FERC Form

Name of Respondent:

SWEPCO

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.			Acquisitions and Impairments
8.			Benefit Plans
9.			Business Segments
10.			Derivatives and Hedging
11.			Fair Value Measurements
12.			Income Taxes
13.			Leases
14.			Financing Activities
15.			Related Party Transactions
16.			Property, Plant and Equipment
17.			Revenue from Contracts with Customers

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

AEGCo						AEP Generating Company, an AEP electric utility subsidiary.
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 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.
APSC						Arkansas Public Service Commission.

ARO						Asset Retirement Obligations.
CLECO						Central Louisiana Electric Company, a nonaffiliated utility company.

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.
DHLC						Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.
EIS						Energy Insurance Services, Inc., a nonaffiliated captive insurance company.
Energy Supply						AEP Energy Supply LLC, a nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.
Excess ADIT						Excess accumulated deferred income taxes.
FAC						Fuel Adjustment Clause.
FASB						Financial Accounting Standards Board.
Federal EPA						United States Environmental Protection Agency.
FERC						Federal Energy Regulatory Commission.


FTR						Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP						Accounting Principles Generally Accepted in the United States of America.

IRS						Internal Revenue Service.
ITC						Investment Tax Credit.
KPCo						Kentucky Power Company, an AEP electric utility subsidiary.
LPSC						Louisiana Public Service Commission.


Maverick						Maverick, part of the North Central Wind Energy Facilities, consists of 287 MWs of wind generation in Oklahoma.
MMBtu						Million British Thermal Units.
MTM						Mark-to-Market.
MW						Megawatt.
MWh						Megawatt-hour.
NCWF						North Central Wind Energy Facilities, a joint PSO and SWEPCo project, which includes three Oklahoma wind facilities totaling approximately 1,484 MWs of wind generation.
NOL						Net operating losses.
NOLC						Net operating loss carryforwards.
OATT						Open Access Transmission Tariff.
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.
Parent						American Electric Power Company, Inc., the equity owner of AEP subsidiaries.

PPA						Purchase Power and Sale Agreement.

PSO						Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PTC						Production Tax Credit.
PUCT						Public Utility Commission of Texas.
Risk Management Contracts						Trading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges.
ROE						Return on Equity.
RTO						Regional Transmission Organization, responsible for moving electricity over large interstate areas.

SIA						System Integration Agreement, effective June 15, 2000, as amended, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP.

SPP						Southwest Power Pool regional transmission organization.

Sundance						Sundance, acquired in April 2021 as part of the North Central Wind Energy Facilities, consists of 199 MWs of wind generation in Oklahoma.
SWEPCo						Southwestern Electric Power Company, an AEP electric utility subsidiary.
Tax Reform						On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018.
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.
Traverse						Traverse, part of the North Central Wind Energy Facilities, consists of 998 MWs of wind generation in Oklahoma.
Turk Plant						John W. Turk, Jr. Plant, a 650 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.
Utility Money Pool						Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
WPCo						Wheeling Power Company, an AEP electric utility subsidiary.

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION

As a public utility, SWEPCo engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to approximately 551,000 retail customers in its service territory in northeastern and the panhandle of Texas, northwestern Louisiana and western Arkansas. SWEPCo sells electric power at wholesale to other utilities, municipalities and electric cooperatives.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Rates and Service Regulation

SWEPCo’s rates are regulated by the FERC and the APSC, LPSC and PUCT. The FERC also regulates SWEPCo’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. SWEPCo’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 SWEPCo 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 APSC, LPSC and PUCT regulate all of the retail distribution operations and rates of SWEPCo’s retail public utility subsidiaries on a cost basis. The APSC, LPSC and PUCT also regulate the retail generation/power supply operations and rates.

The FERC also regulates SWEPCo’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.

In addition, the FERC regulates the SIA, Operating Agreement and TCA, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. See Note 15 - Related Party Transactions for additional information.

Basis of Accounting

SWEPCo’s accounting is subject to the requirements of the APSC, LPSC and PUCT 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 accounting for transactions with Sabine Mining Company as a nonaffiliated company rather than consolidating the entity in accordance with the accounting guidance for “Variable Interest Entities.”
·			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 SPP purchases as operation expenses instead of a reduction in revenue.



·			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 presentation of over/under fuel recovery in revenue rather than as a component 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 accrued unbilled revenue as a current and accrued asset rather than netted against accounts payable for affiliated companies.
·			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 plant impairment in utility plant adjustments rather than in property, plant and equipment - electric generation.
·			The classification of plant impairment in utility plant adjustments rather than in property, plant and equipment - accumulated 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 unrecovered plant costs as accumulated depreciation instead of regulatory assets.


·			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 cloud computing implementation costs as Utility Plant rather than as a noncurrent asset.
·			The classification of the amortization of certain regulatory assets as regulatory debits and credits rather than depreciation and amortization.

Accounting for the Effects of Cost-Based Regulation

SWEPCo’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,		(in millions)
Cash was Paid (Received) for:
	Interest (Net of Capitalized Amounts)	$	125.5		$	110.6
	Income Taxes (Net of Refunds)			(36.2)			(37.2)
Noncash Acquisitions Under Finance Leases				3.6			4.7
As of December 31,
Construction Expenditures Included in Current and Accrued Liabilities				105.6			69.0

AEP System Tax Allocation

SWEPCo and other AEP subsidiaries 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 SWEPCo and other AEP subsidiaries through a reduction of current tax expense. In the first quarter of 2022, SWEPCo and other AEP subsidiaries 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 SWEPCo’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 inventories 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, SWEPCo 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 SWEPCo. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest

in the billed and unbilled receivables they acquire from affiliated utility subsidiaries. See “Securitized Accounts Receivable – AEP Credit” section of Note 14 for additional information.

Allowance for Uncollectible Accounts

Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from SWEPCo. The assessment is performed by SWEPCo, which inherently contemplates any differences in geographical risk characteristics for the allowance. 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 (Applies to Registrant Subsidiaries)

SWEPCo does not have any significant customers that comprise 10% or more of its operating revenues for the years ended December 31, 2022 and 2021.

SWEPCo monitors credit levels and the financial condition of its customers on a continuous basis to minimize credit risk. The APSC, LPSC and PUCT allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying financial statements.

Property, Plant and Equipment

Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs accrued are charged to accumulated depreciation. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses.

Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in-service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed or is not

probable, the cost of that asset shall be 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.

Investment in Subsidiary Companies

SWEPCo has two wholly-owned subsidiaries, DHLC, which is engaged in lignite-mining operations and Southwest Arkansas Utilities Corporation, which is engaged in right of way acquisition. Investment in the net assets of DHLC is carried at cost plus equity in its undistributed earnings since acquisition. Investment in the net assets of Southwest Arkansas Utilities Corporation is carried at cost.

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

SWEPCo 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, wind farms and certain coal-mining facilities. AROs are computed as the present value of the estimated costs associated with the future retirement of an asset and are recorded in the period in which the liability is incurred. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be decommissioned, inflation, and discount rate, which may change significantly over time. The estimated costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. SWEPCo 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 SWEPCo plans to use their facilities indefinitely. The retirement obligation would only be recognized if and when SWEPCo 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 trusts. 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 benefits 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 incorporated into the development of future fuel rates billed to or refunded to customers. The amount of an over-recovery or under-recovery can also be affected by actions of the APSC, LPSC and PUCT. On a routine basis, the APSC, LPSC and PUCT review and/or audit SWEPCo’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. SWEPCo 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, non-existent or not applicable to merchant operations, changes in fuel costs or sharing of off-system sales impact earnings.

Revenue Recognition

Regulatory Accounting

SWEPCo’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

SWEPCo recognizes revenues from customers for retail and wholesale electricity sales and electricity transmission and distribution delivery services. SWEPCo 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. In accordance with the APSC’s, LPSC’s and PUCT’s regulatory treatment, SWEPCo does not include the fuel portion in unbilled revenue, but rather recognizes such revenues when billed to customers.

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 SWEPCo in the fourth quarter of each calendar year and a final annual true-up is recognized by SWEPCo in the second quarter of each calendar year following the filing of annual FERC reports. Any portion of the true-ups applicable to an affiliated company is recorded as Accounts Receivable from Associated Companies or Accounts Payable to Associated Companies on the balance sheets. Any portion of the true-ups applicable to third-parties is recorded as regulatory assets or regulatory liabilities on the balance sheets. See Note 17 - Revenue from Contracts with Customers for additional information.

Gross versus Net Presentation of Certain Electricity Supply and Delivery Activities

Most of the power produced at the generation plants is sold to SPP. SWEPCo also purchases power from SPP 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 SPP, 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, SWEPCo records expenses when purchased electricity is received and when expenses are incurred. SWEPCo defers unrealized MTM amounts as regulatory assets (for losses) and regulatory liabilities (for gains).

Energy Marketing and Risk Management Activities

SWEPCo 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. SWEPCo 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.

SWEPCo 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 transactions that are not derivatives are also recognized upon delivery of the commodity. SWEPCo 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 the balance sheets as Derivative Instrument Assets or Liabilities, as appropriate, and on the statements of income in Operating Revenues. SWEPCo includes realized gains and losses on marketing and risk management transactions 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 SWEPCo 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, SWEPCo subsequently reclassifies the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their statements of income. See “Accounting for Cash Flow Hedging Strategies” section of Note 10 for additional information.

Maintenance

SWEPCo expenses maintenance costs as incurred. If it becomes probable that SWEPCo 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. SWEPCo defers costs above the level included in base rates and amortizes those deferrals commensurate with recovery through rate riders.

Income Taxes and Investment and Production Tax Credits

SWEPCo 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.

SWEPCo 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. Alternatively, PTCs reduce income tax expense as they are earned. PTCs are earned when electricity is produced.

SWEPCo accounts for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” SWEPCo 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, SWEPCo collects from customers certain excise taxes levied by those state or local governments on customers. SWEPCo 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

SWEPCo participates in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans. Substantially all SWEPCo employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. SWEPCo also participates in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees. SWEPCo is allocated a proportionate share of benefit costs and account for their participation in these plans as multiple-employer plans. See Note 8 - Benefit Plans for additional information including significant accounting policies associated with the plans.

Investments Held in Trust for Future Liabilities

AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits. All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations. The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance.

Benefit Plans

All benefit plan assets are invested in accordance with each plan’s investment policy. The investment policy outlines the investment objectives, strategies and target asset allocations by plan.

The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns. Strategies used include:

•Maintaining a long-term investment horizon.

•Diversifying assets to help control volatility of returns at acceptable levels.

•Managing fees, transaction costs and tax liabilities to maximize investment earnings.

•Using active management of investments where appropriate risk/return opportunities exist.

•Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks.

•Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification.

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 SWEPCo’s business. There are no new standards expected to have a material impact on SWEPCo’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 8 - 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	$	1.2	$	(4.4)	$	9.9	$	6.7
Change in Fair Value Recognized in AOCI, Net of Tax	—		—		(9.2)		(9.2)
Amount of (Gain) Loss Reclassified from AOCI
Interest on Long-Term Debt (a)	(0.1)		—		—		(0.1)
Amortization of Prior Service Cost (Credit)	—		(2.0)		—		(2.0)
Reclassifications from AOCI, before Income Tax (Expense) Benefit	(0.1)		(2.0)		—		(2.1)
Income Tax (Expense) Benefit	—		(0.4)		—		(0.4)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	(0.1)		(1.6)		—		(1.7)
Net Current Period Other Comprehensive Income (Loss)	(0.1)		(1.6)		(9.2)		(10.9)
Balance in AOCI as of December 31, 2022	$	1.1	$	(6.0)	$	0.7	$	(4.2)


			Pension and OPEB
			Amortization		Changes in
	Cash Flow Hedge –		of Deferred		Funded
For the Year Ended December 31, 2021	Interest Rate		Costs		Status		Total
	(in millions)
Balance in AOCI as of December 31, 2020	$	(0.3)	$	(2.8)	$	5.0	$	1.9
Change in Fair Value Recognized in AOCI, Net of Tax	—		—		4.9		4.9
Amount of (Gain) Loss Reclassified from AOCI
Interest on Long-Term Debt (a)	1.9		—		—		1.9
Amortization of Prior Service Cost (Credit)	—		(2.0)		—		(2.0)
Reclassifications from AOCI, before Income Tax (Expense) Benefit	1.9		(2.0)		—		(0.1)
Income Tax (Expense) Benefit	0.4		(0.4)		—		—
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	1.5		(1.6)		—		(0.1)
Net Current Period Other Comprehensive Income (Loss)	1.5		(1.6)		4.9		4.8
Balance in AOCI as of December 31, 2021	$	1.2	$	(4.4)	$	9.9	$	6.7

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

4. RATE MATTERS

SWEPCo is involved in rate and regulatory proceedings at the FERC and the APSC, LPSC and PUCT. Rate matters can have a material impact on net income, cash flows and possibly financial condition. SWEPCo’s recent significant rate orders and pending rate filings are addressed in this note.

