9

Total Regulatory Assets Approved for Recovery	1,612.4		1,024.4

Total FERC Account 182.3 Regulatory Assets	$	1,757.0	$	1,129.5

(a) Recovered over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets.



	December 31,				Remaining Refund Period
Regulatory Liabilities:	2022		2021
	(in millions)
Regulatory liabilities approved for payment:














Regulatory Liabilities Currently Not Paying a Return
Income Tax Liabilities (a)	$	697.1	$	765.3	(b)
Unrealized Gain on Forward Commitments	34.5		28.2		2 years
Over-recovered Deferred Wind Power Costs - Virginia	13.6		8.4		2 years
PJM Transmission Enhancement Refund	9.8		13.0		3 years
Other Regulatory Liabilities Approved for Payment	11.0		6.6		various







Total Regulatory Liabilities Approved for Payment	766.0		821.5

Total FERC 254 Account Regulatory Liabilities	$	766.0	$	821.5

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

(b)Recovered over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $19 million and $84 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 6 years.

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, 2022:


Contractual Commitments	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Fuel Purchase Contracts (a)	$	840.9	$	1,102.9	$	263.2	$ 9.2		$	2,216.2
Energy and Capacity Purchase Contracts	40.5		82.7		79.9		127.0		330.1
Total	$	881.4	$	1,185.6	$	343.1	$	136.2	$	2,546.3

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

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, 2022, 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, 2022, 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, 2022, 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. On August 16, 2022, the district court granted the motion to dismiss the complaint without prejudice. The plaintiffs filed a motion for leave to file an amended complaint, which the Court denied on December 1, 2022. The plaintiffs did not file an appeal by the deadline of January 3, 2023.

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 the benefit obligations are shown in the following table:


	Pension Plans						OPEB
	December 31,
Assumption	2022			2021			2022		2021
Discount Rate	5.50	%		2.90	%		5.50	%	2.90	%
Interest Crediting Rate	4.25	%		4.00	%		NA		NA
Rate of Compensation Increase	4.90	%	(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 2022, 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	2022			2021			2022		2021
Discount Rate	2.90	%		2.50	%		2.90	%	2.55	%
Interest Crediting Rate	4.00	%		4.00	%		NA		NA
Expected Return on Plan Assets	5.25	%		4.75	%		5.50	%	4.75	%
Rate of Compensation Increase	4.90	%	(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	2022		2021
Initial	7.50	%	6.25	%
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, 2022, 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, 2022, the pension plans had an actuarial gain primarily due to an increase in the discount rate and was partially offset by increases in the assumed lump sum conversion rate and cash balance account interest crediting rate. For the year ended December 31, 2022, the OPEB plans had an actuarial gain primarily due to an increase in the discount rate and updated per capita cost assumptions. The OPEB plans gains were partially offset by a projected reduction in the Employer Group Waiver Program catastrophic reinsurance offset provided to AEP, resulting from the Inflation Reduction Act as well as an increase in the health care cost trend assumption. 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. 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
	2022		2021		2022		2021
Change in Benefit Obligation	(in millions)
Benefit Obligation as of January 1,	$	619.7	$	668.5	$	144.0	$	173.7
Service Cost	11.4		11.9		0.8		1.0
Interest Cost	17.4		16.3		4.0		4.2
Actuarial Gain	(122.7)		(28.4)		(12.4)		(21.4)
Plan Amendments	—		—		—		(0.9)
Benefit Payments	(41.7)		(48.6)		(21.3)		(19.2)
Participant Contributions	—		—		7.0		6.6
Benefit Obligation as of December 31,	$	484.1	$	619.7	$	122.1	$	144.0

Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1,	$	677.6	$	695.7	$	302.0	$	292.6
Actual Gain (Loss) on Plan Assets	(109.0)		30.5		(59.4)		22.0
Company Contributions	—		—		—		—
Participant Contributions	—		—		7.0		6.6
Benefit Payments	(41.7)		(48.6)		(21.3)		(19.2)
Fair Value of Plan Assets as of December 31,	$	526.9	$	677.6	$	228.3	$	302.0

Funded Status as of December 31,	$	42.8	$	57.9	$	106.2	$	158.0


	Pension Plans				OPEB
	December 31,
	2022		2021		2022		2021
	(in millions)
Special Funds – Prepaid Benefit Costs	$	43.4	$	58.7	$	106.2	$	158.0

Accumulated Provision for Pensions and Benefits – Long-term Benefit Liability	(0.6)		(0.8)		—		—
Funded Status	$	42.8	$	57.9	$	106.2	$	158.0

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,
	2022		2021		2022		2021
Components	(in millions)
Net Actuarial (Gain) Loss	$	93.6	$	82.5	$	44.6	$	(18.5)
Prior Service Credit	—		—		(13.3)		(23.7)

Recorded as
Regulatory Assets	$	93.6	$	82.5	$	14.7	$	(19.8)
Deferred Income Taxes	—		—		3.5		(4.7)
Net of Tax AOCI	—		—		13.1		(17.7)

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


	Pension Plans				OPEB
	2022		2021		2022		2021
Components	(in millions)
Actuarial (Gain) Loss During the Year	$	18.3	$	(30.2)	$	63.1	$	(30.0)
Amortization of Actuarial Loss	(7.2)		(12.0)		—		—
Prior Service Credit	—		—		—		(0.8)
Amortization of Prior Service Credit	—		—		10.4		10.3
Change for the Year Ended December 31,	$	11.1	$	(42.2)	$	73.5	$	(20.5)

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,
2022		2021		2022		2021
12.8	%	12.7	%	14.7	%	14.8	%

The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2022:


Asset Class	Level 1		Level 2		Level 3		Other		Total		Year End Allocation
	(in millions)
Equities (a):
Domestic	$	347.6	$	—	$	—	$	—	$	347.6	8.4	%
International	398.4		—		—		—		398.4		9.7	%
Common Collective Trusts (b)	—		—		—		379.9		379.9		9.2	%
Subtotal – Equities	746.0		—		—		379.9		1,125.9		27.3	%

Fixed Income (a):
United States Government and Agency Securities	(0.6)		1,071.4		—		—		1,070.8		26.0	%
Corporate Debt	—		891.7		—		—		891.7		21.6	%
Foreign Debt	—		140.2		—		—		140.2		3.4	%
State and Local Government	—		37.0		—		—		37.0		0.9	%
Other – Asset Backed	—		0.8		—		—		0.8		—	%
Subtotal – Fixed Income	(0.6)		2,141.1		—		—		2,140.5		51.9	%

Infrastructure (b)	—		—		—		109.2		109.2		2.6	%
Real Estate (b)	—		—		—		276.9		276.9		6.7	%
Alternative Investments (b)	—		—		—		319.7		319.7		7.8	%
Cash and Cash Equivalents (b)	—		64.9		—		58.3		123.2		3.0	%
Other – Pending Transactions and Accrued Income (c)	—		—		—		29.3		29.3		0.7	%

Total	$	745.4	$	2,206.0	$	—	$	1,173.3	$	4,124.7	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 represent investments for which fair value is measured using net asset value per-share.

(c)Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2022:


Asset Class	Level 1		Level 2		Level 3		Other		Total		Year End Allocation
	(in millions)
Equities:
Domestic	$	414.1	$	—	$	—	$	—	$	414.1	26.7	%
International	265.0		—		—		—		265.0		17.1	%
Common Collective Trusts (a)	—		—		—		169.1		169.1		10.9	%
Subtotal – Equities	679.1		—		—		169.1		848.2		54.7	%

Fixed Income:
Common Collective Trust – Debt (a)	—		—		—		120.3		120.3		7.8	%
United States Government and Agency Securities	0.1		155.8		—		—		155.9		10.1	%
Corporate Debt	—		141.5		—		—		141.5		9.1	%
Foreign Debt	—		21.0		—		—		21.0		1.4	%
State and Local Government	62.9		7.8		—		—		70.7		4.6	%
Subtotal – Fixed Income	63.0		326.1		—		120.3		509.4		33.0	%

Trust Owned Life Insurance:
International Equities	—		46.7		—		—		46.7		3.0	%
United States Bonds	—		110.3		—		—		110.3		7.1	%
Subtotal – Trust Owned Life Insurance	—		157.0		—		—		157.0		10.1	%

Cash and Cash Equivalents (a)	23.2		—		—		6.7		29.9		1.9	%
Other – Pending Transactions and Accrued Income (b)	—		—		—		4.8		4.8		0.3	%

Total	$	765.3	$	483.1	$	—	$	300.9	$	1,549.3	100.0	%

(a)Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share.

(b)Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

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

Total	$	854.7	$	3,235.6	$	—	$	1,262.6	$	5,352.9	100.0	%

(b)Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share.

(c)Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

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 (a)	—		—		—		265.0		265.0		13.0	%
Subtotal – Equities	770.3		—		—		265.0		1,035.3		50.7	%

Fixed Income:
Common Collective Trust – Debt (a)	—		—		—		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 (a)	33.0		—		—		6.7		39.7		1.9	%
Other – Pending Transactions and Accrued Income (b)	—		—		—		6.0		6.0		0.3	%

Total	$	895.2	$	703.7	$	—	$	445.4	$	2,044.3	100.0	%

(a)Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share.

(b)Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

Accumulated Benefit Obligation

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


	December 31,
Accumulated Benefit Obligation	2022		2021
	(in millions)
Qualified Pension Plan	$	468.6	$	595.0
Nonqualified Pension Plans	0.3		0.4
Total	$	468.9	$	595.4

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,
	2022		2021
	(in millions)
Projected Benefit Obligation	$	0.6	$	0.8
Fair Value of Plan Assets	—		—
Underfunded Projected Benefit Obligation	$	(0.6)	$	(0.8)

Accumulated Benefit Obligation


	December 31,
	2022		2021
	(in millions)
Accumulated Benefit Obligation	$	0.3	$	0.4
Fair Value of Plan Assets	—		—
Underfunded Accumulated Benefit Obligation	$	(0.3)	$	(0.4)

Estimated Future Benefit Payments and Contributions

APCo expects contributions and payments for the pension plans of $10 thousand during 2023. 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)
2023	$	43.6	$	17.4
2024	43.4		17.6
2025	42.4		18.8
2026	42.8		18.8
2027	41.6		18.6
Years 2028 to 2032, in Total	201.5		88.4

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,
	2022		2021		2022		2021
	(in millions)
Service Cost	$	11.4	$	11.9	$	0.8	$	1.0
Interest Cost	17.4		16.3		4.0		4.2
Expected Return on Plan Assets	(32.1)		(28.8)		(16.1)		(13.4)
Amortization of Prior Service Credit	—		—		(10.4)		(10.3)
Amortization of Net Actuarial Loss	7.2		12.0		—		—
Net Periodic Benefit Cost (Credit)	3.9		11.4		(21.7)		(18.5)
Capitalized Portion	(5.0)		(5.2)		(0.4)		(0.4)
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	(1.1)	$	6.2	$	(22.1)	$	(18.9)

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 plans for the years ended December 31, 2022 and 2021 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

Primary Risk Exposure	2022	2021	Unit of Measure
	(in millions)
Commodity:
Power	17.9	33.1	MWhs
Natural Gas	1.9	—	MMBtus
Heating Oil and Gasoline	1.0	1.1	Gallons

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, 2022 and 2021.

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


	December 31, 2022
	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts -		in the Statement of		Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)		Financial Position (c)
	(in millions)
Derivative Instrument Assets	$	70.0	$	(0.9)	$	69.1
Long-Term Portion of Derivative Instrument Assets	0.7		(0.7)		—

Derivative Instrument Liabilities	4.8		(1.1)		3.7
Long-Term Portion of Derivative Instrument Liabilities	0.7		(0.6)		0.1


	December 31, 2021
	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts -		in the Statement of		Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)		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)		—

(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)	2022		2021
	(in millions)
Operating Revenues	$	0.5	$	(0.5)
Operation Expenses	4.9		2.1
Maintenance Expenses	0.9		0.5
Other Regulatory Assets (a)	(0.1)		(2.7)
Other Regulatory Liabilities (a)	82.4		55.9
Total Gain (Loss) on Risk Management Contracts	$	88.6	$	55.3

(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 2022 and 2021, APCo did not apply cash flow hedging to outstanding power derivatives.

APCo reclassifies gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income on the balance sheets into Interest on Long-term Debt on the statements of income in those periods in which hedged interest payments occur. During the year ended 2021, APCo applied cash flow hedging to outstanding interest rate derivatives. During the years ended 2022 and 2021, APCo did not have outstanding interest rate derivatives.

For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) 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, 2022

December 31, 2021

Interest Rate

Expected to be

Reclassed to

Net Income During

AOCI Gain

the Next

AOCI Gain

the Next

Net of Tax

Twelve Months

Net of Tax

Twelve Months

(in millions)

6.7

0.8

7.5

0.8

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.

Credit-Risk-Related Contingent Features

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, 2022 and 2021.

Cross-Acceleration Triggers

Certain interest rate derivative contracts contain cross-acceleration provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-acceleration provisions could be triggered if there was a non-performance event by APCo under any of their outstanding debt of at least $50 million and the lender on that debt has accelerated the entire repayment obligation. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-acceleration provisions in contracts. APCo had no derivative contracts with cross-acceleration provisions outstanding as of December 31, 2022 and 2021.

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, 2022 and 2021.

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,
2022				2021
Book Value		Fair Value		Book Value		Fair Value
(in millions)
$	5,441.5	$	5,079.2	$	4,967.7	$	6,037.1

Fair Value Measurements of Financial Assets and Liabilities

For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1.

The following tables set forth, by level within the fair value hierarchy, APCo’s financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.


	December 31, 2022
	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)

Special Deposits	$	14.4	$	—	$	—	$	—	$	14.4

Derivative Instrument Assets
Risk Management Commodity Contracts (a) (b)	—		0.7		69.4		(1.0)		69.1

Total Assets	$	14.4	$	0.7	$	69.4	$	(1.0)	$	83.5

Liabilities:

Derivative Instrument Liabilities
Risk Management Commodity Contracts (a) (b)	$	—	$	4.6	$	0.3	$	(1.4)	$	3.5


	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

(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, 2022	Assets (Liabilities)
	(in millions)
Balance as of December 31, 2021	$	41.7
Realized Gain Included in Net Income (or Changes in Net Assets) (a) (b)	3.0
Settlements	(44.7)


Changes in Fair Value Allocated to Regulated Jurisdictions (c)	69.1
Balance as of December 31, 2022	$	69.1


	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)


Changes in Fair Value Allocated to Regulated Jurisdictions (c)	42.1
Balance as of December 31, 2021	$	41.7

(a)Included in revenues on the statements of income.

(b)Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.

(c)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, 2022

Significant

Input/Range

Fair Value

Valuation

Unobservable

Weighted

Assets

Liabilities

Technique

Input (a)

Low

High

Average (b)

(in millions)

FTRs

69.4

0.3

Discounted Cash Flow

Forward Market Price

(2.82)

18.88

3.89


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

(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, 2022 and 2021:

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,
	2022			2021
	(in millions)
Charged (Credited) to Operating Expenses, Net:
Current	$	(54.7)		$	12.0
Deferred			76.9			17.2
Total			22.2			29.2

Charged (Credited) to Non-Operating Income, Net:
Current			(6.3)			(4.9)
Deferred			2.8			(1.7)
Total			(3.5)			(6.6)
Total Income Tax Expense	$	18.7		$	22.6

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:



	2022			2021

Net Income	$	394.2		$	348.9
Income Tax Expense	18.7			22.6
Pretax Income	$	412.9		$	371.5

Income Taxes on Pretax Income at Statutory Rate (21%)	$	86.7		$	78.0
Increase (Decrease) in Income Taxes Resulting from the Following Items:
Reversal of Origination Flow-Through	4.7			11.7
State and Local Income Taxes, Net	(5.5)			1.0
Removal Costs	(9.8)			(7.3)
AFUDC	(3.7)			(4.6)

Tax Reform Excess ADIT Reversal	(50.9)			(60.5)
Return to Provision Adjustment	(2.8)			(0.5)
Tax Adjustments (a)	—			4.9
Other	—			(0.1)
Income Tax Expense	$	18.7		$	22.6

Effective Income Tax Rate	4.5		%	6.1		%

(a) 2021 amount represents an out of period adjustment related to Deferred Income Taxes and Income Tax Expense (Benefit). Management concluded the misstatement and subsequent correction was not material to the 2021 or prior 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,
	2022		2021
	(in millions)
Deferred Tax Assets	$	504.2	$	488.8
Deferred Tax Liabilities	(2,501.1)		(2,298.7)
Net Deferred Tax Liabilities	$	(1,996.9)	$	(1,809.9)

Property Related Temporary Differences	$	(1,509.8)	$	(1,476.5)
Amounts Due to Customers for Future Income Taxes	163.0		182.1
Deferred State Income Taxes	(319.4)		(289.2)
Regulatory Assets	(301.2)		(177.0)
Securitized Assets	(33.9)		(39.3)
Operating Lease Liability	15.6		14.2
All Other, Net	(11.2)		(24.2)
Net Deferred Tax Liabilities	$	(1,996.9)	$	(1,809.9)

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. APCo and other AEP subsidiaries agreed to extend the statute of limitations on the 2017 and 2018 tax returns to December 31, 2023, to allow time for the current IRS audit to be completed including a refund claim approval by the Congressional Joint Committee on Taxation. The statute of limitations for the 2019 return is set to naturally expire in 2023 as well.

The current IRS audit and associated refund claim evolved from a net operating loss carryback to 2015 that originated in the 2017 return. APCo and other AEP subsidiaries have received and agreed to two IRS proposed adjustments on the 2017 tax return, which were immaterial. The exam is nearly complete, and APCo and other AEP subsidiaries are currently working with the IRS to submit the refund claim to the Congressional Joint Committee on Taxation for resolution and final approval.

APCo and other 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. Generally, the statutes of limitations have expired for tax years prior to 2017. In addition, management is monitoring and continues to evaluate the potential impact of federal legislation and corresponding state conformity.

Federal Tax Legislation

Inflation Reduction Act

In August 2022, President Biden signed H.R. 5376 into law, commonly known as the Inflation Reduction Act of 2022 or IRA. Most notably this budget reconciliation legislation creates a 15% minimum tax on adjusted financial statement income (Corporate Alternative Minimum Tax or CAMT), extends and increases the value of PTCs and ITCs, adds a nuclear and clean hydrogen PTC, an energy storage ITC and allows the sale or transfer of tax credits

to third parties for cash. This legislation has no material impact on the current period financial statements. As further significant guidance from Treasury and the IRS is expected on the tax provisions in the IRA, APCo will continue to monitor any issued guidance and evaluate the impact on future net income, cash flows and financial condition.

In November 2022, the IRS released Notice 2022-61 addressing the Prevailing Wage and Apprenticeship Requirements (PWAR) tied to full value PTCs and ITCs for projects that begin construction on or after January 29, 2023. APCo’s future renewable energy projects that begin construction after this date will be required to, and expect to, satisfy the PWAR to receive full value ITCs and PTCs.

In December 2022, the IRS released Notice 2023-7 addressing time sensitive issues related to the CAMT. The notice provided initial guidance that APCo can begin to rely on in 2023 and also stated that additional guidance is expected, of which APCo will continue to monitor and assess. Notably, the interim guidance in Notice 2023-7 confirmed the CAMT depreciation adjustment includes tax depreciation that is capitalized to inventory under §263A and recovered as part of cost of goods sold, providing significant relief to APCo’s potential CAMT exposure.

The enactment of the IRA will have future cash flow and income tax reporting considerations. APCo and other AEP subsidiaries expect to be applicable corporations beginning in 2023 and expect to have CAMT cash tax payments beginning in 2024. CAMT cash taxes are expected to be offset by regulatory recovery, the utilization of tax credits and additionally the cash inflow generated by the sale of tax credits. The sale of tax credits will be presented in the operating section of the statements of cash flows consistent with the presentation of cash taxes paid. APCo will present the gain or loss on sale of tax credits through income tax expense. Management believes this presentation provides consistency in financial statement reporting as it matches the originating income tax benefit of the tax credits.

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,
	2022		2021
	(in millions)
Operating Lease Cost	$	17.9	$	19.3
Finance Lease Cost:
Amortization of Right-of-Use Assets	7.9		7.7
Interest on Lease Liabilities	2.0		2.4
Total Lease Rental Costs (a)	$	27.8	$	29.4

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

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


	December 31,
	2022		2021
	(in millions)
Weighted-Average Remaining Lease Term (years):
Operating Leases	5.29		5.68
Finance Leases	4.25		4.97
Weighted-Average Discount Rate:
Operating Leases	3.61	%	3.42	%
Finance Leases	7.09	%	7.16	%


	Years Ended December 31,
	2022		2021
	(in millions)
Cash paid for amounts included in the measurement of lease liabilities:
Operating Cash Flows from Operating Leases	$	17.9	$	19.3
Operating Cash Flows from Finance Leases	9.9		10.1

Non-cash Acquisitions Under Operating Leases	$	23.1	$	4.2

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


	December 31,
	2022		2021
	(in millions)
Property, Plant and Equipment Under Finance Leases:
Utility Plant (a)	$	29.3	$	35.7


Net Property, Plant and Equipment Under Finance Leases	$	29.3	$	35.7

Obligations Under Finance Leases:
Noncurrent	$	21.6	$	28.1
Current	7.7		7.6
Total Obligations Under Finance Leases	$	29.3	$	35.7

(a) Includes $32 million and $28 million of accumulated provision for depreciation and amortization for the years ended December 31, 2022 and 2021, respectively.


	December 31,
	2022		2021
	(in millions)
Property, Plant and Equipment Under Operating Leases:
Utility Plant (a)	$	73.6	$	66.9


Net Property, Plant and Equipment Under Operating Leases	$	73.6	$	66.9

Obligations Under Operating Leases:
Noncurrent	$	59.1	$	52.4
Current	15.0		15.1
Total Obligations Under Operating Leases	$	74.1	$	67.5

(a) Includes $49 million and $38 million of accumulated provision for depreciation and amortization for the years ended December 31, 2022 and 2021, respectively.

Future minimum lease payments consisted of the following as of December 31, 2022:


	Finance Leases		Operating Leases
	(in millions)
2023	$	9.6	$	17.5
2024	8.8		14.6
2025	7.5		11.8
2026	2.9		10.3
2027	1.8		9.1
After 2027	2.8		19.2
Total Future Minimum Lease Payments	33.4		82.5
Less: Imputed Interest	4.1		8.4
Estimated Present Value of Future Minimum Lease Payments	$	29.3	$	74.1

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, 2022, 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, 2022 and December 31, 2021, 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, 2022	2022	2021	2022		2021













Senior Unsecured Notes	2025-2050	4.68%	2.70%-7.00%	2.70%-7.00%	$	4,625.0	$	4,125.0
Pollution Control Bonds (a)	2024-2036 (b)	2.74%	0.63%-3.80%	0.19%-2.75%	431.0		531.0
Securitization Bonds	2023-2028 (c)	3.67%	2.01%-3.77%	2.01%-3.77%	174.2		200.1
Other Long-term Debt	2023-2026	5.34%	4.84%-13.72%	1.24%-13.72%	226.8		126.9
Unamortized Discount, Net					(15.5)		(15.3)
Total Long-term Debt Outstanding					$	5,441.5	$	4,967.7

(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, 2022, long-term debt was payable as follows:


	(in millions)
2023	$	251.8
2024	113.5
2025	673.3
2026	31.0
2027	355.5
After 2027	4,031.9
Principal Amount	5,457.0
Unamortized Discount, Net	(15.5)
Total Long-term Debt	$	5,441.5

Long-term Debt Subsequent Events

In February 2023, 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 requirement that prohibits the payment of dividends out of capital accounts in certain circumstances; payment of dividends is generally allowed out of retained earnings. 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, 2022, 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 $2.6 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, 2022, the amount of any such restrictions was $543 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, 2022 and 2021 are included in 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)
2022	$	438.4	$	194.7	$	181.7	$	148.9	$	182.2	$	500.0
2021	199.3		595.9		87.5		118.3		199.3		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 Rates		Interest Rates
	for Funds		for Funds		for Funds		for Funds		for Funds		for Funds
	Borrowed from		Borrowed from		Loaned to		Loaned to		Borrowed from		Loaned to
Years ended	the Utility		the Utility		the Utility		the Utility		the Utility		the Utility
December 31,	Money Pool		Money Pool		Money Pool		Money Pool		Money Pool		Money Pool
	(in millions)
2022	5.28	%	0.10	%	3.39	%	1.63	%	2.34	%	2.57	%
2021	0.48	%	0.06	%	0.40	%	0.02	%	0.41	%	0.25	%

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 related to the corporate borrowing programs were $6 million and $100 thousand for the years ended December 31, 2022 and 2021, respectively, and interest income related to the corporate borrowing programs were $3 million and $300 thousand for the years ended December 31, 2022 and 2021, respectively.

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’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and was amended in September 2021 to include a $125 million and a $625 million facility. The $125 million facility was renewed in September 2022 and amended to extend the expiration date to September 2024. The $625 million facility also expires in September 2024.

The amount of accounts receivable and accrued utility revenues under the sale of receivables agreement as of December 31, 2022 and 2021 were $194 million and $153 million, respectively.

The fees paid to AEP Credit for customer accounts receivable sold were $9 million and $5 million for the years ended December 31, 2022 and 2021, respectively. In 2021, due to the successful collection of accounts receivable balances during the COVID-19 pandemic, the allowance for doubtful accounts was reduced, resulting in the issuance of credits to offset the higher fees previously paid by APCo and to lower subsequent fees paid.

The proceeds on the sale of receivables to AEP Credit were $1.6 billion and $1.3 billion for the years ended December 31, 2022 and 2021, respectively.

14. RELATED PARTY TRANSACTIONS

For other related party transactions, also see “AEP System Tax Allocation” section of Note 1 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, 2022 and 2021:


	Years Ended December 31,
Related Party Revenues	2022		2021
	(in millions)
Direct Sales to East Affiliates	$	169.7	$	128.6

Transmission Revenues	77.5		60.3
Other Revenues	8.9		9.0

PJM 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, 2022 and 2021 related to the TA were $345 million and $302 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, 2022 and 2021, AEPTCo billed APCo $3 million and $2 million, respectively.

OVEC

AEP and several nonaffiliated utility companies jointly own OVEC. As of December 31, 2022, the ownership and investment in OVEC were as follows:


	December 31, 2022
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 are 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, 2022 and 2021, OVEC’s outstanding indebtedness was approximately $1.1 billion and $1.1 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 $119 million and $104 million for power purchased from OVEC for the years ended December 31, 2022 and 2021, 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 $36 million and $40 million for the years ended December 31, 2022 and 2021, respectively, as Operation Expenses.

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,
	2022		2021
	(in millions)
Sales	$	16.0	$	6.2
Purchases	2.4		1.0

The amounts above are recorded in Utility Plant on the balance sheets.

Intercompany Billings

APCo performs certain utility services for each other when necessary or practical. The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable basis of proration for services that benefit multiple companies. The billings for services are made at cost and include no compensation for the use of equity capital.

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 $348 million and $313 million for the years ended December 31, 2022 and 2021, respectively.

Charitable Contributions to AEP Foundation

The American Electric Power Foundation is funded by American Electric Power and its utility operating units. The Foundation provides a permanent, ongoing resource for charitable initiatives and multi-year commitments in the communities served by AEP and initiatives outside of AEP’s 11-state service area. In 2022, APCo made a $13 million charitable contribution to the AEP Foundation recorded in Donations on the statements of income. In 2021, there were no charitable contributions made to the AEP Foundation.

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)
2022	2.7	3.7	3.7	2.2	3.6	7.3
2021	2.6	3.6	5.9	2.1	3.5	8.5

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 recorded the following revisions to ARO estimates as of December 31, 2022 and 2021:

•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 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.

•In September 2022, APCo recorded a $14 million revision due to an increase in estimated ash pond closure costs at the Amos Plant.

The following is a reconciliation of the 2022 and 2021 aggregate carrying amounts of ARO:


Year	ARO at January 1,		Accretion Expense		Liabilities Incurred		Liabilities Settled		Revisions in Cash Flow Estimates (a)		ARO at December 31,
	(in millions)
2022	$	404.6	$	15.8	$	3.0	$	(12.7)	$	17.0	$	427.7	(b)(c)
2021	313.1		13.7		—		(6.9)		84.7		404.6		(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 table below represents revenues from contracts with customers, net of respective provisions for refund, by type of revenue for APCo:


	Years Ended December 31,
	2022		2021
	(in millions)
Retail Revenues:
Residential Revenues	$	1,557.4	$	1,378.3
Commercial Revenues	642.8		555.8
Industrial Revenues (a)	663.4		583.7
Other Retail Revenues	87.1		70.7
Total Retail Revenues	2,950.7		2,588.5

Wholesale Revenues:
Generation Revenues (b)	409.8		342.7
Transmission Revenues (c)	167.0		128.8
Total Wholesale Revenues	576.8		471.5

Other Revenues from Contracts with Customers (a)	99.1		69.9

Total Revenues from Contracts with Customers	3,626.6		3,129.9

Other Revenues:
Alternative Revenues	(1.3)		12.3
Other Revenues	0.8		(0.2)
Total Other Revenues	(0.5)		12.1

Total Operating Revenues	$	3,626.1	$	3,142.0

(a)Amounts include affiliated and nonaffiliated revenues.

(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $170 million and $129 million as of December 31, 2022 and 2021, respectively, primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.

(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $78 million and $52 million as of December 31, 2022 and 2021, respectively. 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 tables above.

Wholesale Revenues - Transmission

APCo has performance obligations to transmit electricity to wholesale customers through assets owned and operated. The performance obligation to provide transmission services in PJM 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, 2022. Fixed performance obligations primarily include electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market. APCo elected to apply the exemption to not disclose the value of unsatisfied performance obligations for contracts with an original expected term of one year or less. Due to the annual establishment of revenue requirements, transmission revenues are excluded from the table below. APCo amounts shown in the table below include affiliated and nonaffiliated revenues.


2023		2024-2025		2026-2027		After 2027		Total
(in millions)

$	16.1	$	32.2	$	23.2	$	11.7	$	83.2

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, 2022 and 2021.

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, 2022 and 2021.

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, 2022 and 2021. 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 $65 million and $118 million, as of December 31, 2022 and 2021.

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, 2022 and 2021.

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, 2022 and 2021, 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
			(dollars in millions)
Year Ended December 31, 2022
Balls Gap Station	Distribution	Balls Gap, WV	363	$	0.2		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, 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		—

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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			64,224	8,818,730	833,122		7,921,384
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income				4,891,938	8,337,016		3,445,078
3	Preceding Quarter/Year to Date Changes in Fair Value			36	13,012,772			13,012,736
4	Total (lines 2 and 3)			36	8,120,834	8,337,016		16,457,814	348,937,056	365,394,870
5	Balance of Account 219 at End of Preceding Quarter/Year			64,260	16,939,564	7,503,894		24,379,198
6	Balance of Account 219 at Beginning of Current Year			64,260	16,939,564	7,503,894		24,379,198
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income				1,881,834	834,896		2,716,730
8	Current Quarter/Year to Date Changes in Fair Value			36	26,517,723			26,517,759
9	Total (lines 7 and 8)			36	28,399,557	834,896		29,234,489	394,160,953	364,926,464
10	Balance of Account 219 at End of Current Quarter/Year			64,296	11,459,993	6,668,998		4,855,291

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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)	15,617,495,998	15,617,495,998
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	102,986,071.00	102,986,071.00
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified	1,364,579,011	1,364,579,011
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	17,085,061,080	17,085,061,080
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	711,076,450	711,076,450
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments	181,679.00	181,679.00
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	17,799,463,900	17,799,463,900
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	6,119,554,019	6,119,554,019
15	UtilityPlantNet Net Utility Plant (13 less 14)	11,679,909,881	11,679,909,881
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	5,964,392,029	5,964,392,029
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	154,984,459	154,984,459
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	6,119,376,488	6,119,376,488
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	4,148.00	4,148.00
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)	6,119,554,019	6,119,554,019

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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:

04/12/2023

Year/Period of Report

End of:

2022

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	15,260,558	5,323	593			15,265,288
4	(303) Miscellaneous Intangible Plant	264,481,598	46,657,288	27,880,388			283,258,498
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)	279,875,550	46,662,611	27,880,981			298,657,180
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	402,820,446	40,156,246	9,799,690			433,177,002
10	(312) Boiler Plant Equipment	4,423,503,861	36,063,886	15,752,907			4,443,814,840
11	(313) Engines and Engine-Driven Generators
12	(314) Turbogenerator Units	453,718,309	11,926,171	4,191,632			461,452,848
13	(315) Accessory Electric Equipment	182,711,955	1,627,294	363,553			183,975,696
14	(316) Misc. Power Plant Equipment	86,700,262	6,196,279	1,277,821			91,618,720
15	(317) Asset Retirement Costs for Steam Production	96,925,446	16,990,880				113,916,326
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)	5,658,743,747	112,960,756	31,385,603			5,740,318,900
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	9,800,813					9,800,813
28	(331) Structures and Improvements	30,839,586	2,764,523	217,787			33,386,322
29	(332) Reservoirs, Dams, and Waterways	85,364,429	1,914,455	241,163			87,037,721
30	(333) Water Wheels, Turbines, and Generators	117,251,688	4,682,155	197,663			121,736,180
31	(334) Accessory Electric Equipment	26,320,244	735,676	85,586			26,970,334
32	(335) Misc. Power Plant Equipment	23,231,625	1,220,462	52,282			24,399,805
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)	296,732,843	11,317,271	794,481			307,255,633
36	D. Other Production Plant
37	(340) Land and Land Rights	3,196,932					3,196,932
38	(341) Structures and Improvements	51,797,796	767,133	583,691			51,981,238
39	(342) Fuel Holders, Products, and Accessories	27,022,746					27,022,746
40	(343) Prime Movers
41	(344) Generators	516,909,913	5,547,823	4,332,453			518,125,283
42	(345) Accessory Electric Equipment	48,185,884	103,037	33,166			48,255,755
43	(346) Misc. Power Plant Equipment	32,333,138	2,829,671	1,732,790			33,430,019
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)	685,172,658	9,247,664	6,682,100			687,738,222
46	TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)	6,640,649,248	133,525,691	38,862,184			6,735,312,755
47	3. Transmission Plant
48	(350) Land and Land Rights	215,895,917	3,148,512	1,814,840			217,229,589
48.1	(351) Energy Storage Equipment - Transmission
49	(352) Structures and Improvements	172,492,959	9,332,663	1,212,550		2,021,724	(a) 178,591,348
50	(353) Station Equipment	2,059,913,788	38,901,053	18,692,460		339,733	2,079,782,648
51	(354) Towers and Fixtures	514,568,666	2,981,550	159,838			517,390,378
52	(355) Poles and Fixtures	526,792,823	52,967,565	5,376,294			574,384,094
53	(356) Overhead Conductors and Devices	785,012,763	87,683,463	6,847,848			865,848,378
54	(357) Underground Conduit	17,400,078	1,790,049				19,190,127
55	(358) Underground Conductors and Devices	28,754,978	621,654	583,974			28,792,658
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)	4,320,831,972	197,426,509	34,687,804		2,361,457	4,481,209,220
59	4. Distribution Plant
60	(360) Land and Land Rights	74,550,158	1,016,409	8,563			75,558,004
61	(361) Structures and Improvements	69,000,645	9,213,209	121,391			78,092,463
62	(362) Station Equipment	704,877,139	40,955,384	4,582,713		339,733	741,589,543
63	(363) Energy Storage Equipment – Distribution	5,338,844		5,173,743			165,101
64	(364) Poles, Towers, and Fixtures	871,679,023	60,640,140	6,808,733			925,510,430
65	(365) Overhead Conductors and Devices	1,164,492,018	87,085,070	7,202,224			1,244,374,864
66	(366) Underground Conduit	144,533,172	5,695,889	32,713			150,196,348
67	(367) Underground Conductors and Devices	324,295,551	11,092,322	598,841			334,789,032
68	(368) Line Transformers	650,875,394	29,204,445	10,791,368			669,288,471
69	(369) Services	374,096,304	17,186,676	2,600,963			388,682,017
70	(370) Meters	202,324,879	36,483,797	18,432,071			220,376,605
71	(371) Installations on Customer Premises	63,980,992	5,473,746	2,890,736			66,564,002
72	(372) Leased Property on Customer Premises	771					771
73	(373) Street Lighting and Signal Systems	32,070,814	2,043,870	437,889			33,676,795
74	(374) Asset Retirement Costs for Distribution Plant	3,069	2,968,296				2,971,365
75	TOTAL Distribution Plant (Enter Total of lines 60 thru 74)	4,682,118,773	309,059,253	59,681,948		339,733	4,931,835,811
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	16,003,857	1,322,434	3,786			17,322,505
87	(390) Structures and Improvements	155,037,041	97,959,554	593,741			252,402,854
88	(391) Office Furniture and Equipment	12,023,894	2,507,869	129,163			14,402,600
89	(392) Transportation Equipment	8,674					8,674
90	(393) Stores Equipment	2,075,929	161,041				2,236,970
91	(394) Tools, Shop and Garage Equipment	41,580,214	4,896,865				46,477,079
92	(395) Laboratory Equipment	3,072,914		365,490			2,707,424
93	(396) Power Operated Equipment	132,662	18,328				114,334
94	(397) Communication Equipment	132,429,228	56,336,263	1,371,011			187,394,480
95	(398) Miscellaneous Equipment	8,106,961	461,556	6,500		2,021,724	10,583,741
96	SUBTOTAL (Enter Total of lines 86 thru 95)	370,471,374	163,627,254	2,469,691		2,021,724	533,650,661
97	(399) Other Tangible Property		43,287				43,287
98	(399.1) Asset Retirement Costs for General Plant	1,366,095					1,366,095
99	TOTAL General Plant (Enter Total of lines 96, 97, and 98)	371,837,469	163,670,541	2,469,691		2,021,724	535,060,043
100	TOTAL (Accounts 101 and 106)	16,295,313,012	850,344,605	163,582,608			16,982,075,009
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)	16,295,313,012	850,344,605	163,582,608			16,982,075,009

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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:

04/12/2023

Year/Period of Report

End of:

2022

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:

04/12/2023

Year/Period of Report

End of:

2022

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		287,901.00
4	Shadwell 69KV Substation, Roanoke County, VA 10.637 acres (7662)	08/01/2009	12/31/2023	431,124.00
5	Sheridan 69KV Substation, Lincoln County, WV 4.947 acres (2041)	11/01/2015	12/31/2023	327,042.00
6	Items under $250,000			1,842,554.00
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:

04/12/2023

Year/Period of Report

End of:

2022

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	204MW APCo Wind (Top Hat)	1,784,191
2	ADMS Imp DSN DNEX-APC D	3,030,040
3	AM CCR/ELG Compliance	127,807,989
4	AM FGD Landfill Sequence 4-10	1,004,485
5	AM2 SCR CAT L1 REPLACE	2,135,743
6	Amos 1&2 DSI Project	8,644,179
7	Amos U1 Evergreen Project	6,034,437
8	Amos U1 Phase 3 GSU Replace	2,616,087
9	AMU1 Air Heater Basket Replace	2,119,880
10	AMU2 Air Heater Basket Replace	4,329,227
11	APCO - D	3,969,815
12	APCo - T Work	1,890,783
13	APCO - Transmission Work	2,587,341
14	APCo AMI Project VA	2,088,823
15	APCO AMI Project WV	15,325,848
16	APCo D (Floyd-Stuart Area)	1,981,980
17	APCo D Work (Supplemental)	9,717,100
18	APCO Distr Pre Eng Parent	9,377,955
19	APCo Distribution Work	7,873,996
20	APCO Next Generation Radio Sys	1,258,950
21	APCO T (Baseline)	1,261,393
22	APCo T (Floyd-Stuart Area)	1,544,922
23	APCo T (Station)	2,228,102
24	APCo T (Supplemental)	1,639,538
25	APCo T CI	1,147,369
26	APCO T Supplemental Work	2,482,514
27	APCo T Work 1	3,811,192
28	APCo T Work 2	2,418,762
29	APCo T Work 3	2,513,653
30	APCo T Work 4	1,503,151
31	APCo T Work 5	3,273,682
32	APCo T Work (Supplemental)	12,993,352
33	APCo T-BlnktProj Under $3M	9,601,640
34	APCO Trans Pre Eng Parent	13,630,861
35	APCo Transmission Work	7,891,794
36	APCO T-Work	14,206,834
37	APCo VA Major Eq/ Spares-Trans	7,233,917
38	APCo VA Major Eq/Spares- Distr	1,882,916
39	APCo WV Major Eq/Spares-Trans	2,497,042
40	APCO: RBB Grayson	8,223,230
41	APCO: RBB LOGAN &	14,951,292
42	APCO-D	4,198,594
43	APCo-D BlnktProj Under $3M	1,545,363
44	APCo-D Service Restoration Blk	1,611,633
45	APCo-D Small Cap Adds Blkt	1,364,100
46	APCO-D Telecom	4,158,715
47	APCo-D Third Party Work Blkt	4,668,259
48	APCO-T	3,837,778
49	APCo-T Bluefield TTMP CI	4,846,874
50	APCO-T Virginia CI	1,971,591
51	APCo-T Work 1	18,674,032
52	APCo-T Work 2	1,361,070
53	APCO-Tranco Line Rebuild-T	1,097,203
54	Berry Hill Station	2,067,566
55	Bluefield TTMP APCo-T CI	1,611,509
56	CIS-Common Deployment-APC D	4,700,531
57	CLH 3 Tailrace Disolved Oxygen	1,864,512
58	CLH 4 Tailrace Disolved Oxygen	1,984,730
59	CoCo - Install Dist Bank	1,550,461
60	Corp Prgrm Billing - APCO Tran	3,684,955
61	D/AP/Capital Blanket - APCo	2,424,476
62	D/AP/Distribution Work	5,063,258
63	Ds-Ap-Virg-Ai Recloser Repl	1,031,721
64	Ds-AP-WVirg-AI Recloser Repl	1,340,359
65	Ed-Ci-Apco-D Ast Imp	30,977,476
66	Ed-Ci-Apco-D Cust Serv	3,225,876
67	EV Chargers for GL BU 140	1,677,616
68	Forestry AP WV D Base R W	3,183,015
69	Grundy Service Center	6,360,730
70	Hockman Sta - Sta Work	1,107,324
71	John Vaughan Adjacent Land Pur	2,150,338
72	John Vaughan Truck Garage	7,178,051
73	Kenna- New Station(APCO)	2,554,108
74	Mount Heron - CoalCreek APCO-T	3,050,621
75	MT ELG/CCR Compliance	18,744,654
76	Mullens APCO T Work	3,288,305
77	NIH RELICENSE NIAGARA HYDRO	1,867,942
78	Poplar Creek VDOT EC-F-G69kV	1,105,617
79	Purchase New APCO HDQ Building	4,861,719
80	RCA Station - APCO Station	1,166,404
81	Roanoke Transmission RDC	2,007,594
82	Roanoke TTMP APCo-T CI	3,938,239
83	SS-CI-APCo-D GEN PLT	19,659,090
84	SS-CI-APCo-T GEN PLT	1,226,550
85	SSH Outlet Bank Replacement	2,511,416
86	T/AP/Capital Blanket - APCo	5,592,025
87	T/AP/NERC Physical Security	33,231,905
88	T/AP/Sheridan Trans CI	1,744,086
89	T/AP/Stuart Area Telecom Moder	1,109,048
90	Teays Valley SC Land Purchase	1,217,113
91	Trans line Renew-Refurb WV, VA	2,815,591
92	U3 IP ROTOR & CYLINDER REFURBI	2,939,551
93	West Virginia Uphill Widen CI	8,293,896
94	Wo	5,894,351
95	WS-CI-APCo-G PPB	78,789,350
96	Other Minor Projects under $1,000,000	47,768,072
43	Total	711,076,450

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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	5,627,407,860	5,627,412,008	4,148
2	Depreciation Provisions for Year, Charged to
3	DepreciationExpenseExcludingAdjustments (403) Depreciation Expense	519,972,081	519,972,081
4	DepreciationExpenseForAssetRetirementCosts (403.1) Depreciation Expense for Asset Retirement Costs	7,242,048	7,242,048
5	ExpensesOfElectricPlantLeasedToOthers (413) Exp. of Elec. Plt. Leas. to Others
6	TransportationExpensesClearing Transportation Expenses-Clearing
7	OtherClearingAccounts Other Clearing Accounts	756,165	756,165
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)	527,619,623	527,619,623
11	Net Charges for Plant Retired:
12	BookCostOfRetiredPlant Book Cost of Plant Retired	135,701,627	135,701,627
13	CostOfRemovalOfPlant Cost of Removal	83,317,277	(b) 83,317,277
14	SalvageValueOfRetiredPlant Salvage (Credit)	28,379,302	(c) 28,379,302
15	NetChargesForRetiredPlant TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)	190,639,602	190,639,602
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)	5,964,387,881	5,964,392,029	4,148
Section B. Balances at End of Year According to Functional Classification
20	AccumulatedDepreciationSteamProduction Steam Production	2,850,051,011	2,850,051,011
21	AccumulatedDepreciationNuclearProduction Nuclear Production
22	AccumulatedDepreciationHydraulicProductionConventional Hydraulic Production-Conventional	77,647,325	77,647,325
23	AccumulatedDepreciationHydraulicProductionPumpedStorage Hydraulic Production-Pumped Storage	96,492,951	96,492,951
24	AccumulatedDepreciationOtherProduction Other Production	264,653,195	264,653,195
25	AccumulatedDepreciationTransmission Transmission	849,941,960	849,946,108	4,148
26	AccumulatedDepreciationDistribution Distribution	1,717,284,254	1,717,284,254
27	AccumulatedDepreciationRegionalTransmissionAndMarketOperation Regional Transmission and Market Operation
28	AccumulatedDepreciationGeneral General	108,317,185	108,317,185
29	AccumulatedProvisionForDepreciationOfElectricUtilityPlant TOTAL (Enter Total of lines 20 thru 28)	5,964,387,881	5,964,392,029	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 $36,665,622 of removal cost in retirement work in progress (RWIP).

Includes ($23,956,247) 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:

04/12/2023

Year/Period of Report

End of:

2022

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	Provision for Parent Savings Tax						9,015
18	Undistributed earnings/losses and dividends - Southern Appalachian Coal Company			690,462			690,462
19	Cedar Coal Company
20	SEC File 70-5470, 4-30-74
21	2,000 shares common stock	04/10/1974		200,000			200,000
22	Capital Contributions - Cedar Coal			4,868,403			4,868,403
23	Investment in Subsidiary AOCI			792,348		2,428,075	1,635,727
24	Undistributed earnings/losses and dividends - Cedar Coal Company			2,483,074			2,483,074
42	Total Cost of Account 123.1 $		Total	4,641,308		2,428,075	7,078,398

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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)	61,380,905	151,723,238	Electric
2	Fuel Stock Expenses Undistributed (Account 152)	5,704,904	7,213,740	Electric
3	Residuals and Extracted Products (Account 153)	6,791		Electric
4	Plant Materials and Operating Supplies (Account 154)
5	Assigned to - Construction (Estimated)	63,761,224	53,145,634	Electric
6	Assigned to - Operations and Maintenance
7	Production Plant (Estimated)	43,429,835	74,201,072	Electric
8	Transmission Plant (Estimated)	220,485	220,506	Electric
9	Distribution Plant (Estimated)	1,249,262	1,902,286	Electric
10	Regional Transmission and Market Operation Plant (Estimated)
11	Assigned to - Other (provide details in footnote)	(a) 393,051	(b) 682,511	Electric
12	TOTAL Account 154 (Enter Total of lines 5 thru 11)	109,053,857	130,152,009
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	176,146,456	289,088,987

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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:

04/12/2023

Year/Period of Report

End of:

2022

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	1,126,245	22,118,482	185,984		185,897		161,871		4,208,326		5,868,323	22,118,482
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)	6,177								162,274		168,451
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	15,872	189,545									15,872	189,545
19	Other:
20	Allowances Used
20.1	Allowances Used
21	Cost of Sales/Transfers:
22	Consent Decree Surrenders			148,359								148,359
23
24
25
26
27
28	Total			148,359								148,359
29	Balance-End of Year	1,116,550	(a) 21,928,937	37,535		185,897		161,871		4,370,600		5,872,453	21,928,937
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:

04/12/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: AllowanceInventory

NOX has no book value associated with the quantity. $675,724 is for 59,867 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:

04/12/2023

Year/Period of Report

End of:

2022

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	129,530	675,725	17,129		17,126						163,785	675,725
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)	3,747										3,747
5	Returned by EPA
6
7
8	Purchases/Transfers:
9	Chicago Climate Exchange
10	Other
11	Regional Greenhouse Gas Initiative, Inc.	100,000	1,322,000									100,000	1,322,000
12
13
14
15	Total	100,000	1,322,000									100,000	1,322,000
16
17	Relinquished During Year:
18	Charges to Account 509	68,317	580,944									68,317	580,944
19	Other:
20	Allowances Used
20.1	Allowances Used
21	Cost of Sales/Transfers:
22	Wolverine Power Supply Cooperative, Inc.
23
24
25
26
27
28	Total
29	Balance-End of Year	164,960	(a) 1,416,781	17,129		17,126						199,215	1,416,781
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:

04/12/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: AllowanceInventory

NOX has no book value associated with the quantity. $675,724 is for 59,867 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:

04/12/2023

Year/Period of Report

End of:

2022

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
2	(b) Glen Lyn Unit 6	5,703,621	62,572			4,294,940
3	(c) Kanawha Plant	27,432,795	1,112,230			19,451,869
4	(d) Sporn Plant	10,478,046	458,519			7,321,070
5	(e) Clinch River Plant Coal Assets	58,709,555	2,006,588			44,499,755
20	TOTAL	102,689,194	3,514,765			75,567,634

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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:

04/12/2023

Year/Period of Report

End of:

2022

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:

04/12/2023

Year/Period of Report

End of:

2022

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	11,800	186	11,758	186
3	AE1-108	12,527	186	14,240	186
4	AE1-108	53	186	98	186
5	AE1-250	45,861	186	61,495	186
6	AE2-160	8,198	186	9,869	186
7	AF1-049	2,715	186	2,453	186
8	AF1-323	8,419	186	8,518	186
9	AF2-382	37,919	186	37,867	186
10	AG1-089	114	186
11	AG1-091	441	186
12	AG1-092	297	186
13	AG1-124	911	186	1,086	186
14	AG1-136	431	186
15	AG1-162	528	186
16	AG1-194	144	186
17	AG1-219	210	186
18	AG1-311	84	186
19	AG1-528	122	186
20	AG2-127	25	186	46	186
21	AG2-132	24	186	46	186
22	AG2-168	19	186	35	186
23	AG2-187	26	186	48	186
24	AG2-202	32	186	66	186
25	AG2-203	33	186	69	186
26	AG2-311	24	186	45	186
27	AG2-368	32	186	66	186
28	AG2-568	51	186	104	186
29	AG2-657	57	186	117	186
30	PJM - #AD1-102	82,279	186	79,744	186
31	PJM - #AD2-022	8,001	186	441	186
32	PJM - #AD2-178	11,161	186	11,477	186
33	PJM - #AD2-179	10,379	186	10,585	186
34	PJM - #AE1-212	4,388	186
35	PJM - #AE2-047	13,045	186	12,918	186
36	PJM - #AE2-140	1,668	186	1,954	186
37	PJM - #AE2-166	10,465	186
38	PJM - #AE2-280	12,765	186	25,185	186
39	PJM - #AE2-326	5,778	186	5,102	186
40	PJM - #AF2-302	101	186
41	PJM - #AF2-382	241	186
42	PJM - #AG1-123			54	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:

04/12/2023

Year/Period of Report

End of:

2022

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	SFAS 112 Postemployment Benefits - Rate Order: WV PSC Case 14-1152-E-42T	13,269,171	1,899,540	228	1,425,392	13,743,319
2	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	9,896,664	1,963,326	908	1,867,902	9,992,088
3	Unrealized Loss on Forward Commitments		15,644,616	175/244/254	14,324,785	1,319,831
4	Netting of Trading Activities related to Unrealized Gains/Losses on Forward Commitments between Regulated Assets/Liabilities		3,537,265	254	4,857,096	1,319,831
5	Environmental Compliance Costs - Rate Orders: VA Code Section 56-582B (vi) VASCCPUE-2005-00056 - Amortization Period: 01/2021 - 12/2023	131,187		407	65,593	65,594
6	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	67,249	33,625			33,624
7	Capital Environmental Equity Costs - Rate Orders: VA Code Section 56-582B (vi) VA SCC PUE-2005-00056 - Amortization Period: 01/2021 - 12/2023	8,011	4,005			4,006
8	Defd System Reliability Costs - Rate Orders: VA Code Section 56-582B (vi) VA SCC PUE-2005-00056 - Amortization Period: 01/2021 - 12/2023	30,075	59,812	407	44,944	44,943
9	Equity Costs - Capital Reliability - Rate Orders: VA Code Section 56-582B (vi) VA SCC PUE-2005-00056 - Amortization Period: 01/2021 - 12/2023	40,628	36,279			4,349
10	Defd Carrying Charges - Reliability Capital - Rate Orders: VA Code Section 56-582B (vi) VA SCC PUE-2005-00056 - Amortization Period: 01/2021 - 12/2023	74,179	19,733	182, 566	113,646	19,734
11	Unrecovered Fuel Cost - VA	127,209,224	296,275,226	501	242,778,517	180,705,933
12	Unrecovered Fuel Cost - WV	72,668,955	233,918,855	501	18,095,744	288,492,066
13	SFAS 158 Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans	62,695,553	132,209,459	129, 228	86,636,421	108,268,591
14	VA Demand Response Program - Rate Order: VA SCC PUE-2011-0001	4,082,132	935,059	908	2,427,344	2,589,847
15	Dresden Operating Costs - VA - Rate Order: VA SCC PUE-2011-00036	3,336,495	5,662,623	403	1,019,369	7,979,749
16	SFAS 106 Medicare Subsidy - Amortization period - 1/2013 to 12/2024	1,766,455		926	588,819	1,177,636
17	SFAS 109 Deferred Federal Income Tax	96,649,834	86,033,586	190/254/282/283/409/410/411	68,187,524	114,495,896
18	SFAS 109 Deferred State Income Tax	231,263,370	50,264,682	190/236/254/282/283/409/410/411	20,639,017	260,889,035
19	Carbon Capture and Storage Project FEED Study Costs - Rate Order: WV PSC Case 13-0467-E-GI	76,623		506	76,623
20	WV Vegetation Management Program Costs - Rate Order: WV PSC Case 13-0557-E-P - Rate Order: WV PSC Case 14-1152-E-42T	11,909,455	18,859,986	571/593	17,083,051	13,686,390
21	NBV ARO's Retired Plants - Rate Order: VA SCC PUE-2014-0026 - Rate Order: WV PSC 14-1151-E-D	29,408,315		403	350,671	29,057,644
22	M&S Retiring Plants - Rate Order: VA SCC PUE-2014-0026 - Rate Order: WV PSC 14-1151-E-D	399,456		506	36,324	363,132
23	Unrecovered Fuel - Common Wealth Virginia - Per Agreement with Commonwealth of Virginia. Effective June 4, 2015.	1,393,139	3,694,227	501	1,210,861	3,876,505
24	WV Air Quality Permit Fees - Rate Order: WVPSC Case No. 18-0646-E-42T - Amortization Period: 3/2019 - 2/2024	267,410		506	123,420	143,990
25	WV EE/DR - Company Funded - Case No. PUE-2014-00039	3,844,932	78,469	908	1,020,084	2,903,317
26	WV Deferred Rate Case Expenses - WVPSC Case #18-0646-E-42T - Amortization Period: 03/2019 - 02/2022	29,647		928	29,647
27	COVID-19 Costs - WV General Order: WVPSC 262.4 - VA SCC Case No. PUR-2020-00074	8,030,687	384,712	921	1,337,267	7,078,132
28	Carrying Chgs-COVID-19 Costs - VA SCC Case No. PUR-2020-00074	500,065	540,538			1,040,603
29	Equity Carrying Chgs-COVID-19 Costs - VA SCC Case No. PUR-2020-00074	220,823		431	252,311	473,134
30	Glen Lyn Ash Pond ARO - VA HB443	289,532,368	10,369,279			299,901,647
31	Carrying Chgs-VA Broadband Pilot - VA SCC Case No. PUR-2019-00145	329,733	1,567	403/431	331,300
32	Equity Carrying Chgs-VA Broadband Pilot - VA SCC Case No. PUR-2019-00145	145,312	147,445	182/254	2,133
33	VA T-RAC Costs - VA SCC Case No. PUE-2009-00031	37,237,591	16,635,050	566	35,732,869	18,139,772
34	VA Retired Coal Plants - VA SCC Case No. PUR-2020-00015	30,881,009		407	30,881,009
35	VA E-RAC CCR Expenses - VA SCC Case No. PUR-2020-00015 - Amortization Period: 10/2021 - 09/2022	12,647,324	96,323	501	12,743,647
36	VA Major Storm Expense - VA SCC Case No. PUR-2020-00015	15,150,923	33,127,662	593	10,411,275	37,867,310
37	VA Broadband Under Recovery	59,265		403	59,265
38	LSE PJM Formula Rate Deferral - Amortization Period: 01/2022 - 12/2022	2,695,884		565	2,695,884
39	WV Deferred Storm Expense	53,674,877	74,887,176	593	55,971,920	72,590,133
40	WV MRBC Surcharge Under Recovery	831,794	1,837,872	403	1,803,213	866,453
41	WV CCR/ELG AFUDC Deferral - Amortization Period: 09/2021 - 08/2022	642,465		403	642,465
42	VA Distribution Substation Depreciation Deferral	297,740	87,854	182/403/431	173,416	212,178
43	VA Distribution Substation Carrying Charge Deferral	976,499	276,725	182/403/431	522,177	731,047
44	VA Distribution Substation Equity Carrying Charge Deferral	696,172	480,416	403/431	192,634	408,390
45	VA E-RAC Deferral AFUDC - Amortization Period: 10/2021 - 09/2022 and 12/2022 - 11-2023	194,772	3,394,594	501	863,587	2,725,779
46	VA RGGI Deferral	340,981	253,055	509	49,503	544,533
47	VA VCEA RPS Under Recovery	2,149,843	14,932,710	254/445/555	17,082,553
48	VA E-RAC Under Recovery	233,682	3,431,590	501	3,665,272
49	WV CRR Under Recovery - Case No. 12-1188-E-PC	390,433	3,414,104	407	784,107	3,020,430
50	2022 PJM Transmission True-up	3,451,631	4,694,671	447/565	5,426,136	2,720,166
51	WV Beneficial Electrification Program - Case No. 19-0396-E-PC		317,724			317,724
52	WV ACNR Breach Cost Deferral		34,975			34,975
53	VA PIPP Admin Cost Deferral		592,580			592,580
54	WV ECS Under Recovery		1,139,763	403	76,493	1,063,270
55	VA A.5 RPS-RAC Under Recovery		24,465,211	134,142, 182, 555, 557	8,709,599	15,755,612
56	VA A.5 PCAP-RAC Under Recovery		2,675,179	134,142, 182, 555, 557	1,753,033	922,146
57	VA 2017-2019 Triennial Under Earnings - Amortization Period: 10/2022 - 01/2024		37,037,015	407	6,944,439	30,092,576
58	Unrecovered Fuel Cost - VA - Long-term		223,288,030			223,288,030
44	TOTAL	1,129,473,642	1,309,674,193		682,110,301	1,757,037,534

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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	78,543,016	83,022,999	107,236,408	86,550,406	75,015,609
2	Property Taxes Ohio	5,654,266	6,042,154	107,408	5,654,266	6,042,154
3	Agency Fees - Factored A/R	2,999,430	31,952,046	184,426	31,063,863	3,887,613
4	Labor Accruals - Balance Sheet	1,493	197,548	183.152	195,250	3,791
5	Miscellaneous	324,770	464,439	(a) 142, 143, 232, 253, 593, 243, 588	611,070	178,139
6	Property Taxes - Capital Leases West Virginia	86,985	944,921	408	845,159	186,747
7	Unamortized Credit Line Fees Amortization through June 2022	1,067,801	577,242	431	654,113	990,930
8	Def Lease Assets - Non Taxable	58,279	996,477	143,184	754,945	299,811
9	Deferred Urea Expense	2,602,665	27,412,521	(b) 142,186, 232, 154	27,833,546	2,181,640
10	VA Sales/Use Tax Surcharge	1,099,115	1,806,129	142	772,864	65,850
11	Estimated Barging Bills	907,644	34,731,370	(c) 151/154/186/232	35,639,014
12	PJM Provision for Refund		13,759,038	146, 253	5,934,628	7,824,410
13	Railroad Cars Subleased		29,727	151,236, 408	27,890	1,837
47	Miscellaneous Work in Progress	1,805,188				2,480,420
48	Deferred Regulatroy Comm. Expenses (See pages 350 - 351)
49	TOTAL	92,952,422				99,027,251

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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:

04/12/2023

Year/Period of Report

End of:

2022

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	52,039,166	57,333,967
3	CIAC	12,068,245	13,405,577
4	DSIT Normalized	12,165,004	11,281,512
5	Accrued Book Removal Costs	67,676,004	67,667,198
6	Accrued Book ARO Expenses	84,970,740	89,833,622
7	Other	26,378,365	24,601,332
8	TOTAL Electric (Enter Total of lines 2 thru 7)	255,297,524	264,123,208
9	Gas
15	Other
16	TOTAL Gas (Enter Total of lines 10 thru 15)
17.1	Other (Specify)	233,465,850	(a) 232,973,277
17	Other (Specify)
18	TOTAL (Acct 190) (Total of lines 8, 16 and 17)	488,763,374	497,096,485

Notes

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxes


	Notes


Line 17 Other - Detail		Balance at Beginning of Year		Balance at End of Year

Acc Def Income Taxes - Federal - Hdg-CF-Int Rate		657,335		613,457
Non Utility Items - 190.2		4,695,338		9,383,500
SFAS 109-Regulatory Assets - 190.3, 190.4 & 190.6		232,826,723		219,495,179
Accu Def Income Taxes Pension-OCI		(4,713,546)		3,481,141

Total		$	233,465,850	$	232,973,277


Line 18
Reconciliation of details applicable to Account 190,Line 18,Columns(b)and(c) :

Balance at Beginning of Year		$	488,763,374

(Less) Amounts Debited to:
(a) Account 410.1		(62,390,772)
(b) Account 410.2		(4,533,697)
(c) 1823/254/219/129/427		(67,081,752)

(Plus) Amounts Credited to:
(a) Account 411.1		77,408,311
(b) Account 411.2		3,030,003
(c) 1823/254/219/129/427		61,901,018

Balance at End of Year		$	497,096,485

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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:

2023-04-12

Year/Period of Report

End of:

2022

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	9,016
16	MiscellaneousPaidInCapital Ending Balance Amount	2,651,031
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	1,828,635,966

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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:

04/12/2023

Year/Period of Report

End of:

2022

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	9,674,260	255,476
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	6,319,844
6	Subtotal		380,300,000		4,258,008		17,409					174,174,260	6,575,320
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	(c) Amos Project, Series 2009A, Due 2042 -WV Economic Development Authority, Solid Waste Disposal Facility - 3.75% Bonds, Remarketed 06-01-2022		54,375,000		410,584			05/15/2018	12/01/2042	05/15/2018	06/01/2022	54,375,000	1,784,180
19					338,283			06/01/2022	12/01/2042	06/01/2022	06/01/2025
20	(d) Amos Project, Series 2009B, Due 2042 -WV Economic Development Authority, Solid Waste Disposal Facility - 3.75% Bonds, Remarketed 06-01-2022		50,000,000		377,548			05/15/2018	12/01/2042	05/15/2018	06/01/2022	50,000,000	1,640,625
21					321,042			06/01/2022	12/01/2042	06/01/2022	06/01/2025
22	Mountaineer Project, Series 2008A, Due 2036 -WV Economic Development Authority, Solid Waste Disposal Facility -Variable Rate Demand Bonds		75,000,000		370,548			03/17/2011	02/01/2036	01/13/2016	02/01/2036	75,000,000	948,914
23	Mountaineer Project, Series 2008B, Due 2036 -WV Economic Development Authority, Solid Waste Disposal Facility -Variable Rate Demand Bonds		50,275,000		291,961			03/17/2011	02/01/2036	03/10/2016	02/01/2036	50,275,000	657,046
24	Amos Project, Series 2010A, Due 2038 -WV Economic Development Authority, Solid Waste Disposal Facility - 5.375% Bonds - Subject to mandatory tender for purchase (puttable) on 12/01/2020 -Remarketed 12-23-2020 - 0.625% Bonds		50,000,000		649,267			05/19/2010	12/01/2038	05/19/2010	12/01/2038	50,000,000	312,500
25					384,107			12/23/2020	12/01/2038	12/23/2020	12/05/2025
26	Mason County, WV, Series L, Due 2022 -Pollution Control Revenue Bonds - 1.625% Bonds - Subject to mandatory tender for purchase (puttable) on 10/01/2018 -Remarketed 10/01/2018 - 2.750% Bonds		100,000,000		674,863			10/01/2014	10/01/2022	10/01/2014	10/01/2018		2,062,500
27					608,622			10/01/2018	10/01/2022	10/01/2018	10/01/2022
28	Amos Project, Series 2015A, Due 2040 -WV Economic Development Authority, Solid Waste Disposal Facility - 1.900% Bonds - Subject to mandatory tender for purchase (puttable) on 04/01/2019 -Remarketed 04/01/2019 - 2.550% Bonds		86,000,000		642,924			04/01/2015	03/01/2040	04/01/2015	04/01/2019	86,000,000	2,193,000
29					555,367			04/01/2019	04/01/2024	04/01/2019	04/01/2024
30	Amos Project, Series 2011A, Due 2041 -WV Economic Development Authority, Solid Waste Disposal Facility - 1.700% Bonds - Subject to mandatory tender for purchase (puttable) on 09/01/2020 -Remarketed 09/01/2025 - 1.000% Bonds		65,350,000		416,278			09/01/2016	01/01/2041	09/01/2016	09/01/2020	65,350,000.00	653,500
31					427,620			09/01/2020	01/01/2041	09/01/2020	09/01/2025
32	SENIOR UNSECURED NOTES
33	5.800% Senior Unsecured Notes, Series L, Due 2035		250,000,000		2,334,997		1,900,000	09/29/2005	10/01/2035	09/29/2005	10/01/2035	250,000,000	14,500,000
34	(e) 5.950% Senior Unsecured Notes, Series H, Due 2033		200,000,000		1,900,000		422,000	05/05/2003	05/15/2033	05/05/2003	05/15/2033	200,000,000	11,900,000
35	Interest Expense amortization of Cash Flow Hedge												37,071
36	6.375% Senior Unsecured Notes, Series N, Due 2036		250,000,000		2,266,382		757,500	04/10/2006	04/01/2036	04/10/2006	04/01/2036	250,000,000	15,937,500
37	Interest Expense amortizations of Cash Flow Hedges												194,198
38	6.700% Senior Unsecured Notes, Series P, Due 2037		250,000,000		2,348,344		62,500	08/17/2007	08/15/2037	08/17/2007	08/15/2037	250,000,000	16,750,000
39	7.000% Senior Unsecured Notes, Series Q, Due 2038		500,000,000		4,447,060		3,300,000	03/25/2008	04/01/2038	03/25/2008	04/01/2038	500,000,000	35,000,000
40	Interest Expense amortization of Cash Flow Hedges												159,670
41	4.400% Senior Unsecured Notes, Series U, Due 2044		300,000,000		2,973,178		2,082,000	05/08/2014	05/15/2044	05/08/2014	05/15/2044	300,000,000	13,200,000
42	3.400% Senior Unsecured Notes, Series V, Due 2025		300,000,000		2,312,703		1,065,000	05/18/2015	06/01/2025	05/18/2015	06/01/2025	300,000,000	10,200,000
43	4.450% Senior Unsecured Notes, Series W, Due 2045		350,000,000		3,483,819		2,530,500	05/18/2015	06/01/2045	05/18/2015	06/01/2045	350,000,000	15,575,000
44	3.300% Senior Unsecured Notes, Series X, Due 2027		325,000,000		2,648,060		1,657,500	05/11/2017	06/01/2027	05/11/2017	06/01/2027	325,000,000	10,725,000
45	4.500% Senior Unsecured Notes, Series Y, Due 2049		400,000,000		4,158,436		2,736,000	03/06/2019	03/01/2049	03/06/2019	03/01/2049	400,000,000	18,000,000
46	3.700% Senior Unsecured Notes Series Z, Due 2050		500,000,000		5,106,633		2,955,000	05/14/2020	05/01/2050	05/14/2020	05/01/2050	500,000,000	18,500,000
47	(f) 2.700% Senior Unsecured Notes Series AA, Due 2031		500,000,000		4,160,254		2,203,000	03/11/2021	04/01/2031	03/11/2021	04/01/2031	500,000,000	13,500,000
48	- Interest Expense re amortization of Cash Flow Hedges												1,059,374
49	4.500% Senior Unsecured Notes Series BB, Due 2032, Virginia State Corporation Commission Authority PUR-2021-00271, Tennessee Public Utility Commission Docket No. 21-00126		500,000,000		4,188,837		1,315,000	08/01/2022	08/01/2032	08/01/2022	08/01/2032	500,000,000	9,375,000
50	SALE / LEASEBACK OF PROPERTY
51	Agreement with City of Bedford, VA re Skimmer Station		2,559,040					06/07/1996	06/06/2026	06/07/1996	06/06/2026	1,813,015	253,219
52	Floating Credit Facility - Remarketed on 05/26/2022		125,000,000		511,753			06/05/2019	06/05/2022	06/05/2019	06/05/2022	125,000,000	679,237
53					515,004			05/26/2022	05/26/2025	05/26/2022	05/26/2025		2,818,359
54	Variable Rate Credit Facility, Virginia State Corporation Commission Authority PUR-2021-00271, Tennessee Public Utility Commission Docket No. 21-00126		100,000,000		15,222			07/22/2022	08/22/2023	07/22/2022	08/22/2023	100,000,000	1,763,628
48	Subtotal		5,383,559,040		49,839,696		22,986,000					5,282,813,015	217,872,377
33	TOTAL		5,763,859,040									5,456,987,275	224,447,697

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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.

These are the re-marketed bonds from May 15, 2018.

(d) Concept: ClassAndSeriesOfObligationCouponRateDescription

These are the re-marketed bonds from May 15, 2018.

(e) Concept: ClassAndSeriesOfObligationCouponRateDescription

Issuance : Amos Project, Series 2009A, Due 2042

Principal Amount : $54,375,000

Issuance Date : 03/25/2011

Maturity Date : 12/01/2042

Interest Rate : Variable Rate Demand Bonds

Reacquired Date : 01/19/2017

Remarketed Date : 05/15/2018

(f) Concept: ClassAndSeriesOfObligationCouponRateDescription

Issuance : Senior Unsecured Note Series AA (2.700%) , Due 2031

Principal Amount : $500,000,000

Issuance Date : 03/11/2021

Maturity Date : 04/01/2031

– Issuance expense and Discount expense will be amortized through April 2031

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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)	394,160,953
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	(a) 255,486,649
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:

04/12/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: FederalTaxNetIncome



FOOTNOTE DATA

Schedule Page: 261 Line No.: 28 Column: b

Net Income for the Year per Page 117						394,161


Federal Income Taxes						25,637
State Income Taxes						(6,889)
Pre-Tax Book Income						412,909

Other						18,066
Excess Tax vs Book Depr						94,538
AFUDC & Other Capitalization Differences						(5,951)
Book/Tax Mixed Service Cost Adj						(53,084)
Removal Costs						(61,803)
Pollution Control Equipment						50,607
Provision for Possible Revenue Refunds						18,687
Deferred Fuel Costs						(495,091)
Pension Expenses						2,723
Defd Costs & Carrying Charges						(39,853)
Premium of Reacquired Debt						3,799
SFAS 106 - Post Retire Benefit Exp						(17,281)
Accrued Bk ARO Expense - SFAS 143						23,157
Capitalized Software						18,554
Book/Tax Unit of Property Adj						(225,120)
Virginia T-RAC						19,098
Deferred Storm Damage						(18,886)
Incentive Compensation Plans						(3)
Accrued Book Severance Benefits						(6)
Extra Loss - Plant Retirements						3,502
Stock Compensation						(40)
COVID-19 Incremental Costs						953
Charitable Contribution Carryforward						(8,825)
Regulatory Asset - SFAS 143 - ARO						3,863

Taxable Income before State Taxes						(255,487)

State & Local Current Tax						0

Federal Taxable Income						(255,487)
FIT on Current Year Taxable Income						(53,652)
NOL Deferred Tax Asset						744
Tax Credits						3,180
R & D CREDIT - CURRENT						191
Alt Min						0
Tax Provision Adjustments						0
Estimated Tax Currently Payable (a)						(57,767)

Adjustments of Prior Year's Accruals						(2,723)
Tax Expense for R/C of Net Operating Loss (Prior Yr)


Estimated Current Federal Income Taxes						(60,490)

(a) Represents the allocation of the estimated current year net operating tax income of American Electric Power Company, Inc.

INSTRUCTION 2.

* The tax computation above represents an estimate of the Company's allocated portion of the System consolidated Federal income tax. The computation of actual 2022 System Federal income taxes will not be available until the consolidated Federal income tax return is completed and filed by October 2023. The actual allocation of the System consolidated Federal income tax to the members of the consolidated group will not be available until after the consolidated federal income tax return is filed.