2012 Texas Base Rate Case

In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs.

Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, SWEPCo reversed $114 million of a previously recorded regulatory disallowance in 2013. In 2017, the Texas District Court upheld the PUCT’s 2014 order and intervenors filed appeals with the Texas Third Court of Appeals.

In July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court. In March 2021, the Texas Supreme Court issued an opinion reversing the July 2018 judgment of the Texas Third Court of Appeals and agreeing with the PUCT’s judgment affirming the prudence of the Turk Plant. In addition, the Texas Supreme Court remanded the AFUDC dispute back to the Texas Third Court of Appeals. No parties filed a motion for rehearing with the Texas Supreme Court. In August 2021, the Texas Third Court of Appeals reversed the Texas District Court judgment affirming the PUCT’s order on AFUDC, concluding that the language of the PUCT’s original 2008 order intended to include AFUDC in the Texas jurisdictional capital cost cap, and remanded the case to the PUCT for future proceedings. SWEPCo disagrees with the Court of Appeals decision. SWEPCo and the PUCT submitted Petitions for Review with the Texas Supreme Court in November 2021. In October 2022, the Texas Supreme Court denied the Petitions for Review submitted by SWEPCo and the PUCT. In December 2022, SWEPCo and the PUCT filed requests for rehearing with the Texas Supreme Court. The Texas Supreme Court requested comments on rehearing by March 1, 2023. If SWEPCo’s request for rehearing is denied, the case will be remanded to the PUCT for future proceedings.

Management does not believe a disallowance of capitalized Turk Plant costs or a revenue refund is probable as of December 31, 2022. However, if SWEPCo is ultimately unable to recover AFUDC in excess of the Texas jurisdictional capital cost cap, it would be expected to result in a pretax net disallowance ranging from $80 million to $90 million. In addition, if AFUDC is ultimately determined to be included in the Texas jurisdictional capital cost cap, SWEPCo estimates it may be required to make customer refunds ranging from $0 to $185 million related to revenues collected from February 2013 through December 2022 and such determination may reduce SWEPCo’s future revenues by approximately $15 million on an annual basis.

2016 Texas Base Rate Case

In 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% ROE. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a ROE of 9.6%, effective May 2017. The final order also included: (a) approval to recover the Texas jurisdictional share of environmental investments placed in- service, as of June 30, 2016, at various plants, including Welsh Plant, Units 1 and 3, (b) approval of recovery of, but no return on, the Texas jurisdictional share of the net book value of Welsh Plant, Unit 2, (c) approval of $2 million in additional vegetation management expenses and (d) the rejection of SWEPCo’s proposed transmission cost recovery mechanism.

As a result of the final order, in 2017 SWEPCo: (a) recorded an impairment charge of $19 million, which included $7 million associated with the lack of return on Welsh Plant, Unit 2 and $12 million related to other disallowed plant investments, (b) recognized $32 million of additional revenues, for the period of May 2017 through December 2017, that was surcharged to customers in 2018 and (c) recognized an additional $7 million of expenses consisting primarily of depreciation expense and vegetation management expense, offset by the deferral of rate case expense. SWEPCo implemented new rates in February 2018 billings. The $32 million of additional 2017 revenues was collected during 2018. In March 2018, the PUCT clarified and corrected portions of the final order, without changing the overall decision or amounts of the rate change. The order has been appealed by various intervenors related to limiting SWEPCo’s recovery of AFUDC on Turk Plant and recovery of Welsh Plant, Unit 2. The appeal will move forward following the conclusion of the 2012 Texas Base Rate Case. If certain parts of the PUCT order are overturned, it could reduce future net income and cash flows and impact financial condition.

2020 Texas Base Rate Case

In October 2020, SWEPCo filed a request with the PUCT for a $105 million annual increase in Texas base rates based upon a proposed 10.35% ROE. The request would move transmission and distribution interim revenues recovered through riders into base rates. Eliminating these riders would result in a net annual requested base rate increase of $90 million primarily due to increased investments. SWEPCo subsequently filed a request with the PUCT lowering the requested annual increase in Texas base rates to $100 million which would result in an $85 million net annual base rate increase after moving the proposed riders to rate base.

In January 2022, the PUCT issued a final order approving an annual revenue increase of $39 million based upon a 9.25% ROE. The order also includes: (a) rates implemented retroactively back to March 18, 2021, (b) $5 million of the proposed increase related to vegetation management, (c) $2 million annually to establish a storm catastrophe reserve and (d) the creation of a rider to recover the Dolet Hills Power Station as if it were in rate base until its retirement at the end of 2021 and starting in 2022 the remaining net book value to be recovered as a regulatory asset through 2046. As a result of the final order, SWEPCo recorded a disallowance of $12 million in 2021 associated with the lack of return on the Dolet Hills Power Station. In February 2022, SWEPCo filed a motion for rehearing with the PUCT challenging several errors in the order, which include challenges of the approved ROE, the denial of a reasonable return or carrying costs on the Dolet Hills Power Station and the calculation of the Texas jurisdictional share of the storm catastrophe reserve. In April 2022, the PUCT denied the

motion for rehearing. In May 2022, SWEPCo filed a petition for review with the Texas District Court seeking a judicial review of the several errors challenged in the PUCT’s final order.

2020 Louisiana Base Rate Case

In December 2020, SWEPCo filed a request with the LPSC for a $134 million annual increase in Louisiana base rates based upon a proposed 10.35% ROE. SWEPCo’s requested annual increase includes accelerated depreciation related to the Dolet Hills Power Station, Pirkey Power Plant and Welsh Plant, all of which were or are expected to be retired early. SWEPCo also included recovery of Welsh Plant, Unit 2 over the blended useful life of Welsh Plant, Units 1 and 3. SWEPCo subsequently revised the requested annual increase to $95 million to reflect removing hurricane storm restoration costs from the base case filing, to modify the proposed recovery of the Dolet Hills Power Station and revisions to various proposed amortizations. The hurricane costs have been requested in a separate storm filing. See “2021 Louisiana Storm Cost Filing” below for more information.

In January 2023, the LPSC approved a settlement which provides for an annual revenue increase of $27 million based upon a 9.5% ROE and includes: (a) a $21 million increase in base rates effective February 2023, (b) a $14 million rider to recover costs of the Dolet Hills Power Station and Pirkey Plant including a return, (c) an $8 million reduction in fuel rates, (d) an adoption of a 3-year formula rate term subject to an earnings band and (e) the recovery of certain incremental SPP charges net of associated revenue and the LA jurisdictional share of the return on and of projected transmission capital investment outside of the earnings band. The settlement agreement did not rule on the prudency of the early retirement of the Dolet Hills Power Station, which is being addressed in a separate proceeding.

The primary differences between SWEPCo’s requested annual rate increase and the agreed upon settlement increase are primarily due to: (a) a reduction in the requested ROE, (b) recovery of the Dolet Hills Power Station and Pirkey Plant over ten years in a separate rider mechanism as opposed to base rates with accelerated depreciation rates, (c) maintaining existing depreciation rates for Welsh Plant, Units 1 and 3 and (d) the severing of SWEPCo’s proposed adjustment to include a stand-alone NOLC deferred tax asset in rate base. In January 2023, a hearing was held related to the inclusion of a stand-alone NOLC deferred tax asset in rate base and an order from the LPSC is expected in 2023.

2021 Arkansas Base Rate Case

In July 2021, SWEPCo filed a request with the APSC for an $85 million annual increase in Arkansas base rates based upon a proposed 10.35% ROE with a capital structure of 48.7% debt and 51.3% common equity. The proposed annual increase includes: (a) a $41 million revenue requirement for the North Central Wind Facilities, (b) a $14 million annual depreciation increase primarily due to recovery of the Dolet Hills Power Station through 2026 and Pirkey Plant and Welsh Plant, Units 1 and 3 through 2037 and (c) a $6 million increase due to SPP costs. In January 2022, SWEPCo filed testimony revising the requested annual increase in Arkansas base rates to $81 million. SWEPCo requested that rates become effective in June 2022.

In May 2022, the APSC issued a final order approving an annual revenue increase of $49 million based upon a 9.5% ROE. The order also includes: (a) a capital structure of 55% debt and 45% common equity, (b) approval to recover the Dolet Hills Power Station as a regulatory asset over five years without a return on this investment

resulting in an immaterial disallowance in the second quarter of 2022, (c) the denial of accelerated depreciation for Pirkey Plant and Welsh Plant, Units 1 and 3 and (d) approval of a rider to recover SPP costs and revenues. The final order also denied the inclusion of the stand-alone NOLC in SWEPCo’s deferred tax assets, but included approval of the deferral of the forgone revenue requirement associated with the NOLC and excess NOLC, with recovery of the deferral contingent upon receipt of a supportive private letter ruling from the IRS. Rates were implemented with the first billing cycle of July 2022.

2021 Louisiana Storm Cost Filing

In 2020, Hurricanes Laura and Delta caused power outages and extensive damage to the SWEPCo service territories, primarily impacting the Louisiana jurisdiction. Following both hurricanes, the LPSC issued orders allowing Louisiana utilities, including SWEPCo, to establish regulatory assets to track and defer expenses associated with these storms. In February 2021, severe winter weather impacted the Louisiana jurisdiction and in March 2021, the LPSC approved the deferral of incremental storm restoration expenses related to the winter storm. In October 2021, SWEPCo filed a request with the LPSC for recovery of $145 million in deferred storm costs associated with the three storms. As part of the filing, SWEPCo requested recovery of the carrying charges on the deferred regulatory asset at a weighted average cost of capital through a rider beginning in January 2022. In May 2022, LPSC staff testimony was submitted to the LPSC. In July 2022, SWEPCo filed rebuttal testimony which agreed to make a request for securitization as the LPSC staff had recommended in their testimony. An order is expected in 2023. If any of the storm costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

February 2021 Severe Winter Weather Impacts in SPP

In February 2021, severe winter weather had a significant impact in SPP, resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system. For the time period of February 9, 2021, to February 20, 2021, SWEPCo’s natural gas expenses and purchases of electricity still to be recovered from customers are $329 million as of December 31, 2022, of which $75 million, $122 million and $132 million is related to the Arkansas, Louisiana and Texas jurisdictions, respectively.

In March 2021, the APSC issued an order authorizing recovery of the Arkansas jurisdictional share of the retail customer fuel costs over five years, with the appropriate carrying charge to be determined at a later date. Subsequently, SWEPCo began recovery of these fuel costs. In April 2021, SWEPCo filed testimony supporting a five-year recovery with a carrying charge of 6.05%. In June 2022, the APSC ordered SWEPCo to recover the Arkansas jurisdictional share of the fuel costs over six years with a carrying charge equal to its weighted average cost of capital, subject to a prudency review and true-up.

In March 2021, the LPSC approved a special order granting a temporary modification to the FAC and shortly after SWEPCo began recovery of its Louisiana jurisdictional share of these fuel costs based on a five-year recovery period inclusive of an interim carrying charge of 3.25%. SWEPCo will work with the LPSC to finalize the actual recovery period and determine the appropriate carrying charge in future proceedings.