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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			38,008,766		64,727,866	92,557,757		10,178,875	0	54,522,666			10,205,200
2	Subtotal Federal Tax				38,008,766	0	64,727,866	92,557,757		10,178,875	0	54,522,666			10,205,200
3					0	0				0	0
4	Subtotal State Tax				0	0	0	0	0	0	0	0	0	0	0
5		Local Tax		2019	8,906	0				8,906	0
6		Local Tax	WV	2020						0
7		Local Tax	WV	2021	3,356,933		3,218	3,353,715		0					3,218
8	Subtotal Local Tax				3,365,839	0	3,218	3,353,715	0	8,906	0	0	0	0	3,218
9		Other Taxes	TN	2020						0
10		Other Taxes	TN	2021						0
11		Other Taxes	WV	2020						0
12		Other Taxes	WV	2021	1,463,000	1,855,668	1,124,168	731,500		0					1,124,168
13	Subtotal Other Tax				1,463,000	1,855,668	1,124,168	731,500	0	0	0	0	0	0	1,124,168
14		Property Tax	AR	2021			1,445	1,445		0	0				1,445
15		Property Tax	CO	2021			713	713		0	0				713
16		Property Tax	LA	2022			1,837	1,837		0	0				1,837
17		Property Tax	MO	2021	8,469		8,469			0	0				8,469
18		Property Tax	MO	2022			14,500	13,566		934					14,500
19		Property Tax	OH	2021			9	9		0	0	9
20		Property Tax	OH	2020	1,976,830		124,640	2,101,470		0	0	124,640
21		Property Tax	OH	2021	5,654,266					5,654,266	0	5,654,266			5,654,266
22		Property Tax	OH	2022			6,042,154			6,042,154					6,042,154
23		Property Tax	TN	2021	1,475,900		90,014	1,385,886		0	0	89,482			532
24		Property Tax	TN	2022			1,559,500	5,365		1,564,865	0	1,532,413			27,087
25		Property Tax	VA	2019			1,260	1,260		0	0	1,260
26		Property Tax	VA	2020	143		984	840		1	0	984
27		Property Tax	VA	2021	125,885		32,285	93,600		0	0	32,285
28		Property Tax	VA	2022			545,792	478,643		67,149		545,792
29		Property Tax	VA	2019			251	251		0		251
30		Property Tax	VA	2020			704	704		0		704
31		Property Tax	VA	2021	1,380,801		8,957	1,371,844		0		13,031			4,074
32		Property Tax	VA	2022			26,500,109	25,426,573		1,073,536		25,831,204			668,905
33		Property Tax	VA	2022			67,746	67,746		0		4,975			62,771
34		Property Tax	WV	2020			2,352	2,352		0	0	2,352
35		Property Tax	WV	2021	184,620		127,592	291,037		21,175	0	214,577			86,985
36		Property Tax	WV	2022			375,758			375,758	0	189,011			186,747
37		Property Tax	WV	2019						0		142			142
38		Property Tax	WV	2020	26,232,848		13,178	26,246,026		0		25,560,477			25,547,299
39		Property Tax	WV	2021	53,633,319		910,642	26,449,668		26,273,009		25,677,937			26,588,579
40		Property Tax	WV	2022			49,953,100	238		49,952,862					49,953,100
41		Property Tax	WY	2020	1,288		1,288			0	0				1,288
42		Property Tax	WY	2021			2,300	1,998		302					2,300
43		Property Tax	MS	2020			12	12		0	0				12
44	Subtotal Property Tax				90,674,369	0	84,279,793	83,928,153	0	91,026,009	0	85,201,424	0	0	921,631
45	Subtotal Real Estate Tax				0	0	0	0	0	0	0	0	0	0	0
46	UNEMPLOYMENT 2022	Unemployment Tax			18,059	0	69,507	76,850		10,716	0	35,291			34,216
47	STATE UNEMPLOYMENT 2022	Unemployment Tax	KY		296	0	184	139		341	0	121			63
48	STATE UNEMPLOYMENT 2022	Unemployment Tax	OH		712	0	3,371	3,439		644	0	1,817			1,554
49	STATE UNEMPLOYMENT 2022	Unemployment Tax	TN		3	0	4	4		3	0	2			2
50	STATE UNEMPLOYMENT 2022	Unemployment Tax	VA		10,310	0	21,227	21,510		10,027	0	11,575			9,652
51	STATE UNEMPLOYMENT 2022	Unemployment Tax	WV		28,224	0	140,641	144,359		24,506	0	75,415			65,226
52	Subtotal Unemployment Tax				57,604	0	234,934	246,301	0	46,237	0	124,221	0	0	110,713
53		Sales And Use Tax	OH	2021	79,133	12,950	349,894	283,711		0		134,297			215,597
54		Sales And Use Tax	OH	2022			286,554	262,550		44,127	20,123				286,554
55		Sales And Use Tax	TN	2021	708		263	445		0					263
56		Sales And Use Tax	TN	2022			13,119	1,499		11,620					13,119
57		Sales And Use Tax	TX	2022			14			14					14
58		Sales And Use Tax	VA	2020						0		577			577
59		Sales And Use Tax	VA	2021	308,692		71,095	379,787		0		787			70,308
60		Sales And Use Tax	VA	2022			5,013,810	4,463,986		549,824		673			5,014,483
61		Sales And Use Tax	WV	2021	348,533		18,680	329,853		0		21			18,701
62		Sales And Use Tax	WV	2022			3,477,089	2,889,616		587,473		558			3,476,531
63	Subtotal Sales And Use Tax				737,066	12,950	8,492,816	8,044,025	0	1,193,030	20,123	134,181	0	0	8,626,997
64		Income Tax	IL	2017	163,298					163,298	0
65		Income Tax	IL	2018	149,311					149,311	0
66		Income Tax	IL	2019	324,392					324,392	0
67		Income Tax	IL	2020	141,231					141,231	0
68		Income Tax	IL	2021	20,094			189,103		169,009	0
69		Income Tax	IL	2022			0			0		32,701			32,701
70		Income Tax	KY	2020	2,361					2,361	0
71		Income Tax	KY	2021	9,540			11,040		1,500	0
72		Income Tax	KY	2022			541			541		7,138			6,597
73		Income Tax	MI	2017	6,145					6,145	0
74		Income Tax	MI	2018	6,918					6,918	0
75		Income Tax	MI	2019	3,226					3,226	0
76		Income Tax	MI	2020	2,414					2,414	0
77		Income Tax	MI	2021	1,351			2,937		1,586	0
78		Income Tax	MULTI	2019	8,915					8,915	0
79		Income Tax	MULTI	2021				9		9	0
80		Income Tax	TN	2016	4,104					4,104	0
81		Income Tax	TN	2017	501,938					501,938	0
82		Income Tax	TN	2018	416,030					416,030	0
83		Income Tax	TN	2019	204,591					204,591	0
84		Income Tax	TN	2020	504,784					504,784	0
85		Income Tax	TN	2021	90,819					90,819	0
86		Income Tax	TN	2022			20,853	133,500		154,353	0	272,403			251,550
87		Income Tax	VA	2020	8					8	0
88		Income Tax	VA	2021	8					8	0
89		Income Tax	WV	2017	1,489,463					1,489,463	0
90		Income Tax	WV	2018	767,996					767,996	0
91		Income Tax	WV	2019	17,011,204					17,011,204	0
92		Income Tax	WV	2020	830,160					830,160	0
93		Income Tax	WV	2021	2,504,514			17,182,341		14,677,827	0
94		Income Tax	WV	2022			483,677			483,677	0	108,111			591,788
95	Subtotal Income Tax				15,728,361	0	503,989	17,518,912	0	2,294,540	0	124,453	0	0	379,536
96		Excise Tax		2022	0	0	15,033	15,033		0	0	15,033
97	Subtotal Excise Tax				0	0	15,033	15,033	0	0	0	15,033	0	0	0
98	Subtotal Fuel Tax				0	0	0	0	0	0	0	0	0	0	0
99	Subtotal Federal Insurance Tax				0	0	0	0	0	0	0	0	0	0	0
100		Franchise Tax	KY	2019	1,637					1,637	0
101		Franchise Tax	KY	2020	1,683					1,683	0
102		Franchise Tax	NC	2017	4,035					4,035	0
103		Franchise Tax	NC	2018	200					200	0
104		Franchise Tax	NC	2019	1,910					1,910	0
105		Franchise Tax	NC	2020	393					393	0
106		Franchise Tax	NC	2021	1,707		713	1,298		304	0	713
107		Franchise Tax	NC	2022			994			994		994
108		Franchise Tax	TN	2017	88,451					88,451	0
109		Franchise Tax	TN	2018	9,373					9,373	0
110		Franchise Tax	TN	2019	196,218					196,218	0
111		Franchise Tax	TN	2020	241,181					241,181	0
112		Franchise Tax	TN	2021	241,181		26,924			214,257	0	26,924
113		Franchise Tax	TN	2022			214,257			214,257	0	214,257
114	Subtotal Franchise Tax				779,113	0	187,614	1,298	0	965,429	0	187,614	0	0	0
115	Subtotal Miscellaneous Other Tax				0	0	0	0	0	0	0	0	0	0	0
116										0
117	Subtotal Other Federal Tax				0	0	0	0	0	0	0	0	0	0	0
118		Other State Tax	WV	2002	0					0
119		Other State Tax	WV	2016	0					0
120		Other State Tax	WV	2022			15,610,516	12,122,515		3,488,001		15,572,211			38,305
121		Other State Tax	WV	2022			3,267,411	4,151,603		759,000	1,643,192	100			3,267,511
122		Other State Tax	OH	2021	23,400		24,522	1,122		0		24,522
123		Other State Tax	OH	2022			6,486	4,086		2,400		6,486
124		Other State Tax	WV	2020			183,917	183,917		0		183,917
125		Other State Tax	WV	2021	2,079,593		195,522	1,884,071		0		195,522
126		Other State Tax	WV	2022			34,885,766	32,785,435		2,100,331		38,113,042			3,227,276
127		Other State Tax	VA	2018	68,884					68,884
128		Other State Tax	VA	2019	2,350,965					2,350,965
129		Other State Tax	VA	2020	344,378					344,378
130		Other State Tax	VA	2021	2,764,222		1,134,981	2,526,099		1,373,104		1,134,981
131		Other State Tax	VA	2022			10,320,803	8,930,500		1,390,303		10,320,803
132		Other State Tax	FIN48		0					0
133	Subtotal Other State Tax				2,102,988	0	64,822,002	62,219,270	0	6,348,912	1,643,192	64,743,462	0	0	78,540
134	Subtotal Other Property Tax				0	0	0	0	0	0	0	0	0	0	0
135	Subtotal Other Use Tax				0	0	0	0	0	0	0	0	0	0	0
136	Subtotal Other Advalorem Tax				0	0	0	0	0	0	0	0	0	0	0
137		Other License And Fees Tax	WV	2019	72					72	0
138		Other License And Fees Tax	WV	2020	240			20		260	0
139		Other License And Fees Tax	WV	2021	240			170		410	0
140		Other License And Fees Tax	WV	2022				1,105		1,105
141		Other License And Fees Tax	WV	2022				20		20
142		Other License And Fees Tax	TN	2022						0		100			100
143	Subtotal Other License And Fees Tax				552	0	0	1,315	0	1,867	0	100	0	0	100
144	FICA 2022	Payroll Tax			1,607,440		13,486,031	16,897,263	3,197,288	1,393,496		7,739,096			5,746,935
145	2360105 FICA CARES ACT	Payroll Tax			3,197,288				3,197,288	0
146	Subtotal Payroll Tax				4,804,728	0	13,486,031	16,897,263	0	1,393,496	0	7,739,096	0	0	5,746,935
147	Subtotal Advalorem Tax				0	0	0	0	0	0	0	0	0	0	0
148	Subtotal Other Allocated Tax				0	0	0	0	0	0	0	0	0	0	0
149	Subtotal Severance Tax				0	0	0	0	0	0	0	0	0	0	0
150	Subtotal Penalty Tax				0	0	0	0	0	0	0	0	0	0	0
151	Subtotal Other Taxes And Fees				0	0	0	0	0	0	0	0	0	0	0
40	TOTAL				81,703,750	1,868,618	107,407,318	100,399,028		88,506,737	1,663,315	103,229,650			4,177,668

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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%	306,934	411.1		411.1	11,715		295,219	32 Years
6	State DITC		411.1		411.1
7	30				411.1
8	TOTAL Electric (Enter Total of lines 2 thru 7)	306,934				11,715		295,219
9	Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
10										`
47	OTHER TOTAL
48	GRAND TOTAL	306,934						295,219

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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	1,792,579	454	13,054,945	13,392,875	2,130,509
2	Deferred Gain - Fiber Optic Leases - Amortize through June 2026	2,495,138	124	1,013,777		1,481,361
3	Deferred Revenue - Fiber Optic Lines Sold - Amortize through Jan 2025	82,897	451	37,710		45,187
4	Rents Billed in Advance	184,151	451	184,151
5	Customer Advance Receipts	16,757,690	142	16,757,690	18,241,480	18,241,480
6	IPP - System Upgrade Credits	145,252	232/234	145,659	407
7	Federal Mitigation Deferral - NSR	1,629,306	242	1,629,306
8	Other Deferred Credits	1,237,536	142/143/186/421/506	2,037,107	1,968,797	1,169,226
9	Def Equity Income-Securitization	2,234,101	456	308,085		1,926,016
10	Reliability First FAC-003 Assessment	637,769				637,769
11	Contr In Aid of Constr Advance	5,504,231	107/108	5,504,231	1,854,835	1,854,835
12	Collateral Held During Construction				500,000	500,000
13	Provision for PJM Transmission Revenue Requirement		186	4,224,960	9,704,351	5,479,391
47	TOTAL	32,700,650		44,897,621	45,662,745	33,465,774

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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	235,940,637		17,384,123							218,556,514
5	Other
5.1	Other (provide details in footnote):
8	TOTAL Electric (Enter Total of lines 3 thru 7)	235,940,637		17,384,123							218,556,514
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) 92,217,001					254		254	4,489,230	87,727,771
17	TOTAL (Acct 281) (Total of 8, 15 and 16)	143,723,636		17,384,123						4,489,230	130,828,743
18	Classification of TOTAL
19	Federal Income Tax	143,723,636		17,384,123						4,489,230	130,828,743
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:

04/12/2023

Year/Period of Report

End of:

2022

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)

(92,217,001)

4,489,230

(87,727,771)

Total line 16
(95,799,954)

(92,217,001)

—

4,489,230

(87,727,771)

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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	2,043,267,640	159,933,391	220,900,069							1,982,300,962
3	Gas
4	Other (Specify)
5	Total (Total of lines 2 thru 4)	2,043,267,640	159,933,391	220,900,069							1,982,300,962
6	(a) Others	535,518,390					1823/254	44,309,011	1823/254	157,199,931	422,627,470
9	TOTAL Account 282 (Total of Lines 5 thru 8)	1,507,749,250	159,933,391	220,900,069				44,309,011		157,199,931	1,559,673,492
10	Classification of TOTAL
11	Federal Income Tax	1,507,749,250	159,933,391	220,900,069				44,309,011		157,199,931	1,559,673,492
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:

04/12/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: DescriptionOfNonUtilityAccountDetails


Line 6 Footnote

	Beg Bal	Debits	Credits	End Bal
SFAS 109	(535,518,390)	44,309,011	157,199,931	(422,627,470)
Total Other - Line 6	(535,518,390)	44,309,011	157,199,931	(422,627,470)

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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	ACCRUED BK PENSION EXPENSE	16,607,304	33,685	769,189							15,871,800
4	REG ASSET-SFAS 106 MEDICARE SUBSIDY	29,986,828	593,899	2,832,980							27,747,747
5	DEFD TAX GAIN - SEC I REG ASSET	83,957,244	4,320,554	1,774,027							86,503,771
6	REG ASSET-ADVANCED METERING SYSTEM	81,612,761	103,990,636	5,447,312							180,156,085
7	LOSS ON REACQUIRED DEBT	25,548,939	27,931	578,178							24,998,692
8	Other	16,779,798	149,275,503	76,542,746							55,952,959
9	TOTAL Electric (Total of lines 3 thru 8)	220,933,278	258,242,208	87,944,432							391,231,054
10	Gas
11
12
13
14
15
16
17	TOTAL Gas (Total of lines 11 thru 16)
18	TOTAL Other	(a) 426,297,321			1,333,454	32,321	1823/254	97,662,303	1823/254	82,299,041	412,235,192
19	TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)	647,230,599	258,242,208	87,944,432	1,333,454	32,321		97,662,303		82,299,041	803,466,246
20	Classification of TOTAL
21	Federal Income Tax	358,038,637	248,715,251	78,224,409	1,333,454	32,321		76,773,637		30,985,680	484,042,655
22	State Income Tax	289,191,962	9,526,957	9,720,023				20,888,666		51,313,361	319,423,591
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	2,634,959					265,822		2,369,137
Non-Utility	479,318			1,333,454	32,321	—		1,780,451
SFAS 109	423,183,044					97,396,481	82,299,041	408,085,604
Total	426,297,321			1,333,454	32,321	97,662,303	82,299,041	412,235,192

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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	28,167,013	175, 182, 244, 456	48,571,273	56,264,485	35,860,225
2	Netting of Trading Activities related to Unrealized Gains/Losses on Forward Commitments between Regulated Assets/Liabilities		182	4,857,096	3,537,265	1,319,831
3	FAS 109 Deferred Federal Income Tax	743,622,769	190, 282, 283	173,053,686	105,800,900	676,369,983
4	FAS 109 Deferred State Income Tax	21,669,489	190, 282, 283	1,674,120	784,380	20,779,749
5	PJM trans enhancement settlement for refund	12,995,642	410	3,240,490		9,755,152
6	VA EE-RAC Over Recovery -Case No. PUR - 2017-00126	6,026,199	182, 908	4,736,718	3,642,645	4,932,126
7	WV Broadband Over Recovery	446,477	403	3,933	458,500	901,044
8	VA RPS-RAC Over Recovery	8,376,192	182, 555	8,001,260	13,207,958	13,582,890
9	VA Broadband Pilot Over Recov		182, 403	391	4,043,106	4,042,715
10	WV ECS Over Recovery	174,848	403	395,407	220,559
11	VA A.6 RPS RAC Over Recovery				109,934	109,934
12	VA Base Rate & RCR Rider Provision Interest - Case No. PUR-2020-0015				80,917	80,917
13	WV Business Ready Site Program Over-Recovery				122,149	122,149
14	VA E-RAC Over-Recovery				803,783	803,783
41	TOTAL	821,478,629		244,534,374	189,076,581	766,020,836

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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	1,565,631,035	1,378,288,171	11,159,403	11,206,650	812,256	813,862
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)	646,203,889	555,785,591	6,065,671	5,949,362	139,326	138,485
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)	667,883,583	584,309,527	8,848,569	8,879,317	4,142	4,184
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting	8,697,798	7,993,467	63,099	64,162	1,681	1,684
7	OtherSalesToPublicAuthoritiesAbstract (445) Other Sales to Public Authorities	78,837,545	62,743,388	779,972	745,795	6,350	6,227
8	SalesToRailroadsAndRailwaysAbstract (446) Sales to Railroads and Railways
9	InterdepartmentalSalesAbstract (448) Interdepartmental Sales
10	SalesToUltimateConsumersAbstract TOTAL Sales to Ultimate Consumers	(a) 2,967,253,850	2,589,120,143	26,916,714	26,845,286	963,755	964,442
11	SalesForResaleAbstract (447) Sales for Resale	410,610,220	341,751,443	4,894,856	6,967,140	9	15
12	SalesOfElectricityAbstract TOTAL Sales of Electricity	3,377,864,070	2,930,871,586	31,811,570	33,812,426	963,764	964,457
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds	20,664,643
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds	3,357,199,427	2,930,871,586	31,811,570	33,812,426	963,764	964,457
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts	4,764,442	6,272,184
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	(b) 3,809,400	2,206,090
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power
19	RentFromElectricProperty (454) Rent from Electric Property	30,173,965	21,832,186
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	(c) 60,718,871	41,801,314
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	169,442,448	138,990,094
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	268,909,126	211,101,867
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	3,626,108,552	3,141,973,453
Line12, column (b) includes $ 62,753,668 of unbilled revenues.
Line12, column (d) includes 303,810 MWH relating to unbilled revenues

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: SalesToUltimateConsumers

Total Sales to Ultimate Consumers include $902,361 of Operating Revenues for distribution service provided to Open Access Customers. Megawatt hours delivered to Open Access Consumers were 343,073 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.


Schedule Page: 300 Line No.: 21 Column: b


Descrption	YTD 2022	YTD 2021

Assoc. Business Development	15,591,434	9,046,571
Sale of Renewable Energy Credits	44,663,666	32,293,619
Amort. Of Deferred Equity	308,085	301,831
All Other (under $250K each)	155,686	159,293
Total	60,718,871	41,801,314

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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:

04/12/2023

Year/Period of Report

End of:

2022

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	5	806	0		0.1612
2	OL-Outdoor Lighting	66,216	11,638,748			0.1758
3	RS - Residential Service	10,864,202	1,507,261,839	807,994	13,446	0.1387
4	RSE - Residential Emp.	65,123	9,019,119	3,987	16,334	0.1385
5	RS-EV RESIDENTIAL SERVICE PLUG IN ELECTRIC VEHICLE CHARGING	309	7,714	75	4,120	0.0250
6	RS-LM-TOD Res. Load MGMT	223	31,964	14	15,929	0.1433
7	RS-TOD-Residential TOD	2,896	352,351	185	15,654	0.1217
8	SGS-Small Gen. Service	69	6,658	1	69,000	0.0965
9	PA - PUBLIC AUTHORITY	4	624			0.1560
10	Misc Adjustments		331,376
41	TOTAL Billed Residential Sales	10,999,047	1,528,635,771	812,256	13,541	0.1390
42	TOTAL Unbilled Rev. (See Instr. 6)	160,356	36,995,264			0.2307
43	TOTAL	11,159,403	1,565,631,035	812,256	13,739	0.1403

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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	1,028	148,920			0.1449
2	SGS-Small General Service	3,591,543	372,698,394	20,254	177,325	0.1038
3	SGS-PA - Small General Service-PA	667	72,545	6	111,167	0.1088
4	SGS-TOD-Small General Service	48,019	4,948,487	682	70,409	0.1031
5	IP-Industrial Power Service	6,963	479,930	1	6,963,000	0.0689
6	LCP-Large Capacity Power	485,677	40,129,039	47	10,333,553	0.0826
7	LGS-TOD - Large General Service-T	26,220	2,858,079	81	323,704	0.1090
8	LPS-Large Power Service	301,364	20,632,162	21	14,350,667	0.0685
9	LPS-TOD-Large Power Ser TOD	26,323	2,263,163	4	6,580,750	0.0860
10	MGS-Medium General Service	250,717	30,476,920	2,966	84,530	0.1216
11	OL-Outdoor Lighting	66,286	9,242,059	0		0.1394
12	RS-Residential Service	0	26	0
13	SGS-Small General Service	823,679	103,246,670	109,767	7,504	0.1253
14	SGS-TOD-Small General Service	3,152	433,972	548	5,752	0.1377
15	SS-School Service	250,762	29,364,182	1,050	238,821	0.1171
16	SWS-Sanctuary Worship	100,983	14,307,672	3,898	25,906	0.1417
17	Winterplace	748	138,898	1	748,000	0.1857
18	PA - PUBLIC AUTHORITY	2	341
19	Misc Adjustments		101,040
41	TOTAL Billed Small or Commercial	5,984,133	631,542,499	139,326	42,951	0.1055
42	TOTAL Unbilled Rev. Small or Commercial (See Instr. 6)	81,538	14,661,390			0.1798
43	TOTAL Small or Commercial	6,065,671	646,203,889	139,326	43,536	0.1065

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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	70,306	4,125,101	1	70,306,000	0.0587
2	Constellium	192,739	12,376,359	1	192,739,000	0.0642
3	Estimated	28,152	1,600,203			0.0568
4	Felman	227,250	12,377,758	1	227,250,000	0.0545
5	GS-General Service	908,320	90,291,036	1,357	669,359	0.0994
6	GS-TOD-General Service TOD	1,760	196,667	18	97,778	0.1117
7	IP-Industrial Power Service	302,413	19,039,711	3	100,804,333	0.0630
8	LCP-Large Capacity Power	2,219,197	177,028,874	94	23,608,479	0.0798
9	LGS-TOD - Large General Service-T	573	82,745	3	191,000	0.1444
10	LPS-Large Power Service	3,277,729	216,656,162	96	34,143,010	0.0661
11	LPS-TOD-Large Power Ser TOD	1,029,661	75,384,892	31	33,214,871	0.0732
12	MGS-Medium General Service	144,919	17,820,659	403	359,600	0.1230
13	OL-Outdoor Lighting	6,427	803,754			0.1251
14	SGS-Small General Service	20,127	2,464,362	2,132	9,440	0.1224
15	WV Manufacturing	415,923	25,858,557	1	415,923,000	0.0622
16	WV Recycle	9,998	1,570,805	1	9,998,000	0.1571
17	APCo Rider		935,059
18	Misc Adjustments		693,057
41	TOTAL Billed Large (or Ind.) Sales	8,799,190	659,305,761	4,142	2,124,382	0.0749
42	TOTAL Unbilled Rev. Large (or Ind.) (See Instr. 6)	49,379	8,577,822			0.1737
43	TOTAL Large (or Ind.)	8,848,569	667,883,583	4,142	2,136,303	0.0755

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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:

04/12/2023

Year/Period of Report

End of:

2022

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	3,630	450,890	547	6,636	0.1242
2	Estimated	747	109,494
3	GS-General Service	1,473	175,343	25	58,920	0.1190
4	GS-TOD-General Service TOD	607	54,370	5	121,400	0.0896
5	MGS-PA-Med Gen Ser - PA
6	OL-Outdoor Lighting	194	26,863			0.1385
7	SGS-Small General Service	2,519	371,488	586	4,299	0.1475
8	SGS-PA -Small Gen Ser - PA	926	133,182	326	2,840	0.1438
9	SL-Street Lighting	52,882	7,353,279	192	275,427	0.1391
10	Misc Adjustments		185
41	TOTAL Billed Public Street and Highway Lighting	62,978	8,675,094	1,681	37,465	0.1377
42	TOTAL Unbilled Rev. (See Instr. 6)	121	22,704
43	TOTAL	63,099	8,697,798	1,681	37,537	0.1378

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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	129,416	13,258,303	924	140,061	0.1024
2	Estimated	111	12,579			0.1133
3	Flood Walls	221	16,635	22	10,045	0.0753
4	GS-General Service	24,368	2,070,893	19	1,282,526	0.0850
5	GS-PA -General Service -PA	366,081	34,322,298	636	575,599	0.0938
6	GS-TOD-PA-Gen Ser TOD -PA	2,688	285,210	94	28,596	0.1061
7	LPS-TOD - LARGE POWER SERVICE TOD	19,525	1,278,602	1	19,525,000	0.0655
8	LPS-TOD-PA Large Pow Ser	16,817	1,351,348	2	8,408,500	0.0804
9	MGS - MEDIUM GENERAL SERVICE	1,214	145,321	9	134,889	0.1197
10	MGS-PA-Med Gen Ser - PA	155,098	17,671,052	645	240,462	0.1139
11	OL-Outdoor Lighting	2,977	405,809			0.1363
12	Public Authority-Large General Svc-TOD-Pri	123	12,680	1	123,000	0.1031
13	Public Authority-Large General Svc-TOD-Sec	3,354	382,907	23	145,826	0.1142
14	SGS-Small General Service	441	51,188	32	13,781	0.1161
15	SGS-PA- Small Gen Ser - PA	45,069	5,166,418	3,940	11,439	0.1146
16	PA-PEV PUBLIC AUTHORITY	53	7,653	2	26,500
17	APCo Rider		123,828
18	Misc Adjustments		25,988
41	TOTAL Billed Other Sales to Public Authorities	767,556	76,341,056	6,350	120,875	0.0995
42	TOTAL Unbilled Rev. (See Instr. 6)	12,416	2,496,489
43	TOTAL	779,972	78,837,545	6,350	122,830	0.1011

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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		20,664,643

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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	26,612,904	2,904,500,181	963,755	2,339,213
42	TOTAL Unbilled Rev. (See Instr. 6) - All Accounts	303,810	62,753,669
43	TOTAL - All Accounts	26,916,714	(a) 2,967,253,850	963,755	2,339,213

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: RevenueFromSalesOfElectricityByRateSchedulesIncludingUnbilledRevenue


FOOTNOTE DATA


Schedule Page: 304.2 Line No.: 32 Column: a


2022 FUEL ADJUSTMENT CLAUSE
ACCT	F1 Codes	Sum of Fuel
4400 RE	OL - OUTDOOR LIGHTING	803,597
	PA - PUBLIC AUTHORITY	98
	RS - RESIDENTIAL SERVICE	155,700,993
	RSE - RESIDENTIAL SERVICE - EMPLOYEE	535,757
	RS-TOD - RESIDENTIAL SERVICE TOD	70,670
	SGS - SMALL GENERAL SERVICE	13
	Unbilled	10,620,856
4400 RE	Total	167,731,984
4420 CO	Estimated	21,541
	GS - GENERAL SERVICE	40,070,899
	GS-PA - GENERAL SERVICE-PA	16,452
	GS-TOD - GENERAL SERVICE TOD	832,757
	LGS-TOD - LARGE GENERAL SERVICE-TOD	611,691
	LPS - LARGE POWER SERVICE	6,847,826
	LPS-TOD - LARGE POWER SERVICE TOD	662,142
	MGS - MEDIUM GENERAL SERVICE	6,295,048
	OL - OUTDOOR LIGHTING	904,470
	PA - PUBLIC AUTHORITY	53
	RS - RESIDENTIAL SERVICE	1
	SGS - SMALL GENERAL SERVICE	15,067,161
	SWS - SANCTUARY WORSHIP SERVICE	758,616
	Unbilled	4,239,081
	SGS-TOD - SMALL GENERAL SERVICE-TOD	1,048
4420 CO	Total	76,328,788
4420 IN	Estimated	2,118,486
	GS - GENERAL SERVICE	14,197,782
	GS-TOD - GENERAL SERVICE TOD	13,120
	LGS-TOD - LARGE GENERAL SERVICE-TOD	14,712
	LPS - LARGE POWER SERVICE	75,376,197
	LPS-TOD - LARGE POWER SERVICE TOD	26,273,558
	MGS - MEDIUM GENERAL SERVICE	3,686,744
	OL - OUTDOOR LIGHTING	101,010
	SGS - SMALL GENERAL SERVICE	344,442
	Unbilled	2,921,660
4420 IN	Total	125,047,713
4440 PU	Commonwealth of VA	106,574
	Estimated	32,279
	OL - OUTDOOR LIGHTING	2,314
	SGS - SMALL GENERAL SERVICE	128
	SGS-PA - SMALL GENERAL SERVICE-PA	23,832
	SL - STREET LIGHTING	740,400
	Unbilled	2,875
4440 PU	Total	908,403
4450 OT	Commonwealth of VA	3,804,536


	Estimated	3,794
	GS - GENERAL SERVICE	611,303
	GS-PA - GENERAL SERVICE-PA	9,275,000
	GS-TOD-PA - GEN SERVICE TOD-PA	68,470
	LPS-TOD - LARGE POWER SERVICE TOD	483,134
	LPS-TOD-PA - LARGE POW SER TOD-PA	430,653
	MGS - MEDIUM GENERAL SERVICE	31,607
	MGS-PA - MEDIUM GENERAL SERVICE-PA	3,931,503
	OL - OUTDOOR LIGHTING	76,819
	Public Authority-Large General Svc-TOD-Pri	3,218
	Public Authority-Large General Svc-TOD-Sec	85,888
	SGS - SMALL GENERAL SERVICE	11,160
	SGS-PA - SMALL GENERAL SERVICE-PA	1,156,799
	PA-PEV PUBLIC AUTHORITY	1,492
	Unbilled	1,053,181
4450 OT	Total	21,028,557
Grand Total		391,045,444

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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	AEP SERVICE CORPORATION	OS	(c) 20				0
2	AMEREX POWER, LTD	OS	NOTE 1				0		89		89
3	B.P. ENERGY COMPANY	OS	NOTE 1				0
4	CITIGROUP ENERGY INC.	OS	NOTE 1				0		8,128		8,128
5	CITY OF RADFORD, VA	RQ	NOTE 1				172,746	5,252,569	8,867,738		14,120,307
6	CITY OF SALEM, VA	RQ	NOTE 1				366,347	11,061,229	19,923,694		30,984,923
7	CRAIG-BOTETOURT ELECTRIC COOP	RQ	NOTE 1				54,347	1,913,963	2,933,499		4,847,461
8	DUQUESNE LIGHT COMPANY	OS	NOTE 1				0
9	FIRSTENERGY TRADING SERVICES	OS	NOTE 1				16,529		682,562		682,562
10	(a) KINGSPORT	RQ	23				1,938,878	41,868,277	89,933,202	37,847,136	169,648,615
11	(b) OHIO POWER COMPANY (AUCTION)	OS	(d) NOTE 1				71			2,047	2,047
12	OLD DOMINION ELECTRIC	RQ	NOTE 1				156,059	5,679,818	8,193,543		13,873,361
13	PJM INTERCONNECTION	OS	NOTE 1				1,826,058	8,411,912	151,506,069	9,051,526	168,969,507
14	PJM INTERCONNECTION	RQ	VARIOUS				0		3,012,274	(e) 26,228,457	23,216,183
15	PPL ELECTRIC UTILITIES CORP	OS	NOTE 1				6		223		223
16	UNITED LIGHT & POWER COMPANY	RQ	151				53,163	1,787,026	3,007,937		4,794,963
17	VIRGINIA TECH	RQ	155				310,807	8,771,773	16,768,695		25,540,468
18	WELLS FARGO SECURITIES, LLC	OS	NOTE 1				0		374,720		374,720
15	Subtotal - RQ						3,052,347	76,334,655	152,640,582	11,618,679	240,593,916
16	Subtotal-Non-RQ						1,842,510	8,411,912	152,554,912	9,049,479	170,016,303
17	Total						4,894,856	84,746,567	305,195,494	20,668,158	410,610,220

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: NameOfCompanyOrPublicAuthorityReceivingElectricityPurchasedForResale

An affiliated company

(b) Concept: NameOfCompanyOrPublicAuthorityReceivingElectricityPurchasedForResale

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.

FERC Electric Tariff, First Revised Volume No. 5

(d) Concept: RateScheduleTariffNumber

(e) Concept: OtherChargesRevenueSalesForResale

PJM transmission expenses related to wholesale customers.

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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	21,677,227	19,520,337
5	FuelSteamPowerGeneration (501) Fuel	(a) 137,379,824	384,765,119
6	SteamExpensesSteamPowerGeneration (502) Steam Expenses	42,197,963	50,532,264
7	SteamFromOtherSources (503) Steam from Other Sources
8	SteamTransferredCredit (Less) (504) Steam Transferred-Cr.
9	ElectricExpensesSteamPowerGeneration (505) Electric Expenses	174,070	203,351
10	MiscellaneousSteamPowerExpenses (506) Miscellaneous Steam Power Expenses	18,490,892	19,293,080
11	RentsSteamPowerGeneration (507) Rents	42,363	39,073
12	Allowances (509) Allowances	566,936	612,073
13	SteamPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 4 thru 12)	220,529,275	474,965,297
14	SteamPowerGenerationMaintenanceAbstract Maintenance
15	MaintenanceSupervisionAndEngineeringSteamPowerGeneration (510) Maintenance Supervision and Engineering	2,293,937	2,363,425
16	MaintenanceOfStructuresSteamPowerGeneration (511) Maintenance of Structures	6,358,982	4,229,814
17	MaintenanceOfBoilerPlantSteamPowerGeneration (512) Maintenance of Boiler Plant	57,007,353	47,508,488
18	MaintenanceOfElectricPlantSteamPowerGeneration (513) Maintenance of Electric Plant	18,892,575	13,342,587
19	MaintenanceOfMiscellaneousSteamPlant (514) Maintenance of Miscellaneous Steam Plant	11,578,044	11,801,008
20	SteamPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 15 thru 19)	96,130,891	79,245,322
21	PowerProductionExpensesSteamPower TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)	316,660,165	554,210,618
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	1,718,131	1,612,103
45	WaterForPower (536) Water for Power	25,712	24,080
46	HydraulicExpenses (537) Hydraulic Expenses	1,352,480	984,313
47	ElectricExpensesHydraulicPowerGeneration (538) Electric Expenses	260,358	397,988
48	MiscellaneousHydraulicPowerGenerationExpenses (539) Miscellaneous Hydraulic Power Generation Expenses	3,738,318	3,347,023
49	RentsHydraulicPowerGeneration (540) Rents	349,955	362,506
50	HydraulicPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 44 thru 49)	7,444,954	6,728,013
51	HydraulicPowerGenerationContinuedAbstract C. Hydraulic Power Generation (Continued)
52	HydraulicPowerGenerationMaintenanceAbstract Maintenance
53	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration (541) Mainentance Supervision and Engineering	212,204	241,930
54	MaintenanceOfStructuresHydraulicPowerGeneration (542) Maintenance of Structures	5,009,165	2,846,737
55	MaintenanceOfReservoirsDamsAndWaterways (543) Maintenance of Reservoirs, Dams, and Waterways	2,638,011	2,840,543
56	MaintenanceOfElectricPlantHydraulicPowerGeneration (544) Maintenance of Electric Plant	4,101,071	2,698,931
57	MaintenanceOfMiscellaneousHydraulicPlant (545) Maintenance of Miscellaneous Hydraulic Plant	175,391	131,686
58	HydraulicPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 53 thru 57)	12,135,842	8,759,827
59	PowerProductionExpensesHydraulicPower TOTAL Power Production Expenses-Hydraulic Power (Total of Lines 50 & 58)	(b) 19,580,796	15,487,840
60	OtherPowerGenerationAbstract D. Other Power Generation
61	OtherPowerGenerationOperationAbstract Operation
62	OperationSupervisionAndEngineeringOtherPowerGeneration (546) Operation Supervision and Engineering	288,478	290,411
63	Fuel (547) Fuel	34,170,944	18,842,965
64	GenerationExpenses (548) Generation Expenses	724,407	556,276
64.1	OperationOfEnergyStorageEquipment (548.1) Operation of Energy Storage Equipment
65	MiscellaneousOtherPowerGenerationExpenses (549) Miscellaneous Other Power Generation Expenses	180,541	229,348
66	RentsOtherPowerGeneration (550) Rents	64	29
67	OtherPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 62 thru 67)	35,364,434	19,919,028
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	202,010	237,571
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)	202,010	237,571
74	PowerProductionExpensesOtherPower TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)	35,566,444	20,156,599
75	OtherPowerSuplyExpensesAbstract E. Other Power Supply Expenses
76	PurchasedPower (555) Purchased Power	1,079,588,594	579,121,879
76.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations	0
77	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching	2,335,645	2,490,558
78	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	12,781,533	6,760,693
79	OtherPowerSupplyExpense TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)	1,094,705,772	588,373,130
80	PowerProductionExpenses TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74 & 79)	1,466,513,177	1,178,228,188
81	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
82	TransmissionExpensesOperationAbstract Operation
83	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	15,051,026	14,515,410
85	LoadDispatchReliability (561.1) Load Dispatch-Reliability
86	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	2,036,410	2,043,828
87	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling
88	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services	6,563,776	6,341,973
89	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development	488,374	782,506
90	TransmissionServiceStudies (561.6) Transmission Service Studies
91	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies
92	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services	1,882,571	1,852,032
93	StationExpensesTransmissionExpense (562) Station Expenses	(c) 1,780,188	1,499,414
93.1	OperationOfEnergyStorageEquipmentTransmissionExpense (562.1) Operation of Energy Storage Equipment
94	OverheadLineExpense (563) Overhead Lines Expenses	176,551	186,419
95	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses	13	30,398
96	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	358,817,631	316,382,461
97	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	23,134,029	14,394,958
98	RentsTransmissionElectricExpense (567) Rents	55,949	61,491
99	TransmissionOperationExpense TOTAL Operation (Enter Total of Lines 83 thru 98)	409,986,518	329,300,973
100	TransmissionMaintenanceAbstract Maintenance
101	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering	205,034	171,417
102	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	99,343	71,059
103	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware	(d) 31,330	38,506
104	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software	792,598	598,061
105	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment	46,987	44,159
106	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	3,864,777	3,705,459
107.1	MaintenanceOfEnergyStorageEquipmentTransmission (570.1) Maintenance of Energy Storage Equipment
108	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	17,538,834	23,644,071
109	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines	9,873	10,578
110	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant	97,110	145,042
111	TransmissionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 101 thru 110)	22,685,885	28,428,353
112	TransmissionExpenses TOTAL Transmission Expenses (Total of Lines 99 and 111)	432,672,403	357,729,327
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	5,709,851	6,603,034
122	RentsRegionalMarketExpenses (575.8) Rents
123	RegionalMarketOperationExpense Total Operation (Lines 115 thru 122)	5,709,851	6,603,034
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)	5,709,851	6,603,034
132	DistributionExpensesAbstract 4. DISTRIBUTION EXPENSES
133	DistributionExpensesOperationAbstract Operation
134	OperationSupervisionAndEngineeringDistributionExpense (580) Operation Supervision and Engineering	5,837,523	5,546,699
135	LoadDispatching (581) Load Dispatching	21,112	7,211
136	StationExpensesDistribution (582) Station Expenses	1,776,130	1,368,052
137	OverheadLineExpenses (583) Overhead Line Expenses	3,127,806	587,051
138	UndergroundLineExpenses (584) Underground Line Expenses	2,604,693	2,170,984
138.1	OperationOfEnergyStorageEquipmentDistribution (584.1) Operation of Energy Storage Equipment
139	StreetLightingAndSignalSystemExpenses (585) Street Lighting and Signal System Expenses	102,739	590,853
140	MeterExpenses (586) Meter Expenses	2,228,048	1,785,362
141	CustomerInstallationsExpenses (587) Customer Installations Expenses	740,288	624,927
142	MiscellaneousDistributionExpenses (588) Miscellaneous Expenses	17,624,429	10,652,763
143	RentsDistributionExpense (589) Rents	2,848,171	1,451,899
144	DistributionOperationExpensesElectric TOTAL Operation (Enter Total of Lines 134 thru 143)	36,910,939	24,785,802
145	DistributionExpensesMaintenanceAbstract Maintenance
146	MaintenanceSupervisionAndEngineering (590) Maintenance Supervision and Engineering	166,004	181,056
147	MaintenanceOfStructuresDistributionExpense (591) Maintenance of Structures	163,169	199,244
148	MaintenanceOfStationEquipment (592) Maintenance of Station Equipment	(e) 1,579,014	1,369,389
148.1	MaintenanceOfEnergyStorageEquipment (592.2) Maintenance of Energy Storage Equipment
149	MaintenanceOfOverheadLines (593) Maintenance of Overhead Lines	140,844,272	126,395,547
150	MaintenanceOfUndergroundLines (594) Maintenance of Underground Lines	2,582,506	1,277,470
151	MaintenanceOfLineTransformers (595) Maintenance of Line Transformers	2,386,920	1,892,232
152	MaintenanceOfStreetLightingAndSignalSystems (596) Maintenance of Street Lighting and Signal Systems	732,379	528,276
153	MaintenanceOfMeters (597) Maintenance of Meters	440,068	380,371
154	MaintenanceOfMiscellaneousDistributionPlant (598) Maintenance of Miscellaneous Distribution Plant	5,525,168	4,759,687
155	DistributionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 146 thru 154)	154,419,501	136,983,273
156	DistributionExpenses TOTAL Distribution Expenses (Total of Lines 144 and 155)	191,330,441	161,769,075
157	CustomerAccountsExpensesAbstract 5. CUSTOMER ACCOUNTS EXPENSES
158	CustomerAccountsExpensesOperationsAbstract Operation
159	SupervisionCustomerAccountExpenses (901) Supervision	502,386	478,550
160	MeterReadingExpenses (902) Meter Reading Expenses	3,613,628	3,934,277
161	CustomerRecordsAndCollectionExpenses (903) Customer Records and Collection Expenses	26,135,341	24,315,220
162	UncollectibleAccounts (904) Uncollectible Accounts	5,763,349	5,625,956
163	MiscellaneousCustomerAccountsExpenses (905) Miscellaneous Customer Accounts Expenses	108,140	135,767
164	CustomerAccountExpenses TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)	36,122,844	34,489,770
165	CustomerServiceAndInformationalExpensesAbstract 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166	CustomerServiceAndInformationalExpensesOperationAbstract Operation
167	SupervisionCustomerServiceAndInformationExpenses (907) Supervision	603,866	653,360
168	CustomerAssistanceExpenses (908) Customer Assistance Expenses	20,754,369	15,033,181
169	InformationalAndInstructionalAdvertisingExpenses (909) Informational and Instructional Expenses
170	MiscellaneousCustomerServiceAndInformationalExpenses (910) Miscellaneous Customer Service and Informational Expenses	54,574	83,279
171	CustomerServiceAndInformationExpenses TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)	21,412,810	15,769,820
172	SalesExpenseAbstract 7. SALES EXPENSES
173	SalesExpenseOperationAbstract Operation
174	SupervisionSalesExpense (911) Supervision
175	DemonstratingAndSellingExpenses (912) Demonstrating and Selling Expenses	155,789	168,708
176	AdvertisingExpenses (913) Advertising Expenses
177	MiscellaneousSalesExpenses (916) Miscellaneous Sales Expenses
178	SalesExpenses TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)	155,789	168,708
179	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
180	AdministrativeAndGeneralExpensesOperationAbstract Operation
181	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	45,534,021	46,182,639
182	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	6,365,105	5,058,941
183	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit	5,739,469	5,484,021
184	OutsideServicesEmployed (923) Outside Services Employed	20,782,504	13,463,107
185	PropertyInsurance (924) Property Insurance	(f) 4,780,211	4,446,810
186	InjuriesAndDamages (925) Injuries and Damages	8,073,292	3,496,246
187	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	5,809,498	5,144,960
188	FranchiseRequirements (927) Franchise Requirements
189	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	9,595,185	10,695,109
190	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.	145,799	145,001
191	GeneralAdvertisingExpenses (930.1) General Advertising Expenses	403,278	728,098
192	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	10,297,292	7,759,245
193	RentsAdministrativeAndGeneralExpense (931) Rents	1,436,533	1,950,065
194	AdministrativeAndGeneralOperationExpense TOTAL Operation (Enter Total of Lines 181 thru 193)	79,426,072	93,296,198
195	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
196	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	12,345,833	11,869,482
197	AdministrativeAndGeneralExpenses TOTAL Administrative & General Expenses (Total of Lines 194 and 196)	91,771,904	105,165,680
198	OperationsAndMaintenanceExpensesElectric TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 156, 164, 171, 178, and 197)	2,245,689,219	1,859,923,603

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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:

04/12/2023

Year/Period of Report

End of:

2022

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					243,742					22,531,888		22,531,888
2	BLUFF POINT WIND ENERGY CENTER	OS					421,654					16,145,829		16,145,829
3	CAMP GROVE WIND FARM LLC	OS					232,358					15,725,587		15,725,587
4	FOWLER RIDGE III WIND FARM LLC	OS					203,106					15,070,100		15,070,100
5	GAULEY RIVER POWERS PARTNERS	OS					212,324					6,435,643		6,435,643
6	GRAND RIDGE ENERGY II LLC	OS					114,999					11,842,743		11,842,743
7	GRAND RIDGE WIND FARM 3	OS					105,838					10,739,038		10,739,038
8	LUMINAIRE TECHNOLOGIES, INC.	OS					635				1,626	41,499		43,125
9	OLD DOMINION ELECTRIC	OS					4					3,550		3,550
10	OVEC POWER SCHEDULING	OS					1,733,380				61,018,355	58,287,967		119,306,322
11	PJM INTERCONNECTION	OS					12,196,355				112,270	858,387,950		858,500,220
12	RBC Captial Market, LLC	OS					0					1,960,043		1,960,043
13	(a) WIND DEFERRAL	OS					0					1,284,504		1,284,504
15	TOTAL						15,464,394	0	0	0	61,132,251	1,018,456,341		1,079,588,592

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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:

04/12/2023

Year/Period of Report

End of:

2022

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 Whlsl

Various

FNO

(a)

PJM OATT

Various

13,814,591

PJM Network Integ Trans Serv

Various

FNO

PJM OATT

Various

54,961,908

PJM Trans Enhancement Rev

Various

FNO

PJM OATT

Various

10,137,321

PJM Trans Enhancement Rev Whlsle

Various

FNO

PJM OATT

Various

325,356

PJM Trans Enhancement Rev - Affil

Various

FNO

PJM OATT

Various

615,076

PJM Network Integ Rev - Affil

Various

FNO

PJM OATT

Various

77,584,751

PJM Point to Point Trans Serv

Various

LFP

PJM OATT

Various

10,000,887

PJM Trans Owner Admin Revenue

Various

OLF

PJM OATT

Various

2,454

PJM Trans Owner Serv Rev Whlsl

Various

OLF

PJM OATT

Various

1,245

PJM Power Factor Credits Rev Whlsl

Various

PJM OATT

Various

(b)

93,314

PJM Power Factor Credits Rev Nonaffiliated

Various

PJM OATT

Various

(c)

157,315

PJM Transmission Distribution & Metering

Various

PJM OATT

Various

(d)

107,170

PJM Trans Owner Serv Revenue Affiliated

Various

OLF

PJM OATT

Various

1,648,458

TOTAL

167,439,890

1,644,759

357,799

169,442,448

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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:

04/12/2023

Year/Period of Report

End of:

2022

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:

04/12/2023

Year/Period of Report

End of:

2022

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) 36,976,342	36,976,342
2	PJM - NITS	OS					(b) 321,257,954	321,257,954
3	PJM - Trans Owner Serv	OS					(c) 583,335	583,335
	TOTAL		0	0	0	0	358,817,631	358,817,631

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:

04/12/2023

Year/Period of Report

End of:

2022

MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line No.	Description (a)	Amount (b)
1	IndustryAssociationDues Industry Association Dues	524,002
2	NuclearPowerResearchExpenses Nuclear Power Research Expenses
3	OtherExperimentalAndGeneralResearchExpenses Other Experimental and General Research Expenses	1,847
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	8,295,965
7	Affiliated Intercompany Billings	903,364
8	Broadband Study	43,832
9	Corporate Contributions and Memberships	134,844
10	Various Chambers of Commerce	58,436
11	Trustee Fees	73,740
12	Utility Corp Borrowing Program Shared Costs	261,516
13	Various Expenses	254
46	MiscellaneousGeneralExpenses TOTAL	10,297,292

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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			44,772,781		44,772,781
2	Steam Production Plant	208,080,229	4,155,876			212,236,105
3	Nuclear Production Plant
4	Hydraulic Production Plant-Conventional	6,451,261	30,476			6,481,737
5	Hydraulic Production Plant-Pumped Storage	4,381,193	45,648			4,426,841
6	Other Production Plant	13,787,587				13,787,587
7	Transmission Plant	97,339,701				97,339,701
8	Distribution Plant	176,084,952	2,968,365			179,053,317
9	Regional Transmission and Market Operation
10	General Plant	13,447,738	41,683	104,122		13,593,543
11	Common Plant-Electric
12	TOTAL	519,572,661	7,242,048	44,876,903		571,691,612

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	58,032	61 years	3	3.07
14	311 - Amos U3	117,032	60 years	3	2.97
15	311 - Central Plt Maint	86	0 years		2.02
16	311 - Clinch River	27,099	67 years	4	0.94
17	311 - Little Broad Mtn	267	0 years		3.62
18	311 - Mountaineer	194,761	60 years	5	2.92
19	311 - Mountaineer CCR/ELG	26,820	0 years		5.46
20	312 - Amos U1&2	1,381,328	61 years	3	3.91
21	312 - Amos U1&2 SCR	20,163	61 years	3	7.26
22	312 - Amos U3	1,578,367	60 years	3	4.06
23	312 - Amos U3 SCR	18,634	60 years	3	9.72
24	312 - Clinch River	215,488	67 years	4	5.43
25	312 - Little Broad Mtn	50,334	0 years		3.71
26	312 - Mountaineer	1,159,814	60 years	5	3.07
27	312 - Mountaineer SCR	18,740	8 years	5	10.85
28	314 - Amos U1&2	128,094	61 years	3	4.96
29	314 - Amos U3	161,115	60 years	3	4.5
30	314 - Clinch River	40,524	67 years	4	2.37
31	314 - Mountaineer	131,720	60 years	5	3.1
32	315 - Amos U1&2	58,233	61 years	3	3.91
33	315 - Amos U3	37,762	60 years	3	2.85
34	315 - Clinch River	11,045	67 years	4	1.31
35	315 - Little Broad Mtn	65	0 years		3.76
36	315 - Mountaineer	76,642	60 years	5	1.87
37	316 - Amos U1&2	5,813	61 years	3	5.08
38	316 - Amos U3	31,577	60 years	3	3.2
39	316 - Centrl Mach Shop	22,581	0 years		2.63
40	316 - Clinch River	6,435	67 years	4	4.26
41	316 - Mountaineer	24,189	60 years	5	2.54
42	TOTAL STEAM	5,602,760
43	HYDRO
44	331 - Buck Hydro	570	112 years	24	4.9
45	331 - Byllesby Hydro	1,446	112 years	24	9.83
46	331 - Claytor Hydro	3,863	102 years	24	3.08
47	331 - Leesville Hydro	3,860	76 years	24	2.77
48	331 - London Hydro	652	109 years	24	2.69
49	331 - Marmet Hydro	1,744	109 years	24	2.01
50	331 - Niagara Hydro	721	106 years	24	16.63
51	331 - Winfield Hydro	2,986	112 years	24	2.97
52	332 - Buck Hydro	7,896	112 years	24	9.32
53	332 - Byllesby Hydro	7,470	102 years	24	12.9
54	332 - Claytor Hydro	12,714	76 years	24	2.19
55	332 - Leesville Hydro	12,111	109 years	24	2.19
56	332 - London Hydro	1,708	109 years	24	1.97
57	332 - Marmet Hydro	2,262	118 years	24	2.33
58	332 - Niagara Hydro	6,734	106 years	24	9.35
59	332 - Winfield Hydro	2,931	112 years	24	2.22
60	333 - Buck Hydro	1,937	112 years	24	6.77
61	333 - Byllesby Hydro	3,702	102 years	24	11.69
62	333 - Claytor Hydro	4,897	76 years	24	3.08
63	333 - Leesville Hydro	3,764	109 years	24	2.02
64	333 - London Hydro	10,337	109 years	24	2.99
65	333 - Marmet Hydro	10,033	118 years	24	3.4
66	333 - Niagara Hydro	640	106 years	24	5.23
67	333 - Winfield Hydro	7,741	112 years	24	3.32
68	334 - Buck Hydro	2,518	112 years	24	7.71
69	334 - Byllesby Hydro	1,110	102 years	24	7.18
70	334 - Claytor Hydro	3,254	76 years	24	2.65
71	334 - Leesville Hydro	1,975	109 years	24	4.03
72	334 - London Hydro	1,972	109 years	24	2.16
73	334 - Marmet Hydro	2,236	118 years	24	2.21
74	334 - Niagara Hydro	500	106 years	24	13.51
75	334 - Winfield Hydro	274	112 years	24	3.18
76	335 - Buck Hydro	951	112 years	24	14.45
77	335 - Byllesby Hydro	1,047	102 years	24	9.53
78	335 - Claytor Hydro	3,117	76 years	24	3.27
79	335 - Leesville Hydro	3,233	109 years	24	3.34
80	335 - London Hydro	682	109 years	24	2.66
81	335 - Marmet Hydro	919	118 years	24	2.44
82	335 - Niagara Hydro	314	106 years	24	8.85
83	335 - Winfield Hydro	3,437	112 years	24	2.02
84	336 - Buck Hydro	3	102 years	24	2.44
85	336 - Claytor Hydro	32	76 years	24	0.98
86	336 - Leesville Hydro	81	109 years	24	0.99
87	336 - London Hydro	49	109 years	24	1.19
88	336 - Marmet Hydro	1	109 years	24	1.16
89	336 - Winfield Hydro	24	106 years	24	2.09
90	TOTAL HYDRO	140,448
91	HYDRO PUMPED
92	331	16,535	75 years	24	2.14
93	332	33,091	75 years	24	1.54
94	333	78,536	75 years	24	3.38
95	334	13,040	75 years	24	3.66
96	335	10,695	75 years	24	3.66
97	336	1,052	75 years	24	1.05
98	TOTAL HYDRO PUMPED	152,949
99	OTHER GENERATION
100	341 Ceredo Plant	1,706	40 years		1.27
101	341 Dresden Plant	48,623	35 years	1	3.34
102	341 Dresden - VA AFUDC	858	0 years		21.62
103	342 Dresden Plant	26,209	35 years	1	3.01
104	342 Dresden - VA AFUDC	432	0 years		21.62
105	344 Ceredo Plant	182,620	40 years		1.32
106	344 Dresden Plant	324,256	35 years	1	3.07
107	344 Dresden - VA AFUDC	5,948	0 years		21.62
108	345 Ceredo Plant	19,434	40 years		1.48
109	345 Dresden Plant	28,008	35 years	1	3.26
110	345 Dresden - VA AFUDC	430	0 years		21.62
111	346 Ceredo Plant	1,665	40 years		3.7
112	346 Dresden Plant	31,585	35 years	1	3.74
113	346 Dresden - VA AFUDC	69	0 years		21.62
114	348 Battery Storage	5,726	0 years		5
115	TOTAL OTHER	677,569
116	TRANSMISSION
117	350 - VA (Rights)	100,687	0 years		0.66
118	352	177,016	60 years	20	1.86	R3
119	353	2,065,506	43 years	10	2.53	R2
120	353 Dresden Plant - VA AFUDC	787			21.62
121	353.16	19,727	43 years	10	2.53	R2
122	354	517,097	75 years	19	1.67	R4
123	355	566,643	37 years	20	3.05	L1.5
124	356	810,317	68 years	8	1.65	R4
125	356.16	49,884	68 years	8	1.65	R4
126	357	19,130	42 years		2.96	S6
127	358	20,276	24 years		4.73	L3.5
128	358.16	8,503	24 years		4.73	L3.5
129	TOTAL TRANSMISSION	4,355,573
130	DISTRIBUTION
131	360 - VA (Rights)	25,167	0 years		1.49
132	361 - VA	43,204	50 years	10	2.46	R5
133	361 - WV	28,795	55 years	12	1.9	R3
134	361-373 - TN	47	0 years		4
135	362 - VA	427,864	50 years	19	2.32	L0.5
136	362 - WV	290,393	45 years	16	2.52	R1
137	362.16 - VA	7,809	50 years	19	2.32	L0.5
138	362.16 - WV	5,086	45 years	16	2.52	R1
139	363 - WV	165	15 years		7.38	SQ
140	364 - VA	448,760	40 years	72	3.65	R0.5
141	364 - WV	473,223	33 years	67	4.77	R0.5
142	365 - VA	641,080	35 years	18	3.3	R0.5
143	365 - WV	597,207	35 years	16	3.38	R0.5
144	366 - VA	83,311	57 years		1.61	R4
145	366 - WV	65,538	55 years		1.73	R4
146	367 - VA	212,693	51 years		1.83	R2.5
147	367 - WV	120,574	48 years		2.05	R1.5
148	368 - VA	419,310	35 years	21	3.05	L0
149	368 - WV	248,334	27 years	20	4.65	R0.5
150	369 - VA	203,638	35 years	28	3.48	L1.5
151	369 - WV	183,952	30 years	26	4.22	R0.5
152	370 - VA	20,738	15 years	6	8.14	L1
153	370 - WV	38,343	15 years	10	12.43	S6
154	370.16 - VA	98,981	15 years	6	8.14	L1
155	370.16 - WA	59,483	15 years	10	12.43	S6
156	371 - VA	41,072	16 years	21	4.73	L0
157	371 - WV	25,294	12 years	22	9.3	R0.5
158	372 - VA	1	25 years		2.01	L3
159	373 - VA	21,782	23 years	33	4.91	R0.5
160	373 - WV	11.812	20 years	31	8.17	R0.5
161	TOTAL DISTRIBUTION	4,843,656
162	GENERAL PLANT
163	390	245,877	45 years	8	1.98	R2.5
164	391	14,388	30 years		3.21	SQ
165	392	8	27 years		3.44	SQ
166	393	2,231	55 years		1.88	SQ
167	394	44,649	43 years	10	2.63	SQ
168	395	2,707	37 years		3.92	SQ
169	396	5	25 years		1.84	SQ
170	397	138,051	24 years	8	4.94	SQ
171	397.12	41	24 years	8	4.94	SQ
172	397.16	41,103	24 years	8	4.94	SQ
173	398	10,584	35 years		2.73	SQ
174	TOTAL GENERAL PLANT	499,644
175	DEPRECIABLE SUM	(a) 16,272,599

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

FOOTNOTE DATA

(a) Concept: DepreciablePlantBase

The depreciable plant base is the November 30, 2022 total company depreciable plant.

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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	1,468,266		1,468,266			928	1,468,266
2	Leesville Hydro Project #2210 - Proportion of cost of administering the Federal Water Power Act	45,168		45,168			928	45,168
3	Claytor Hydro Project #739 - Proportion of cost of administering the Federal Water Power Act	226,857		226,857			928	226,857
4	Byllesby Buck Hydro Project #2514 - Proportion of cost of administering the Federal Water Power Act	85,633		85,633			928	85,633
5	Marmet and London Hydro Project #1175 - Proportion of cost of administering the Federal Water Power Act	97,838		97,838			928	97,838
6	Winfield Hydro Project #1290 - Proportion of cost of administering the Federal Water Power Act	74,549		74,549			928	74,549
7	Niagara Hydro Project #2466 - Proportion of cost of administering the Federal Water Power Act	7,306		7,306			928	7,306
8	Misc Exp - items less than $25,000		155,996	155,996			928	155,996
9	West Virginia Base Case		176,309	176,309	29,646		928	176,309		928	29,646
10	Virginia Broadband Filing		69,864	69,864			928	69,864
11	Virginia Fuel Filing		55,756	55,756			928	55,756
12	Virginia Energy Efficiency RAC filing		94,150	94,150			928	94,150
13	Virginia Triennial Filing		908,582	908,582			928	908,582
14	West Virginia Coal Combustion Residuals and Effluent Limitation Guidelines Filing		31,723	31,723			928	31,723
15	Virginia Blue Ridge Petition Filing		58,710	58,710			928	58,710
16	Virginia Transmission RAC Filing		36,217	36,217			928	36,217
17	State Commission Fees		4,391,679	4,391,679			928	4,391,679
18	Virginia Integrated Resource Plan Filing		385,277	385,277			928	385,277
19	Virginia Clean Economy Act Filing		569,826	569,826			928	569,826
20	Virginia Environmental RAC Filing		306,708	306,708			928	306,708
21	FERC Formula Rate Filing		121,672	121,672			928	121,672
22	West Virginia ENEC Filing		94,848	94,848			928	94,848
23	West Virginia Regulatory and Legislative Activities		51,861	51,861			928	51,861
24	Virginia Regulatory and Legislative Activities		41,964	41,964			928	41,964
25	Virginia Collegiate Declarator Relief Filing		38,426	38,426			928	38,426
46	TOTAL	2,005,617	7,589,568	9,595,185	29,646			9,595,185			29,646

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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	243,790		506	243,790
4		2 Item(s) Under $50,000	27,664		506	27,664
5	A(1)e CEATI (Centre for Energy Advancement through Technological Innovation) Membership	1 Item(s) Under $50,000	457		506	457
6	A(2) Transmission:	1 Item(s) Under $50,000	11,100		566	11,100
7	A(3) Distribution:	1 Item(s) Under $50,000	18,446		588	18,446
8	A(5) Environment: (Other Than Equipment)	2 Item(s) Under $50,000	43,315		506	43,315
9	A(6) Other:	Corporate Technology Prog Mgmt	51,582		506,566,588	51,582
10		1 Item(s) Under $50,000	227		506,566,588	227
11	A(6)a:
12	A(6)f Other: Metering	1 Item(s) Under $50,000	2,514		588	2,514
13	A(6)g Research - General:	1 Item(s) Under $50,000	6,105		566, 588	6,105
14	A(7) TOTAL COST INCURRED INTERNALLY		405,200			405,200
15	ELECTRIC UTILITY RESEARCH, DEVELOPMENT & DEMONSTRATION PERFORMED EXTERNALLY	6 Item(s) Under $50,000		84,062	506,566,588	84,062
16	B(1) Research Support to Elec. Research Council & Elec. Power Research Inst.	EPRI Research Portfolio		1,061,683	506,566,588	1,061,683
17		EPRI Environmental Science		705,744	506	705,744
18		Low Carbon Resource Initiative		204,727	506,566,588	204,727
19		IT - EPRI Annual Research Port		68,649	506,566,588	68,649
20		24 Item(s) Under $50,000		136,993	506,566,588	136,993
21	B(4) Research Support to Others	1 Item(s) under $50,000		22,275	506	22,275
22	B(5) TOTAL COST INCURRED EXTERNALLY			2,284,133		2,284,133

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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	25,169,694
4	SalariesAndWagesElectricOperationTransmission Transmission	95,739
5	SalariesAndWagesElectricOperationRegionalMarket Regional Market
6	SalariesAndWagesElectricOperationDistribution Distribution	9,770,205
7	SalariesAndWagesElectricOperationCustomerAccounts Customer Accounts	6,258,744
8	SalariesAndWagesElectricOperationCustomerServiceAndInformational Customer Service and Informational	2,663,269
9	SalariesAndWagesElectricOperationSales Sales
10	SalariesAndWagesElectricOperationAdministrativeAndGeneral Administrative and General	1,445,694
11	SalariesAndWagesElectricOperation TOTAL Operation (Enter Total of lines 3 thru 10)	45,403,345
12	SalariesAndWagesElectricMaintenanceAbstract Maintenance
13	SalariesAndWagesElectricMaintenanceProduction Production	26,292,520
14	SalariesAndWagesElectricMaintenanceTransmission Transmission	51,780
15	SalariesAndWagesElectricMaintenanceRegionalMarket Regional Market
16	SalariesAndWagesElectricMaintenanceDistribution Distribution	29,973,324
17	SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral Administrative and General	2,813,015
18	SalariesAndWagesElectricMaintenance TOTAL Maintenance (Total of lines 13 thru 17)	59,130,639
19	SalariesAndWagesElectricOperationAndMaintenanceAbstract Total Operation and Maintenance
20	SalariesAndWagesElectricProduction Production (Enter Total of lines 3 and 13)	51,462,214
21	SalariesAndWagesElectricTransmission Transmission (Enter Total of lines 4 and 14)	147,519
22	SalariesAndWagesElectricRegionalMarket Regional Market (Enter Total of Lines 5 and 15)
23	SalariesAndWagesElectricDistribution Distribution (Enter Total of lines 6 and 16)	39,743,529
24	SalariesAndWagesElectricCustomerAccounts Customer Accounts (Transcribe from line 7)	6,258,744
25	SalariesAndWagesElectricCustomerServiceAndInformational Customer Service and Informational (Transcribe from line 8)	2,663,269
26	SalariesAndWagesElectricSales Sales (Transcribe from line 9)
27	SalariesAndWagesElectricAdministrativeAndGeneral Administrative and General (Enter Total of lines 10 and 17)	4,258,709
28	SalariesAndWagesElectricOperationAndMaintenance TOTAL Oper. and Maint. (Total of lines 20 thru 27)	104,533,984	7,893,774	112,427,758
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)	104,533,984	7,893,774	112,427,758
66	SalariesAndWagesUtilityPlantAbstract Utility Plant
67	SalariesAndWagesUtilityPlantConstructionAbstract Construction (By Utility Departments)
68	SalariesAndWagesUtilityPlantConstructionElectricPlant Electric Plant	53,316,368	4,026,130	57,342,498
69	SalariesAndWagesUtilityPlantConstructionGasPlant Gas Plant
70	SalariesAndWagesUtilityPlantConstructionOther Other (provide details in footnote):
71	SalariesAndWagesUtilityPlantConstruction TOTAL Construction (Total of lines 68 thru 70)	53,316,368	4,026,130	57,342,498
72	SalariesAndWagesPlantRemovalAbstract Plant Removal (By Utility Departments)
73	SalariesAndWagesPlantRemovalElectricPlant Electric Plant	11,878,038	896,958	12,774,996
74	SalariesAndWagesPlantRemovalGasPlant Gas Plant
75	SalariesAndWagesPlantRemovalOther Other (provide details in footnote):
76	SalariesAndWagesPlantRemoval TOTAL Plant Removal (Total of lines 73 thru 75)	11,878,038	896,958	12,774,996
77	SalariesAndWagesOtherAccountsAbstract Other Accounts (Specify, provide details in footnote):
78	SalariesAndWagesOtherAccountsDescription Other Accounts (Specify, provide details in footnote):
79	SalariesAndWagesOtherAccountsDescription 152 - Fuel Stock Undistributed	8,107,273		8,107,273
80	SalariesAndWagesOtherAccountsDescription 154 - Materials and Supplies
81	SalariesAndWagesOtherAccountsDescription 163 - Stores Expense Undistributed	5,951,358	5,951,358
82	SalariesAndWagesOtherAccountsDescription 165 - Other Prepayments
83	SalariesAndWagesOtherAccountsDescription 182 - Other Regulatory Assets
84	SalariesAndWagesOtherAccountsDescription 183 - Prelim Survey	302,755	302,755
85	SalariesAndWagesOtherAccountsDescription 184 - Clearing Accounts	6,562,749	6,562,749
86	SalariesAndWagesOtherAccountsDescription 185 - ODD Temporary Facilities	217,668		217,668
87	SalariesAndWagesOtherAccountsDescription 186 - Misc Deferred Debits	495,279		495,279
88	SalariesAndWagesOtherAccountsDescription 188 - Research & Development
89	SalariesAndWagesOtherAccountsDescription 228 - RAD Waste Accrual
90	SalariesAndWagesOtherAccountsDescription 242 - Misc Current & Accrued Liab
91	SalariesAndWagesOtherAccountsDescription 418 - Nonoperating Rental Income	4,600		4,600
92	SalariesAndWagesOtherAccountsDescription 421 - Misc Nonoperating Income
93	SalariesAndWagesOtherAccountsDescription 426 - Political Activities	509,460		509,460
94	SalariesAndWagesOtherAccountsDescription 451 - Misc Service Rev - Nonaffil
95	SalariesAndWagesOtherAccountsDescription 456 - Other Electric Revenue
95	SalariesAndWagesOtherAccounts TOTAL Other Accounts	22,151,142	12,816,862	9,334,280
96	SalariesAndWagesGeneralExpense TOTAL SALARIES AND WAGES	191,879,532		191,879,532

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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:

04/12/2023

Year/Period of Report

End of:

2022

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)				816,012,561
2.1	Net Purchases (Account 555.1)
3	Net Sales (Account 447)				159,608,429
4	Transmission Rights				81,237,494
5	Ancillary Services				9,531,676
6	Other Items (list separately)
7	Congestion				77,431,744
8	Operating Reserves				2,504,360
9	Transmission Purchase Expense				26,230,918
10	Transmission Losses				30,557,628
11	Meter Correction				589,677
12	Inadvertent				1,043,503
13	Capacity Credits				8,411,912
46	TOTAL				707,548,506

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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:

04/12/2023

Year/Period of Report

End of:

2022

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:

04/12/2023

Year/Period of Report

End of:

2022

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:

04/12/2023

Year/Period of Report

End of:

2022

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:

04/12/2023

Year/Period of Report

End of:

2022

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:

2023-04-12

Year/Period of Report

End of:

2022

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)	26,916,714
3	Steam	12,610,105	23	Requirements Sales for Resale (See instruction 4, page 311.)	3,052,347
4	Nuclear		24	Non-Requirements Sales for Resale (See instruction 4, page 311.)	1,842,510
5	Hydro-Conventional	603,755	25	Energy Furnished Without Charge	(a) 342,194
6	Hydro-Pumped Storage	437,699	26	Energy Used by the Company (Electric Dept Only, Excluding Station Use)
7	Other	4,905,165	27	Total Energy Losses	2,043,880
8	Less Energy for Pumping	507,861	27.1	Total Energy Stored
9	Net Generation (Enter Total of lines 3 through 8)	18,048,863	28	TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL LINE 20 UNDER SOURCES	33,513,257
10	Purchases (other than for Energy Storage)	15,464,394
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)	33,513,257

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

2023-04-12

Year/Period of Report

End of:

2022

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			(343,073)
Hydropower to Government			879
			(342,194)

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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	3,645,298	176,411	6,631	27	8
30	February	2,931,512	66,418	6,352	15	8
31	March	2,675,753	127,153	5,663	13	8
32	April	2,368,549	111,810	4,548	20	8
33	May	2,462,917	160,003	4,874	31	18
34	June	2,638,561	115,754	5,348	15	16
35	July	3,082,326	358,686	3,965	31	18
36	August	3,080,111	390,411	5,307	9	15
37	September	2,361,727	63,960	4,694	21	17
38	October	2,317,951	46,597	4,579	20	8
39	November	2,670,492	176,440	5,509	21	8
40	December	3,278,060	136,809	7,395	24	8
41	Total	33,513,257	1,930,452

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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)		2,862	568	453	666	1,330
7	PlantHoursConnectedToLoad Plant Hours Connected to Load		6,283	1,061	435	7,862	5,559
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		227	7	35	32	148
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh		7,306,850,000	398,272,000	85,722,000	4,506,893,000	5,217,533,000
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		175,066,206	1,706,255	27,098,637	50,274,983	230,926,388
15	CostOfEquipmentSteamProduction Equipment Costs		3,416,935,464	203,718,893	273,685,097	423,114,911	1,461,972,146
16	AssetRetirementCostsSteamProduction Asset Retirement Costs		97,726,142	0	4,831,339	0	11,358,844
17	CostOfPlant Total cost (total 13 thru 20)		3,697,035,646	206,335,147	306,116,172	475,676,827	1,708,811,914
18	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 17/5) Including		1,247.7339	397.4251	429.6367	711.0266	1,294.5545
19	OperationSupervisionAndEngineeringExpense Production Expenses: Oper, Supv, & Engr		13,926,376	292,950	1,103,084	585,819	6,057,476
20	FuelSteamPowerGeneration Fuel		241,618,913	34,937,247	(a) 21,548,486	186,467,583	168,249,860
21	CoolantsAndWater Coolants and Water (Nuclear Plants Only)		0	0	0	0	0
22	SteamExpensesSteamPowerGeneration Steam Expenses		25,481,414	89,736	3,350,805	322,484	12,953,524
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		173,958	724,407	0	0	112
26	MiscellaneousSteamPowerExpenses Misc Steam (or Nuclear) Power Expenses		5,466,742	185,512	1,428,537	3,478,532	8,112,110
27	RentsSteamPowerGeneration Rents		29,332	3	0	0	13,028
28	Allowances Allowances		93,353	0	427,942	141	45,500
29	MaintenanceSupervisionAndEngineeringSteamPowerGeneration Maintenance Supervision and Engineering		348,079	0	663	587,011	1,358,185
30	MaintenanceOfStructuresSteamPowerGeneration Maintenance of Structures		3,435,071	0	892,911	521,355	1,509,644
31	MaintenanceOfBoilerPlantSteamPowerGeneration Maintenance of Boiler (or reactor) Plant		37,602,955	1,722	3,107,334	698,491	15,596,851
32	MaintenanceOfElectricPlantSteamPowerGeneration Maintenance of Electric Plant		9,439,862	202,378	1,069,577	3,694,947	4,687,820
33	MaintenanceOfMiscellaneousSteamPlant Maintenance of Misc Steam (or Nuclear) Plant		6,474,654	0	784,643	1,752,132	2,566,616
34	PowerProductionExpensesSteamPower Total Production Expenses	0	344,090,709	36,433,955	33,713,982	198,108,495	221,150,726
35	ExpensesPerNetKilowattHour Expenses per Net kWh		0.0471	0.0915	0.3933	0.0440	0.0424

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	3,059,685	83,231	4,494,837	1,038,326	29,006,754	2,149,707	28,871
39	FuelBurnedAverageHeatContent Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)	12,307	137,803	1,083,000	1,033,000	1,065,000	12,300	137,267
40	AverageCostOfFuelPerUnitAsDelivered Avg Cost of Fuel/unit, as Delvd f.o.b. during year	71.610	174.233	7.697	20.269	6.262	70.350	160.445
41	AverageCostOfFuelPerUnitBurned Average Cost of Fuel per Unit Burned	64.444	158.289	7.582	20.479	6.280	64.719	107.419
42	AverageCostOfFuelBurnedPerMillionBritishThermalUnit Average Cost of Fuel Burned per Million BTU	2.618	27.349	7.001	19.825	5.897	2.631	18.632
43	AverageCostOfFuelBurnedPerKilowattHourNetGeneration Average Cost of Fuel Burned per kWh Net Gen	0.027	0.000	0.086	0.248	0.040	0.027	0.000
44	AverageBritishThermalUnitPerKilowattHourNetGeneration Average BTU per kWh Net Generation	10,400.000	0.000	12,219.000	12,227.000	7,263.000	10,163.000	0.000