In August 2021, SWEPCo filed an application with the PUCT to implement a net interim fuel surcharge for the Texas jurisdictional share of these retail fuel costs. The application requested a five-year recovery with a carrying

charge of 7.18%. In March 2022, the PUCT ordered SWEPCo to recover the Texas jurisdictional share of the fuel costs over five years with a carrying charge of 1.65% and ordered SWEPCo to file a fuel reconciliation addressing fuel costs from January 1, 2020 through December 31, 2021.

If SWEPCo is unable to recover any of the costs relating to the extraordinary fuel and purchases of electricity, or obtain authorization of a reasonable carrying charge on these costs, it could reduce future net income and cash flows and impact financial condition.

FERC SPP Transmission Formula Rate Challenge

In May 2021, certain joint customers submitted a formal challenge at the FERC related to the 2020 Annual Update of the 2019 SPP Transmission Formula Rates of the AEP transmission owning subsidiaries within SPP. In March 2022, the FERC issued an order on the formal challenge which ruled in favor of the joint customers on several issues. Management has determined that the result of the order will have an immaterial impact to the financial statements of SWEPCo. In November 2022, certain joint customers appealed the FERC decision to the U.S. Court of Appeals for the District of Columbia Circuit.

5. EFFECTS OF REGULATION

Coal-Fired Generation Plants

Compliance with extensive environmental regulations requires significant capital investment in environmental monitoring, installation of pollution control equipment, emission fees, disposal costs and permits. Management continuously evaluates cost estimates of complying with these regulations which has resulted in, and in the future may result in, a decision to retire coal-fired generating facilities earlier than their currently estimated useful lives.

Management is seeking or will seek regulatory recovery, as necessary, for any net book value remaining when the plants are retired. To the extent the net book value of these generation assets is not deemed recoverable, it could materially reduce future net income and cash flows and impact financial condition.

Regulated Generating Units that have been Retired

In April 2016, Welsh Plant, Unit 2 was retired. As part of the 2016 Texas Base Rate Case, the PUCT authorized recovery of SWEPCo’s Texas jurisdictional share of Welsh Plant, Unit 2, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $7 million in 2017. See “2016 Texas Base Rate Case” section of Note 4 for additional information. As part of the 2019 Arkansas Base Rate Case, SWEPCo received approval from the APSC to recover the Arkansas jurisdictional share of Welsh Plant, Unit 2. In December 2020, SWEPCo filed a request with the LPSC to recover the Louisiana jurisdictional share of Welsh Plant, Unit 2. In January 2023, the LPSC approved a settlement agreement which provided recovery of Welsh Plant, Unit 2 as requested. See “2020 Louisiana Base Rate Case” section of Note 4 for additional information.

In December 2021, the Dolet Hills Power Station was retired. As part of the 2020 Texas Base Rate Case, the PUCT authorized recovery of SWEPCo’s Texas jurisdictional share of the Dolet Hills Power Station through 2046, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $12 million in 2021. As part of the 2021 Arkansas Base Rate Case, the APSC authorized recovery of SWEPCo’s Arkansas jurisdictional share of the Dolet Hills Power Station through 2027, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $2 million in the second quarter of 2022. Also, the APSC did not rule on the prudency of the early retirement of the Dolet Hills Power Station, which will be addressed in a future proceeding. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo’s Louisiana share of the Dolet Hills Power Station, through a separate rider, through 2032, but did not rule on the prudency of the early retirement of the plant, which is being addressed in a separate proceeding. See “2020 Texas Base Rate Case”, “2020 Louisiana Base Rate Case” and “2021 Arkansas Base Rate Case” sections of Note 4 for additional information.

Regulated Generating Units to be Retired

In November 2020, management announced plans to retire Pirkey Plant in 2023 and that it will cease using coal at the Welsh Plant in 2028. As a result of the announcement, SWEPCo began recording accelerated depreciation.

The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of December 31, 2022, of generating facilities planned for early retirement:


Plant	Net Book Value		Accelerated Depreciation		Cost of Removal			Projected Retirement Date	Current Authorized Recovery Period	Annual Depreciation (a)
	(dollars in millions)
Pirkey Plant	$	35.1	$	179.5	$	39.8		2023	(b)	$	11.7
Welsh Plant, Units 1 and 3	416.8		85.6		58.3		(c)	2028	(d)	37.9

(a)Represents the amount of annual depreciation that has been collected from customers over the prior 12-month period.

(b)Pirkey Plant is currently being recovered through 2032 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.

(c)Includes Welsh Plant, Unit 2, which was retired in 2016. Removal of Welsh Plant, Unit 2, will be performed with Welsh Plant, Units 1 and 3, after retirement.

(d)Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.

Dolet Hills Power Station and Related Fuel Operations

In 2020, management of SWEPCo and CLECO determined DHLC would not develop additional Oxbow Lignite Company (Oxbow) mining areas for future lignite extraction and ceased extraction of lignite at the mine in May 2020. In April 2020, SWEPCo and CLECO jointly filed a notification letter to the LPSC providing notice of the cessation of lignite mining. In December 2021, the Dolet Hills Power Station was retired. While in operation, DHLC provided 100% of the fuel supply to Dolet Hills Power Station.

The remaining book value of Dolet Hills Power Station non-fuel related assets are recoverable by SWEPCo through rate riders. As of December 31, 2022, SWEPCo’s share of the net investment in the Dolet Hills Power Station is $112 million, including materials and supplies, net of cost of removal collected in rates.

Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses and are subject to prudency determinations by the various commissions. After closure of the DHLC mining operations and the Dolet Hills Power Station, additional reclamation and other land-related costs incurred by DHLC and Oxbow will continue to be billed to SWEPCo and included in existing fuel clauses. As of December 31, 2022, SWEPCo had a net under-recovered fuel balance of $257 million, inclusive of costs related to Dolet Hills Power Station billed by DHLC, but excluding impacts of the February 2021 severe winter weather event.

In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $20 million of fuel costs in 2021 and defer approximately $32 million of additional costs with a recovery period to be determined at a later date. In August 2022, the LPSC staff filed testimony recommending fuel disallowances of $72 million, including denial of recovery of the $32 million deferral, with refunds to customers over five years. In September 2022, SWEPCo filed rebuttal testimony addressing the LPSC staff recommendations.

In March 2021, the APSC approved fuel rates that provide recovery of $20 million for the Arkansas share of the 2021 Dolet Hills Power Station fuel costs over five years through the existing fuel clause.

In August 2022, SWEPCo filed a fuel reconciliation with the PUCT covering the fuel period of January 1, 2020 through December 31, 2021. Intervenor testimony is due in the first quarter of 2023 and a decision from the PUCT is expected in the third quarter of 2023.

If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Pirkey Power Plant and Related Fuel Operations

In 2020, management announced plans to retire the Pirkey Plant in 2023. The Pirkey Plant non-fuel costs are recoverable by SWEPCo through base rates and rate riders. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized recovery of SWEPCo’s Louisiana share of the Pirkey Plant through a separate rider. Fuel costs are recovered through active fuel clauses and are subject to prudency determinations by the various commissions. As of December 31, 2022, SWEPCo’s share of the net investment in the Pirkey Plant is $215 million, including CWIP, before cost of removal. Sabine is a mining operator providing mining services to the Pirkey Plant. Under the provisions of the mining agreement, SWEPCo is required to pay, as part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. SWEPCo expects fuel deliveries, including billings of all fixed and operating costs, from Sabine to cease during the first quarter of 2023. Under the fuel agreements, SWEPCo’s fuel inventory and unbilled fuel costs from mining related activities were $43 million as of December 31, 2022. As of December 31, 2022, SWEPCo had a net under-recovered fuel balance of $257 million, inclusive of costs related to Pirkey Plant billed by Sabine, but excluding impacts of the February 2021 severe winter weather event. Upon cessation of lignite deliveries by Sabine to the Pirkey Plant, additional operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in existing fuel clauses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Regulatory Assets and Liabilities

Regulatory assets and liabilities are comprised of the following items:


	December 31,				Remaining Recovery Period
	2022		2021
Regulatory Assets:	(in millions)


Regulatory assets pending final regulatory approval:

Regulatory Assets Currently Earning a Return
Unrecovered Winter Storm Fuel Costs (a)	$	84.6	$	367.5
Dolet Hills Power Station Fuel Costs - Louisiana	32.0		30.9
Other Regulatory Assets Pending Final Regulatory Approval	2.5		2.3
Total Regulatory Assets Currently Earning a Return	119.1		400.7
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs - Louisiana	151.5		148.0
Asset Retirement Obligation - Louisiana	11.8		10.3
Other Regulatory Assets Pending Final Regulatory Approval	16.0		18.4
Total Regulatory Assets Currently Not Earning a Return	179.3		176.7

Total Regulatory Assets Pending Final Regulatory Approval	298.4		577.4

Regulatory assets approved for recovery:

Regulatory Assets Currently Earning a Return
Under-recovered Fuel Costs (b)	257.2		81.2		1 year
Unrecovered Winter Storm Fuel Costs (a)	244.4		62.7		5 years
Environmental Controls Projects	10.0		11.0		10 years
Other Regulatory Assets Approved for Recovery	6.9		5.2		various
Total Regulatory Assets Currently Earning a Return	518.5		160.1
Regulatory Assets Currently Not Earning a Return
Income Tax Assets	267.1		295.7		(c)
Pension and OPEB Funded Status	88.7		67.5		12 years
Plant Retirement Costs - Unrecovered Plant, Texas	51.7		51.9		24 years
Plant Retirement Costs - Unrecovered Plant, Arkansas	21.1		—		5 years
Dolet Hills Power Station Fuel Costs - Arkansas	8.9		13.0		4 years
Other Regulatory Assets Approved for Recovery	27.7		13.4		various
Total Regulatory Assets Currently Not Earning a Return	465.2		441.5

Total Regulatory Assets Approved for Recovery	983.7		601.6

Total FERC Account 182.3 Regulatory Assets	$	1,282.1	$	1,179.0

(a)In 2022, Unrecovered Winter Storm Costs in the Arkansas and Texas jurisdictions were approved for recovery by the APSC and PUCT. As of December 31, 2022, Unrecovered Winter Storm Fuel Costs in the Louisiana jurisdiction are pending final regulatory approval with the LPSC. See “February 2021 Severe Winter Weather Impacts in SPP” section of SWEPCo Rate Matters in Note 4 for additional information.

(b)2022 amount includes Arkansas and Texas jurisdictions. 2021 amount includes Arkansas, Louisiana and Texas jurisdictions.

(c)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
	2022		2021
Regulatory Liabilities:	(in millions)


Regulatory liabilities pending final regulatory determination:

Regulatory Liabilities Currently Paying a Return
Income Tax Liabilities (a)	$	7.0	$	—
Total Regulatory Liabilities Pending Final Regulatory Determination	7.0		—

Regulatory liabilities approved for payment:

Regulatory Liabilities Currently Paying a Return
Income Tax Liabilities (a)	594.8		625.8		(b)
Other Regulatory Liabilities Approved for Payment	3.7		2.4		various
Total Regulatory Liabilities Currently Paying a Return	598.5		628.2
Regulatory Liabilities Currently Not Paying a Return
Other Regulatory Liabilities Approved for Payment	7.2		12.1		various
Total Regulatory Liabilities Currently Not Paying a Return	7.2		12.1

Total Regulatory Liabilities Approved for Payment	605.7		640.3

Total FERC 254 Account Regulatory Liabilities	$	612.7	$	640.3

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

(b)Refunded 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 $7 million and $7 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 1 year.

6. COMMITMENTS, GUARANTEES AND CONTINGENCIES

SWEPCo is subject to certain claims and legal actions arising in the ordinary course of business. In addition, SWEPCo’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

SWEPCo 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 SWEPCo’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)	$	133.7	$	84.7	$	—	$	—	$	218.4
Energy and Capacity Purchase Contracts	10.1		31.6		13.2		—		54.9
Total	$	143.8	$	116.3	$	13.2	$	—	$	273.3

(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

SWEPCo 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 PSO and SWEPCo, who are jointly and severally liable for activity conducted on their behalf.

Lease Obligations

SWEPCo leases equipment under master lease agreements. See “Master Lease Agreements” section of Note 13 for additional information.