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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:

04/12/2023

Year/Period of Report

End of:

2022

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	15	79	50	12	12	22
7	PlantHoursConnectedToLoad Plant Hours Connect to Load		8,269	8,097	5,826	1,933	7,060	7,473	7,747
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	4	4
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh		37,059,000	52,122,000	213,230,000	49,480,000	51,951,000	65,902,000	125,788,000
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		880,253	1,631,207	4,327,421	3,859,754	651,516	1,788,911	2,992,064
16	CostOfReservoirsDamsAndWaterwaysHydroelectricProduction Reservoirs, Dams, and Waterways		7,895,918	7,469,565	12,713,953	12,139,863	1,707,849	2,354,076	2,931,197
17	EquipmentCostsHydroelectricProduction Equipment Costs		5,405,419	(a) 11,585,080	11,314,159	8,972,398	13,002,125	13,188,399	11,452,606
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)		14,185,027.00	20,928,318	30,362,406	27,033,874	15,525,076	17,462,075.00	17,537,177
21	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 20 / 5)		1,325.7	968.9036	404.8321	675.8469	1,078.1303	1,212.6	1,184.9444
22	ProductionExpensesAbstract Production Expenses
23	OperationSupervisionAndEngineeringExpense Operation Supervision and Engineering		46,728	66,243	270,830	78,089	64,651	207,931	203,595
24	WaterForPower Water for Power		594	492	1,053		7,857	7,857	7,857
25	HydraulicExpenses Hydraulic Expenses		4,903	6,531	715,839	88,810	12,715	10,532	16,198
26	ElectricExpensesHydraulicPowerGeneration Electric Expenses		8,366	10,574	41,081	9,416	9,886	12,540	23,936
27	MiscellaneousHydraulicPowerGenerationExpenses Misc Hydraulic Power Generation Expenses		76,097	146,238	602,272	103,340	304,278	480,031	278,810
28	RentsHydraulicPowerGeneration Rents				4,695	13	78,743	78,743	184,996
29	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration Maintenance Supervision and Engineering		591	832	22,791	790	7,791	9,653	11,218
30	MaintenanceOfStructuresHydraulicPowerGeneration Maintenance of Structures		89,541	100,402	345,455	850,620	608,053	506,508	241,710
31	MaintenanceOfReservoirsDamsAndWaterways Maintenance of Reservoirs, Dams, and Waterways		169,001	224,106	78,914	616,696	59,905	57,032	172,032
32	MaintenanceOfElectricPlantHydraulicPowerGeneration Maintenance of Electric Plant		364,583	84,490	652,222	149,099	285,566	59,410	77,449
33	MaintenanceOfMiscellaneousHydraulicPlant Maintenance of Misc Hydraulic Plant		8,190	8,259	14,992	58,850	6,692	7,287	6,781
34	PowerProductionExpensesHydraulicPower Total Production Expenses (total 23 thru 33)		768,594	648,167	2,750,144	1,955,723	1,446,137	1,437,524	1,224,582
35	ExpensesPerNetKilowattHour Expenses per net kWh		0.0207	0.0124	0.0129	0.0395	0.0278	0.0218	0.0097

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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:

04/12/2023

Year/Period of Report

End of:

2022

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	596
6	PlantHoursConnectedToLoad Plant Hours Connect to Load While Generating	0	880
7	NetContinuousPlantCapability Net Plant Capability (in megawatts)	0	565
8	PlantAverageNumberOfEmployees Average Number of Employees		18
9	NetGenerationExcludingPlantUse Generation, Exclusive of Plant Use - kWh	0	437,699,000
10	EnergyUsedForPumping Energy Used for Pumping		507,861,000
11	NetOutputForLoad Net Output for Load (line 9 - line 10) - Kwh	0	70,162,000
12	CostOfPlantAbstract Cost of Plant
13	CostOfLandAndLandRightsPumpedStoragePlant Land and Land Rights		6,168,815
14	CostOfStructuresAndImprovementsPumpedStoragePlant Structures and Improvements	0	16,534,567
15	CostOfReservoirsDamsAndWaterwaysPumpedStoragePlant Reservoirs, Dams, and Waterways	0	33,091,294
16	CostOfWaterWheelsTurbinesAndGeneratorsPumpedStoragePlant Water Wheels, Turbines, and Generators	0	78,675,122
17	CostOfAccessoryElectricEquipmentPumpedStoragePlant Accessory Electric Equipment	0	13,085,323
18	CostOfMiscellaneousPowerPlantEquipmentPumpedStoragePlant Miscellaneous Powerplant Equipment	0	10,694,990
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)		160,989,419
22	CostPerKilowattOfInstalledCapacity Cost per KW of installed cap (line 21 / 4)		248.8244
23	ProductionExpensesAbstract Production Expenses
24	OperationSupervisionAndEngineeringExpense Operation Supervision and Engineering	0	763,811
25	WaterForPower Water for Power	0	2
26	PumpedStorageExpenses Pumped Storage Expenses	0	492,590
27	ElectricExpensesPumpedStoragePlant Electric Expenses	0	142,994
28	MiscellaneousPumpedStoragePowerGenerationExpenses Misc Pumped Storage Power generation Expenses	0	1,721,185
29	RentsPumpedStoragePlant Rents	0	2,764
30	MaintenanceSupervisionAndEngineeringPumpedStoragePlant Maintenance Supervision and Engineering	0	158,406
31	MaintenanceOfStructuresPumpedStoragePlant Maintenance of Structures	0	2,101,716
32	MaintenanceOfReservoirsDamsAndWaterwaysPumpedStoragePlant Maintenance of Reservoirs, Dams, and Waterways	0	1,143,134
33	MaintenanceOfElectricPlantPumpedStoragePlant Maintenance of Electric Plant	0	2,394,084
34	MaintenanceOfMiscellaneousPumpedStoragePlant Maintenance of Misc Pumped Storage Plant	0	59,096
35	PowerProductionExpenseBeforePumpingExpenses Production Exp Before Pumping Exp (24 thru 34)		8,979,782
36	PumpingExpenses Pumping Expenses		28,217,770
37	PowerProductionExpensesPumpedStoragePlant Total Production Exp (total 35 and 36)		37,197,552
38	ExpensesPerNetKilowattHour Expenses per kWh (line 37 / 9)		0.0850
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:

04/12/2023

Year/Period of Report

End of:

2022

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

2.5

8,223,000

8,958,508

48,245

321,888

TOTAL HYDRO (Small Plants)

8,223,000

8,958,508

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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:

04/12/2023

Year/Period of Report

End of:

2022

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	0.00	0.00	1	2049KCM ACAR
3	0400 CANE RIVER, TN CIR-A	NAGEL, TN	230	230	3	46.00	0.00	1	1590KCM ACSR
4	0400 CANE RIVER, TN CIR-B	NAGEL, TN	230	230	3	1.00	45.00	1	1590KCM ACSR
5	0351 CLINCH RIVER, VA	NAGEL, TN	138	138	3	0.00	0.00	1	1590KCM ACSR
6	0353 NAGEL, TN	REEDY CREEK, TN	138	138	3	0.00	0.00	1	1590KCM ACSR
7	0349 BROADFORD, VA	NAGEL, TN	138	138	3	13.00	0.00	1	397KCM ACSR
8	0349 BROADFORD, VA	NAGEL, TN	0	0	1	0.00	0.00	0
9	0355 NAGEL, TN	WEST KINGSPORT, TN	138	138	3	0.00	1.00	1	556KCM
10	0355 NAGEL, TN	WEST KINGSPORT, TN	0	0	1	0.00	0.00	0
11	0176 NORTH BRISTOL, VA	WEST KINGSPORT, VA	138	138	3	6.00	11.00	1	397KCM ACSR
12	0176A HOLSTON, TN	REEDY CREEK, TN	138	138	3	0.00	6.00	1	397KCM ACSR
13	0179 BOONE DAM, TN	HOLSTON, TN	138	138	3	0.00	0.00	1	636KCM ACSR
14	0179 BOONE DAM, TN	HOLSTON, TN	0	0	1	8.00	0.00	0
15	0180 HOLSTON, TN	WALTERS, NC	138	138	3	65.00	0.00	1	250KCM CU
16	0180 HOLSTON, TN	WALTERS, NC	138	138	1	0.00	0.00	1	1033KCM ACSR
17	0570 SALTVILLE	KINGSPORT (TN)	138	138	3	17.00	0.00	2	397.5KCM ACSR
18	STATE OF VIRGINIA	STATE OF VIRGINIA				0.00	0.00
19	0186 BAKER, KY	BROADFORD, VA	765	765	3	0.00	0.00	1	954KCM ACSR
20	0186 BAKER, KY	BROADFORD, VA	0	0	3	47.00	0.00	0
21	0187 BROADFORD, VA	JACKSONS FERRY, VA	765	765	3	49.00	0.00	1	954KCM ACSR
22	0253 CLOVERDALE, VA	JACKSONS FERRY, VA	765	765	3	65.00	0.00	1	954KCM ACSR
23	0310 CLOVERDALE, VA	JOSHUA FALLS, VA	765	765	3	57.00	0.00	1	1351KCM ACSR
24	0406 JACKSON FERRY	WYOMING	765	765	3	57.00	0.00	1	795 KCM ACSR
25	0334 AXTON, VA	JACKSONS FERRY, VA	765	765	3	73.00	0.00	1	1351KCM ACSR
26	0181 BROADFORD, VA	SULLIVAN, TN	500	500	3	33.00	0.00	1	2049KCM ACAR
27	0001CLOVERDALE, VA	LEXINGTON, VA	500	500	3	36.00	0.00	1	2-1780KCM ACSS
28	0001 CLOVERDALE	LEXINGTON, VA	500	500	2	0.00	0.00	1	2-1780kcm ACSS
29	0182 JACKSONS FERRY, VA	MCGUIRE, NC	500	500	3	26.00	0.00	1	2049KCM ACAR
30	0008A KANAWHA, WV	MATT FUNK, VA	345	345	3	8.00	0.00	1	1563KCM ACAR
31	0008A KANAWHA, WV	MATT FUNK, VA	0	0	3	34.00	0.00	0
32	0008 CLOVERDALE, VA	MATT FUNK, VA	345	345	3	0.00	8.00	1	954 KCM ACSR
33	0008 CLOVERDALE, VA	MATT FUNK, VA	0	0	3	19.00	0.00	0
34	0142 EAST DANVILLE NO. 1,VA	ROXBORO, NC	230	230	3	8.00	0.00	1	1590KCM ACSR
35	0142 EAST DANVILLE NO. 2,VA	ROXBORO, NC	230	230	3	0.00	8.00	1	1590KCM ACSR
36	0417 BAILEYSVILLE, WV	HALES BRANCH, VA	138	138	3	0.00	0.00	1	636KCM ACSR
37	0417 BAILEYSVILLE, WV	HALES BRANCH, VA	0	0	1	6.00	0.00	0
38	0054 GARDEN CREEK, VA	HALES BRANCH, VA	138	138	3	0.00	0.00	1	636KCM ACSR
39	0054 GARDEN CREEK, VA	HALES BRANCH, VA	0	0	1	7.00	0.00	0
40	0409 LOONEY CREEK TAP, VA		138	138	3	10.00	0.00	1	795KCM ACSR
41	0434 GRASSY CREEK, VA	HALES BRANCH, VA	138	138	3	0.00	0.00	2	1033.5KCM ACSR
42	0434 GRASSY CREEK, VA	HALES BRANCH, VA	138	138	3	6.00	0.00	1	795KCM ACSR
43	0434 GRASSY CREEK, VA	HALES BRANCH, VA	0	0	1	2.00	0.00	0
44	0110 CLAYTOR, VA	MATT FUNK, VA	138	138	3	30.00	0.00	1	397KCM ACSR
45	0110 CLAYTOR, VA	MATT FUNK, VA	138	138	3	0.00	0.00	1	556KCM ACSR
46	0112 MATT FUNK, VA	ROANOKE, VA	138	138	3	13.00	5.00	1	397KCM ACSR
47	0113 CLAYTOR, VA	HANCOCK, VA	138	138	3	0.00	39.00	1	397KCM ACSR
48	0114 HANCOCK, VA	ROANOKE, VA	138	138	3	5.00	4.00	1	397KCM ACSR
49	0229 MERRIMAC TAP, VA		138	138	1	7.00	0.00	1	556KCM ACSR
50	0138 COLLINSVILLE	TAP LINE	138	138		0.00	0.00	0
51	8161 CVEC	SCOTTSVILLE	46	138	3	1.00	0.00	1
52	0422 JACKSONS FERRY, VA	PEAK CREEK, VA	138	138	1	13.00	0.00	1	795KCM ACSR
53	0422 JACKSONS FERRY, VA	PEAK CREEK, VA	138	138	3	1.00	0.00	0	954KCM ACSR
54	0129 PHILPOTT TAP, VA		138	138	1	0.00	0.00	1	4/0KCM ACSR
55	0248 CLAYTOR, VA	FIELDALE	138	138	3	0.00	0.00	1	556KCM ACSR
56	0248 CLAYTOR, VA	FIELDALE	0	0	1	38.00	0.00	0
57	0249 FIELDALE, VA	WEST BASSETT, VA	138	138	3	0.00	0.00	1	556KCM ACSR
58	0249 FIELDALE, VA	WEST BASSETT, VA	0	0	1	6.00	0.00	0
59	0120 BEAVER CREEK, KY	CLINCH RIVER, VA	138	138	3	26.00	0.00	1	636KCM ACSR
60	0120 BEAVER CREEK, KY	CLINCH RIVER, VA	138	138	1	0.00	0.00	0	636KCM ACSR
61	0122 CLINCH RIVER, VA	FREMONT, VA	138	138	3	0.00	18.00	1	636KCM ACSR
62	0123 BEAVER CREEK, KY	FREMONT, VA	138	138	3	0.00	9.00	1	636KCM ACSR
63	0289 COOPER RIDGE LOOP, VA		138	138	1	0.00	0.00	1	636KCM ACSR
64	0350 CLINCH RIVER, VA	NAGEL, TN	138	138	3	5.00	37.00	1	636KCM ACSR
65	0352 NAGEL, TN	REEDY CREEK, TN	138	138	3	0.00	5.00	1	556KCM ACSR
66	0365 DICKENS TAP		138	138	1	3.00	0.00	1	795KCM ACSR
67	0259A EAST DANVILLE, WV	EAST MONUMENT	138	138		4.00	0.00	0
68	0125 CLINCH RIVER, VA	MORELAND DRIVE, TN	138	138	3	49.00	0.00	1	636KCM ACSR
69	0148 CLINCH RIVER, VA	SALTVILLE #1A, VA	138	138	3	0.00	25.00	1	636KCM ACSR
70	0148 CLINCH RIVER, VA	SALTVILLE #1B, VA	138	138	3	26.00	0.00	1	1033KCM ACSR
71	0256 LEBANON 138KV TAP VA		138	138	1	0.00	0.00	1	336KCM ACSR
72	7539 DAN, VA	CAROLINA	138	138		0.00	0.00	0
73	0154 CLINCH RIVER, VA	SALTVILLE #2, VA	138	138	3	3.00	40.00	1	397KCM ACSR
74	0193 BROADFORD, VA	SALTVILLE NO.2, VA	138	138	3	5.00	0.00	2	795KCM ACSR
75	0191 BROADFORD, VA	NAGEL, TN	138	138	3	45.00	0.00	1	397KCM ACSR
76	0354 NAGEL, TN	WEST KINGSPORT, TN	138	138	3	0.00	5.00	1	1590KCM ACSR
77	0361 CLINCH RIVER, VA	SPRING CREEK, VA	138	138	3	18.00	4.00	1	636KCM ACSR
78	0192 NORTH BRISTOL, VA	SPRING CREEK, VA	138	138	3	0.00	9.00	1	795 KCM ACSR
79	0153 NORTH BRISTOL, VA	WEST KINGSPORT, VA	138	138	3	0.00	4.00	1	397KCM ACSR
80	0167 CLINCH RIVER, VA	GARDEN CREEK, VA	138	138	3	2.00	0.00	1	636KCM ACSR
81	0167 CLINCH RIVER, VA	GARDEN CREEK, VA	0	0	1	22.00	0.00	0
82	0298 FLETCHERS RIDGE TAP,VA		138	138	1	0.00	0.00	1	300KCM CU
83	0313 SKEGGS BRANCH, VA		138	138	1	0.00	0.00	1	397KCM ACSR
84	0167A CLINCHFIELD LOOP SITE		138	138	1	0.00	0.00	1	636KCM ACSR
85	0416 CLOVERDALE, VA	HUNTINGTON COURT, VA	138	138	3	6.00	0.00	1	795KCM ACSR
86	0124 CLOVERDALE, VA	SMITH MOUNTAIN, VA	138	138	3	32.00	0.00	1	556KCM ACSR
87	0141 DANVILLE B CIR, VA	EAST DANVILLE, VA	138	138	3	0.00	3.00	1	336KCM ACSR
88	1020 CLINCH RIVER	VIRGINA CITY	138	138		0.00	0.00	0
89	0358 AXTON, VA	DANVILLE #1-A, VA	138	138	3	0.00	16.00	1	336 KCM ACSR
90	0358 AXTON, VA	DANVILLE #1-A, VA	138	138	2	0.00	0.00	1	1033.5 ACSR
91	0359 AXTON, VA	MARTINSVILLE, VA	138	138	3	11.00	0.00	1	966KCM ACSR
92	0135 AXTON, VA	DANVILLE #2, VA	138	138	3	0.71	0.00	2	1033KCM ACSR
93	0135 AXTON, VA	DANVILLE #2, VA	138	138	2	16.57	0.00	1	1033KCM ACSR
94	0135 AXTON, VA	DANVILLE #2, VA	138	138	3	0.55	0.00	2	795KCM SSAC
95	0135 AXTON, VA	DANVILLE #2, VA	138	138	2	0.32	0.00	1	795KCM SSAC
96	0146 FIELDDALE, VA	RIDGEWAY, VA	138	138	1	10.00	0.00	1	397KCM ACSR
97	0300 DAN RIVER, NC	RIDGEWAY, VA	138	138	2	4.00	0.00	1	397KCM ACSR
98	0300 DAN RIVER, NC	RIDGEWAY, VA	138	138	1	0.00	0.00	1	397KCM ACSR
99	0300 DAN RIVER, NC	RIDGEWAY, VA	138	138	1	0.00	0.00	1	1033KCM ACSR
100	0391 SHEFFIELD LOOP		138	138	3	0.00	0.00	1	795KCM ACSR
101	0025 GLEN LYN, VA	SOUTH PRINCETON, WV	138	138	3	0.00	0.00	1	1590KCM ACSR
102	0058 GLEN LYN, VA	WYTHE, VA	138	138	3	29.00	0.00	1	556KCM ACSR
103	0058 GLEN LYN, VA	WYTHE, VA	0	0		1.00	0.00	0	1590KCM ACSR
104	0058 GLEN LYN, VA	WYTHE, VA	138	138	3	1.00	29.00	1	556KCM ACSR
105	0375 PROGRESS PARK EXT		138	138	3	3.00	0.00	1	1590KCM ACSR
106	0427 EVINGTON 138KV TAP VA		138	138	2	0.00	0.00	0	397KCM ACSR
107	0063 BROADFORD, VA	SALTVILLE NO.1A&1B, VA	138	138	3	4.00	4.00	2	795KCM ACSR
108	0063 BROADFORD, VA	SALTVILLE NO.1A&1B, VA	138	138	3	0.00	4.00	2	556KCM ACSR
109	0063 BROADFORD, VA	SALTVILLE NO.1A&1B, VA	138	138	1	0.00	0.00	2	795KCM ACSR
110	0061B RURAL RETREAT	LOOP, WV	138	138	3	0.00	0.00	1	795KCM ACSR
111	0333 BROADFORD, VA	RICHLANDS, VA	138	138	2	14.00	0.00	1	1033KCM ACSR
112	0368 CLAY POOL HILL LOOP,VA		138	138	1	0.00	0.00	1	1033KCM ACSR
113	0241A HUFFMAN, VA	JACKSONS FERRY, VA	138	138	3	0.00	2.00	1	1033KCM ACSR
114	0241A HUFFMAN, VA	JACKSONS FERRY, VA	0	0	1	8.00	0.00	0
115	0241 HUFFMAN, VA	WYTHE, VA	138	138	3	2.00	1.00	1	795KCM ACSR
116	0241 HUFFMAN, VA	WYTHE, VA	138	138	1	37.00	0.00	1	795KCM ACSR
117	0061 ATKINS, VA	BROADFORD CIR A, VA	138	138	3	20.00	0.00	1	556KCM ACSR
118	0061 ATKINS, VA	BROADFORD CIR B, VA	138	138	3	0.00	16.00	1	556KCM ACSR
119	0063 ATKINS, VA	WYTHE CIR A, VA	138	138	3	22.00	0.00	1	1590KCM ACSR
120	0063 ATKINS, VA	WYTHE CIR B, VA	138	138	3	0.00	21.00	1	556KCM ACSR
121	0433 HUFFMAN, VA	WILLIS GAP, VA	138	138	1	14.00	0.00	1	1033KCM ACSR
122	0106 CLAYTOR, VA	GLEN LYN #1, VA	138	138	3	26.00	0.00	1	397KCM ACSR
123	0106 CLAYTOR, VA	GLEN LYN #2, VA	138	138	3	0.00	26.00	1	397KCM ACSR
124	0109 MORGANS CUT LOOP, VA		138	138	3	0.00	0.00	1	397KCM ACSR
125	0117 HANCOCK, VA	MATT FUNK, VA	138	138	3	11.00	0.00	1	556KCM ACSR
126	0118 CLOVERDALE, VA	MATT FUNK, VA	138	138	3	0.00	21.00	1	636KCM ACSR
127	0119 CLOVERDALE, VA	GLEN LYN, VA	138	138	3	20.00	39.00	1	556KCM ACSR
128	0119 CLOVERDALE, VA	GLEN LYN, VA	138	138	1	0.00	0.00	1	556KCM ACSR
129	0119 CLOVERDALE, VA	GLEN LYN, VA	138	138	3	0.00	0.00	2	795KCM ACSR
130	0374 PATRIOT CENTRE EXT		138	138	3	3.00	0.00	1	795KCM ACSR
131	0367 BURLINGTON HEIGHTS LOO		138	138	3	0.00	0.00	1	795KCM ACSR
132	0383 WEST SALEM LOOP, VA		138	138	3	0.00	0.00	1	795KCM ACSR
133	0116 CELANESE, VA	GLEN LYN, VA	138	138	3	4.00	0.00	1	556KCM ACSR
134	0116 CELANESE, VA	GLEN LYN, VA	0	0	1	4.00	0.00	0
135	0462 MATT FUNK EXT		138	138	3	5.00	0.00	0	1590 KCM ACSR
136	0115 CELANESE, VA	MATT FUNK, VA	138	138	3	34.00	0.00	1	556KCM ACSR
137	0115 CELANESE, VA	MATT FUNK, VA	138	138	1	2.00	0.00	1	556KCM ACSR
138	0115 CELANESE, VA	MATT FUNK, VA	138	138	3	0.00	0.00	2	1033KCM ACSR
139	0038 BRADLEY CIR-A, WV	GLEN LYN-HINTON, VA	138	138	3	0.00	4.00	1	556KCM ACSR
140	0224 BRADLEY CIR-B, WV	GLEN LYN-HINTON	138	138	3	4.00	0.00	1	556KCM ACSR
141	0145 ALTAVISTA, VA	REUSENS, VA	138	138	3	5.00	0.00	1	397KCM ACSR
142	0145 ALTAVISTA, VA	REUSENS, VA	138	138	2	20.00	0.00	1	397KCM ACSR
143	0311 OPOSSUM CREEK, VA	REUSENS, VA	138	138	3	9.00	5.00	1	397KCM ACSR
144	0311 OPOSSUM CREEK, VA	REUSENS, VA	138	138	1	0.00	0.00	2	1033KCM ACSR
145	0312 BRUSH TAVERN TAP, VA		138	138	1	3.00	0.00	1	556KCM ACSR
146	0145A BOONSBORO LOOP, VA		138	138	3	0.00	0.00	1	397KCM ACSR
147	0394 GRAVES MILLS LOOP, VA		138	138	3	0.00	0.00	1	795KCM ACSR
148	7119 HANCOCK, VA	ROANOKE, VA TOWER 198	138	138		0.00	0.00	0
149	0156A CLIFFORD, VA	REUSENS, VA	138	138	3	23.00	4.00	1	795KCM ACSR
150	0156 CLIFFORD, VA	SCOTTSVILLE, VA	138	138	3	29.00	0.00	1	397KCM ACSR
151	0156B BREMO, VA	SCOTTSVILLE, VA	138	138	3	7.00	0.00	1	397KCM ACSR
152	0170 OPOSSUM CREEK, VA	SMITH MOUNTAIN, VA	138	138	3	15.00	0.00	1	556KCM ACSR
153	0170 OPOSSUM CREEK, VA	SMITH MOUNTAIN, VA	0	0	1	19.00	0.00	0
154	0170 LEESVILLE, VA	SMITH MOUNTAIN, VA	138	138	3	0.00	8.00	1	556KCM ACSR
155	0173 ALTAVISTA, VA	LEESVILLE, VA	138	138	3	0.00	5.00	1	556KCM ACSR
156	0173 ALTAVISTA, VA	LEESVILLE, VA	0	0	1	3.00	0.00	0
157	0258 OPOSSUM CREEK, VA	PEAKSVIEW, VA	138	138	1	0.00	0.00	1	556KCM ACSR
158	0258 OPOSSUM CREEK, VA	PEAKSVIEW, VA	138	138	2	1.00	0.00	1	556KCM ACSR
159	0258 OPOSSUM CREEK, VA	PEAKSVIEW, VA	138	138	3	0.00	0.00	1	556KCM ACSR
160	0309 EAST LYNCHBURG, VA	OPOSSUM CREEK, VA	138	138	3	3.00	0.00	1	1590KCM ACSR
161	0322 JOSHUA FALLS, VA	REUSENS A&B, VA	138	138	3	7.00	0.00	2	556KCM ACSR
162	0322 JOSHUA FALLS, VA	REUSENS A&B, VA	138	138	3	0.00	0.00	2	1590KCM ACSR
163	0322 JOSHUA FALLS, VA	REUSENS A&B, VA	138	138	3	3.00	0.00	1	1590KCM ACSR
164	0322 JOSHUA FALLS, VA	REUSENS A&B, VA	138	138	1	0.00	0.00	1	1590KCM ACSR
165	0322 JOSHUA FALLS, VA	REUSENS A&B, VA	138	138	1	0.00	0.00	2	1590KCM ACSR
166	0321 JOSHUA FALLS, VA	OPOSSUM CREEK, VA	138	138	3	0.00	7.00	1	1590KCM ACSR
167	0320 EAST LYNCHBURG, VA	JOSHUA FALLS, VA	138	138	3	3.00	0.00	2	1590KCM ACSR
168	0320 EAST LYNCHBURG, VA	JOSHUA FALLS, VA	138	138	1	1.00	0.00	1	1590KCM ACSR
169	0366 RUSTBURG TAP, VA		138	138	1	4.00	0.00	1	795KCM ACSR
170	0395 MONEL LOOP, VA		138	138	3	0.00	0.00	1	1590KCM ACSR
171	0399 TANK HILL TAP, VA		138	138	1	1.00	0.00	1	795KCM ACSR
172	0161 CLOVERDALE, VA	ROANOKE, VA	138	138	3	16.00	0.00	1	556KCM ACSR
173	0161 CLOVERDALE, VA	ROANOKE, VA	0	0	3	1.00	0.00	0	795KCM ACSR
174	0160 CLOVERDALE, VA	REUSENS, VA	138	138	3	36.00	8.00	1	397KCM ACSR
175	0160 CLOVERDALE, VA	REUSENS, VA	138	138	1	1.00	0.00	0	636 KCM ACSR
176	MOSELEY, VA	REUSENS, VA	138	138	3	0.00	22.00	1	397KCM ACSR
177	0163 MOSELEY, VA	ROANOKE, VA	138	138	3	1.00	20.00	1	795KCM ACSR
178	0421 MOUNT UNION	CLOVERDALE	138	138	2	7.00	0.00	1	795KCM ACSR
179	0292 VINTON LOOP, VA		138	138	3	0.00	0.00	1	795KCM ACSR
180	0396 BONSACK LOOP, VA		138	138	3	0.00	0.00	1	795KCM ACSR
181	0168 EAST DANVILLE, VA	SMITH MOUNTAIN, VA	138	138	3	32.00	0.00	1	556KCM ACSR
182	0168A BEARSKIN TAP, VA		138	138	3	0.00	0.00	1	556KCM ACSR
183	0419 PENHOOK, VA	SMITH MOUNTAIN, VA	138	138	3	7.00	0.00	1	1033KCM ACSR
184	0371 PENHOOK, VA	WESTLAKE	138	138	1	15.00	0.00	1	1033KCM ACSR
185	0371 PENHOOK, VA	WESTLAKE	138	138	1	0.00	0.00	2	1033KCM ACSR
186	0369 BLAINE, VA	WESTLAKE	138	138	3	11.00	0.00	1	1033.5 KCM ACSR
187	0423 STONEWALL TAP		69	138	1	8.00	0.00	1
188	0423 STONEWALL TAP		0	0	3	1.00	0.00	0	795 KCM ACSR
189	0259 REGIS, VA	MONUMENT, VA	138	138	1	2.00	1.00	1	795KCM ACSR
190	0266 HANCOCK, VA	ROANOKE ELECTRIC STEEL, VA	138	138	3	1.00	0.00	1	795KCM ACSR
191	0266 HANCOCK, VA	ROANOKE ELECTRIC STEEL, VA	0	0	1	0.00	0.00	0
192	0042 SALTVILLE, VA	TAZEWELL, VA	138	138	3	21.00	0.00	1	1272KCM ACSR
193	0042 SALTVILLE, VA	TAZEWELL, VA	138	138	3	0.00	21.00	1	397KCM ACSR
194	0042 SALTVILLE, VA	TAZEWELL, VA	138	138	1	0.00	0.00	1	1033KCM ACSR
195	0270 BLUEFIELD, WV	TAZEWELL, VA	138	138	1	20.00	0.00	1	795KCM ACSR
196	0270 BLUEFIELD, WV	TAZEWELL, VA	138	138	2	0.00	0.00	1	1033KCM ACSR
197	BAILEYSVILLE, WV	TAZEWELL, VA	138	138	3	9.00	0.00	1	397KCM ACSR
198	BAILEYSVILLE, WV	TAZEWELL, VA	138	138	3	0.00	9.00	1	397KCM ACSR
199	0338 BLUEFIELD, VA	SOUTH PRINCETON, VA	138	138	1	6.00	0.00	1	556KCM ACSR
200	0414 RIVERVILLE TAP, VA		138	138	3	0.00	0.00	1	795KCM ACSR
201	0132 ROANOKE	CAROLINA	138	138	1	9.00	0.00	0
202	0132 ROANOKE	CAROLINA	138	138	3	44.00	57.00	1	795KCM ACSR
203	0385 CAPITALIZED SPARE PART	MAX MEADOW	138	138		0.00	0.00	1
204	1004 KEYWOOD TAP		138	138	1	0.00	0.00	0
205	0467 CLEARBROOK, VA	MATT FUNK, VA	138	138	1	0.00	0.00	1	1590KCM ACSR
206	0380 FALLING BRANCH	MERRIMAC	138	138	1	6.00	0.00	1	1033 KCM ACSR
207	0380 FALLING BRANCH	MERRIMAC	138	138	1	1.00	0.00	1	1033 KCM ACSR
208	0380 FALLING BRANCH	MERRIMAC	69	138	1	1.00	0.00	1	1033 KCM ACSR
209	0381 LAKE FOREST, VA		138	138	3	3.00	0.00	2	1590KCM ACSR
210	0464 HUNTINGTON COURT	ROANOKE	138	138	1	6.00	0.00	1	795 ACSR
211	0464 HUNTINGTON COURT	ROANOKE	138	138	1	0.00	0.00	1	1590KCM ACSR
212	0465 SUNSCAPE		138	138	1	1.00	0.00	2	1590KCM ACSR
213	0470 LOCKHART, VA		138	138	3	0.00	0.00	1	795KCM ACSR
214	0435 DUTY, VA	138KV EXTENSION	138	138		0.00	0.00	1
215	0388 TECH DRIVE	138KV EXTENSION	138	138	3	0.00	0.00	1	1590 KCM ACSR
216	0484 HORSEPEN	138KV EXTENSION	138	138		0.00	0.00	0
217	0485 JACKSONS FERRY	WYTHE	138	138	2	5.00	0.00	1	1590KCM ACSR/MA2
218	0485 JACKSONS FERRY	WYTHE	138	138	3	13.00	0.00	2	1590KCM ACSR/MA2
219	0502 PROGRESS PARK TAP		138	138	2	1.00	0.00	1	1590KCM ACSR/MA2
220	0502 PROGRESS PARK TAP		138	138	1	0.00	0.00	1	1590KCM ACSR/MA2
221	0512 CLOVERDALE 765	CLOVERDALE 138	345	345	3	0.00	0.00	1	1590KCM ACSS
222	0508 CLOVERDALE EAST	CLOVERDALE TIE LINE NO 2	345	345	1	0.00	0.00	1	2-1926.9KCM ACSR/
223	0509 CLOVERDALE 765	CLOVERDALE EAST	500	500	2	0.00	0.00	1	4-954KCM ACSR
224	0516 RICHLANDS	WHITEWOOD	138	138	2	8.00	0.00	1	1033.5KCM ACSR
225	0513 WHITEWOOD EXT		138	138	1	1.00	0.00	2	1033.5KCM ACSR
226	0513 WHITEWOOD EXT		138	138	3	0.00	0.00	2	1033.5KCM ACSR
227	0519 OWENS DRIVE EXT		69	138	1	2.00	0.00	1	795KCM ACSR
228	0459 GEORGE STREET	LYNBROOK	138	138	1	1.00	0.00	1	1233.6KCM ACSR/TW
229	0459 GEORGE STREET	LYNBROOK	138	138	2	2.00	0.00	1	1233.6KCM ACSR/TW
230	0110A FALLING BRANCH	LOOP	138	138	2	1.00	0.00	1	556.5 KCM 26/7 AC
231	0460 BRUSH TAVERN	LYNBROOK	138	138	1	4.00	0.00	1	1233.6KCM ACSR/TW
232	0501 JACKSONS FERRY	BUS TIE #3	138	138	1	0.00	0.00	1	1590 KCM ACSR
233	0461 George Street	South Lynchburg	138	138	1	3.00	0.00	1	1233.6KCM ACSR/TW
234	0461 George Street	South Lynchburg	138	138	2	0.00	0.00	1	1233.6KCM ACSR/TW
235	0507 Cloverdale East	Cloverdale Tie Line No. 1	345	345	1	0.00	0.00	1	2 - 1926.9 KCM AC
236	0517 Town Creek	Progress Park	138	138	1	3.00	0.00	1	1033.5KCM ACSR
237	0517 Town Creek	Progress Park	138	138	2	7.00	0.00	1	1033.5KCM ACSR
238	0517 Town Creek	Progress Park	138	138	3	3.00	0.00	1	1033.5KCM ACSR
239	0518 TOWN CREEK	SOUTH BLUEFIELD	138	138	1	1.00	0.00	1	1033.5KCM ACSR
240	0518 TOWN CREEK	SOUTH BLUEFIELD	138	138	2	1.00	0.00	1	1033.5KCM ACSR
241	0518 TOWN CREEK	SOUTH BLUEFIELD	138	138	3	10.00	0.00	1	1033.5KCM ACSR
242	0514 BEARWALLOW	FARADAY	138	138	2	2.00	0.00	1	1033.5KCM ACSR
243	0515 FARADAY	TAZEWELL	138	138	2	7.00	0.00	1	1033.5KCM ACSR
244	0545 Tazewell Bus Tie No 1		138	138	1	0.00	0.00	1	1033.5KCM ACSR
245	0569 HINTON	WEST VACO (VA)	138	138	3	0.00	0.00	1	336KCM ACSR
246	0522 SOUTH ABINGDON EXT		138	138	1	4.00	0.00	2	1033.5KCM ACSR
247	0524 Joshua Falls 765/138kV Bus Tie No. 1		138	138	1	0.00	0.00	1	1590KCM ACSR
248	0541 IRONTO EXTENSION		138	138	1	0.00	0.00	2	1033.5KCM ACSR
249	0537 WOLF GLADE EXTENSION		138	138	1	2.00	0.00	2	795KCM ACSR
250	0567 Glenmary Extension		138	138	3	0.00	0.00	2	795KCM ACSR
251	0581 Museville Extension		138	138	1	0.00	0.00	2	1272 ACSS
252	0538 Elk Garden Tap		138	138	1	0.00	0.00	1	1590KCM ACSR
253	0538 Elk Garden Tap		138	138	2	0.00	0.00	1	336KCM ACSR
254	0571 Garden Creek	Baileysville (VA)	138	138	2	13.00	0.00	1	636KCM ACSR
255	0578 Redeye Extension		138	138	1	0.00	0.00	2	795KCM ACSR
256	0566 Berry Hill Extension		138	138	1	5.00	0.00	2	1033 KCM ACSR
257	0584 Wythe County Solar Farm Extension		138	138	1	0.08	0.00	1	556KCM ACSR
258	STATE OF WEST VIRGINIA	STATE OF WEST VIRGINIA				0.00	0.00
259	0276 AMOS, WV	HANGING ROCK, H	765	765	3	25.00	0.00	1	954KCM ACSR
260	0297 GAVIN, OH	MOUNTAINEER, WV	765	765	3	8.00	0.00	1	1351KCM ACSR
261	0296 KAMMER, WV	MOUNTAINEER, WV	765	765	3	19.00	0.00	1	1351KCM ACSR
262	0296 KAMMER, WV	MOUNTAINEER, WV	0	0	3	95.00	0.00	0
263	0183 AMOS, WV	CULLODEN, WV	765	765	3	15.00	0.00	1	954KCM ACSR
264	0183A BAKER, KY	CULLODEN, WV	765	765	3	34.00	0.00	1	954KCM ACSR
265	0324 CULLODEN, WV	WYOMING, WV	765	765	3	58.00	0.00	1	1351KCM ACSR
266	0344 CULLODEN, WV	GAVIN, OH	765	765	3	42.00	0.00	1	1351KCM ACSR
267	0405 JACKSONS FERRY	WYOMING	765	765	3	32.00	0.00	1	795KCM ACSR
268	0295 AMOS, WV	MOUNTAINEER, WV	765	765	3	47.00	0.00	1	1351KCM ACSR
269	0185 BAKER, KY	BROADFORD, VA	765	765	3	4.00	0.00	1	954KCM ACSR
270	0263 AMOS, WV	GAVIN	765	765		0.00	0.00	1
271	0012 BAKER, KY	TRI STATE, WV	345	345	3	6.00	0.00	1	954KCM ACSR
272	0003 KYGER CREEK, OH	SPORN, WV	345	345	3	12.00	0.00	1	1414KCM ACSR
273	0003 KYGER CREEK, OH	SPORN, WV	345	345	1	0.00	0.00	1	1272 ACSS
274	0004 MUSKINGUM, WV	SPORN, WV	345	345	3	0.00	2.00	1	1275KCM ACSR
275	0004 MUSKINGUM, WV	SPORN, WV	345	345	1	2.00	0.00	2	959.6 KCM ACSS
276	0005 KANAWHA, WV	MATT FUNK, VA	345	345	3	1.00	0.00	1	2156KCM ACSR
277	0005 KANAWHA, WV	MATT FUNK, VA	345	345	3	64.00	0.00	1	2-954KCM ACSR
278	0218 AMOS, WV	SPORN, WV	345	345	3	46.00	0.00	1	1563KCM ACSR
279	0006 KANAWHA, WV	SPORN, WV	345	345	3	0.00	62.00	1	1414KCM ACSR
280	0006A AMOS, WV	KANAWHA, WV	345	345	3	28.00	12.00	1	1563KCM ACSR
281	0011 KYGER CREEK, WV	TRI-STATE, WV	345	345	3	63.00	0.00	0	2303KCM ACSR
282	0011 KYGER CREEK, WV	TRI-STATE, WV	345	345	2	0.00	0.00	0	2303KCM ACSR
283	0228A BETH TAP WV		138	138	1	1.00	0.00	1	336KCM ACSR
284	0053 BAILEYSVILLE, WV	HALES BRANCH, VA	138	138	3	0.00	0.00	2	636KCM ACSR
285	0308 PAD FORK LOOP, WV		138	138	1	0.00	0.00	1	397KCM ACSR
286	0330 JIM BRANCH, WV	WYOMING, WV	138	138	3	7.00	0.00	1	1590KCM ACSR
287	0330 JIM BRANCH, WV	WYOMING, WV	0	0	1	16.00	0.00	0
288	0210 BAILYESVILLE, WV	WYOMING, WV	138	138	3	0.00	5.00	1	1590KCM ACSR
289	0332 WELCH TAP, WV		138	138	1	0.00	0.00	1	795KCM ACSR
290	0053 BAILEYSVILLE, WV	HALES BRANCH, VA	138	138	1	21.00	0.00	1	636KCM ACSR
291	0035 STOTESBURY TAP, WV		138	138	1	0.00	0.00	1	795KCM ACSR
292	0035 STOTESBURY TAP, WV		138	138	2	6.00	0.00	1	795KCM ACSR
293	0211 MULLENSVILLE LOOP, WV		138	138	3	1.00	1.00	1	556KCM ACSR
294	0212 PINNACLE CREEK LOOP, W		138	138	3	3.00	3.00	1	556KCM ACSR
295	0294 NORTH BECKLEY LOOP, WV		138	138	3	1.00	1.00	1	556KCM ACSR
296	0210 BAILEYSVILLE, WV	WYOMING, WV	138	138	3	0.00	6.00	1	1590KCM ACSR
297	MULLENS, WV	WYOMING, WV	138	138	3	6.00	0.00	1	556KCM ACSR
298	MULLENS, WV	WYOMING, WV	0	0	1	17.00	0.00	0
299	0356 PEMBERTON TAP, WV		138	138	1	0.00	0.00	1	336KCM ACSR
300	0356 PEMBERTON TAP, WV		138	138	2	1.00	0.00	1	336KCM ACSR
301	0356 PEMBERTON TAP, WV		138	138	3	1.00	0.00	1	336KCM ACSR
302	0216B BRADLEY, WV	TAMS MOUNTAIN, WV	138	138	1	1.00	0.00	1	556KCM ACSR
303	0216B BRADLEY, WV	TAMS MOUNTAIN, WV	138	138	2	14.00	0.00	1	556KCM ACSR
304	0216B BRADLEY, WV	TAMS MOUNTAIN, WV	138	138	3	1.00	0.00	1	556KCM ACSR
305	0216 MULLENS, WV	TAMS MOUNTAIN, WV	138	138	2	9.00	0.00	1	556KCM ACSR
306	0216 MULLENS, WV	TAMS MOUNTAIN, WV	138	138	1	0.00	0.00	0	556KCM ACSR
307	0094 BIG SANDY, KY	DEWEY, KY	138	138	3	0.00	0.00	1	636KCM ACSR
308	0426 BIG SANDY, KY	INEZ A&B, KY	138	138	3	8.00	0.00	1	795KCM ACSR
309	0092 BELLEFONTE, KY	TRI STATE, WV	138	138	3	4.00	0.00	1	795KCM ACSR
310	0429 MIDKIFF, WV	TRI STATE, WV	138	138	1	26.00	0.00	1	795KCM ACSR
311	0028 CABIN CREEK, WV	KANAWHA #1, WV	138	138	3	0.00	3.00	1	556KICM ACSR
312	0029 CABIN CREEK, WV	KANAWHA #2, WV	138	138	3	3.00	0.00	1	556KCM ACSR
313	0098 CAPITOL HILL, WV	KANAWHA, WV	138	138	3	18.00	0.00	1	556KCM ACSR
314	0098 CAPITOL HILL, WV	KANAWHA, WV	138	138	3	3.00	0.00	1	556KCM ACSS
315	0326 RENSFORD LOOP, WV	KANAWHA, WV	138	138	3	1.00	0.00	1	556KCM ACSR
316	0098A FLATWOOD TAP, WV		138	138	3	5.00	0.00	1	795KCM ACSR
317	0245 GILBOA, WV	KANAWHA, WV	138	138	3	0.00	0.00	1	795KCM ACSR
318	0245 GILBOA, WV	KANAWHA, WV	0	0	1	15.00	0.00	0
319	0390 BELVA TAP, WV		138	138	3	1.00	1.00	1	954KCM ACSR
320	0372 JEHU EXT WV		138	138	3	1.00	0.00	1	556KCM ACSR
321	0097 CAPITOL HILL, WV	CHEMICAL, WV	138	138	3	6.00	0.00	2	556KCM ACSR
322	0097 CAPITOL HILL, WV	CHEMICAL, WV	138	138	3	0.00	0.00	1	1272KCM ACSS
323	0101 DEXTER, WV	SPORN CIR B, OH	138	138	3	9.00	0.00	1	397KCM ACSR
324	0101 DEXTER, WV	SPORN CIR B, OH	138	138	1	0.00	0.00	1	397KCM ACSR
325	0104 BANCROFT TAP, WV		138	138	3	1.00	0.00	1	556KCM ACSR
326	0101 DEXTER, OH	SPORN CIR A, WV	138	138	3	0.00	9.00	1	397KCM ACSR
327	0225A LEON LOOP, WV		138	138	3	0.00	0.00	1	1033KCM ACSR
328	AMERICAN ALLOYS, WV	SPORN, WV	138	138	3	0.00	0.00	1	556KCM ACSR
329	0402 SISSON TAP, WV		138	138	3	10.00	1.00	1	795KCM ACSR
330	0402 SISSON TAP, WV		0	0	1	0.00	0.00	0
331	0225 AMOS, WV	SOUTH BUFFALO CIR B, WV	138	138	3	12.00	6.00	1	397KCM ACSR
332	0225 SOUTH BUFFALO, WV	SPORN CIR A, WV	138	138	3	0.00	31.00	1	397KCM ACSR
333	0225 SOUTH BUFFALO, WV	SPORN CIR B WV	138	138	3	36.00	0.00	1	1351KCM ACSR
334	0023 MINNIX MOUNTAIN LOOP		138	138	3	0.00	0.00	1	1033KCM ACSR
335	0024 SPEEDWAY TAP, WV		138	138	3	0.00	0.00	1	556KCM ACSR
336	0024 SPEEDWAY TAP, WV		0	0	1	7.00	0.00	0
337	0020 GLEN LYN, VA	SOUTH PRINCETON, WV	138	138	3	13.00	0.00	1	397KCM ACSR
338	0424 GLEN LYN, VA	SOUTH PRINCETON, WV	138	138	3	0.00	13.00	1	1351KCM ACSR
339	0020A SOUTH PRINCETON, WV	SWITCHBACK A, WV	138	138	3	15.00	0.00	1	397KCM ACSR
340	0020B SOUTH PRINCETON, WV	SWITCHBACK B, WV	138	138	3	0.00	15.00	1	397KCM ACSR
341	0055 GLEN LYN, VA	WYTHE, VA	138	138	3	1.00	0.00	1	556KCM ACSR
342	0055 GLEN LYN, VA	WYTHE, VA	138	138	3	0.00	1.00	1	556KCM ACSR
343	0093 BIG SANDY	WEST HUNTINGTON, WV	138	138	2	0.00	0.00	2	1780KCM ACSR
344	0093 BIG SANDY	WEST HUNTINGTON, WV	138	138	3	3.00	0.00	1	1351KCM ACSR
345	0093 BIG SANDY	WEST HUNGINGTON, WV	0	0	3	16.00	0.00	0
346	0031 BRADLEY, WV	KANAWHA #1, WV	138	138	3	0.00	27.00	1	556KCM ACSR
347	0222 BRADLEY, WV	KANAWHA #2, WV	138	138	3	27.00	0.00	1	556KCM ACSR
348	0032 BRADLEY CIR A, WV	GLEN LYN-HINTON, VA	138	138	3	0.00	41.00	1	556KCM ACSR
349	0223 BRADLEY CIR B, WV	GLEN LYN-HINTON, VA	138	138	3	43.00	2.00	1	1590KCM ACSR
350	0219 KINCAID LOOP, WV		138	138	3	0.00	0.00	1	556KCM ACSR
351	0246 BRADLEY, WV	DAMERON, WV	138	138	1	10.00	0.00	1	795KCM ACSR
352	0415 CLIFFTOP TAP, WV		138	138	3	3.00	0.00	1	795KCM ACSR
353	0049 BAILEYSVILLE, WV	KANAWHA #1, WV	138	138	3	46.00	0.00	1	636KCM ACSR
354	0049 BAILEYSVILLE, WV	KANAWHA #2, WV	138	138	3	0.00	46.00	1	636KCM ACSR
355	0049 BAILEYSVILLE, WV	KANAWHA #2, WV	0	0	1	0.00	0.00	0
356	0052 BIM TAP, WV		138	138	1,3	12.00	0.00	1	556KCM ACSR
357	3827 BRADLEY	LAYLAND	69	138	1	12.00	0.00	1
358	3484 COBB TAP		46	138	1	0.00	0.00	1
359	0420 FRANKS BRANCH		46	138	1	5.00	0.00	1
360	2123 SOUTH NEAL	WEST HUNTINGTON	69	138	3	2.00	0.00	1
361	0220 KOPPERSTON LOOP, WV		138	138	3	0.00	0.00	1	1033KCM ACSR
362	0243 BOLT TAP, WV		138	138	1	6.00	0.00	1	795KCM ACSR
363	0301 WHARTON TAP, WV		138	138	1	0.00	0.00	1	556KCM ACSR
364	0384 HINTON	WESTVACO, WV	138	138	3	13.00	0.00	1	556KCM ACSR
365	0384 HINTON	WESTVACO, WV	138	138	3	23.00	0.00	1	336KCM ACSR
366	0389 GREENBRIER LOOP, WV		138	138	3	0.00	0.00	1	246KCM ACAR
367	0393 RONCEVERTE LOOP, WV		138	138	3	0.00	0.00	1	4/0 ACSR
368	0357 GRASSY FALLS, WV	MCCLUNG, WV	138	138	1	0.00	0.00	1	954KCM ACSR
369	0304 RUM CREEK TAP, WV		138	138	1	2.00	0.00	1	556KCM ACSR
370	0318 M&B TAP, WV		138	138	1	0.00	0.00	1	556KCM ACSR
371	0013 LOGAN, WV	WYOMING #1-A, WV	138	138	3	12.00	14.00	1	1590KCM ACSR
372	0013 LOGAN, WV	WYOMING #1-B, WV	138	138	3	22.00	0.00	1	1590KCM ACSR
373	0387 LOGAN, WV	WYOMING #2, WV	138	138	3	23.00	0.00	1	1033KCM ACSR
374	0387 LOGAN, WV	WYOMING #2, WV	138	138	2	0.00	0.00	1	1033KCM ACSR
375	0045 LOGAN, WV	SPRIGG #1 & #2, WV	138	138	3	18.00	0.00	2	397KCM ACSR
376	3791 BOLT, WV	TRAP HILL, WV	46	138	1	6.00	0.00	1
377	0048 CHAUNCEY TAP, WV		138	138	3	4.00	0.00	1	397KCM ACSR
378	0328 RAGLAND LOOP, WV		138	138	1	1.00	0.00	1	556KCM ACSR
379	0317 GRANT BRANCH TAP, WV		138	138	1	7.00	0.00	1	556KCM ACSR
380	0346 PINE CREEK TAP, WV		138	138	1	2.00	0.00	1	556KCM ACSR
381	0401 HATFIELD, WV	SPRIGG, WV	138	138	1	11.00	0.00	1	1033KCM ACSR
382	0401A CINDERELLA LOOP, WV		138	138	3	0.00	0.00	1	1035KCM ACSR
383	0325 JIM BRANCH, WV	SWITCHBACK, WV	138	138	2	18.00	1.00	1	1033KCM ACSR
384	0077 MILLBROOK, OH	SPORN, WV	138	138	3	9.00	0.00	1	477KCM ACSR
385	0077 MILLBROOK, OH	SPORN, WV	138	138	1	0.25	0.00	1	477KCM ACSR
386	0077A ADDISON LICK, WV	SPORN, WV	138	138	3	0.00	9.00	1	477KCM ACSR
387	0075 SOUTH POINT, OH	SPORN, WV	138	138	3	10.00	0.00	1	397KCM ACSR
388	0075 SOUTH POINT, OH	SPORN, WV	138	138	1	1.00	0.00	1	397KCM ACSR
389	NORTH PROCTORVILLE, OH	SPORN, WV	138	138	3	0.00	10.00	1	397KCM ACSR
390	0076 DARRAH, WV	NORTH PROCTORVILLE, OH	138	138	3	2.00	0.00	1	795KCM ACSR
391	0076 DARRAH, WV	NORTH PROCTORVILLE, OH	138	138	3	0.00	2.00	1	556KCM ACSR
392	0081 RAVENSWOOD, WV	SPORN #1, WV	138	138	3	1.00	0.00	1	795KCM ACSR
393	0081 RAVENSWOOD, WV	SPORN #2, WV	138	138	3	0.00	1.00	1	795KCM ACSR
394	0083 RAVENSWOOD, WV	SPORN #3, WV	138	138	3	1.00	0.00	1	795KCM ACSR
395	0083 RAVENSWOOD, WV	SPORN #4, WV	138	138	3	0.00	1.00	1	795KCM ACSR
396	0247 EAST HUNTINGTON, WV	NORTH PROCTORVILLE, OH	138	138	3	1.00	0.00	1	795KCMACSR
397	0067 JOHNS CREEK, KY	SPRIGG, WV	138	138	1	1.00	0.00	1	397KCM ACSR
398	0271 BLUEFIELD, WV	TAZEWELL, VA	138	138	1	1.00	0.00	1	795KCM ACSR
399	0017 BAILEYSVILLE, WV	TAZEWELL, VA	138	138	3	31.00	0.00	1	1590KCM ACSR
400	0016 BAILEYSVILLE, WV	TAZEWELL, VA	138	138	3	3.00	28.00	1	397KCM ACSR
401	0016A CARSWELL TAP, WV		138	138	3	1.00	1.00	1	397KCM ACSR
402	0069 CABIN CREEK, WV	TURNER #1 CIR A, WV	138	138	3	23.00	0.00	1	336KCM ACSR
403	0070 CABIN CREEK, WV	TURNER #1 CIR B. WV	138	138	3	5.00	19.00	1	1590KCM ACSR/MA
404	0194 CHESTERFIELD TAP, WV		138	138		0.00	0.00	0
405	0071 CABIN CREEK, WV	TURNER #2, WV	138	138	3	0.00	1.00	1	250KCM ACSR
406	0071 CABIN CREEK, WV	TURNER #2, WV	0	0	1	22.00	0.00	0
407	0268 ST ALBANS LOOP, WV		138	138	3	0.00	0.00	1	1033KCM ACSR
408	0230 AMOS, WV	TURNER #1, WV	138	138	3	12.00	0.00	1	1033KCM ACSR
409	0230 AMOS, WV	TURNER #2, WV	138	138	3	0.00	12.00	1	1033KCM ACSR
410	0226 AMOS, WV	CHEMICAL #1 A, WV	138	138	3	1.00	8.00	1	397KCM ACSR
411	0226 AMOS, WV	CHEMICAL #1 B, WV	138	138	3	6.00	0.00	1	1033KCM ACSR
412	0226 AMOS, WV	CHEMICAL #2 A, WV	138	138	3	8.00	9.00	1	1033KCM ACSR
413	0226 AMOS, WV	CHEMICAL #2 B, WV	138	138	3	0.00	4.00	1	397KCM ACSR
414	0226 AMOS, WV	CHEMICAL 1A-2A AND 1B-2B	138	138	3	1.00	0.00	2	1033 KCM ACSR
415	0343 STONE BRANCH TAP, WV		138	138	1	6.00	0.00	1	795KCM ACSR
416	HOPKINS, WV	LOGAN, WV	138	138	3	8.00	11.00	1	336KCM ACSR
417	HOPKINS, WV	LOGAN, WV	138	138	3	19.00	0.00	1	336KCM ACSR
418	0228 AMOS, WV	HOPKINS, WV	138	138	3	2.00	17.00	1	336KCM ACSR
419	0228 AMOS, WV	HOPKINS, WV	138	138	3	28.00	0.00	1	795KCM ACSR
420	0228 AMOS, WV	HOPKINS, WV	138	138	3	2.00	0.00	1	1590KCM ACSR/MA
421	0364 GRASSY FORK TAP, WV		138	138	1	2.00	0.00	1	795KCM ACSR
422	0376 DINGESS LOOP, WV		138	138	3	0.00	0.00	1	1033KCM ACSR
423	0376 DINGESS LOOP, WV		0	0	1	0.00	0.00	0
424	0306 INEZ, KY	LOGAN, WV	138	138	3	0.00	1.00	1	795KCM ACSR
425	0306 INEZ, KY	LOGAN, WV	0	0	1	23.00	0.00	0
426	0428 SHARPLES TAP 138KV		138	138	1	7.00	0.00	1	795KCM ACSR
427	0432 MUD FORK LOOP, WV		138	138	3	1.00	1.00	1	795KCM ACSR
428	0087 DARRAH, WV	TRI STATE, WV	138	138	3	10.00	4.00	1	397KCM
429	0436 DAWES LOOP, 138KV, WV		138	138		0.00	0.00	0
430	0088 TRI-STATE, WV	WEST HUNTINGTON, WV	138	138	3	0.00	6.00	1	397KCM ACSR
431	0090 SOUTH POINT, OH	TRI-STATE CIR A, WV	138	138	3	8.00	0.00	1	397KCM ACSR
432	0090 SOUTH POINT, OH	TRI-STATE CIR B, WV	138	138	3	0.00	7.00	1	1351KCM ACSR
433	0225 AMOS	SPORN	138	138	3	0.00	11.00	0	397KCM ACSR
434	0237 AMOS, WV	DARRAH, WV	138	138	3	35.00	0.00	1	397KCM ACSR
435	0238 AMOS, WV	WEST HUNTINGTON, WV	138	138	3	5.00	41.00	1	1033KCM ACSR
436	0238 AMOS, WV	WEST HUNTINGTON, WV	0	0	1	0.00	0.00	0
437	0238 PARK HILL TAP, WV		138	138	3	0.00	0.00	1	397KCM ACSR
438	0277 CABELL LOOP, WV		138	138	3	1.00	1.00	1	954KCM ACSR
439	0302 MILTON LOOP, WV		138	138	3	2.00	2.00	1	795KCM ACSR
440	0378 CURRY LOOP, WV		138	138	3	2.00	2.00	1	1033KCM ACSR
441	0095 CARBIDE MAIN, WV	TURNER, WV	138	138	3	0.00	0.00	1	1590 KCM ACSR
442	0096 CARBIDE #8, WV	CHEMICAL-TURNER A, WV	138	138	3	0.00	1.00	1	397KCM ACSR
443	0096 CARBIDE #8, WV	CHEMICAL-TURNER B, WV	138	138	3	7.00	0.00	1	1033KCM ACSR
444	0096 CARBIDE #8, WV	CHEMICAL-TURNER B, WV	138	138	3	1.00	0.00	2	1033KCM ACSR
445	0337 BLUEFIELD, WV	SOUTH PRINCETON, WV	138	138	2	8.00	0.00	1	556KCM ACSR
446	0337 BLUEFIELD, WV	SOUTH PRINCETON, WV	138	138	1	0.00	0.00	2	556KCM ACSR
447	0336 CLENDENIN TAP		138	138	1	8.00	0.00	0
448	CAPITALIZED SPARE PARTS	0373,0379	138	138		0.00	0.00	1
449	1005 CHERRY CREEK	CLIFFTOP	138	138	1	7.00	0.00	1	795 ACSR
450	0377 SPORN	CLINE ENERGY EXTENSION	138	138	1	0.00	0.00	1	397KCM ACSR
451	0370 SOUTHRIDGE EXTENSION		138	138	1	2.00	0.00	2	1590KCM ACSR/MA
452	0098A FLATWOOD TAP 138KV		0	0		0.00	0.00	0
453	0386 GARRISON WV		138	138	1	0.00	0.00	2	795 KCM ACSR
454	0382 LANHAM, WV		138	138	1	1.00	0.00	2	795 KCM ACSR
455	0473 CARETTA	JIM BRANCH	138	138		0.00	0.00	0
456	0471 HALLS RIDGE	SOUTH PRINCETON, WV	138	138	3	0.00	0.00	1	1590KCM ACSR
457	0466 IAEGER	WHARNCLIFFE, WV	46	138	3	6.00	0.00	1	556.5KCM26/7 AC
458	1050 ROCKHOUSE		138	138		0.00	0.00	0
459	1072 CLENDENIN, WV	MORRIS BRANCH	138	138	3	2.00	0.00	1	795 KCM ACSR
460	0474 COBB, WV	THOROFARE CREEK	138	138	3	0.00	0.00	1	795 KCM ACSR
461	0463 CROOKED CREEK, WV		138	138	3	1.00	0.00	1	1033KCM ACSR
462	0472 MERRITS CREEK, WV		138	138	3	4.00	0.00	1	1033KCM ACSR
463	3843 BIM, WV		47	138	3	0.00	0.00	1
464	3843 BIM, WV		0	0	1	11.00	0.00	0
465	0478 POLYMER LOOP, WV		138	138	3	3.00	0.00	1	795 KCM ACSR
466	0478 POLYMER LOOP, WV		138	138	1	0.00	0.00	1	795KCM ACSR
467	0477 BROAD RUN, WV	THOROFARE CREEK	138	138		1.00	0.00	1
468	0475 PATRIOT COAL, WV	POINT LICK	138	138	3	0.00	0.00	1	556.5 KCM 26/7 AC
469	0482 CLARK BRANCH, WV	138KV EXTENSION	138	138		0.00	0.00	1
470	0481 LAKEVIEW	138KV EXTENSION	138	138		0.00	0.00	0
471	0483 HERNSHAW	138KV EXTENSION	138	138	3	2.00	0.00	2	1590 KCM ACSR
472	0486 PAX BRANCH	138KV EXTENSION	138	138	3	1.00	0.00	2	1033.5 KCM ACSR
473	0487 PIERPONT	138KV EXTENSION	138	138	3	1.00	0.00	1	1033.5 KCM
474	0479 HARMON BRANCH	138KV EXTENSION	138	138	3	1.00	0.00	2	1033.5 KCM ACSR
475	0492 TRI-STATE	TWELVEPOLE CREEK	138	138	3	1.00	0.00	2	795 KCM ACSR
476	0503 CLINTWOOD EXTENSION		69	138	1	0.00	0.00	2	1033.5 KCM ACSR
477	3827 BRADLEY	LAYLAND NO.2B	69	138	1	1.00	0.00	1	1158.4KCM ACSR/TW
478	0015 BERWIND	FARADAY	138	138		0.00	0.00	0
479	0018 BERWIND	YUKON	138	138		0.00	0.00	0
480	0016 JIM BRANCH	YUKON	138	138		0.00	0.00	0
481	0568 GRANGSTON LOOP		138	138	3	0.00	0.00	2	556.5KCM ACSR
482	0526 COMMONWEALTH CROSSING	138KV EXTENSION	138	138	1	6.00	0.00	2	1033 KCM ACSR
483	0527 COCO Extension		138	138	1	0.00	0.00	2	1033.5 KCM ACSR
484	0528 CAPITOL HILL	CHESTERFIELD AVE	69	138	1	0.00	0.00	1	1033.5 KCM ACSR
485	0539 TRI-STATE 345KV - 138KV BUS TIE NO. 1		138	138	3	0.00	0.00	1	2-1590KCM ACSR
486						0.00	0.00
487	Lines Under 138KV					1,525.82	181.00
488	Line cost and expense are	not available by individual								208,976,967	1,945,585,271	2,154,562,237	176,564	17,548,707		17,725,271
489	transmission line	Total shown in Column j - p
36	TOTAL					5,042	1,330	470		208,976,967	1,945,585,271	2,154,562,237	176,564	17,548,707	0	17,725,271

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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.

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

(m)

(n)

(o)

(p)

(q)

0566 Berry Hill Extension

1033

ACSR

138

20,707

5,970,797

2,253,249

8,244,753

0584 Wythe County Solar Farm Extension

556

ACSR

138

72,865

TOTAL

20,707

6,043,662

2,253,249

8,317,618

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/12/2023

Year/Period of Report

End of:

2022

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	12.00		22.40	1			0	0.00
2	ABERT - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	9.60
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	12.00		6.25	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 138KV - WV	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	172.80
17	AMOS 345KV - WV	Transmission		345.00	138.00	34.50	1350.00	2			0	0.00
18	AMOS 345KV - WV	Transmission		34.50	7.20		1.66	2			0	0.00
19	AMOS 765KV - WV	Transmission		765.00	138.00	13.80	750.00	3			0	0.00
20	AMOS 765KV - WV	Transmission		765.00	345.00	34.50	1500.00	3			0	0.00
21	AMOS 765KV - WV	Transmission		138.00	69.00	46.00	130.00	0	1		0	0.00
22	AMOS 765KV - WV	Transmission		765.00	345.00	34.50		0	1		0	0.00
23	APPLE GROVE - WV	Transmission		138.00	69.00	12.00	56.00	1			0	0.00
24	APPLE GROVE - WV	Transmission		69.00	12.00		10.50	1			0	0.00
25	ARCHER CREEK - VA	Distribution		69.00	12.00		10.50	1			0	0.00
26	ARROWHEAD - VA	Distribution		69.00	13.09		12.00	1			0	0.00
27	ATKINS - VA	Distribution		138.00	34.50		30.00	1			0	0.00
28	ATKINS - VA	Distribution		69.00	12.00		10.50	0	1		0	0.00
29	ATKINS - VA	Distribution		138.00	34.50	12.00	9.38	0	1		0	0.00
30	AUSTINVILLE - VA	Distribution		138.00	34.50			1			0	0.00
31	AXTON - VA	Transmission		765.00	138.00	13.80	750.00	3			0	0.00
32	AXTON - VA	Transmission		138.00	0.00	0.00	0.00			4000A Air-Core Reactor	3
33	AXTON - VA	Transmission		765.00						REACTOR	4	400.00
34	BAILEYSVILLE - WV	Transmission		46.00	12.00		6.25	1			0	0.00
35	BAILEYSVILLE - WV	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	126.00
36	BAILEYSVILLE - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	9.60
37	BAILEYSVILLE - WV	Transmission		138.00	46.00		90.00	1			0	0.00
38	BALD KNOB - WV	Distribution		46.00	12.00		2.50	1			0	0.00
39	BALLOU - VA	Distribution		69.00	34.50		75.00	1			0	0.00
40	BALLOU - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	2	32.40
41	BANCROFT - WV	Transmission		138.00	13.09		25.00	1			0	0.00
42	BANCROFT - WV	Transmission		138.00	69.00	12.00	67.20	1			0	0.00
43	BANCROFT - WV	Transmission		138.00	34.50		20.00	1			0	0.00
44	BARNETT - WV	Distribution		69.00	13.09		20.00	1			0	0.00
45	BARNETT - WV	Distribution		69.00	12.00		20.00	1			0	0.00
46	BASSETT - VA	Distribution		69.00	12.00		25.00	1			0	0.00
47	BASSETT WALKER - VA	Distribution		34.50	7.50		3.75	3			0	0.00
48	BASSETT WALKER - VA	Distribution		34.50	7.20		5.64	3			0	0.00
49	BEALE - WV	Distribution		69.00	13.09		7.50	1			0	0.00
50	BEARWALLOW - VA	Transmission		138.00	70.50	13.09	54.00	1			0	0.00
51	BECCO - WV	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	9.60
52	BECCO - WV	Distribution		46.00	12.00		9.38	1			0	0.00
53	BECKLEY - WV	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	12.00
54	BECKLEY - WV	Distribution		46.00	4.16		6.25	1			0	0.00
55	BECKLEY - WV	Distribution		46.00	12.00		40.00	2			0	0.00
56	BELCHER MOUNTAIN - WV	Distribution		88.00	14.00		4.50	3			0	0.00
57	BELLE - WV	Transmission		46.00	12.00		20.00	1			0	0.00
58	BELVA - WV	Transmission		46.00	36.20		10.50	1			0	0.00
59	BELVA - WV	Transmission		138.00	46.00		30.00	1			0	0.00
60	BENS CREEK - WV	Distribution		46.00	13.20		2.50	1			0	0.00
61	BENT MOUNTAIN - VA	Distribution		138.00	34.00		10.50	1			0	0.00
62	BENT MOUNTAIN - VA	Distribution		138.00	13.09		8.40	1			0	0.00
63	BIG BRANCH - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	9.60
64	BIG ROCK - VA	Distribution		34.50	13.65		5.00	1			0	0.00
65	BIM - WV	Transmission		138.00	69.00	46.00	84.00	1			0	0.00
66	BIM - WV	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	13.19
67	BIM - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	14.40
68	BLACKWATER - VA	Distribution		34.50	12.00		20.00	1			0	0.00
69	BLACKWATER - VA	Distribution		34.50	0.00	0.00	0.00			STATCAP	1	9.60
70	BLAINE - VA	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	52.80
71	BLAINE - VA	Distribution		138.00	13.09		8.40	1			0	0.00
72	BLAINE - VA	Distribution		138.00	34.50		30.00	1			0	0.00
73	BLUE PENNANT - WV	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.40
74	BLUE RIDGE - VA	Distribution		12.00	4.00		0.30	3			0	0.00
75	BLUE RIDGE - VA	Distribution		34.50	12.00		10.94	2			0	0.00
76	BLUEFIELD AVENUE - WV	Distribution		138.00	13.09		44.80	2			0	0.00
77	BOLT - WV	Transmission		138.00	69.00	46.00	129.00	1			0	0.00
78	BOLT - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	9.60
79	BONSACK - VA	Distribution		138.00	34.50		30.00	1			0	0.00
80	BOONE - WV	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	9.60
81	BOONE - WV	Distribution		46.00	12.00		4.69	1			0	0.00
82	BOONSBORO - VA	Distribution		138.00	13.09		20.00	1			0	0.00
83	BORDERLAND - WV	Distribution		138.00	13.09		20.00	1			0	0.00
84	BOWYER - WV	Distribution		46.00	7.20		3.00	3			0	0.00
85	BOXWOOD - VA	Distribution		138.00	13.09		20.00	1			0	0.00
86	BRADLEY - WV	Transmission		138.00	69.00	46.00	130.00	1			0	0.00
87	BRADLEY - WV	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	50.40
88	BRADLEY - WV	Transmission		46.00	12.00		8.40	1			0	0.00
89	BRIAR MOUNTAIN - WV	Distribution		46.00	7.20		3.00	3			0	0.00
90	BRIDGE - WV	Distribution		69.00	13.09		45.00	2			0	0.00
91	BROADFORD 138KV - VA	Transmission		138.00	0.00	0.00	0.00			Air Core Reactor	2
92	BROADFORD 765KV - VA	Transmission		765.00	138.00	13.80	672.00	3			0	0.00
93	BROADFORD 765KV - VA	Transmission		765.00						REACTOR	3	300.00
94	BROADFORD 765KV - VA	Transmission		765.00	500.00	13.80	1500.00	3			0	0.00
95	BROCKWAY GLASS - VA	Distribution		69.00	4.00		9.38	1			0	0.00
96	BROOKVILLE - VA	Distribution		138.00	13.09		22.40	1			0	0.00
97	BROWNSVILLE (AP) - WV	Distribution		69.00	12.00		6.25	1			0	0.00
98	BRUSH TAVERN - VA	Distribution		138.00	34.50		60.00	2			0	0.00
99	BUCKHORN - VA	Distribution		138.00	34.50		30.00	1			0	0.00
100	BURLINGTON HEIGHTS - VA	Distribution		138.00	34.50		30.00	1			0	0.00
101	BYLLESBY - VA	Transmission		69.00	7.20		0.83	1			0	0.00
102	BYLLESBY - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	13.19
103	CABELL - WV	Distribution		138.00	36.20		30.00	1			0	0.00
104	CABELL - WV	Distribution		138.00	34.50		30.00	1			0	0.00
105	CABIN CREEK 46KV - WV	Transmission		138.00	46.00		75.00	1			0	0.00
106	CABIN CREEK 46KV - WV	Transmission		138.00	46.20		75.00	1			0	0.00
107	CABIN CREEK 46KV - WV	Transmission		46.00	12.00		22.40	1			0	0.00
108	CAMBRIA - VA	Distribution		69.00	13.09		25.00	1			0	0.00
109	CAMPBELL AVENUE - VA	Distribution		69.00	12.00		44.80	2			0	0.00
110	CAMPBELL AVENUE - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	9.60
111	CAMPBELL AVENUE - VA	Distribution		34.50	0.00	0.00	0.00			STATCAP	1	9.60
112	CAMPBELL AVENUE - VA	Distribution		69.00	34.50		30.00	1			0	0.00
113	CANDLERS MOUNTAIN - VA	Distribution		138.00	13.09		22.40	1			0	0.00
114	CAPITOL HILL 138KV - WV	Transmission		138.00	46.00		45.00	1			0	0.00
115	CAPITOL HILL 138KV - WV	Transmission		138.00	69.00	46.00	90.00	1			0	0.00
116	CAPITOL HILL 138KV - WV	Transmission		138.00	13.09		20.00	1			0	0.00
117	CAPITOL HILL 46KV - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	18.00
118	CARBONDALE - WV	Transmission		138.00	69.00	46.00	128.80	1			0	0.00
119	CARBONDALE - WV	Transmission		46.00	36.20		10.50	1			0	0.00
120	CARSWELL - WV	Transmission		138.00	88.00	13.20	20.00	0	1		0	0.00
121	CARSWELL - WV	Transmission		138.00	88.00	7.98	60.00	3			0	0.00
122	CATAWBA - VA	Transmission		138.00	34.50		30.00	1			0	0.00
123	CATAWBA - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	64.80
124	CATAWBA - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	16.20
125	CATAWBA - VA	Transmission		138.00	69.00	34.50		1			0	0.00
126	CAVE SPRING - VA	Distribution		138.00	13.09		42.40	2			0	0.00
127	CEDAR GROVE (AP) - WV	Distribution		46.00	12.00		5.00	1			0	0.00
128	CENTERVILLE - VA	Transmission		138.00	13.09		10.50	1			0	0.00
129	CENTERVILLE - VA	Transmission		138.00	69.00	34.50	84.00	1			0	0.00
130	CENTRAL AVENUE (AP) - WV	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	20.39
131	CENTRAL MACHINE SHOP - WV	Distribution		46.00	4.00		3.75	1			0	0.00
132	CEREDO - WV	Distribution		34.50	4.00		6.25	1			0	0.00
133	CHAUNCEY - WV	Transmission		46.00	12.00		10.50	1			0	0.00
134	CHAUNCEY - WV	Transmission		138.00	46.00	19.50	30.00	3			0	0.00
135	CHEMICAL - WV	Transmission		138.00	69.00	46.00	84.00	1			0	0.00
136	CHEMICAL - WV	Transmission		138.00	46.00		290.00	3			0	0.00
137	CHEMICAL - WV	Transmission		46.00	12.00		22.40	1			0	0.00
138	CHEMICAL - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	2	52.19
139	CHERRY CREEK - WV	Distribution		138.00	13.09		20.00	1			0	0.00
140	CHERRY CREEK - WV	Distribution		138.00	34.50		30.00	1			0	0.00
141	CHESTERFIELD AVENUE - WV	Transmission		138.00	13.09		40.00	2			0	0.00
142	CHESTERFIELD AVENUE - WV	Transmission		138.00	70.50	46.00	90.00	1			0	0.00
143	CINDERELLA - WV	Distribution		138.00	13.09		20.00	1			0	0.00
144	CLAREMONT - WV	Distribution		69.00	12.00		8.40	1			0	0.00
145	CLAYPOOL HILL - VA	Distribution		138.00	13.09		40.00	2			0	0.00
146	CLAYTOR HILLTOP - VA	Transmission			0.00	0.00	0.00			STATCAP	1	57.60
147	CLEARBROOK - VA	Distribution		138.00	13.09		42.40	2			0	0.00
148	CLENDENIN - WV	Transmission		46.00	34.50	20.90	25.00	1			0	0.00
149	CLENDENIN - WV	Transmission		138.00	46.00		125.00	1			0	0.00
150	CLIFFORD - VA	Transmission		138.00	46.00		20.00	1			0	0.00
151	CLIFFORD - VA	Transmission		138.00	69.00	46.00	50.00	1			0	0.00
152	CLIFFORD - VA	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	3.59
153	CLIFFTOP - WV	Distribution		138.00	13.09		20.00	1			0	0.00
154	CLIFFVIEW - VA	Distribution		69.00	13.00		9.38	1			0	0.00
155	CLIFFVIEW - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	13.19
156	CLIFFVIEW - VA	Distribution		69.00	36.20		96.00	4			0	0.00
157	CLINCHFIELD - VA	Transmission		138.00	70.50	36.20	90.00	1			0	0.00
158	CLINCHFIELD - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.39
159	CLINTWOOD - VA	Distribution		69.00	12.00		20.00	1			0	0.00
160	CLINTWOOD - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	9.60
161	CLOVERDALE 138KV - VA	Transmission		345.00	137.50	13.80	450.00	1			0	0.00
162	CLOVERDALE 138KV - VA	Transmission		138.00	70.50	36.20	200.00	0	1		0	0.00
163	CLOVERDALE 138KV - VA	Transmission		345.00	137.50	13.14	448.00	1			0	0.00
164	CLOVERDALE 138KV - VA	Transmission		345.00	138.00	34.50	675.00	1			0	0.00
165	CLOVERDALE 138KV - VA	Transmission		138.00	36.20		30.00	1			0	0.00
166	CLOVERDALE 138KV - VA	Transmission		69.00	13.09		20.00	1			0	0.00
167	CLOVERDALE 765KV - VA	Transmission		765.00	528.00	13.80	1950.00	3			0	0.00
168	CLOVERDALE 765KV - VA	Transmission		138.00	12.00		15.00	0	1		0	0.00
169	CLOVERDALE 765KV - VA	Transmission		138.00	34.00		20.00	0	1		0	0.00
170	CLOVERDALE 765KV - VA	Transmission		69.00	34.50		20.00	0	1		0	0.00
171	CLOVERDALE 765KV - VA	Transmission		138.00	69.00	13.10	84.00	0	1		0	0.00
172	CLOVERDALE 765KV - VA	Transmission		138.00	13.09		20.00	0	1		0	0.00
173	CLOVERDALE 765KV - VA	Transmission		34.50	7.20		1.50	0	1		0	0.00
174	CLOVERDALE 765KV - VA	Transmission		138.00	12.00		12.50	0	1		0	0.00
175	CLOVERDALE 765KV - VA	Transmission		138.00	70.50	46.00	90.00	0	1		0	0.00
176	CLOVERDALE 765KV - VA	Transmission		138.00	70.50	13.09	54.00	0	1		0	0.00
177	CLOVERDALE 765KV - VA	Transmission		138.00	70.50	13.09	78.00	0	1		0	0.00
178	CLOVERDALE 765KV - VA	Transmission		138.00	34.50		9.38	0	1		0	0.00
179	CLOVERDALE 765KV - VA	Transmission		69.00	12.00		20.00	0	1		0	0.00
180	CLOVERDALE 765KV - VA	Transmission		69.00	13.09		20.00	0	1		0	0.00
181	CLOVERDALE 765KV - VA	Transmission		138.00	70.50	36.20	78.00	0	1		0	0.00
182	CLOVERDALE 765KV - VA	Transmission		138.00	13.09	34.50	500.00	0	1		0	0.00
183	CLOVERDALE 765KV - VA	Transmission		138.00	13.09	34.50	15.00	0	1		0	0.00
184	CLOVERDALE 765KV - VA	Transmission		138.00	345.00	34.50	500.00	0	1		0	0.00
185	CLOVERDALE 765KV - VA	Transmission		138.00	345.00	34.50	15.00	0	1		0	0.00
186	CLOVERDALE 765KV - VA	Transmission		69.00	12.00		5.25	0	1		0	0.00
187	CLOVERDALE 765KV - VA	Transmission		138.00	13.09		10.50	0	1		0	0.00
188	CLOVERDALE 765KV - VA	Transmission		69.00	13.09		7.50	0	1		0	0.00
189	CLOVERDALE 765KV - VA	Transmission		69.00	13.09		9.38	0	1		0	0.00
190	CLOVERDALE 765KV - VA	Transmission		69.00	12.00		7.50	0	1		0	0.00
191	CLOVERDALE 765KV - VA	Transmission		69.00	12.00		9.38	0	1		0	0.00
192	CLOVERDALE 765KV - VA	Transmission		765.00	345.00	34.50	5400.00	32			0	0.00
193	CLOVERDALE 765KV - VA	Transmission		765.00						REACTOR	5	500.00
194	CLOVERDALE EAST 500KV - VA	Transmission		500.00	345.00	13.80	3500.00	7			0	0.00
195	COAL CREEK - VA	Distribution		69.00	12.00		10.00	1			0	0.00
196	COAL MOUNTAIN - WV	Distribution		46.00	7.20		1.66	2			0	0.00
197	COFFEE - VA	Distribution		138.00	13.09		20.00	1			0	0.00
198	COLLINSVILLE (AP) - VA	Distribution		138.00	13.09		22.40	1			0	0.00
199	CORNING GLASS (AP) - VA	Distribution		69.00	4.00		8.40	1			0	0.00
200	CORNING GLASS (AP) - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	8.10
201	COTTAGEVILLE - WV	Distribution		69.00	12.00		6.25	1			0	0.00
202	COVE ROAD - VA	Distribution		69.00	13.09		20.00	1			0	0.00
203	CRAB ORCHARD - WV	Distribution		46.00	12.00		3.75	1			0	0.00
204	CROOKED CREEK - WV	Distribution		138.00	13.09		20.00	1			0	0.00
205	CROSSROADS (AP) - VA	Distribution		69.00	13.09		22.40	1			0	0.00
206	CROSSROADS (AP) - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	9.60
207	CURRY - WV	Distribution		138.00	13.09		20.00	1			0	0.00
208	DALEWOOD - WV	Distribution		138.00	13.09		20.00	1			0	0.00
209	DAMASCUS - VA	Distribution		69.00	12.00		20.00	1			0	0.00
210	DAMERON - WV	Transmission		138.00	69.00	46.00	129.00	1			0	0.00
211	DAMERON - WV	Transmission		46.00	34.50		20.00	1			0	0.00
212	DAMERON - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	9.60
213	DAN RIVER RESEARCH - VA	Distribution		7.62	0.60		0.50	2			0	0.00
214	DAN RIVER RESEARCH - VA	Distribution		12.00	0.60		0.25	1			0	0.00
215	DAN RIVER RESEARCH - VA	Distribution		69.00	12.00		1.00	1			0	0.00
216	DANVILLE - VA	Transmission		138.00	69.00	12.00	115.00	1			0	0.00
217	DARRAH - WV	Transmission		138.00	34.50		45.50	1			0	0.00
218	DARRAH - WV	Transmission		138.00	13.09		22.40	1			0	0.00
219	DARRAH - WV	Transmission		138.00	69.00	34.50	90.00	1			0	0.00
220	DARRAH - WV	Transmission		138.00	34.50		30.00	1			0	0.00
221	DEARINGTON - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.40
222	DEARINGTON - VA	Distribution		69.00	12.00		20.00	1			0	0.00
223	DEARINGTON - VA	Distribution		69.00	13.09		25.00	1			0	0.00
224	DEHUE - WV	Distribution		46.00	13.09		9.38	1			0	0.00
225	DINGESS - WV	Distribution		138.00	34.50		30.00	1			0	0.00
226	Dismal River - VA	Distribution		69.00	12.00		10.50	1			0	0.00
227	Dismal River - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.39
228	DISSTON - VA	Distribution		69.00	4.00		3.13	1			0	0.00
229	DOROTHY - WV	Distribution		46.00	2.30		1.50	3			0	0.00
230	DUBLIN (AP) - VA	Distribution		34.50	12.00		18.76	3			0	0.00
231	DUNBAR - WV	Distribution		46.00	13.09		20.00	1			0	0.00
232	DUPONT (AP) - VA	Distribution		69.00	12.00		4.20	1			0	0.00
233	EAST DANVILLE - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.39
234	EAST DANVILLE - VA	Transmission		138.00	69.50	13.09	60.00	1			0	0.00
235	EAST DANVILLE - VA	Transmission		69.00	12.00		8.40	1			0	0.00
236	EAST DANVILLE - VA	Transmission		230.00	138.00	34.50	1500.00	2			0	0.00
237	EAST DANVILLE - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	52.79
238	EAST HUNTINGTON - WV	Transmission		138.00	34.50		30.00	1			0	0.00
239	EAST HUNTINGTON - WV	Transmission		34.50	12.00		9.38	1			0	0.00
240	EAST HUNTINGTON - WV	Transmission		138.00	69.00	34.50	90.00	1			0	0.00
241	EAST LYNCHBURG - VA	Transmission		138.00	69.00	34.50	196.00	1			0	0.00
242	EAST LYNCHBURG - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	57.60
243	EAST MONUMENT - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	52.79
244	EAST RIVER MOUNTAIN - WV	Distribution		138.00	34.50		9.38	1			0	0.00
245	EDGEMONT - VA	Distribution		138.00	13.09		22.40	1			0	0.00
246	EDWIGHT - WV	Distribution		46.00	7.20		2.49	3			0	0.00
247	ELK CREEK - WV	Distribution		46.00	12.00		3.75	1			0	0.00
248	ELK GARDEN - VA	Distribution		138.00	36.20		30.00	1			0	0.00
249	ELK GARDEN - VA	Distribution		138.00	34.50		30.00	1			0	0.00
250	ELK GARDEN - VA	Distribution		138.00	13.09		7.50	1			0	0.00
251	ELM STREET - VA	Distribution		34.50	12.00		20.00	1			0	0.00
252	ELM STREET - VA	Distribution		34.50	0.00	0.00	0.00			STATCAP	1	9.60
253	ELMO - WV	Distribution		69.00	12.00		5.00	1			0	0.00
254	ESMONT - VA	Distribution		46.00	12.00		4.69	1			0	0.00
255	EXPRESSWAY - VA	Distribution		69.00	12.00		42.40	2			0	0.00
256	EXPRESSWAY - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	10.80
257	FALLING BRANCH - VA	Distribution		138.00	13.09		9.38	1			0	0.00
258	FARADAY 138KV - WV	Distribution		34.50	0.00	0.00	0.00			Air Core Reactor	3
259	FARADAY 138KV - WV	Distribution		34.50	0.00	0.00	0.00			STATCAP	1	6,000.00
260	FAYETTEVILLE (AP) - WV	Distribution		69.00	13.09		20.00	1			0	0.00
261	FIELDALE - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	26.39
262	FIELDALE - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	100.80
263	FIELDALE - VA	Transmission		138.00	70.50	36.20	78.00	1			0	0.00
264	FIELDALE - VA	Transmission		34.50	12.00		9.40	2			0	0.00
265	FIELDALE - VA	Transmission		34.50	0.00	0.00	0.00			STATCAP	1	7.19
266	FIELDCREST MILLS - VA	Distribution		69.00	4.00		20.00	1			0	0.00
267	FLATWOOD - WV	Distribution		138.00	34.50		30.00	1			0	0.00
268	FLATWOOD - WV	Distribution		138.00	12.47		22.40	1			0	0.00
269	FLETCHERS RIDGE - VA	Distribution		138.00	13.09		10.50	1			0	0.00
270	FLOYD - VA	Transmission		138.00	13.09		10.50	1			0	0.00
271	FLOYD - VA	Transmission		138.00	69.00	34.50	56.00	1			0	0.00
272	FLOYD - VA	Transmission		138.00	12.00		9.38	1			0	0.00
273	FOREST (AP) - VA	Distribution		138.00	13.09		42.40	2			0	0.00
274	FRANKLIN - VA	Distribution		138.00	13.09		22.40	1			0	0.00
275	FRANKLIN - VA	Distribution		138.00	34.50		30.00	1			0	0.00
276	FRANKLIN STREET - VA	Distribution		34.50	12.00		6.25	1			0	0.00
277	FREMONT (AP) - VA	Transmission		138.00	70.50	13.09	208.00	2			0	0.00
278	FRIES - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.40
279	FRIES - VA	Distribution		69.00	12.00		10.28	2			0	0.00
280	FULKS - WV	Distribution		34.50	34.50	5.00	25.00	1			0	0.00
281	FULKS - WV	Distribution		34.50	13.09		9.38	1			0	0.00
282	FULKS - WV	Distribution		34.50	34.50	6.50	30.00	1			0	0.00
283	GALAX - VA	Distribution		69.00	12.00		44.80	2			0	0.00
284	GALAX - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	2	26.38
285	GALLAGHER - WV	Distribution		46.00	12.00		4.69	1			0	0.00
286	GARDEN CREEK - VA	Transmission		69.00	12.00		22.40	1			0	0.00
287	GARDEN CREEK - VA	Transmission		138.00	69.50	13.09	84.00	1			0	0.00
288	GARDEN CREEK - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	50.40
289	GATE CITY - VA	Distribution		69.00	12.00		22.40	1			0	0.00
290	GAULEY MOUNTAIN - WV	Distribution		69.00	12.00		8.40	1			0	0.00
291	GILBERT - WV	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	9.60
292	GILBERT - WV	Distribution		46.00	12.00		20.00	1			0	0.00
293	GLADE - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	9.60
294	GLADE - VA	Distribution		69.00	34.50		30.00	1			0	0.00
295	GLADE - VA	Distribution		69.00	12.00		10.50	1			0	0.00
296	GLAMORGAN - VA	Distribution		34.50	4.00		9.38	1			0	0.00
297	GLEN LYN - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	4	203.99
298	GLEN LYN - VA	Transmission		88.00	69.00	13.10	84.00	0	1		0	0.00
299	GLEN LYN - VA	Transmission		138.00	13.20		18.75	3			0	0.00
300	GLEN WHITE - WV	Distribution		46.00	12.00		6.25	1			0	0.00
301	GLENWOOD (AP) - VA	Distribution		23.00	12.00		9.40	1			0	0.00
302	GLENWOOD (AP) - VA	Distribution		12.00	0.24		0.33	2			0	0.00
303	GLENWOOD (AP) - VA	Distribution		13.20	0.24		0.17	1			0	0.00
304	GLENWOOD (AP) - VA	Distribution		12.00	0.24		0.17	0	1		0	0.00
305	GLENWOOD (AP) - VA	Distribution		23.00	12.00		3.75	0	1		0	0.00
306	GOMINGO - VA	Distribution		138.00	13.09		22.40	1			0	0.00
307	GRAPEVINE - WV	Distribution		46.00	7.20		6.99	6			0	0.00
308	GRASSY FORK - WV	Distribution		138.00	34.50		20.00	1			0	0.00
309	GRAVES MILL - VA	Distribution		138.00	13.09		40.00	2			0	0.00
310	GREENBRIER - WV	Distribution		69.00	13.09		25.00	1			0	0.00
311	GREENBRIER METERING - WV	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	28.79
312	GRUNDY - VA	Transmission		69.00	34.50		25.00	1			0	0.00
313	GRUNDY - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	13.19
314	GRUNDY - VA	Transmission		69.00	12.00		10.50	1			0	0.00
315	GUTHRIE - WV	Distribution		46.00	34.50		25.00	1			0	0.00
316	HALES BRANCH - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.39
317	HALES BRANCH - VA	Transmission		138.00	69.00	12.00	84.00	1			0	0.00
318	HALES BRANCH - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	50.40
319	HALLS RIDGE - WV	Distribution		138.00	34.50			1			0	0.00
320	HAMPTON - WV	Distribution		46.00	12.00		3.75	1			0	0.00
321	HAMPTON - WV	Distribution		46.00	7.20		4.50	3			0	0.00
322	HANCOCK - VA	Transmission		34.50	0.00	0.00	0.00			STATCAP	1	12.00
323	HANCOCK - VA	Transmission		34.50	36.20		15.00	1			0	0.00
324	HANCOCK - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	50.40
325	HANCOCK - VA	Transmission		138.00	34.50	11.00	45.00	3			0	0.00
326	HANCOCK - VA	Transmission		138.00	69.00	34.50	128.80	1			0	0.00
327	HANS MEADOW - VA	Distribution		69.00	12.00		10.50	0	1		0	0.00
328	HANS MEADOW - VA	Distribution		69.00	13.09		25.00	1			0	0.00
329	HANSONVILLE - VA	Distribution		138.00	13.09		20.00	1			0	0.00
330	HARDY - WV	Distribution		46.00	7.20		4.50	3			0	0.00
331	HARMON BRANCH - WV	Distribution		138.00	12.00		15.00	1			0	0.00
332	HARTLAND - WV	Distribution		46.00	13.09		12.50	1			0	0.00
333	HARTLAND - WV	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	5.40
334	HASH RIDGE - WV	Distribution		138.00	34.50		30.00	1			0	0.00
335	HAYSI - VA	Distribution		69.00	12.00		20.00	1			0	0.00
336	HENRY S.D. - VA	Distribution		34.50	13.00		3.75	1			0	0.00
337	HEWETT - WV	Distribution		46.00	12.00		10.50	1			0	0.00
338	HICKMAN - VA	Distribution		69.00	13.09		20.00	1			0	0.00
339	HICKORY GAP - WV	Distribution		34.50	12.00		2.50	1			0	0.00
340	HILL - VA	Transmission		138.00	69.00	34.50	40.00	1			0	0.00
341	HILL - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	13.19
342	HILL - VA	Transmission		138.00	13.09		8.40	1			0	0.00
343	HILLMAN HIGHWAY - VA	Distribution		69.00	13.09		25.00	1			0	0.00
344	HILLMAN HIGHWAY - VA	Distribution		69.00	12.00		22.40	1			0	0.00
345	HILLSVILLE - VA	Distribution		34.50	12.00		6.75	2			0	0.00
346	HINTON (AP) - WV	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	43.20
347	HOPKINS - WV	Transmission		138.00	13.09		20.00	1			0	0.00
348	HOPKINS - WV	Transmission		138.00	34.50		20.00	1			0	0.00
349	HOPKINS - WV	Transmission		138.00	0.00	0.00	0.00			Air Core Reactor	4	0.00
350	HOPKINS - WV	Transmission		138.00	69.00	46.00	56.00	1			0	0.00
351	HOPKINS FORK - WV	Distribution		46.00	7.20		2.49	3			0	0.00
352	HUBBARDSTOWN - WV	Distribution		138.00	34.50		20.00	1			0	0.00
353	HUFF CREEK - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	9.60
354	HUFF CREEK - WV	Transmission		46.00	13.09		20.00	1			0	0.00
355	HUFF CREEK - WV	Transmission		138.00	69.00	46.00	130.00	1			0	0.00
356	HUFFMAN - VA	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	28.80
357	HUGHESTON - WV	Distribution		46.00	2.40		2.50	3			0	0.00
358	HUNTINGTON COURT - VA	Distribution		69.00	34.50		75.00	1			0	0.00
359	HUNTINGTON COURT - VA	Distribution		69.00	12.00		20.00	1			0	0.00
360	HUNTINGTON COURT - VA	Distribution		138.00	69.00	34.50	175.00	1			0	0.00
361	HUNTINGTON COURT - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	28.80
362	HUNTINGTON COURT - VA	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	64.80
363	HURLEY - VA	Distribution		69.00	12.00		22.40	1			0	0.00
364	HURRICANE - WV	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	21.60
365	HURRICANE - WV	Distribution		69.00	12.00		25.00	1			0	0.00
366	INDEPENDENCE - VA	Distribution		69.00	12.00		10.50	1			0	0.00
367	INDEPENDENCE - VA	Distribution		69.00	34.50		20.00	1			0	0.00
368	INGLES - VA	Distribution		69.00	13.09		20.00	1			0	0.00
369	INGLES - VA	Distribution		69.00	34.50		50.00	1			0	0.00