ENVIRONMENTAL CONTINGENCIES

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation

By-products from the generation of electricity include materials such as ash, slag and sludge. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and non-hazardous materials. SWEPCo 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, SWEPCo was named as a Potentially Responsible Party (PRP) for one site by the Federal EPA for which alleged liability is unresolved. There are three additional sites for which SWEPCo received information requests which could lead to PRP designation. SWEPCo was also named potentially liable at a site under state law. 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

SWEPCo maintains insurance coverage normal and customary for electric utilities, subject to various deductibles. SWEPCo 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 SWEPCo. 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. ACQUISITIONS AND IMPAIRMENTS

ACQUISITIONS

North Central Wind Energy Facilities

In 2020, PSO and SWEPCo received regulatory approvals to acquire the NCWF, comprised of three Oklahoma wind facilities totaling 1,484 MWs, on a fixed cost turn-key basis. PSO and SWEPCo own undivided interests of 45.5% and 54.5% of the NCWF, respectively. In total, the three wind facilities cost approximately $2 billion and consist of Traverse (998 MW), Maverick (287 MW) and Sundance (199 MW). Output from the NCWF serves retail load in PSO’s Oklahoma service territory and both retail and FERC wholesale load in SWEPCo’s service territories in Arkansas and Louisiana. The Oklahoma and Louisiana portions of the NCWF revenue requirement, net of PTC benefit, are recoverable through authorized riders until the amounts are reflected in base rates. Recovery of the Arkansas portion of the NCWF revenue requirement through base rates was approved by the APSC in May 2022. The NCWF are subject to various regulatory performance requirements. If these performance requirements are not met, SWEPCo would recognize a regulatory liability to refund retail customers.

In April 2021, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Sundance during its development and construction for $270 million, the first of the three NCWF acquisitions. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Sundance assets in proportion to their undivided ownership interests. Sundance was placed in-service in April 2021.

In September 2021, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Maverick during its development and construction for $383 million, the second of the three NCWF acquisitions. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Maverick assets in proportion to their undivided ownership interests. Maverick was placed in-service in September 2021.

In March 2022, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Traverse during its development and construction for $1.2 billion, the third of the three NCWF acquisitions. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Traverse assets in proportion to their undivided ownership interests. Traverse was placed in-service in March 2022.

In accordance with the guidance for “Business Combinations,” management determined that the acquisitions of the NCWF projects represent asset acquisitions. As of December 31, 2022 and 2021, SWEPCo had approximately $1.1 billion and $378 million, respectively, of gross Utility Plant on the balance sheets related to the NCWF projects. On an ongoing basis, management further determined that SWEPCo should apply the joint plant accounting model to account for its respective undivided interests in the assets, liabilities, revenues and expenses of the NCWF projects.

The respective Purchase and Sale Agreements (PSAs) include collective interests in numerous land contracts, as originally executed between the nonaffiliated party and the respective owners of the properties as defined in the contracts. These contracts provide for easement and access rights to the land that Sundance, Maverick and Traverse were built upon. The lessee interests in the land contracts were transferred to Sundance, Maverick and Traverse (and subsequently to PSO and SWEPCo) as a part of the closings of the respective PSAs. The current Obligations Under Operating Leases related to the NCWF projects were not material as of December 31, 2022 and 2021 for SWEPCo. See the table below for the noncurrent Obligations Under Operating Leases for the NCWF projects for SWEPCo:


		December 31,
		2022		2021
	(in millions)
Project
Sundance		$	15.1	$	15.1
Maverick		21.6		21.6
Traverse		47.7		—
Total		$	84.4	$	36.7

IMPAIRMENTS

2020 Texas Base Rate Case

In January 2022, the PUCT issued a final order which included a return of investment only for the recovery of the Dolet Hills Power Station. As a result of the final order, SWEPCo recorded a disallowance of $12 million associated with the lack of return on the Dolet Hills Power Station. In February 2022, SWEPCo filed a motion for rehearing with the PUCT challenging denial of a reasonable return or carrying costs on the Dolet Hills Power Station among other items. In April 2022, the PUCT denied the motion for rehearing. In May 2022, SWEPCo filed a petition for review with the Texas District Court seeking a judicial review of the several errors challenged in the PUCT’s final order. See “2020 Texas Base Rate Case” section of Note 4 for additional information.

8. BENEFIT PLANS

For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Fair Value Measurements of Assets and Liabilities” and “Investments Held in Trust for Future Liabilities” sections of Note 1.

SWEPCo participates in an AEP sponsored qualified pension plan and two unfunded non-qualified pension plans. Substantially all employees are covered by the qualified plan or both the qualified and a non-qualified pension plan. SWEPCo also participates in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees.

SWEPCo 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. SWEPCo recognizes an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, 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. SWEPCo 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	5.00	%	(a)	4.95	%	(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	5.00	%	(a)	4.95	%	(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,	$	317.7	$	334.5	$	65.2	$	77.1
Service Cost	10.6		11.2		0.6		0.8
Interest Cost	9.1		8.5		1.8		1.9
Actuarial Gain	(57.9)		(3.5)		(6.6)		(9.2)
Plan Amendments	—		—		—		(0.4)
Benefit Payments	(28.8)		(33.0)		(8.8)		(7.6)
Participant Contributions	—		—		2.9		2.6
Benefit Obligation as of December 31,	$	250.7	$	317.7	$	55.1	$	65.2

Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1,	$	308.3	$	326.9	$	136.6	$	129.9
Actual Gain (Loss) on Plan Assets	(48.3)		14.3		(27.7)		11.7
Company Contributions	0.1		0.1		—		—
Participant Contributions	—		—		2.9		2.6
Benefit Payments	(28.8)		(33.0)		(8.8)		(7.6)
Fair Value of Plan Assets as of December 31,	$	231.3	$	308.3	$	103.0	$	136.6

Funded (Underfunded) Status as of December 31,	$	(19.4)	$	(9.4)	$	47.9	$	71.4


	Pension Plans				OPEB
	December 31,
	2022		2021		2022		2021
	(in millions)
Special Funds – Prepaid Benefit Costs	$	—	$	—	$	47.9	$	71.4
Miscellaneous Current and Accrued Liabilities – Short-term Benefit Liability	(0.1)		(0.1)		—		—
Accumulated Provision for Pensions and Benefits – Long-term Benefit Liability	(19.3)		(9.3)		—		—
Funded (Underfunded) Status	$	(19.4)	$	(9.4)	$	47.9	$	71.4

Amounts Included in Regulatory Assets, Deferred Income Taxes and AOCI

The following tables show the components of the plans included in regulatory assets, Accumulated Deferred Income Taxes, AOCI and income tax expense and the items attributable to the change in these components:


	Pension Plans				OPEB
	December 31,
	2022		2021		2022		2021
Components	(in millions)
Net Actuarial (Gain) Loss	$	77.6	$	76.4	$	25.0	$	(3.5)
Prior Service Credit	—		—		(7.0)		(12.3)

Recorded as
Regulatory Assets	$	77.6	$	76.4	$	11.2	$	(8.9)
Deferred Income Taxes	—		—		1.5		(1.4)
Net of Tax AOCI	—		—		5.3		(5.5)


	Pension Plans				OPEB
	2022		2021		2022		2021
Components	(in millions)
Actuarial (Gain) Loss During the Year	$	5.0	$	(4.3)	$	28.5	$	(15.0)
Amortization of Actuarial Loss	(3.8)		(6.2)		—		—
Prior Service Credit	—		—		—		(0.4)
Amortization of Prior Service Credit	—		—		5.3		5.3
Change for the Year Ended December 31,	$	1.2	$	(10.5)	$	33.8	$	(10.1)

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 SWEPCo using the percentages in the table below:


Pension Plan				OPEB
December 31,
2022		2021		2022		2021
5.6	%	5.8	%	6.6	%	6.7	%

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	$	234.0	$	291.4
Nonqualified Pension Plans	1.1		1.3
Total	$	235.1	$	292.7

Obligations in Excess of Fair Values

The tables below show the underfunded pension plans that had obligations in excess of plan assets.

Projected Benefit Obligation


	December 31,
	2022		2021
	(in millions)
Projected Benefit Obligation	$	250.7	$	317.7
Fair Value of Plan Assets	231.3		308.3
Underfunded Projected Benefit Obligation	$	(19.4)	$	(9.4)

Accumulated Benefit Obligation


	December 31,
	2022		2021
	(in millions)
Accumulated Benefit Obligation	$	235.1	$	1.3
Fair Value of Plan Assets	231.3		—
Underfunded Accumulated Benefit Obligation	$	(3.8)	$	(1.3)

Estimated Future Benefit Payments and Contributions

SWEPCo expects contributions and payments for the pension plans of $124 thousand during 2023. For the pension plans, this amount includes the payment of unfunded nonqualified benefits plus contributions to the qualified trust fund of at least the minimum amount required by the Employee Retirement Income Security Act. For the qualified pension plan, SWEPCo may also make additional discretionary contributions to maintain the funded status of the plan.

The table below reflects the total benefits expected to be paid from the plan or from SWEPCo’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	$	24.2	$	7.5
2024	25.1		7.8
2025	25.3		8.5
2026	25.4		8.6
2027	25.4		8.5
Years 2028 to 2032, in Total	107.9		41.2

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	$	10.6	$	11.2	$	0.6	$	0.8
Interest Cost	9.1		8.5		1.8		1.9
Expected Return on Plan Assets	(14.6)		(13.5)		(7.3)		(6.1)
Amortization of Prior Service Credit	—		—		(5.3)		(5.3)
Amortization of Net Actuarial Loss	3.8		6.2		—		—
Net Periodic Benefit Cost (Credit)	8.9		12.4		(10.2)		(8.7)
Capitalized Portion	(4.0)		(4.1)		(0.2)		(0.3)
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	4.9	$	8.3	$	(10.4)	$	(9.0)

American Electric Power System Retirement Savings Plan

SWEPCo 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 $6 million and $6 million, respectively.

9. BUSINESS SEGMENTS

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

10. DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

AEPSC is agent for and transacts on behalf of SWEPCo.

SWEPCo 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 SWEPCo 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, SWEPCo 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.

SWEPCo 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. SWEPCo 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. SWEPCo 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, Energy Supply 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 the Registrants’ outstanding derivative contracts:


Notional Volume of Derivative Instruments

Primary Risk Exposure	2022	2021	Unit of Measure
	(in millions)
Commodity:
Power	2.2	3.4	MWhs
Natural Gas	2.1	5.1	MMBtus
Heating Oil and Gasoline	1.0	1.0	Gallons

Cash Flow Hedging Strategies

SWEPCo 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. SWEPCo does not hedge all commodity price risk.

SWEPCo utilizes a variety of interest rate derivative transactions in order to manage interest rate risk exposure. SWEPCo also utilizes interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. SWEPCo 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, SWEPCo 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,” SWEPCo 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, SWEPCo 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 SWEPCo’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	$	16.8	$	(0.4)	$	16.4
Long-Term Portion of Derivative Instrument Assets	—		—		—

Derivative Instrument Liabilities	2.0		(0.6)		1.4
Long-Term Portion of Derivative Instrument Liabilities	—		—		—


	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	$	11.2	$	(0.3)	$	10.9
Long-Term Portion of Derivative Instrument Assets	1.1		—		1.1

Derivative Instrument Liabilities	2.1		—		2.1
Long-Term Portion of Derivative Instrument Liabilities	—		—		—

(a)Derivative instruments within these categories 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)
Operation Expenses	$	0.8	$	0.4
Maintenance Expenses	1.1		0.5
Other Regulatory Assets (a)	(2.1)		3.6
Other Regulatory Liabilities (a)	77.9		37.0
Total Gain on Risk Management Contracts	$	77.7	$	41.5

(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), SWEPCo 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, SWEPCo did not apply cash flow hedging to outstanding power derivatives.

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

For details on effective cash flow hedges included in Accumulated Other Comprehensive Income on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 - Comprehensive Income.