370	INGLES - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.40
371	ITMANN - WV	Distribution		138.00	13.09		22.40	1			0	0.00
372	IVY HILL - VA	Distribution		138.00	13.09		20.00	1			0	0.00
373	JACKSONS FERRY - VA	Transmission		765.00		13.80	250.00	2			0	0.00
374	JACKSONS FERRY - VA	Transmission		20.78	0.00	0.00	0.00			STATCAP	3	888.84
375	JACKSONS FERRY - VA	Transmission		765.00			250.00	2			0	0.00
376	JACKSONS FERRY - VA	Transmission		765.00	20.65	13.80		1			0	0.00
377	JACKSONS FERRY - VA	Transmission		13.20	0.00	0.00	0.00			STATCAP	1	3.59
378	JACKSONS FERRY - VA	Transmission		765.00	500.00	13.80	500.00	3			0	0.00
379	JACKSONS FERRY - VA	Transmission		13.80	0.00	0.00	0.00			STATCAP	1	3.60
380	JACKSONS FERRY - VA	Transmission		765.00	138.00		250.00	2			0	0.00
381	JACKSONS FERRY - VA	Transmission		765.00	138.00	13.80	1750.00	8			0	0.00
382	JARROLD - WV	Distribution		46.00	13.09		5.00	1			0	0.00
383	JEWELL RIDGE - VA	Distribution		69.00	12.00		9.38	1			0	0.00
384	JIM BRANCH - WV	Transmission		69.00	12.00		10.00	1			0	0.00
385	JIM BRANCH - WV	Transmission		138.00	69.00	46.00	128.80	1			0	0.00
386	JOHNSONS LANE - WV	Distribution		34.50	34.50	5.00	25.00	1			0	0.00
387	JOSHUA FALLS - VA	Transmission		765.00	138.00	13.80	750.00	3			0	0.00
388	JUBAL EARLY - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	43.20
389	JUBAL EARLY - VA	Transmission		138.00	69.00	34.50	84.00	1			0	0.00
390	KANAWHA CITY - WV	Distribution		46.00	12.00		22.40	1			0	0.00
391	KANAWHA CITY - WV	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	15.60
392	KANAWHA RIVER - WV	Transmission		345.00	138.00	13.80		1			0	0.00
393	KANAWHA RIVER - WV	Transmission		138.00	13.09		20.00	1			0	0.00
394	KENOVA - WV	Transmission		138.00	34.50		30.00	1			0	0.00
395	KENOVA - WV	Transmission		34.50	13.09		9.38	1			0	0.00
396	KENOVA - WV	Transmission		138.00	69.00	34.50	200.00	1			0	0.00
397	KENOVA - WV	Transmission		138.00	69.00	46.00	150.00	0	1		0	0.00
398	KENOVA - WV	Transmission		34.50	4.00		3.75	1			0	0.00
399	KENOVA - WV	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.40
400	KILLARNEY - WV	Distribution		46.00	7.20		0.50	1			0	0.00
401	KILLARNEY - WV	Distribution		46.00	7.20		0.66	2			0	0.00
402	KINCAID - WV	Transmission		138.00	69.00	46.00	84.00	1			0	0.00
403	KNOTTY POPLAR - VA	Distribution		69.00	12.00		6.25	1			0	0.00
404	KOPPERSTON - WV	Distribution		138.00	13.09		20.00	1			0	0.00
405	KUMIS - VA	Distribution		138.00	13.09		22.40	1			0	0.00
406	LAKE FOREST - VA	Distribution		138.00	36.20		30.00	1			0	0.00
407	LAKEVIEW - WV	Distribution		138.00	13.09		20.00	1			0	0.00
408	LAKIN - WV	Transmission		138.00	69.00	12.00	90.00	1			0	0.00
409	LAKIN - WV	Transmission		138.00	13.09		20.00	1			0	0.00
410	LATROBE - WV	Distribution		46.00	7.20		4.50	3			0	0.00
411	LAVALETTE - WV	Distribution		138.00	34.50		30.00	1			0	0.00
412	LAYLAND - WV	Distribution		69.00	13.09		2.50	1			0	0.00
413	LEBANON - VA	Distribution		138.00	13.09		22.40	1			0	0.00
414	LEE HIGHWAY - VA	Distribution		69.00	12.00		10.00	1			0	0.00
415	LEIVASY - WV	Distribution		69.00	12.00		8.40	1			0	0.00
416	LICK FORK - VA	Distribution		69.00	34.50		10.50	1			0	0.00
417	LOCK LANE - WV	Distribution		69.00	12.00		6.25	1			0	0.00
418	LOCKHART - VA	Distribution		138.00	13.04		20.00	1			0	0.00
419	LOGAN - WV	Transmission		138.00	13.09		22.40	1			0	0.00
420	LOGAN - WV	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	115.19
421	LONESOME PINE - VA	Distribution		138.00	13.09		22.40	1			0	0.00
422	LOONEY CREEK - VA	Transmission		138.00	69.00	34.50	90.00	1			0	0.00
423	LOUDENDALE - WV	Distribution		46.00	12.00		10.50	1			0	0.00
424	LOUP CREEK - WV	Distribution		46.00	12.00		3.00	1			0	0.00
425	LUKENS - VA	Distribution		69.00	13.09		20.00	1			0	0.00
426	MAMMOTH - WV	Distribution		46.00	12.00		3.75	1			0	0.00
427	MARIANNA - WV	Distribution		46.00	12.00		10.50	1			0	0.00
428	MARMET - WV	Distribution		46.00	12.00		7.00	1			0	0.00
429	MARSH FORK - WV	Distribution		46.00	12.00		10.50	1			0	0.00
430	MARTINSVILLE - VA	Transmission		138.00	34.50		90.00	3			0	0.00
431	MARTINSVILLE - VA	Transmission		138.00	70.50	36.20	54.00	1			0	0.00
432	MARTINSVILLE - VA	Transmission		138.00	69.00	34.50	128.80	1			0	0.00
433	MASON CREEK - VA	Distribution		69.00	12.00		25.00	1			0	0.00
434	MATT FUNK 138KV - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	147.60
435	MATT FUNK 345KV - VA	Transmission		345.00	138.00	13.10	672.00	1			0	0.00
436	MATT FUNK 345KV - VA	Transmission		345.00	138.00	34.50	675.00	1			0	0.00
437	MCDOWELL - WV	Transmission		34.50	13.20		7.50	1			0	0.00
438	MCGRAWS - WV	Distribution		46.00	13.09		12.50	1			0	0.00
439	MCROSS - WV	Distribution		69.00	34.50		30.00	1			0	0.00
440	MCROSS - WV	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	9.60
441	MEADOW BRIDGE - WV	Distribution		69.00	34.50		8.40	1			0	0.00
442	MEADOWVIEW - VA	Distribution		138.00	13.09		20.00	1			0	0.00
443	MEADOWVIEW - VA	Distribution		138.00	69.00	34.50	56.00	1			0	0.00
444	MELROSE - VA	Distribution		69.00	12.00		22.40	1			0	0.00
445	MERRIMAC - VA	Transmission		138.00	69.00	13.09	78.00	1			0	0.00
446	MERRIMAC - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	27.00
447	MERRIMAC - VA	Transmission		138.00	69.00	12.00	128.00	1			0	0.00
448	MERRITTS CREEK - WV	Distribution		138.00	36.20		30.00	1			0	0.00
449	MIDDLE BURNING CREEK - WV	Distribution		34.50	12.00		5.00	1			0	0.00
450	MIDKIFF - WV	Distribution		138.00	34.50		20.00	1			0	0.00
451	MIDWAY (AP) - VA	Distribution		69.00	4.00		12.25	2			0	0.00
452	MIKES RUN - WV	Distribution		46.00	12.00		3.75	1			0	0.00
453	MILBURN - WV	Distribution		46.00	7.20		1.50	3			0	0.00
454	MILL RUN - WV	Distribution		69.00	12.00		9.38	1			0	0.00
455	MILTON - WV	Transmission		138.00	69.00	34.50	90.00	1			0	0.00
456	MILTON - WV	Transmission		138.00	36.20		25.00	1			0	0.00
457	MILTON - WV	Transmission		138.00	13.09		25.00	2			0	0.00
458	MILTON - WV	Transmission		69.00	36.20		30.00	1			0	0.00
459	MINK SHOALS - WV	Distribution		69.00	13.09		20.00	1			0	0.00
460	MINNIX MOUNTAIN - WV	Distribution		138.00	34.00		25.00	1			0	0.00
461	MOHAWK RUBBER - VA	Distribution		69.00	2.40		25.00	2			0	0.00
462	MONEL - VA	Distribution		138.00	13.09		20.00	1			0	0.00
463	MONETA - VA	Distribution		138.00	34.50		30.00	1			0	0.00
464	MONROE (AP) - VA	Distribution		69.00	13.09		20.00	1			0	0.00
465	MONTEREY - VA	Distribution		69.00	12.00		10.50	1			0	0.00
466	MONTGOMERY - WV	Distribution		46.00	12.00		22.40	1			0	0.00
467	MORGANS CUT - VA	Transmission		138.00	69.00	34.50	200.00	1			0	0.00
468	MORGANS CUT - VA	Transmission		138.00	69.00	34.50	84.00	0	1		0	0.00
469	MORGANS CUT - VA	Transmission		34.50	0.00	0.00	0.00			STATCAP	1	13.50
470	MORRIS NOVELTY - VA	Distribution		34.50	12.00		3.75	1			0	0.00
471	MORRIS NOVELTY - VA	Distribution		34.50	0.00	0.00	0.00			STATCAP	1	15.60
472	MOSELEY - VA	Transmission		138.00	69.00	12.00	56.00	1			0	0.00
473	MOSS - VA	Distribution		69.00	12.00		8.40	1			0	0.00
474	MOUNT AIRY - VA	Distribution		138.00	34.50		20.00	1			0	0.00
475	MOUNT HOPE - WV	Distribution		46.00	4.00		3.75	1			0	0.00
476	MOUNT UNION - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	13.19
477	MOUNT UNION - VA	Transmission		69.00	34.50		30.00	1			0	0.00
478	MOUNT UNION - VA	Transmission		69.00	12.00		20.00	1			0	0.00
479	MOUNT VIEW - VA	Distribution		69.00	12.00		22.40	1			0	0.00
480	MUD FORK - WV	Distribution		138.00	13.09		22.40	1			0	0.00
481	MUDLICK - VA	Distribution		69.00	12.00		22.40	1			0	0.00
482	MULLENS - WV	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	50.40
483	MULLENS - WV	Transmission		138.00	34.50		25.00	1			0	0.00
484	MULLENS - WV	Transmission		138.00	46.00		30.00	1			0	0.00
485	MULLENS TOWN - WV	Distribution		34.50	4.00		4.70	1			0	0.00
486	MULLENSVILLE - WV	Transmission		138.00	46.00		30.00	1			0	0.00
487	NAGEL - TN	Transmission		138.00	34.50		30.00	1			0	0.00
488	NAGEL - TN	Transmission		500.00	138.00	13.80		3			0	0.00
489	NAGEL - TN	Transmission		500.00	230.00	13.80	750.00	3			0	0.00
490	NEECE CREEK - VA	Distribution		69.00	12.00		8.40	1			0	0.00
491	NEW CASTLE - VA	Distribution		34.50	0.00	0.00	0.00			STATCAP	1	3.59
492	NEW CASTLE - VA	Distribution		34.50	12.00		7.00	1			0	0.00
493	NEW HOPE (AP) - WV	Distribution		138.00	13.09		22.40	1			0	0.00
494	NEW HOPE (AP) - WV	Distribution		138.00	34.50		25.00	1			0	0.00
495	NEW LONDON - VA	Transmission		138.00	34.50		30.00	1			0	0.00
496	NITRO - WV	Distribution		69.00	12.00		20.00	1			0	0.00
497	NORTH BECKLEY - WV	Distribution		138.00	34.50		30.00	1			0	0.00
498	NORTH BECKLEY - WV	Distribution		138.00	13.09		25.00	1			0	0.00
499	NORTH BLACKSBURG - VA	Transmission		138.00	69.00	12.00	128.80	1			0	0.00
500	NORTH BLACKSBURG - VA	Transmission		138.00	13.09		22.40	1			0	0.00
501	NORTH CLAYTOR - VA	Transmission		138.00	69.00	34.50	200.00	1			0	0.00
502	NORTH CLAYTOR - VA	Transmission		138.00	69.00	34.50	84.00	0	1		0	0.00
503	NORTH POINTE - WV	Distribution		138.00	34.50		20.00	1			0	0.00
504	OAK HILL (AP) - WV	Distribution		69.00	12.00		22.40	1			0	0.00
505	OAK LEVEL - VA	Distribution		138.00	13.09		20.00	1			0	0.00
506	OCEANA - WV	Distribution		46.00	12.00		16.75	2			0	0.00
507	OPOSSUM CREEK - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	105.58
508	ORCHARD - VA	Distribution		34.50	12.00		6.25	1			0	0.00
509	ORTIN - WV	Distribution		138.00	13.09		20.00	1			0	0.00
510	PACKSVILLE - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	9.60
511	PAD FORK - WV	Distribution		138.00	34.50		20.00	1			0	0.00
512	PANTHER - WV	Distribution		46.00	7.20		4.50	3			0	0.00
513	PARK HILL - WV	Distribution		138.00	13.09		22.40	1			0	0.00
514	PATRICK STREET - WV	Distribution		46.00	13.09		20.00	1			0	0.00
515	PATRIOT CENTRE - VA	Distribution		138.00	34.50		30.00	1			0	0.00
516	PAX BRANCH 138KV - WV	Transmission		138.00	12.00		20.00	2			0	0.00
517	PAX BRANCH 138KV - WV	Transmission		138.00	46.00		216.00	4			0	0.00
518	PAX BRANCH 138KV - WV	Transmission		138.00	13.09		20.00	2			0	0.00
519	PEAK CREEK - VA	Distribution		138.00	34.50		30.00	1			0	0.00
520	PEAK CREEK - VA	Distribution		138.00	13.09		20.00	1			0	0.00
521	PEAKLAND - VA	Distribution		69.00	12.00		20.00	1			0	0.00
522	PEAKSVIEW - VA	Transmission		138.00	69.00	34.50	130.00	1			0	0.00
523	PEARISBURG - VA	Distribution		34.50	12.00		6.25	1			0	0.00
524	PEMBERTON - WV	Transmission		138.00	69.00	46.00	90.00	1			0	0.00
525	PEMBERTON - WV	Transmission		46.00	4.00		5.00	1			0	0.00
526	PENHOOK - VA	Distribution		138.00	34.50		30.00	1			0	0.00
527	PERKINS PARK - VA	Distribution		69.00	12.00		20.00	1			0	0.00
528	PETERS MOUNTAIN - VA	Distribution		138.00	34.50		30.00	1			0	0.00
529	PEYTONA - WV	Distribution		46.00	13.09		10.50	1			0	0.00
530	PHOENIX - VA	Distribution		46.00	7.20		1000.83	3			0	0.00
531	PIGEON CREEK - WV	Distribution		138.00	34.50		60.00	2			0	0.00
532	PINE CREEK - WV	Distribution		138.00	13.09		12.50	1			0	0.00
533	PINE GAP - WV	Distribution		46.00	12.00		3.00	1			0	0.00
534	PINNACLE CREEK - WV	Distribution		138.00	34.50	12.00	13.30	1			0	0.00
535	PINNACLE CREEK - WV	Distribution		138.00	34.50		9.38	1			0	0.00
536	PIPERS GAP - VA	Distribution		138.00	34.00		30.00	1			0	0.00
537	PIPERS GAP - VA	Distribution		138.00	36.20		30.00	1			0	0.00
538	PLANT ROAD - WV	Distribution		69.00	12.00		22.40	1			0	0.00
539	PLANTATION PIPELINE - VA	Distribution		34.50	7.50		4.50	3			0	0.00
540	POAGES MILL - VA	Distribution		138.00	13.09		20.00	1			0	0.00
541	POINT PLEASANT - WV	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	9.60
542	POLEYARD - WV	Distribution		138.00	13.09		25.00	1			0	0.00
543	POPLAR FORK - WV	Distribution		138.00	13.09		20.00	1			0	0.00
544	POPLAR GAP - WV	Distribution		46.00	7.20		4.50	3			0	0.00
545	POUND - VA	Distribution		69.00	12.00		6.25	1			0	0.00
546	POUND - VA	Distribution		69.00	34.50		25.00	1			0	0.00
547	POWELLTON - WV	Distribution		46.00	7.20		2.49	3			0	0.00
548	PRICES FORK - VA	Distribution		69.00	12.00		22.40	1			0	0.00
549	PRICES FORK - VA	Distribution			0.00	0.00	0.00			STATCAP	1
550	PRICES FORK - VA	Distribution		69.00	13.09		25.00	1			0	0.00
551	PRINCE - WV	Distribution		69.00	13.09		5.25	1			0	0.00
552	PRINCETON - WV	Distribution		34.50	12.00		20.00	2			0	0.00
553	PROGRESS PARK - VA	Distribution		138.00	34.50		30.00	1			0	0.00
554	PROGRESS PARK - VA	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	57.60
555	PROGRESS PARK - VA	Distribution		138.00	36.20		30.00	1			0	0.00
556	PUTNAM VILLAGE - WV	Distribution		69.00	13.09		20.00	1			0	0.00
557	RADFORD - VA	Distribution		34.50	0.00	0.00	0.00			STATCAP	1	10.80
558	RAGLAND - WV	Distribution		138.00	34.50		25.00	1			0	0.00
559	RAVENSWOOD - WV	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.40
560	RAVENSWOOD - WV	Distribution		69.00	13.09		25.00	1			0	0.00
561	RED HILL - VA	Distribution		138.00	13.09		8.40	1			0	0.00
562	RENSFORD - WV	Distribution		138.00	34.50		25.00	1			0	0.00
563	REUSENS - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	57.60
564	REUSENS - VA	Transmission		138.00	69.00	13.09	130.00	1			0	0.00
565	REUSENS - VA	Transmission		138.00	34.50		60.00	2			0	0.00
566	REUSENS - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	13.50
567	RICH ACRES - VA	Distribution		69.00	34.50		30.00	1			0	0.00
568	RICH CREEK - WV	Distribution		46.00	12.00		10.50	1			0	0.00
569	RICHLANDS - VA	Transmission		138.00	69.00	13.10	130.00	1			0	0.00
570	RICHLANDS - VA	Transmission		138.00	69.00	13.09	78.00	1			0	0.00
571	RIDGEWAY - VA	Transmission		138.00	69.00	4.00	40.00	1			0	0.00
572	RIDGEWAY - VA	Transmission		138.00	13.09		9.38	0	1		0	0.00
573	RIDGEWAY - VA	Transmission		138.00						REACTOR	48	3,230.40
574	RIDGEWAY - VA	Transmission		138.00	34.50		25.00	1			0	0.00
575	RIDGEWAY - VA	Transmission		138.00	69.00	7.20	35.00	1			0	0.00
576	RIGIS - VA	Transmission		138.00	69.00	12.00	115.00	1			0	0.00
577	RIPLEY - WV	Distribution		138.00	69.00	13.09	78.00	1			0	0.00
578	RIPLEY - WV	Distribution		69.00	13.09		12.50	1			0	0.00
579	RIPLEY - WV	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	9.60
580	RIPLEY - WV	Distribution		69.00	34.50		25.00	1			0	0.00
581	RIVERBEND - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.40
582	RIVERBEND - VA	Distribution		69.00	12.00		9.38	1			0	0.00
583	RIVERBEND - VA	Distribution		69.00	12.00		7.00	1			0	0.00
584	RIVERMONT - VA	Distribution		69.00	12.00		20.00	1			0	0.00
585	RIVERVILLE - VA	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	32.40
586	RIVERVILLE - VA	Distribution		138.00	13.09		104.00	3			0	0.00
587	ROANOKE (AP) - VA	Transmission		138.00	69.00	12.00	130.00	1			0	0.00
588	ROANOKE (AP) - VA	Transmission		138.00	34.50		30.00	1			0	0.00
589	ROANOKE (AP) - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	122.39
590	ROANOKE (AP) - VA	Transmission		34.50	0.00	0.00	0.00			STATCAP	1	7.19
591	ROANOKE (AP) - VA	Transmission		138.00	13.09		20.00	1			0	0.00
592	ROANOKE ELECTRIC STEEL - VA	Distribution		138.00	34.50		197.00	2			0	0.00
593	ROANOKE ELECTRIC STEEL - VA	Distribution		34.50	0.00	0.00	0.00			STATCAP	4	278.50
594	ROANOKE ELECTRIC STEEL - VA	Distribution		138.00	34.50		16.67	0	1		0	0.00
595	ROBINSON - WV	Distribution		69.00	12.00		10.40	1			0	0.00
596	ROBINSON - WV	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	13.19
597	RONDA - WV	Distribution		46.00	12.00		3.75	1			0	0.00
598	RONDA - WV	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	7.20
599	RURAL RETREAT - VA	Distribution		138.00	34.50		25.00	1			0	0.00
600	RUSTBURG - VA	Distribution		138.00	13.09		20.00	1			0	0.00
601	RUTH - WV	Distribution		138.00	13.09		20.00	1			0	0.00
602	SALTVILLE - VA	Transmission		138.00	69.00	34.50	56.00	1			0	0.00
603	SALTVILLE - VA	Transmission		138.00	13.09		10.50	1			0	0.00
604	SALTVILLE - VA	Transmission		138.00	34.50		20.00	1			0	0.00
605	SCARBRO - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	9.60
606	SCHUYLER - VA	Distribution		46.00	7.20		2010.00	3			0	0.00
607	SCHUYLER - VA	Distribution		46.00	7.20		0.83	0	1		0	0.00
608	SCOTTSVILLE (AP) - VA	Transmission		46.00	12.00		5.00	0	1		0	0.00
609	SCOTTSVILLE (AP) - VA	Transmission		138.00	46.00		40.00	3			0	0.00
610	SCOTTSVILLE (AP) - VA	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	3.59
611	SCOTTSVILLE (AP) - VA	Transmission		46.00	13.09		9.38	1			0	0.00
612	SEVENTH STREET - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.40
613	SEVENTH STREET - VA	Distribution		69.00	12.00		69.80	3			0	0.00
614	SHABDUE - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	9.60
615	SHARPLES - WV	Distribution		46.00	12.00		4.69	1			0	0.00
616	SHARPLES - WV	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	9.60
617	SHAWSVILLE - VA	Distribution		138.00	13.09		10.50	1			0	0.00
618	SHEFFIELD (AP) - VA	Distribution		138.00	34.50		30.00	1			0	0.00
619	SHERIDAN (AP) - WV	Distribution		69.00	12.00		22.40	1			0	0.00
620	SHERWILL - VA	Distribution		69.00	12.00		20.00	1			0	0.00
621	SHIPMAN - VA	Distribution		46.00	12.00		4.70	1			0	0.00
622	SISSON - WV	Distribution		138.00	34.50		30.00	1			0	0.00
623	SKEGGS BRANCH - VA	Transmission		138.00	69.00	4.00	30.00	1			0	0.00
624	SKIMMER - VA	Distribution		69.00	12.00		30.00	1			0	0.00
625	SKIMMER - VA	Distribution		115.00	69.00		112.00	2			0	0.00
626	SKIMMER - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	26.40
627	SKIN FORK - WV	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	9.60
628	SKIN FORK - WV	Distribution		46.00	12.00		8.40	1			0	0.00
629	SLAB FORK - WV	Distribution		46.00	7.20		0.99	3			0	0.00
630	SLATE CREEK - VA	Distribution		69.00	13.09		20.00	1			0	0.00
631	SMITH LANE - VA	Distribution		34.50	12.00		6.25	1			0	0.00
632	SMYTH - VA	Distribution		138.00	34.50		25.00	1			0	0.00
633	SMYTH - VA	Distribution		138.00	36.20		30.00	1			0	0.00
634	SOLITE - VA	Distribution		69.00	12.00		5.25	1			0	0.00
635	SOPHIA - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	14.40
636	SOURWOOD - WV	Distribution		138.00	13.09		8.40	1			0	0.00
637	SOUTH BLUEFIELD - WV	Transmission		138.00	13.09		30.00	1			0	0.00
638	SOUTH BUFFALO - WV	Distribution		138.00	13.09		60.00	3			0	0.00
639	SOUTH BUFFALO - WV	Distribution		138.00	36.20		30.00	1			0	0.00
640	SOUTH CHARLESTON - WV	Distribution		46.00	12.00		22.40	1			0	0.00
641	SOUTH CHRISTIANSBURG - VA	Transmission		138.00	69.00	12.00	56.00	1			0	0.00
642	SOUTH CHRISTIANSBURG - VA	Transmission		138.00	13.09		20.00	1			0	0.00
643	SOUTH HILLS - WV	Distribution		46.00	13.09		25.00	1			0	0.00
644	SOUTH HILLS - WV	Distribution		46.00	12.00		22.40	1			0	0.00
645	SOUTH LYNCHBURG - VA	Transmission		138.00	13.09		40.00	2			0	0.00
646	SOUTH LYNCHBURG - VA	Transmission		138.00	69.00	34.50	50.00	1			0	0.00
647	SOUTH NEAL - WV	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.40
648	SOUTH NEAL - WV	Distribution		69.00	12.00		40.00	2			0	0.00
649	SOUTH PRINCETON - WV	Distribution		138.00	34.50		55.00	2			0	0.00
650	SOUTHRIDGE - WV	Distribution		138.00	13.09		20.00	1			0	0.00
651	SPEEDWAY - WV	Distribution		138.00	34.50		30.00	1			0	0.00
652	SPORN 138KV - WV	Transmission		138.00	13.09		20.00	1			0	0.00
653	SPORN 345KV - WV	Transmission		345.00	137.50	13.80	1350.00	3			0	0.00
654	SPRIGG - WV	Transmission		138.00	13.20	12.00	9.38	1			0	0.00
655	SPRIGG - WV	Transmission		138.00	34.50		25.00	1			0	0.00
656	SPRIGG - WV	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	72.00
657	SPRIGG - WV	Transmission		138.00	69.00	46.00	84.00	1			0	0.00
658	SPRIGG - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	9.60
659	SPRING CREEK - VA	Distribution		138.00	13.09		21.00	2			0	0.00
660	ST. ALBANS - WV	Distribution		138.00	13.09		50.00	2			0	0.00
661	STANLEYTOWN - VA	Distribution		69.00	12.00		22.40	1			0	0.00
662	STARKEY - VA	Distribution		138.00	13.09		40.00	2			0	0.00
663	STOCKTON - VA	Distribution		138.00	34.50		30.00	1			0	0.00
664	STONE BRANCH - WV	Distribution		138.00	34.50		25.00	1			0	0.00
665	STONE BRANCH - WV	Distribution		138.00	13.09		20.00	1			0	0.00
666	STOTESBURY - WV	Distribution		138.00	13.09		10.50	1			0	0.00
667	STUART - VA	Distribution		69.00	34.50		30.00	1			0	0.00
668	STUART - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	10.80
669	STUART - VA	Distribution		69.00	12.00		10.50	1			0	0.00
670	SUN MINE - WV	Distribution		46.00	12.00		20.00	1			0	0.00
671	SUNDIAL - WV	Transmission		138.00	69.00	46.00	90.00	1			0	0.00
672	SUNDIAL - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	9.60
673	SUNSCAPE - VA	Distribution		138.00	12.00		20.00	1			0	0.00
674	SWITCHBACK - WV	Transmission		138.00	34.50		25.00	1			0	0.00
675	SWITCHBACK - WV	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	50.40
676	TACKETT CREEK - WV	Distribution		138.00	13.09		25.00	1			0	0.00
677	TANK HILL - VA	Distribution		138.00	13.09		40.00	2			0	0.00
678	TAZEWELL - VA	Transmission		34.50	13.00		6.25	1			0	0.00
679	TAZEWELL - VA	Transmission		138.00	34.50		30.00	1			0	0.00
680	TAZEWELL - VA	Transmission		34.50	12.00		6.25	1			0	0.00
681	TAZEWELL - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	28.80
682	TEAYS - WV	Distribution		69.00	12.00		22.40	1			0	0.00
683	TECH DRIVE - VA	Distribution		138.00	12.00		20.00	1			0	0.00
684	THOMAS (AP) - VA	Distribution		34.50	7.20		3.00	3			0	0.00
685	THORNTON - VA	Distribution		138.00	34.50	12.00	7.50	1			0	0.00
686	THORNTON - VA	Distribution		138.00	13.09		9.38	1			0	0.00
687	TOMS FORK - WV	Distribution		46.00	12.00		4.69	1			0	0.00
688	TOMS FORK - WV	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	9.60
689	TONEY FORK - WV	Distribution		46.00	12.00		8.40	1			0	0.00
690	TOWER 117 - WV	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	13.19
691	TRAIL FORK - WV	Distribution		138.00	13.09		12.50	1			0	0.00
692	TRAMMEL - VA	Transmission		69.00	12.00		6.25	1			0	0.00
693	TRAP HILL - WV	Distribution		46.00	36.20		40.00	2			0	0.00
694	TRI-STATE - WV	Transmission		345.00	137.50	13.80	270.00	1			0	0.00
695	TRI-STATE - WV	Transmission		345.00	138.00	13.80		2			0	0.00
696	TULTEX - VA	Distribution		34.50	7.50		2.50	2			0	0.00
697	TULTEX - VA	Distribution		35	7		5	4			0	0
698	TURKEY PEN - VA	Distribution		69	12		11	1			0	0
699	TURNER - WV	Transmission		46	13		9	0	1		0	0
700	TURNER - WV	Transmission		138	71	46	54	0	1		0	0
701	TURNER - WV	Transmission		69	12		6	0	1		0	0
702	TURNER - WV	Transmission		138	13		20	0	1		0	0
703	TURNER - WV	Transmission		138	69	11	50	1			0	0
704	TURNER - WV	Transmission		138	69	46	84	1			0	0
705	TURNER - WV	Transmission		46	4		3	1			0	0
706	TURNER - WV	Transmission		138	13		22	1			0	0
707	TWENTY FOURTH STREET - WV	Distribution		35	4		6	1			0	0
708	UNITED FUEL GAS COMPANY - WV	Distribution		69	4		6	1			0	0
709	UPPER BRANCH - WV	Distribution		46	7		2	3			0	0
710	URY - WV	Distribution		46	12		20	1			0	0
711	VAN - WV	Distribution		69	12		6	1			0	0
712	VETERANS HOSPITAL - VA	Distribution		35	4		10	2			0	0
713	VICKER - VA	Distribution		138	13		20	1			0	0
714	VINTON - VA	Distribution		138	13		25	1			0	0
715	VINTON - VA	Distribution		138	35		30	1			0	0
716	WALNUT AVENUE - VA	Distribution		69	12		22	1			0	0
717	WALTON PARK - VA	Distribution		69	2		2	1			0	0
718	WARD HOLLOW - WV	Transmission		46	12		40	2			0	0
719	WARD HOLLOW - WV	Transmission		46	0	0	0			STATCAP	1	32
720	WASENA - VA	Distribution		69	12		20	1			0	0
721	WASENA - VA	Distribution		69	13		20	1			0	0
722	WAYNE - WV	Distribution		35	12		5	1			0	0
723	WAYNE - WV	Distribution		35	13		11	1			0	0
724	WELCH - WV	Distribution		138	13		22	1			0	0
725	WEST BASSETT - VA	Transmission		138	69	35	128	1			0	0
726	WEST BASSETT - VA	Transmission		69	0	0	0			STATCAP	1	29
727	WEST BASSETT - VA	Transmission		35	35		25	1			0	0
728	WEST HUNTINGTON - WV	Transmission		138	69	35	130	1			0	0
729	WEST HUNTINGTON - WV	Transmission		35	0	0	0			STATCAP	1	10
730	WEST HUNTINGTON - WV	Transmission		138	13		9	1			0	0
731	WEST HUNTINGTON - WV	Transmission		138	35		25	1			0	0
732	WEST SALEM - VA	Distribution		138	13		12	1			0	0
733	WESTLAKE - VA	Distribution		138	35		60	2			0	0
734	WHARNCLIFFE - WV	Transmission		46	0	0	0			STATCAP	1	10
735	WHEATLAND - VA	Distribution		69	12		20	1			0	0
736	WHETSTONE BRANCH - VA	Transmission		69	0	0	0			STATCAP	1	14
737	WHITESTICK - WV	Distribution		46	12		22	1			0	0
738	WILLIS GAP - VA	Distribution		138	35		20	1			0	0
739	WITT - VA	Distribution		69	4		13	1			0	0
740	WOOLWINE - VA	Distribution		69	35		25	1			0	0
741	WURNO - VA	Distribution		138	35		30	1			0	0
742	WURNO - VA	Distribution		138	0	0	0			STATCAP	1	14
743	WYOMING - WV	Transmission		765	138	12	250	1			0	0
744	WYOMING - WV	Transmission		138	0	0	0			Air Core Reactor	6	0
745	WYOMING - WV	Transmission		765	138	14	1250	5			0	0
746	WYOMING - WV	Transmission		765						REACTOR	3	300
747	WYTHE - VA	Transmission		138	0	0	0			STATCAP	1	50
748	WYTHE - VA	Transmission		138	35		35	1			0	0
749	WYTHE - VA	Transmission		138	69	35	84	1			0	0
750	WYTHE - VA	Transmission		138	34		25	1			0	0
751	TotalTransmissionSubstationMember											15,303
752	Total											15,303