Cash flow hedges included in Accumulated Other Comprehensive Income on the balance sheets were:

Impact of Cash Flow Hedges on the Balance Sheets

December 31, 2022

December 31, 2021

Interest Rate

Expected to be

Reclassified to

Net Income During

AOCI Gain (Loss)

the Next

AOCI Gain (Loss)

the Next

Net of Tax

Twelve Months

Net of Tax

Twelve Months

(in millions)

1.1

0.2

1.2

0.1

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. SWEPCo has not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. SWEPCo 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 SWEPCo 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. SWEPCo had no derivative contracts with cross-acceleration provisions outstanding as of December 31, 2022 and 2021.

Cross-Default Triggers

In addition, a majority of SWEPCo’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 SWEPCo were immaterial for years ended December 31, 2022 and 2021.

11. FAIR VALUE MEASUREMENTS

Fair Value Measurements of Long-term Debt

The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.

The book values and fair values of Long-term Debt are summarized in the following table:


December 31,
2022				2021
Book Value		Fair Value		Book Value		Fair Value
(in millions)
$	3,319.1	$	2,778.1	$	3,318.7	$	3,682.9

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, SWEPCo’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)

Derivative Instrument Assets
Risk Management Commodity Contracts (a) (b)	$	—	$	2.2	$	14.6	$	(0.4)	$	16.4

Liabilities:

Derivative Instrument Liabilities
Risk Management Commodity Contracts (a) (b)	$	—	$	1.6	$	0.4	$	(0.6)	$	1.4


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

Derivative Instrument Assets
Risk Management Commodity Contracts (a) (b)	$	—	$	0.3	$	11.0	$	(0.4)	$	10.9

Liabilities:

Derivative Instrument Liabilities
Risk Management Commodity Contracts (a) (b)	$	—	$	2.1	$	0.1	$	(0.1)	$	2.1

(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	$	10.9
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)	35.8
Settlements	(45.0)
Transfers out of Level 3 (c)	6.9
Changes in Fair Value Allocated to Regulated Jurisdictions (d)	5.6
Balance as of December 31, 2022	$	14.2


	Derivative Instrument
Year Ended December 31, 2021	Assets (Liabilities)
	(in millions)
Balance as of December 31, 2020	$	1.6
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)	9.5
Settlements	(15.5)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)	15.3
Balance as of December 31, 2021	$	10.9

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

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

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

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

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

December 31, 2022

Significant

Input/Range

Fair Value

Valuation

Unobservable

Weighted

Assets

Liabilities

Technique

Input (a)

Low

High

Average (c)

(in millions)

FTRs

14.6

0.4

Discounted Cash Flow

Forward Market Price

(36.45)

3.40

(7.55)


December 31, 2021
						Significant	Input/Range
	Fair Value				Valuation	Unobservable					Weighted
	Assets		Liabilities		Technique	Input	Low		High		Average (c)
	(in millions)
Natural Gas Contracts	$	3.6	$	—	Discounted Cash Flow	Forward Market Price (b)	$	3.11	$	4.02	$	3.47
FTRs	7.4		0.1		Discounted Cash Flow	Forward Market Price (a)	(18.39)		1.87		(2.57)
Total	$	11.0	$	0.1

(a)Represents market prices in dollars per MWh.

(b)Represents market prices in dollars per MMBtu.

(c)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 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)

12.

INCOME TAXES

Income Tax Benefit

The details of SWEPCo’s Income Tax Benefit as reported are as follows:


	Years Ended December 31,
	2022		2021
	(in millions)
Charged (Credited) to Operating Expenses, Net:
Current	$	(39.6)	$	(20.6)
Deferred	17.4		22.2
Total	(22.2)		1.6

Charged (Credited) to Non-Operating Income, Net:
Current	(4.6)		(2.4)
Deferred	0.5		(0.6)
Total	(4.1)		(3.0)
Income Tax Benefit	$	(26.3)	$	(1.4)

The following is a reconciliation between the federal income taxes computed by multiplying pretax income (loss) by the federal statutory tax rate and the income taxes reported:


	Years Ended December 31,
	2022			2021
	(in millions)
Net Income	$	290.1		$	239.0
Less: Equity Earnings – Dolet Hills	(1.4)			(3.4)
Income Tax Benefit	(26.3)			(1.4)
Pretax Income	$	262.4		$	234.2

Income Taxes on Pretax Income at Statutory Rate (21%)	$	55.1		$	49.2
Increase (Decrease) in Income Taxes Resulting from the Following Items:
Reversal of Origination Flow-Through	2.3			1.8
Depletion	(4.0)			(2.7)
State and Local Income Taxes, Net	(4.9)			(7.1)
Tax Reform Excess ADIT Reversal	(14.8)			(31.1)
Production Tax Credits	(57.1)			(7.2)
Other	(2.9)			(4.3)
Income Tax Benefit	$	(26.3)		$	(1.4)

Effective Income Tax Rate	(10.0)		%	(0.6)		%

Net Deferred Tax Asset

The following table shows elements of SWEPCo’s net deferred tax asset and significant temporary differences:


	December 31,
	2022		2021
	(in millions)
Deferred Tax Assets	$	358.2	$	321.8
Deferred Tax Liabilities	(1,447.0)		(1,399.5)
Net Deferred Tax Assets	$	(1,088.8)	$	(1,077.7)

Property Related Temporary Differences	$	(1,053.8)	$	(969.1)
Amounts Due to Customers for Future Income Taxes	146.2		154.8
Deferred State Income Taxes	(208.7)		(232.1)
Regulatory Assets	(114.1)		(101.4)
Tax Credit Carryforward	66.0		8.5
Net Operating Loss Carryforward	42.7		63.6
All Other, Net	32.9		(2.0)
Net Deferred Tax Assets	$	(1,088.8)	$	(1,077.7)

Tax Credit Carryforward

As of December 31, 2022, SWEPCo has federal tax credit carryforwards in the amount of $66 million. If these credits are not utilized, federal general business tax credits will expire in the years 2037 through 2042. SWEPCo anticipates future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused.

Valuation Allowance

SWEPCo assesses the available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate tax character will be generated to realize the benefits of existing deferred tax assets. When the evaluation of the evidence indicates that it is more-likely-than-not that SWEPCo will not be able to realize the benefits of existing deferred tax assets, a valuation allowance is recorded to reduce existing deferred tax assets to the net realizable amount. Objective evidence evaluated includes whether SWEPCo has a history of recognizing income, future reversals of existing temporary differences and tax planning strategies.

Federal and State Income Tax Audit Status

The statute of limitations for the IRS to examine SWEPCo and other AEP subsidiaries originally filed federal return has expired for tax years 2016 and earlier. SWEPCo has 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. SWEPCo 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 SWEPCo 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.

SWEPCo and other AEP subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns, and SWEPCo 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.

Net Income Tax Operating Loss Carryforward

SWEPCo has state net income tax operating loss carryforwards as of December 31, 2022 as indicated in the table below:

State Net Income

Tax Operating

Loss

Years of

State/Municipality

Carryforward

Expiration

(in millions)

Arkansas

224.2

2023 - 2032

Louisiana

577.2

N/A (a)

(a)NOL’s generated beginning in 2001 can be carried forward indefinitely, effective January 1, 2022.

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 (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, SWEPCo 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. SWEPCo’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 SWEPCo can begin to rely on in 2023 and also stated that additional guidance is expected, of which SWEPCo 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 SWEPCo’s potential CAMT exposure.

The enactment of the IRA will have future cash flow and income tax reporting considerations. SWEPCo 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. SWEPCo 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 November 2021, Louisiana approved Constitutional Amendment 2, thereby also enacting HB 292. HB 292 reduces the Louisiana corporate income tax rate from 8% to 7.5%. In the fourth quarter of 2021, SWEPCo recorded an immaterial amount of Income Tax Expense as a result of remeasuring Louisiana deferred taxes at the lowered statutory tax rate of 7.5%.

In December 2021, Arkansas enacted HB 1001. HB 1001 reduces the Arkansas corporate income tax rate from 5.9% to 5.7%, with additional reductions to 5.3% contingent upon future events. In the fourth quarter of 2021, SWEPCo recorded an immaterial amount of Income Tax Expense as a result of remeasuring Arkansas deferred taxes at the lowered statutory tax rate of 5.7%.

In August 2022, Arkansas enacted Senate Bill 1. Senate Bill 1 reduces the Arkansas corporate income tax rate from 5.7% to 5.3%. In the third quarter of 2022, SWEPCo recorded an immaterial amount of Income Tax Expense as a result of remeasuring Arkansas deferred taxes at the lowered statutory tax rate of 5.3%.

13. LEASES

SWEPCo 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. SWEPCo 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 SWEPCo 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, SWEPCo 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	$	15.0	$	12.0
Finance Lease Cost:
Amortization of Right-of-Use Assets	5.7		6.1
Interest on Lease Liabilities	1.3		1.4
Total Lease Rental Costs (a)	$	22.0	$	19.5

(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	23.59		20.36
Finance Leases	4.89		5.21
Weighted-Average Discount Rate:
Operating Leases	3.42	%	3.36	%
Finance Leases	4.63	%	4.42	%


	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	$	13.4	$	11.5
Operating Cash Flows from Finance Leases	7.0		7.5

Non-cash Acquisitions Under Operating Leases	$	53.6	$	42.9

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


	December 31,
	2022		2021
	(in millions)
Property, Plant and Equipment Under Finance Leases
Utility Plant (a)	$	28.2	$	30.2

Obligations Under Finance Leases
Noncurrent	$	23.2	$	25.0
Current	5.3		5.4
Total Obligations Under Finance Leases	$	28.5	$	30.4

(a) Includes $24 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)	$	122.8	$	79.5

Obligations Under Operating Leases
Noncurrent	$	120.2	$	77.7
Current	8.4		8.0
Total Obligations Under Operating Leases	$	128.6	$	85.7

(a) Includes $29 million and $20 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	$	6.5	$	14.1
2024	11.6		12.7
2025	3.2		11.4
2026	2.8		10.2
2027	2.4		8.8
After 2027	5.6		141.7
Total Future Minimum Lease Payments	32.1		198.9
Less: Imputed Interest	3.6		70.3
Estimated Present Value of Future Minimum Lease Payments	$	28.5	$	128.6

Master Lease Agreements

SWEPCo 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, SWEPCo 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 SWEPCo for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was $5 million.

Lessor Activity

SWEPCo’s lessor activity was immaterial as of and for the twelve months ended December 31, 2022 and December 31, 2021, respectively.

14. FINANCING ACTIVITIES

Long-term Debt

The following table details long-term debt outstanding:


		Weighted-Average	Interest Rate Ranges as of		Outstanding as of
		Interest Rate as of	December 31,		December 31,
	Maturity	December 31, 2022	2022	2021	2022		2021

Senior Unsecured Notes	2026-2051	3.57%	1.65%-6.20%	1.65%-6.20%	$	3,325.0	$	3,325.0
Unamortized Discount, Net					(5.9)		(6.3)
Total Long-term Debt Outstanding					$	3,319.1	$	3,318.7

As of December 31, 2022, outstanding long-term debt was payable as follows:


	(in millions)
2023	$	—
2024	—
2025	—
2026	900.0
2027	—
After 2027	2,425.0
Principal Amount	3,325.0
Unamortized Discount, Net	(5.9)
Total Long-term Debt	$	3,319.1

Dividend Restrictions

SWEPCo pays dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of SWEPCo to transfer funds to Parent in the form of dividends.

All of the dividends declared by SWEPCo 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.

SWEPCo 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 SWEPCo is through the credit agreements. As of December 31, 2022, the maximum amount of restricted net assets of SWEPCo that may not be distributed to the Parent in the form of a loan, advance or dividend was $1.8 billion.