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: Date of Incorporation: 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

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

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	Julia A. Sloat, Vice President and Chief Financial Officer	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, Vice President and Secretary	Columbus, Ohio	false	false
6	Ann P. Kelly, Vice President and Chief Financial Officer	Columbus, Ohio	false	false
7	Therace M. Risch, Vice President	Columbus, Ohio	false	false
8	Peggy I.Simmons, Vice President	Columbus, Ohio	false	false
9	Toby L. Thomas, Vice President	New Albany, Ohio	false	false
10	Rajagopalan.Sundararajan, Vice President	Columbus, Ohio	false	false
11	Phillip R.Ulrich,Vice President	Columbus, Ohio	false	false
12	Aaron D.Walker, President, Chief Operating Officer and Vice President	Charleston, WV	false	false
13	Lisa M. Barton, Vice President	Columbus, Ohio	false	false
14	Charles R. Patton, Vice President	Columbus, Ohio	false	false
15	Note: The Respondent does not have an Executive Committee.

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.

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

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	20221208-5094	12/08/2022	ER17-405	AEP PJM OATT Proj Transmission	PJM OATT Attachment H-14
2	20221101-5174	11/01/2022	ER17-405	AEP PJM OATT Proj Transmission	PJM OATT Attachment H-14
3	20220527-5370	05/27/2022	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	17,088,387,450	16,401,181,030
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	711,076,450	471,403,315
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		17,799,463,900	16,872,584,345
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	6,119,554,019	5,765,578,075
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		11,679,909,881	11,107,006,270
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)		11,679,909,881	11,107,006,270
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)
17	OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS
18	NonutilityProperty Nonutility Property (121)		19,716,711	13,295,371
19	AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Prov. for Depr. and Amort. (122)		5,345,122	5,192,401
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224	7,078,398	4,641,308
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances	228	22,901,397	22,004,289
24	OtherInvestments Other Investments (124)		178,111,548	205,198,349
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)		149,639,072	216,680,819
30	DerivativeInstrumentAssetsLongTerm Long-Term Portion of Derivative Assets (175)
31	DerivativeInstrumentAssetsHedgesLongTerm Long-Term Portion of Derivative Assets - Hedges (176)
32	OtherPropertyAndInvestments TOTAL Other Property and Investments (Lines 18-21 and 23-31)		372,102,004	456,627,735
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)		7,486,465	2,496,136
36	SpecialDeposits Special Deposits (132-134)		22,063,688	89,614,237
37	WorkingFunds Working Fund (135)
38	TemporaryCashInvestments Temporary Cash Investments (136)
39	NotesReceivable Notes Receivable (141)
40	CustomerAccountsReceivable Customer Accounts Receivable (142)		173,834,591	166,951,944
41	OtherAccountsReceivable Other Accounts Receivable (143)		234,124	162,884
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		1,719,326	1,629,934
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)		90,736,053	127,358,814
45	FuelStock Fuel Stock (151)	227	151,723,238	61,380,905
46	FuelStockExpensesUndistributed Fuel Stock Expenses Undistributed (152)	227	7,213,740	5,704,904
47	Residuals Residuals (Elec) and Extracted Products (153)	227		6,791
48	PlantMaterialsAndOperatingSupplies Plant Materials and Operating Supplies (154)	227	130,152,009	109,053,857
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	23,345,718	22,794,207
53	NoncurrentPortionOfAllowances (Less) Noncurrent Portion of Allowances	228	22,901,397	22,004,289
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)		8,271,859	7,799,236
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)		44,764	365
60	RentsReceivable Rents Receivable (172)		1,463,031	1,277,779
61	AccruedUtilityRevenues Accrued Utility Revenues (173)		91,259,622	54,013,000
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)
63	DerivativeInstrumentAssets Derivative Instrument Assets (175)		69,090,847	41,975,558
64	DerivativeInstrumentAssetsLongTerm (Less) Long-Term Portion of Derivative Instrument Assets (175)
65	DerivativeInstrumentAssetsHedges Derivative Instrument Assets - Hedges (176)
66	DerivativeInstrumentAssetsHedgesLongTerm (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176)
67	CurrentAndAccruedAssets Total Current and Accrued Assets (Lines 34 through 66)		752,299,026	666,956,394
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		30,972,977	28,847,639
70	ExtraordinaryPropertyLosses Extraordinary Property Losses (182.1)	230a	75,567,634	79,082,399
71	UnrecoveredPlantAndRegulatoryStudyCosts Unrecovered Plant and Regulatory Study Costs (182.2)	230b
72	OtherRegulatoryAssets Other Regulatory Assets (182.3)	232	1,757,037,534	1,129,473,642
73	PreliminarySurveyAndInvestigationCharges Prelim. Survey and Investigation Charges (Electric) (183)		7,842,200	5,487,298
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)		134,448	144,576
77	TemporaryFacilities Temporary Facilities (185)
78	MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186)	233	99,027,251	92,952,422
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)		74,394,767	78,193,342
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	497,096,485	488,763,374
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		2,542,073,296	1,902,944,692
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		15,346,384,207	14,133,535,091

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	1,828,635,966	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	2,894,696,533	2,538,035,582
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)	4,855,291	24,379,199
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		4,975,471,763	4,648,036,287
17	LongTermDebtAbstract LONG-TERM DEBT
18	Bonds Bonds (221)	256	174,174,260	200,079,231
19	ReacquiredBonds (Less) Reaquired Bonds (222)	256
20	AdvancesFromAssociatedCompanies Advances from Associated Companies (223)	256
21	OtherLongTermDebt Other Long-Term Debt (224)	256	5,282,813,015	4,782,910,721
22	UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225)
23	UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Debit (226)		15,461,240	15,252,087
24	LongTermDebt Total Long-Term Debt (lines 18 through 23)		5,441,526,034	4,967,737,864
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		80,754,270	80,452,977
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		2,914,692	5,159,571
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		10,715,639	10,921,258
30	AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4)
31	AccumulatedProvisionForRateRefunds Accumulated Provision for Rate Refunds (229)		18,532,621
32	LongTermPortionOfDerivativeInstrumentLiabilities Long-Term Portion of Derivative Instrument Liabilities		74,470	2,137
33	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges Long-Term Portion of Derivative Instrument Liabilities - Hedges
34	AssetRetirementObligations Asset Retirement Obligations (230)		427,779,151	404,622,571
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		540,621,902	501,158,515
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)
38	AccountsPayable Accounts Payable (232)		451,229,361	262,186,705
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)		182,155,076	199,282,967
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		142,594,329	118,534,546
41	CustomerDeposits Customer Deposits (235)		75,090,133	73,923,266
42	TaxesAccrued Taxes Accrued (236)	262	88,506,737	81,703,750
43	InterestAccrued Interest Accrued (237)		57,935,097	47,869,294
44	DividendsDeclared Dividends Declared (238)
45	MaturedLongTermDebt Matured Long-Term Debt (239)
46	MaturedInterest Matured Interest (240)
47	TaxCollectionsPayable Tax Collections Payable (241)		4,735,041	4,696,419
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		66,311,001	51,649,564
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		22,838,869	22,748,700
50	DerivativesInstrumentLiabilities Derivative Instrument Liabilities (244)		3,544,080	819,652
51	LongTermPortionOfDerivativeInstrumentLiabilities (Less) Long-Term Portion of Derivative Instrument Liabilities		74,470	2,137
52	DerivativeInstrumentLiabilitiesHedges Derivative Instrument Liabilities - Hedges (245)
53	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges
54	CurrentAndAccruedLiabilities Total Current and Accrued Liabilities (lines 37 through 53)		1,095,014,194	863,412,725
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)
57	AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255)	266	295,219	306,934
58	DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256)
59	OtherDeferredCredits Other Deferred Credits (253)	269	33,465,774	32,700,650
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	766,020,836	821,478,629
61	UnamortizedGainOnReacquiredDebt Unamortized Gain on Reaquired Debt (257)
62	AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty Accum. Deferred Income Taxes-Accel. Amort.(281)	272	130,828,743	143,723,636
63	AccumulatedDeferredIncomeTaxesOtherProperty Accum. Deferred Income Taxes-Other Property (282)		1,559,673,492	1,507,749,250
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		803,466,246	647,230,599
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		3,293,750,310	3,153,189,698
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		15,346,384,203	14,133,535,089

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	3,626,108,552	3,141,973,453			3,626,108,552	3,141,973,453
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	1,947,769,256	1,594,399,774			1,947,769,256	1,594,399,774
5	MaintenanceExpense Maintenance Expenses (402)	320	297,919,962	265,523,828			297,919,962	265,523,828
6	DepreciationExpense Depreciation Expense (403)	336	519,572,661	497,621,638			519,572,661	497,621,638
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336	7,242,048	3,452,247			7,242,048	3,452,247
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	44,876,903	41,256,314			44,876,903	41,256,314
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)		35,244,275	8,179,991			35,244,275	8,179,991
13	RegulatoryCredits (Less) Regulatory Credits (407.4)		37,037,015	524,237			37,037,015	524,237
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	157,876,769	148,738,854			157,876,769	148,738,854
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	54,522,666	9,367,566			54,522,666	9,367,566
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	124,453	2,592,072			124,453	2,592,072
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	480,566,371	449,012,755			480,566,371	449,012,755
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	403,636,935	431,854,357			403,636,935	431,854,357
19	InvestmentTaxCreditAdjustments Investment Tax Credit Adj. - Net (411.4)	266	9,420	9,420			9,420	9,420
20	GainsFromDispositionOfPlant (Less) Gains from Disp. of Utility Plant (411.6)		628,614	531,291			628,614	531,291
21	LossesFromDispositionOfServiceCompanyPlant Losses from Disp. of Utility Plant (411.7)			6,086				6,086
22	GainsFromDispositionOfAllowances (Less) Gains from Disposition of Allowances (411.8)		742,500	59			742,500	59
23	LossesFromDispositionOfAllowances Losses from Disposition of Allowances (411.9)
24	AccretionExpense Accretion Expense (411.10)		5,454,874	1,381,730			5,454,874	1,381,730
25	UtilityOperatingExpenses TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)		3,003,916,410	2,592,708,386			3,003,916,410	2,592,708,386
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		622,192,142	549,265,067			622,192,142	549,265,067
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)		435	684
35	NonoperatingRentalIncome Nonoperating Rental Income (418)		127,209	21,806
36	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1)	119
37	InterestAndDividendIncome Interest and Dividend Income (419)		3,065,740	898,177
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		11,692,346	15,567,699
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		942,659	637,741
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)		13,695,255	59,242
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		29,268,356	17,183,981
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)		1,133,704	417,560
44	MiscellaneousAmortization Miscellaneous Amortization (425)
45	Donations Donations (426.1)		13,706,762	1,708,560
46	LifeInsurance Life Insurance (426.2)
47	Penalties Penalties (426.3)		52,256	212,059
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		1,732,368	1,680,552
49	OtherDeductions Other Deductions (426.5)		10,258,826	6,758,655
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		26,883,916	10,353,268
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262	345,639	314,263
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262	5,947,311	4,423,826
54	IncomeTaxesOther Income Taxes-Other (409.2)	262	379,536	430,325
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272	5,867,151	2,317,737
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272	3,062,324	4,004,143
57	InvestmentTaxCreditAdjustmentsNonutilityOperations Investment Tax Credit Adj.-Net (411.5)		2,295	2,437
58	InvestmentTaxCredits (Less) Investment Tax Credits (420)
59	TaxesOnOtherIncomeAndDeductions TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)		3,178,676	6,228,731
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		5,563,117	13,059,444
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		224,447,697	211,947,638
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		4,358,897	4,116,805
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)		3,798,575	3,866,685
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)		5,565,782	137,743
68	OtherInterestExpense Other Interest Expense (431)		1,888,082	854,617
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		6,464,727	7,536,033
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		233,594,306	213,387,455
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		394,160,953	348,937,056
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)		394,160,953	348,937,056

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		2,518,949,597	2,233,348,136
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
9	AdjustmentsToRetainedEarningsCredit TOTAL Credits to Retained Earnings (Acct. 439)
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)		394,160,952	348,937,056
17	AppropriationsOfRetainedEarningsAbstract Appropriations of Retained Earnings (Acct. 436)
17.1	AppropriationsOfRetainedEarnings Appropriations of Retained Earnings (Acct. 436)			835,595
17.2	AppropriationsOfRetainedEarnings Excess Earnings on Hydro Licensed Projects
22	AppropriationsOfRetainedEarnings TOTAL Appropriations of Retained Earnings (Acct. 436)			835,595
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		37,500,000	62,500,000
36	DividendsDeclaredCommonStock TOTAL Dividends Declared-Common Stock (Acct. 438)		37,500,000	62,500,000
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)		2,875,610,549	2,518,949,597
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	19,085,985
47	AppropriatedRetainedEarningsIncludingReserveAmortization TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)		19,085,984	19,085,985
48	RetainedEarnings TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)		2,894,696,533	2,538,035,582
	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)	394,160,953	348,937,056
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	575,786,507	546,425,093
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of Regulatory Debits and Credits	1,792,739	7,655,755
5.2	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Customer Deposits	1,166,867	3,895,830
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	79,734,263	15,471,992
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)	11,715	11,857
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	29,528,615	79,468,006
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	112,942,532	116,670,745
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory	551,511	372,157
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	206,891,285	15,762,573
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	89,502,713	65,247,305
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	44,363,447	28,775,303
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	11,692,346	15,567,699
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other (provide details in footnote):	(a) 44,779,056	105,960,212
18.2	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Over/Under Recovered Fuel, net	501,807,801	195,996,845
18.3	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Impairment of Long-Lived Assets	24,855,449
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	593,406,974	613,178,606
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)	1,058,810,437	859,309,687
27	GrossAdditionsToNuclearFuelInvestingActivities Gross Additions to Nuclear Fuel
28	GrossAdditionsToCommonUtilityPlantInvestingActivities Gross Additions to Common Utility Plant
29	GrossAdditionsToNonutilityPlantInvestingActivities Gross Additions to Nonutility Plant	7,253,727	10,598
30	AllowanceForOtherFundsUsedDuringConstructionInvestingActivities (Less) Allowance for Other Funds Used During Construction	11,692,346	15,567,699
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
31.1	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Other (provide details in footnote):
31.2	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Acquired Assets	953,330	684,622
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	1,055,325,148	844,437,208
36	AcquisitionOfOtherNoncurrentAssets Acquisition of Other Noncurrent Assets (d)
37	ProceedsFromDisposalOfNoncurrentAssets Proceeds from Disposal of Noncurrent Assets (d)	(b) 33,650,706	6,497,418
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
52	NetIncreaseDecreaseInPayablesAndAccruedExpensesInvestingActivities Net Increase (Decrease) in Payables and Accrued Expenses
53	OtherAdjustmentsToCashFlowsFromInvestmentActivities Other (provide details in footnote):
53.1	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Contribution in Aid of Construction Proceeds	(c) 9,814,905	8,748,660
53.2	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription (Increase) Decrease in other special deposits	6,513,339	6,470,985
53.3	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Notes Receivable from Associated Companies
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	1,005,346,197	835,662,115
59	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
60	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
61	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b)	704,375,000	500,000,000
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	6,345,387	5,998,004
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
67.1	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Proceeds on Capital Leaseback	711,092	741,069
67.2	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Notes Payable to Associates Companies		180,643,071
67.3	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Capital Contributions from Parent	9,015
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	698,749,720	675,386,136
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)	230,377,676	392,977,930
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	17,127,891
78	NetDecreaseInShortTermDebt Net Decrease in Short-Term Debt (c)
80	DividendsOnPreferredStock Dividends on Preferred Stock
81	DividendsOnCommonStock Dividends on Common Stock	37,500,000	62,500,000
83	CashFlowsProvidedFromUsedInFinancingActivities Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)	413,744,153	219,908,206
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)	1,804,929	2,575,303
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	20,102,262	22,677,565
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	21,907,191	20,102,262

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	5,773,420
3	Administrative and General Expenses - Operation	AEPSC	920-926,928,930-931	15,524,672
4	Audit Services	AEPSC	920,923	1,474,972
5	Barging	I&M	1510	36,148,413
6	Bus Ops & Perf Assurance	AEPSC	920,923	1,779,480
7	Civil & Political Activities and Other Svcs	AEPSC	426	1,708,055
8	Construction Services	AEPSC	107, 108	162,086,509
9	Construction Services	KgPCo	107, 108	1,931,510
10	Corp Safety & Health	AEPSC	920,923	2,276,177
11	Corporate Accounting	AEPSC	920,923	3,164,030
12	Corporate Communications	AEPSC	920,923	1,318,831
13	Corporate Human Resources	AEPSC	920, 923	4,516,034
14	Corporate Planning & Budgeting	AEPSC	920,923	1,878,931
15	Customer Accounts Expenses	AEPSC	901-903,905	17,851,279
16	Customer Accounts Expenses	KGPCO	902,903	275,191
17	Customer Operations and Support	KgPCo	920,923	679,149
18	Customer Service and Informational Expenses	AEPSC	907,908,910	315,576
19	Distribution Expenses - Operation	AEPSC	580-584,586-589	6,611,405
20	Distribution Expenses - Operation	KGPCO	580,583,586-588	405,895
21	Distribution Expenses - Maintenance	AEPSC	590-598	1,894,019
22	Distribution Expenses - Maintenance	I&M	593-597	402,383
23	Distribution Expenses - Maintenance	KGPCO	590,593-596,598	1,093,243
24	Economic & Business Development	AEPSC	920,923	514,003
25	Environmental Services	AEPSC	920, 923	753,449
26	Factored Customer A/R Bad Debts	AEP Credit	426	4,682,152
27	Factored Customer A/R Expense	AEP Credit	426	4,746,500
28	Fuel & Storeroom Services	AEPSC	152,163	11,825,803
29	Grid Solutions	AEPSC	920,923	810,738
30	Hydraulic Power Generation - Maintenance	AEPSC	541-545	939,036
31	Hydraulic Power Generation - Operation	AEPSC	535,537-540	3,799,900
32	Information Technology	AEPSC	920,923	10,042,070
33	Infrastructure Ops & Support	AEPSC	920,923	1,539,234
34	Legal GC/Administration	AEPSC	920,923	8,467,056
35	Materials and Supplies	I&M	107.154.500,502,506,511-514,544,592,935	366,757
36	Materials and Supplies	KPCO	107-108,163,511-514,571,935	315,895
37	Materials and Supplies	OPCO	107-108,184,186,512-513,560,562,570-571,592,930,935	6,736,236
38	Nuclear Power Generation - MaintenanceOperations & Performance Transformation	AEPSC	920,923	769,969
39	Other Power Supply Expenses	AEPSC	556-557	7,305,943
40	Physical & Cyber Security	AEPSC	920,923	1,565,627
41	Real Estate & Workplace Svcs	AEPSC	920,923	2,754,429
42	Regulatory Services	AEPSC	920,923	2,087,998
43	Research and Other Services	AEPSC	183-184,186,188	6,333,527
44	Steam Power Generation - Maintenance	AEPSC	510-514	5,504,713
45	Steam Power Generation - Operation	AEPSC	500-502,506	20,265,371
46	Strategy & Transformation	AEPSC	920,923	383,157
47	Tax Services	AEPSC	920,923	1,398,850
48	Transmission Expenses - Maintenance	AEPSC	568-573	6,184,886
49	Transmission Expenses - Operation	AEPSC	560-567,920,923	21,985,453
50	Treasury & Risk	AEPSC	920,923	3,074,992
51	Urea	KPCO	154	758,851
19
20	Non-power Goods or Services Provided for Affiliated
21	Administrative and General Expenses - Maintenance	KPCO	935	263,657
22	Building and Property Leases	AEPSC	454	3,301,173
23	Central Machine Shop	I&M	107-108,163,501,506,512-513,524,531-532,544	2,704,159
24	Central Machine Shop	KPCo	107-108,506,511-514,570,592	1,012,304
25	Central Machine Shop	PSO	107-108,500-513,546,549,553	891,063
26	Central Machine Shop	SWEPCo	107,108,512,513.00	312,588
27	Construction Services	KGPCO	107,108	5,469,638
28	Construction Services	KPCO	107,108	591,918
29	Construction Services	WPCO	(b) 107,108	970,065
30	Construction Services	WVTCo	107,108	1,240,736
31	Distribution Expenses - Maintenance	KgPCo	593-597	362,850
32	Distribution Expenses - Maintenance	WPCo	593-594,597	1,129,884
33	Expenses of Nonutility Operations	I&M	417	5,015,372
34	Facility Rent	WVTCo	454	2,906,577
35	Fleet and Vehicle Charges	AEPSC	See Footnote	4,298,675
36	O&M Services for Jointly Owned Facility - Sporn	AEP Generation Resources	408,500,506,925-926	682,217
37	Other Operating Revenues	OPCO	456	825,634
38	Other Operating Revenues	PSO	456	277,897
39	Service and Administration Fees	Appalachian Rate Relief Fund	456	290,150
40	Urea	KPCO	154	818,932
41	Use of Jointly Owned Facility	APTCO	454	1,928,246
42	Use of Jointly Owned Facility	WVTCo	454	595,278
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