The credit agreement covenant restrictions can limit the ability of SWEPCo to pay dividends out of retained earnings. As of December 31, 2022, the amount of any such restrictions was $373 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 loans to (borrowings from) the Utility Money Pool as of December 31, 2022 and 2021 are included in Notes Payable to Associated Companies and Notes Receivable from Associated Companies, respectively, on the balance sheets. SWEPCo’s money pool activity and corresponding authorized borrowing limits are described in the following table:


	Maximum				Average				Net Loans to
	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	$	358.4	$	156.6	$	219.6	$	109.7	$	(310.7)	$	400.0
2021	280.3		561.9		142.4		287.4		153.8		400.0

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	%	0.69	%	0.94	%	0.10	%	2.80	%	0.55	%
2021	0.39	%	0.02	%	0.48	%	0.02	%	0.26	%	0.18	%

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 was $5 million and $329 thousand for the years ended December 31, 2022 and 2021, respectively. The interest income related to the corporate borrowing programs was immaterial for the years ended December 31, 2022 and 2021.

Securitized Accounts Receivables – AEP Credit

Under this sale of receivables arrangement, SWEPCo 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 SWEPCo’s receivables. The costs of customer accounts receivable sold are reported in Other Deductions on SWEPCo’s statements of income. SWEPCo manages and services its customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for SWEPCo and retains the remainder.

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 SWEPCo and to lower subsequent fees paid.

The proceeds on the sale of receivables to AEP Credit were $1.9 billion and $1.6 billion for the years ended December 31, 2022 and 2021, respectively.

15. 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 14.

Operating Agreement

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 SPP generally accrue to the benefit of PSO and SWEPCo. 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 West Affiliates	$	1.3	$	—
Transmission Coordination Agreement Sales	51.5		39.6
Other Revenues	1.1		1.4
Total Affiliated Revenues	$	53.9	$	41.0

SPP Transmission Service Charges

PSO, SWEPCo and AEPSC are parties to the TCA in connection with the operation of the transmission assets of PSO and SWEPCo. The TCA has been approved by the FERC and establishes a coordinating committee, which is charged with overseeing the coordinated planning of the transmission facilities of the parties to the agreement. This includes the performance of transmission planning studies, the interaction of such companies with independent system operators and other regional bodies interested in transmission planning and compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such a tariff.

Under the TCA, the parties to the agreement delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. The allocations have been governed by the FERC-approved OATT for the SPP. Additional costs for transmission services provided by AEPTCo and other transmission affiliates are billed to PSO and SWEPCo through the SPP OATT. SWEPCo’s net expenses allocated among parties to the TCA pursuant to the SPP OATT protocols were $62 million and $56 million for the years ended December 31, 2022 and 2021, respectively. The net expenses were recorded in Operation Expenses on the statements of income.

Cook Coal Terminal

Cook Coal Terminal also performs railcar maintenance services at cost for SWEPCo. AEGCo billed SWEPCo $3 million and $3 million for the years ended December 31, 2022 and 2021, respectively, for railcar maintenance services. SWEPCo recorded the cost of the railcar maintenance services in Fuel Stock on the balance sheets.

Sales and Purchases of Property

SWEPCo 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	$	1.0	$	0.4
Purchases	2.8		0.3

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

AEP Wind Holdings LLC PPAs

Prior to its acquisition, one of the 50% owned joint venture wind farms in the AEP Wind Holdings, LLC portfolio, Flat Ridge 2, had an existing PPA with SWEPCo for a portion of its energy production which totaled $14 million and $14 million of purchased electricity for the years ended December 31, 2022 and 2021, respectively. AEP disposed of its 50% interest in Flat Ridge 2 in the fourth quarter of 2022.

Intercompany Billings

SWEPCo and other AEP subsidiaries perform 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 SWEPCo. The costs of the services are based on a direct charge or on a prorated basis and billed to SWEPCo at AEPSC’s cost. AEPSC and its billings are subject to regulation by the FERC. SWEPCo’s total billings from AEPSC were $192 million and $169 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, SWEPCo made a $9 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.

16. PROPERTY, PLANT AND EQUIPMENT

Depreciation

SWEPCo 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	Steam		Other Generation		Transmission		Distribution		General
	(in percentages)
2022	2.8	%	2.4	%	2.3	%	2.9	%	9.0	%
2021	2.8	%	1.3	%	2.4	%	2.8	%	8.6	%

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

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

•In March 2022, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Traverse during its development and construction. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Traverse assets in proportion to their undivided ownership interests. Traverse was placed in-service in March 2022. As a result, SWEPCo incurred additional ARO liabilities of $15 million. See the “North Central Wind Energy Facilities” section of Note 7 for additional information.

•In March 2022, SWEPCo recorded a $13 million revision due to an increase in estimated ash pond closure costs at the Pirkey Plant and the Welsh Plant. In September 2022, SWEPCo recorded a $14 million revision due to an increase in estimated landfill closure costs at Pirkey 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		ARO at December 31,
	(in millions)
2022	$	128.3	$	6.8	$	15.4	$	(25.8)	$	34.3	$	159.0	(a)(b)(c)(d)
2021	133.4		5.8		9.2		(20.9)		0.8		128.3		(a)(b)(c)(d)

(a)Includes ARO related to ash disposal facilities.

(b)Includes ARO related to DHLC.

(c)Includes ARO related to asbestos removal.

(d)Includes ARO related to wind farms.

Jointly-owned Electric Facilities

SWEPCo has electric facilities that are jointly-owned with affiliated and nonaffiliated companies. Using its own financing, SWEPCo is obligated to pay its share of the costs of these jointly-owned facilities in the same proportion as its ownership interest. SWEPCo’s proportionate share of the operating costs associated with these facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Utility Plant as follows:


				Share as of December 31, 2022
	Fuel Type	Percent of Ownership		Utility Plant in Service		Construction Work in Progress		Accumulated Depreciation
				(in millions)
Flint Creek Generating Station, Unit 1 (a)	Coal	50.0	%	$	382.9	$	16.4	$	149.4
Pirkey Plant, Unit 1 (a)	Lignite	85.9	%	632.0		—		632.0
Turk Generating Plant (a)	Coal	73.3	%	1,611.1		5.1		314.7
North Central Wind Energy Facilities (b)(c)	Wind	54.5	%	1,066.8		10.1		35.2
Total				$	3,692.8	$	31.6	$	1,131.3


				Share as of December 31, 2021
	Fuel Type	Percent of Ownership		Utility Plant in Service		Construction Work in Progress		Accumulated Depreciation
				(in millions)
Flint Creek Generating Station, Unit 1 (a)	Coal	50.0	%	$	377.6	$	6.3	$	133.5
Pirkey Plant, Unit 1 (a)	Lignite	85.9	%	613.8		—		528.3
Turk Generating Plant (a)	Coal	73.3	%	1,598.0		10.2		285.6
North Central Wind Energy Facilities (b)(c)	Wind	54.5	%	376.2		—		5.4
Total				$	2,965.6	$	16.5	$	952.8

(a)Operated by SWEPCo.

(b)PSO and SWEPCo own undivided interests of 45.5% and 54.5% of the NCWF, respectively. Sundance was placed into service in April 2021. Maverick was placed into service in September 2021. Traverse was placed into service in March 2022. See the “Acquisitions” section of Note 7 for additional information.

(c)Operated by PSO.

17. 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 SWEPCo.


	Years Ended December 31,
	2022		2021
	(in millions)
Retail Revenues:
Residential Revenues	$	850.3	$	861.5
Commercial Revenues	643.7		652.2
Industrial Revenues	437.1		468.7
Other Retail Revenues	10.1		10.0
Total Retail Revenues	1,941.2		1,992.4

Wholesale Revenues:
Generation Revenues (a)	319.0		427.6
Transmission Revenues (a)	148.7		122.7
Total Wholesale Revenues	467.7		550.3

Other Revenues from Contracts with Customers (a)	24.6		22.1

Total Revenues from Contracts with Customers	2,433.5		2,564.8

Other Revenues:
Alternative Revenues	1.2		5.8
Other Revenues	0.4		1.5
Total Other Revenues	1.6		7.3

Total Operating Revenues	$	2,435.1	$	2,572.1

(a)Amounts include affiliated and nonaffiliated revenues.

Performance Obligations

SWEPCo 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. SWEPCo 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 SWEPCo are summarized as follows:

Retail Revenues

SWEPCo 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 SWEPCo 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

SWEPCo has performance obligations to sell electricity to wholesale customers from generation assets in SPP. 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.

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.

Wholesale Revenues - Transmission

SWEPCo has performance obligations to transmit electricity to wholesale customers through assets owned and operated. The performance obligation to provide transmission services in SPP 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 monthly for SPP.

SWEPCo 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.

PSO, SWEPCo and AEPSC are parties to the TCA by and among PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two AEP utility subsidiaries. Affiliate revenues as a result of the TCA are reflected as Transmission Revenues in the disaggregated revenues tables above.

Contract Assets and Liabilities

Contract assets are recognized when SWEPCo 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. SWEPCo did not have any material contract assets as of December 31, 2022 and 2021.

When SWEPCo 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. SWEPCo’s contract liabilities typically arise from services provided under joint use agreements for utility poles. SWEPCo 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 SWEPCo’s balance sheets within the Customer Accounts Receivable line item. SWEPCo’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 14 for additional information.

The amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable from Associated Companies on SWEPCo’s balance sheets were $19 million and $25 million, as of December 31, 2022 and 2021.

Contract Costs

Contract costs to obtain or fulfill a contract for SWEPCo 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. SWEPCo did not have material contract costs as of December 31, 2022 and 2021.

Name of Respondent:

SWEPCO

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				2,122,962	121,439		2,001,523
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income				1,629,067	1,517,836		111,231
3	Preceding Quarter/Year to Date Changes in Fair Value				4,863,211			4,863,211
4	Total (lines 2 and 3)				3,234,144	1,517,836		4,751,980	239,006,488	243,758,468
5	Balance of Account 219 at End of Preceding Quarter/Year				5,357,106	1,396,397		6,753,503
6	Balance of Account 219 at Beginning of Current Year				5,357,106	1,396,397		6,753,503
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income				19,519,239	126,487		19,392,752
8	Current Quarter/Year to Date Changes in Fair Value				8,638,260	210,979		8,427,280
9	Total (lines 7 and 8)				10,880,979	84,492		10,965,472	290,060,102	279,094,630
10	Balance of Account 219 at End of Current Quarter/Year				5,523,873	1,311,905		4,211,969

Name of Respondent:

SWEPCO

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)	9,970,940,886	9,970,940,886
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	151,078,330	151,078,330
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold	64,005	64,005
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified	1,262,701,301	1,262,701,301
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	11,384,784,522	11,384,784,522
9	UtilityPlantLeasedToOthers Leased to Others
10	UtilityPlantHeldForFutureUse Held for Future Use	1,693,761	1,693,761
11	ConstructionWorkInProgress Construction Work in Progress	372,772,642	372,772,642.00
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments	18,043,976	18,043,976
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	11,777,294,901	11,777,294,901
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	3,419,289,601	3,419,289,601
15	UtilityPlantNet Net Utility Plant (13 less 14)	8,358,005,300	8,358,005,300
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	3,318,102,358	3,318,102,358
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	83,143,696	83,143,696
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	3,401,246,054	3,401,246,054
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	429	429
29	AmortizationUtilityPlantHeldForFutureUse Amortization
30	DepreciationAndAmortizationUtilityPlantHeldForFutureUse Total Held for Future Use (28 & 29)	429	429
31	AbandonmentOfLeases Abandonment of Leases (Natural Gas)
32	AmortizationOfPlantAcquisitionAdjustment Amortization of Plant Acquisition Adjustment	18,043,976	18,043,976
33	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Total Accum Prov (equals 14) (22,26,30,31,32)	3,419,289,601	3,419,289,601

Name of Respondent:

SWEPCO

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:

SWEPCO

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	12,202					12,202
3	(302) Franchise and Consents
4	(303) Miscellaneous Intangible Plant	167,581,838	30,961,859	18,485,894			180,057,803
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)	167,594,040	30,961,859	18,485,894			180,070,005
6	2. PRODUCTION PLANT
7	A. Steam Production Plant
8	(310) Land and Land Rights	25,389,217					25,389,217
9	(311) Structures and Improvements	584,646,107	13,565,677	1,065,820			597,145,964
10	(312) Boiler Plant Equipment	2,477,523,765	14,107,389	5,355,193			2,486,275,961
11	(313) Engines and Engine-Driven Generators
12	(314) Turbogenerator Units	687,779,839	10,475,181	3,725,689			694,529,331
13	(315) Accessory Electric Equipment	233,921,584	2,395,528	2,745,092			233,572,020
14	(316) Misc. Power Plant Equipment	202,332,404	2,410,846	479,431			204,263,819
15	(317) Asset Retirement Costs for Steam Production	65,455,801	29,209,116				94,664,917
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)	4,277,048,717	72,163,737	13,371,225			4,335,841,229
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
28	(331) Structures and Improvements
29	(332) Reservoirs, Dams, and Waterways
30	(333) Water Wheels, Turbines, and Generators
31	(334) Accessory Electric Equipment
32	(335) Misc. Power Plant Equipment
33	(336) Roads, Railroads, and Bridges
34	(337) Asset Retirement Costs for Hydraulic Production
35	TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)
36	D. Other Production Plant
37	(340) Land and Land Rights	2,695,194	344,838			11,706	3,051,738
38	(341) Structures and Improvements	31,452,547		14,782			31,437,765
39	(342) Fuel Holders, Products, and Accessories
40	(343) Prime Movers
41	(344) Generators	451,625,045	675,081,215	254,372		11,706	1,126,440,182
42	(345) Accessory Electric Equipment	9,034,341	897,304	810,555			9,121,090
43	(346) Misc. Power Plant Equipment	956,130	916,321	2			1,872,449
44	(347) Asset Retirement Costs for Other Production	9,158,686	15,385,728				24,544,414
44.1	(348) Energy Storage Equipment - Production
45	TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)	504,921,943	692,625,406	1,079,711			1,196,467,638
46	TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)	4,781,970,660	764,789,143	14,450,936			5,532,308,867
47	3. Transmission Plant
48	(350) Land and Land Rights	110,171,288	4,647,725	278			114,818,735
48.1	(351) Energy Storage Equipment - Transmission
49	(352) Structures and Improvements	42,609,446	12,557,876	162,693		469,600	54,535,029
50	(353) Station Equipment	804,033,387	46,216,779	5,673,674			844,576,492
51	(354) Towers and Fixtures	40,269,116		3,909,551			36,359,565
52	(355) Poles and Fixtures	854,405,195	79,668,705	7,827,819			926,246,081
53	(356) Overhead Conductors and Devices	463,243,669	38,522,389	2,449,693		93	499,316,458
54	(357) Underground Conduit	8,993,504	2,504,568			98	11,497,974
55	(358) Underground Conductors and Devices	626,037	201,545			5	827,587
56	(359) Roads and Trails	131,947					131,947
57	(359.1) Asset Retirement Costs for Transmission Plant
58	TOTAL Transmission Plant (Enter Total of lines 48 thru 57)	2,324,483,589	184,319,587	20,023,708		469,600	2,488,309,868
59	4. Distribution Plant
60	(360) Land and Land Rights	10,228,553	8,930	164,683			10,072,800
61	(361) Structures and Improvements	10,718,863	3,239,173	21,732			13,936,304
62	(362) Station Equipment	385,280,086	23,987,665	4,495,743			404,772,008
63	(363) Energy Storage Equipment – Distribution
64	(364) Poles, Towers, and Fixtures	519,120,744	41,149,425	4,499,144			555,771,025
65	(365) Overhead Conductors and Devices	535,257,956	19,354,623	5,633,317			548,979,262
66	(366) Underground Conduit	79,609,887	5,212,889	18,059			84,804,717
67	(367) Underground Conductors and Devices	253,826,448	13,619,320	768,225			266,677,543
68	(368) Line Transformers	439,261,799	39,290,000	11,939,028			466,612,771
69	(369) Services	106,217,668	6,360,451	248,578			112,329,541
70	(370) Meters	91,646,023	25,347,311	10,131,389			106,861,945
71	(371) Installations on Customer Premises	46,870,729	5,053,704	2,512,219			49,412,214
72	(372) Leased Property on Customer Premises
73	(373) Street Lighting and Signal Systems	47,571,521	5,704,198	1,966,873			51,308,846
74	(374) Asset Retirement Costs for Distribution Plant
75	TOTAL Distribution Plant (Enter Total of lines 60 thru 74)	2,525,610,277	188,327,689	42,398,990			2,671,538,976
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	22,463,967	1,040,208	87,425			23,416,750
87	(390) Structures and Improvements	109,811,908	2,424,664	611,381			111,625,191
88	(391) Office Furniture and Equipment	8,316,421	37,358	1,060,673			7,293,106
89	(392) Transportation Equipment	3,875,443					3,875,443
90	(393) Stores Equipment	3,081,835	355,407	76,138			3,361,104
91	(394) Tools, Shop and Garage Equipment	30,754,460	2,086,373	244,509			32,596,324
92	(395) Laboratory Equipment	5,328,257		131,097			5,197,160
93	(396) Power Operated Equipment	698,227					698,227
94	(397) Communication Equipment	65,851,041	24,171,367	1,945,164			88,077,244
95	(398) Miscellaneous Equipment	2,986,656	124,378	87,196		469,600	3,493,438
96	SUBTOTAL (Enter Total of lines 86 thru 95)	253,168,215	30,239,755	4,243,583		469,600	279,633,987
97	(399) Other Tangible Property	80,507,195	7,350				80,514,545
98	(399.1) Asset Retirement Costs for General Plant	1,265,939					1,265,939
99	TOTAL General Plant (Enter Total of lines 96, 97, and 98)	334,941,349	30,247,105	4,243,583		469,600	361,414,471
100	TOTAL (Accounts 101 and 106)	10,134,599,915	1,198,645,383	99,603,111			11,233,642,187
101	(102) Electric Plant Purchased (See Instr. 8)	64,005					64,005
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)	10,134,663,920	1,198,645,383	99,603,111			11,233,706,192

Name of Respondent:

SWEPCO

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:

SWEPCO

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	Cardnell Road 138KV Substation (1062)	05/01/2009	12/31/2023	393,043.00
3	McCann Road 138/35kV Substation (1225)	06/01/2022	12/31/2023	649,660
4	Items under $250,000			651,058.00
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			1,693,761

Name of Respondent:

SWEPCO

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	ADMS Imp DSN DNEX-SWP D	1,724,132.00
2	AMI SWEPCO Louisiana	5,048,133.00
3	AMI SWEPCO Texas	2,864,260.00
4	Arsenal Hill Non-TX CI	2,814,941.00
5	Arsenal Hill TX CI	1,446,158.00
6	Bann - Texarkana Ops Non-TX CI	1,207,080.00
7	Bentonville Non-TX CI	2,203,900.00
8	Bentonville Non-TX CI Shadow	1,132,059.00
9	Booneville to Branch non-tx CI	6,193,428.00
10	Booneville to Branch TX CI	3,180,143.00
11	CARDNELL RD - D-LINE	1,685,255.00
12	CARDNELL RD - D-Station Comp	8,764,374.00
13	CIS-Common Deployment-SWP D	2,494,599.00
14	Corp Prgrm Billing-SWEPCO Tran	1,177,618.00
15	D/SW/Capital Blanket - SWEPCo	2,573,628.00
16	D/SW/Capital Blanket-SWEPCo-TX	1,965,085.00
17	DA Distibution Station - LA	1,852,280.00
18	DA Distribution Station - Ark	2,155,876.00
19	DeQueen CI non-tx	4,109,853.00
20	DeQueen CI TX	2,111,484.00
21	Dierks to Mena 111 CI	1,483,121.00
22	Dierks to Mena 194 CI	2,887,837.00
23	Ed-Ci-Sepco-D Ast Imp	6,153,191.00
24	Ed-Ci-Sepco-D Cust Serv	4,649,299.00
25	Ed-Ci-Sepcotx-D Ast Imp	3,977,373.00
26	Ed-Ci-Sepcotx-D Cust Serv	1,448,436.00
27	Eureka Springs 3 Terminal	1,236,988.00
28	FLC U1 DBA Conver (CCR/ELG)	15,583,315.00
29	Forestry SEP LA DAC R W	1,053,298.00
30	Gilmer to Pittsburg Non-TX CI	1,283,194.00
31	IPC Domin to W Atlan Non-TX CI	5,142,915.00
32	IPC Domino to W Atlanta TX CI	2,640,051.00
33	Jeffers S - Marshall Non-TX CI	4,742,952.00
34	Jeffers S - Marshall TX CI	2,428,843.00
35	Knox Lee - Rock Hill Non TX CI	2,662,230.00
36	Knox Lee to Rock Hill TX CI	1,367,836.00
37	Lake Paul - W Child non-TX CI	2,719,226.00
38	Lake Paul-W Child TX CI	1,397,017.00
39	Longwood Stat non-tx CI	1,361,079.00
40	Mineola to N Minola Non-TX CI	1,029,537.00
41	Murfreesboro West D-station	1,151,516.00
42	Natchitoches Land Purchase	2,032,564.00
43	NGUCS/Radio SWEPCO Valley Impr	3,545,156.00
44	North Benton D CI	2,977,220.00
45	Patterson to S Nash 111 CI	6,057,872.00
46	Patterson to S Nash CI 194	11,791,901.00
47	Red Point Non-TX CI	1,179,676.00
48	Replace Tower #88 Maverick	1,084,093.00
49	Sabine - D-Station	2,057,483.00
50	SEP-D Telecom	5,060,570.00
51	SEPT-D Telecom	1,553,029.00
52	SHADOW NORTH BENTON	3,695,140.00
53	Shreveport Service Center(New)	5,953,300.00
54	Shreveport Telecom Office/Shop	2,524,074.00
55	SHREVEPORT TOC	30,333,431.00
56	Shreveport TOC - GL 111	15,584,571.00
57	Ss-Ci-Sepco-D Gen Plt	4,225,201.00
58	Ss-Ci-SepcoTx-D Gen Plt	4,151,289.00
59	SWEPCo Distr Pre Eng Parent	10,622,698.00
60	SWEPCo Major Eq/Spares-Distr	6,706,749.00
61	SWEPCO Next Gen Radio Sys 1	3,639,362.00
62	SWEPCO Next Gen Radio Sys 2	2,465,897.00
63	SWEPCo Trans Pre Eng Parent	10,088,849.00
64	SWEPCo Transco Line RB SHADOW	1,016,812.00
65	SWEPCO Transmission 1	7,186,563.00
66	SWEPCO Transmission 2	1,156,069.00
67	SWEPCO: Clarendon-NW Memphis	1,249,535.00
68	SWEPCo-D Spare/Major Equip CI	1,690,935.00
69	SWEPCo-D-Tx Spare/Mjr Equip CI	1,681,702.00
70	SWEPCo-T Spare/Major Equipm CI	1,685,662.00
71	SW-T BlnktProj Under $3M	14,798,655.00
72	SW-T BlnktProj Under$3M-Shadow	3,719,230.00
73	T/SW/CapBlnkt-SW ShadowParent	1,034,056.00
74	T/SW/Capital Blanket - SWEPCo	2,007,081.00
75	T/SW/Telecom Modernization Pro	1,738,657.00
76	Traverse Wind Project SWEPCo	7,970,880.00
77	TRK OVATION CONTROLS REPLACE	1,520,422.00
78	TRK SCR CATALYST LEVEL 2 REPL	1,561,746.00
79	WS Spare Generator Winding Kit	2,086,998.00
80	WS-CI-SEPCo-G PPB	13,957,688.00
81	Other Minor Projects Which is under 5% or $1,000,000	46,276,286.00
43	Total	372,772,642.00

Name of Respondent:

SWEPCO

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	3,104,612,034	3,104,612,034
2	Depreciation Provisions for Year, Charged to
3	DepreciationExpenseExcludingAdjustments (403) Depreciation Expense	298,691,001	298,691,001
4	DepreciationExpenseForAssetRetirementCosts (403.1) Depreciation Expense for Asset Retirement Costs	1,997,322	1,997,322
5	ExpensesOfElectricPlantLeasedToOthers (413) Exp. of Elec. Plt. Leas. to Others
6	TransportationExpensesClearing Transportation Expenses-Clearing
7	OtherClearingAccounts Other Clearing Accounts	654,444	654,444
8	OtherAccounts Other Accounts (Specify, details in footnote):
9.1	Other Accounts (Specify, details in footnote):	1,737,902	(a) 1,737,902
10	DepreciationProvision TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)	303,080,669	303,080,669
11	Net Charges for Plant Retired:
12	BookCostOfRetiredPlant Book Cost of Plant Retired	81,117,217	81,117,217
13	CostOfRemovalOfPlant Cost of Removal	33,705,934	(b) 33,705,934
14	SalvageValueOfRetiredPlant Salvage (Credit)	8,491,757	(c) 8,491,757
15	NetChargesForRetiredPlant TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)	106,331,394	106,331,394
16	OtherAdjustmentsToAccumulatedDepreciation Other Debit or Cr. Items (Describe, details in footnote):
17.1	Other Debit or Cr. Items (Describe, details in footnote):	16,740,620	16,741,049	(d) 429
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)	3,318,101,929	3,318,102,358	429
Section B. Balances at End of Year According to Functional Classification
20	AccumulatedDepreciationSteamProduction Steam Production	1,588,544,437	1,588,544,437
21	AccumulatedDepreciationNuclearProduction Nuclear Production
22	AccumulatedDepreciationHydraulicProductionConventional Hydraulic Production-Conventional
23	AccumulatedDepreciationHydraulicProductionPumpedStorage Hydraulic Production-Pumped Storage
24	AccumulatedDepreciationOtherProduction Other Production	77,363,133	77,363,133
25	AccumulatedDepreciationTransmission Transmission	637,215,854	637,215,854
26	AccumulatedDepreciationDistribution Distribution	836,056,809	836,057,238	429
27	AccumulatedDepreciationRegionalTransmissionAndMarketOperation Regional Transmission and Market Operation
28	AccumulatedDepreciationGeneral General	178,921,696	178,921,696
29	AccumulatedProvisionForDepreciationOfElectricUtilityPlant TOTAL (Enter Total of lines 20 thru 28)	3,318,101,929	3,318,102,358	429

FOOTNOTE DATA

(a) Concept: OtherAccounts


Depr Exp classified to acct 1510001			$ 705,086
Ash Pond Exp account 1823099			$ (5,093)
Louisiana ARO asbestos depr exp			$ 415,038
Louisiana ARO ash pond depr exp			$ 622,578
Arkansas ARO ash pond amortization			$ 293
Total			$ 1,737,902

(b) Concept: CostOfRemovalOfPlant

Includes $501,672 of removal cost in retirement work in progress (RWIP).

Includes ($4,729,369) of salvage in retirement work in progress (RWIP).

(d) Concept: OtherAdjustmentsToAccumulatedDepreciation

Transfer assets between accounts of $429

Name of Respondent:

SWEPCO

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	Southwest Arkansas Utilities Corp. 100 shares, $100 par value
2	common stock	03/24/2028		10,000			10,000
3	Dolet Hills Lignite Company (1)	06/01/2001
4	Investment - Dolet Hills			8,087,121			8,087,121
5	Dividends - Dolet Hills			20,215,155			20,215,155
6	Equity in Undistributed Earnings - Dolet Hills			43,552,695	1,359,935	24,774,577	20,138,053
7	Oxbow Lignite Company, LLC (2)	12/29/2009
8	Investment - Oxbow Lignite			12,872,791			12,872,791
9	Additional Investments (2016 Cash Infusion)			5,473,685			5,473,685
10	Dividends - Oxbow Lignite			16,274,183			16,274,183
11	Capital Contributions to Subs
12	Mutual Energy SWEPCO, LLC	08/21/2015				1,429	1,429
13	Investment - Mutual Energy			1,943,764			1,943,764
14	Equity in Undistributed Earnings - Mutual Energy			128,369	34,005		162,374
42	Total Cost of Account 123.1 $		Total	35,579,087	1,393,940	24,773,148	12,199,879

Name of Respondent:

SWEPCO

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)	67,208,288	(a) 64,682,162	Electric
2	Fuel Stock Expenses Undistributed (Account 152)	1,935,438	2,463,830	Electric
3	Residuals and Extracted Products (Account 153)
4	Plant Materials and Operating Supplies (Account 154)
5	Assigned to - Construction (Estimated)	34,993,471	39,070,797	Electric
6	Assigned to - Operations and Maintenance
7	Production Plant (Estimated)	33,730,328	43,956,593	Electric
8	Transmission Plant (Estimated)	77,242	159,522	Electric
9	Distribution Plant (Estimated)	936,687	1,267,460	Electric
10	Regional Transmission and Market Operation Plant (Estimated)
11	Assigned to - Other (provide details in footnote)	167,529	(b) 678,397	Electric
12	TOTAL Account 154 (Enter Total of lines 5 thru 11)	69,905,257	(c) 85,132,769
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)	1,700	1,700
17
18
19
20	TOTAL Materials and Supplies	139,050,683	152,280,461

Name of Respondent:

SWEPCO

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: FuelStock

Formula Rate uses 13 month average.

(b) Concept: PlantMaterialsAndOperatingSuppliesOther

Assigned to - Other: Includes Customer Accounts and Administrative and General

Expenses (applies to both beginning and ending balances).

Formula Rate uses 13 month average. Production materials and supplies are identified

by a query of the general ledger system.

Name of Respondent:

SWEPCO

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	697,798.00		72,752.00		72,752.00		72,752.00		1,883,287.00		2,799,341.00
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)									64,489.00		64,489.00
5	Returned by EPA
6
7
8	Purchases/Transfers:
9	Unknown
10	Other
11
12
13
14
15	Total
16
17	Relinquished During Year:
18	Charges to Account 509	12,341.00										12,341.00
19	Other:
20	Allowances Used
20.1	Allowances Used
21	Cost of Sales/Transfers:
22	Surrenders
23	Consent Decree Surrenders
24	Unknown
25	Other
26
27
28	Total
29	Balance-End of Year	685,457.00		72,752.00		72,752.00		72,752.00		1,947,776.00		2,851,489.00
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:

SWEPCO

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	4,809.00	65,592	3,646.00		3,646.00						12,101.00	65,592
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)	68.00										68.00
5	Returned by EPA
6
7
8	Purchases/Transfers:
9	Allegheny Energy Supply Company, LLC	2,727.00	7,082,620									2,727.00	7,082,620
10	Other
11	Total Purchases	2,727.00	7,082,620									2,727.00	7,082,620
12
13
14
15	Total
16
17	Relinquished During Year:
18	Charges to Account 509	5,388.00	4,422,346									5,388.00	4,422,346
19	Other:
20	Allowances Used
20.1	Allowances Used
21	Cost of Sales/Transfers:
22	Luminant Generation Company LLC
23	Surrenders
24	Birchwood Power Partners, L.P.
25	Wolverine Power Supply Cooperative, Inc.
26	Allegheny Energy Supply Company, LLC
27	Consent Decree Surrenders
28	Total
29	Balance-End of Year
30
31	Sales:
32	Net Sales Proceeds(Assoc. Co.)	2,216.00	2,725,867	3,646.00		3,646.00						9,508.00	2,725,867
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:

SWEPCO

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
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
20	TOTAL

Name of Respondent:

SWEPCO

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:

SWEPCO

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
20	Total
21	Generation Studies
22	PIRKEY SOLAR PRE-CI			60,000	183
23	PIRKEY SOLAR PRE-CI 2			10,000	183
39	Total			70,000
40	Grand Total			70,000

Name of Respondent:

SWEPCO

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 109 Deferred Federal Income Tax	60,833,409	26,152,814	182/190/236/254/255/281/282/283/409/410/411	28,566,275	58,419,948
2	SFAS 109 Deferred State Income Tax	234,887,901	34,336,131	283	60,513,929	208,710,103
3	SFAS 106 Medicare Subsidy (Amortization 5 period Jan 2013 - Dec 2024)	1,599,928		926	533,310	1,066,618
4	Unrealized Gain/Loss on Forward Commitments	2,148,755	2,148,755
5	Deferral of Fuel Underrecovery - Louisiana	11,069,773	16,530,178	182/254/440/442/444/557	27,599,951
6	Deferral of Fuel Underrecovery - Texas	47,000,381	146,682,288	182/254/440/442/444/557	2,279,065	191,403,604
7	Deferral of Fuel Underrecovery - Arkansas	23,085,252	86,256,857	182/254/440/442/444/557	43,508,863	65,833,246
8	Asset Retirement Obligation - Ash Ponds - SFAS 143	10,723,697	1,524,075	108/403/411	17,932	12,229,840
9	SFAS No. 158 - Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans	67,486,007	98,716,449	228	77,486,334	88,716,122
10	Various Rate Case Expenses Pending Future Approval for Collection from State Commission Authorities	6,011,213	2,247,674			8,258,887
11	Rate Case Expenses Approved for Recovery 21 in PUCT Final Orders: PUCT Docket 46449 - 3 Years beg Feb 2018 and PUCT Docket 47141 - 3 Years beg Sept 2020	3,490,153		108/142/163/172/184/186/236/419/442/586/588/928/935	2,580,172	909,981
12	Underrecovery of Energy Efficiency Program Expenses - Texas	3,950,206	6,769,888	440/442/907/908	6,992,464	3,727,630
13	Louisiana 2013 Formula Rate Plan (FRP) Excess Refunds	936,507				936,507
14	Deferred Wilkes Chapel Hill SPP Transmission Project Expense
15	Deferred Arkansas Environmental Chemical Costs per Docket No. 14-080-U 2	2,229,897		502	743,299	1,486,598
16	Underrecovered Environmental Adjustment Clause - Louisiana	324,060	2,058,007	254/509	2,114,011	268,056
17	2015 SPP Formula Rate True-up - 3rd Party Schedule 11 Base Plan Funding - SPP 42 Zone 1
18	Welsh Power Plant Unit 2 Asbestos ARO Texas Portion - to be amortized over 24 years per PUCT Docket No. 46449	470,810		407	11,572	459,238
19	Welsh/Flint Creek Power Plants - Environmental Deferral - LPSC Docket No. U-34200 Amortized over 15 Years beginning May 2017	11,042,112	574,818	182/403/408/431	1,643,410	9,973,520
20	Deferred O&M Expenses related to City of Shreveport Sewer Work per LPSC Docket No. U-32220, Feb 2016. Approved for recovery in LPSC Docket No. U-34200 over 15 months beginning May 2017.	1,728,735	62,599	421/593	96	1,791,238
21	Louisiana 2015 Formula Rate Plan Asset - Southwest Power Pool Deferral (LPSC Docket No. U-34200) - to be Amortized over 4 years beginning Aug 2018	702,496	40,559	182/421/431/456/565/593	743,055
22	Welsh Power Plant Unit 2 Texas Portion - Recovery of Retired Undepreciated Balance per PUCT Docket No. 46449	15,530,840		407	548,768	14,982,072
23	Arkansas Transition Cost Docket 01-042-U	1				1
24	Deferred Storm Expense	148,003,099	3,696,821	583/593	231,951	151,467,969
25	Mattison Res Chg Equity Contra	138,073		182/419	85,198	223,271
26	Reg Asset-Mattison Res Charge	2,224,620	203,636			2,428,256
27	COVID-19 Deferred Expense	6,451,983	2,577,792	182/426/506/512/588/593/903/920/921/923	4,713,519	4,316,256
28	Defer TX Line Inspection Costs	1,132,475	677,155	571/931	235,060	1,574,570
29	Environmental CWIP	7,958,893		182/512	153,792	7,805,101
30	Unrecov Fuel Cost 2021 Weather	430,220,078	10,290,716	182/419/440/442/444/557	245,835,535	194,675,259
31	Dolet Hills Fuel-Deferred LA	30,942,528	1,107,316			32,049,844
32	North Central Wind.over/under recovery of the WFA Rider	1,877,743	13,080,902	403	8,596,161	6,362,484
33	Dolet Hills Fuel-Deferred AR	12,960,403		182	4,092,759	8,867,644
34	Texas retail share of the Dolet Hills Net Book Value regulatory asset. (PUCT Docket 51415)	43,999,470	3,648,201	107/108/146/151/154/163/183/184/232/234/236/242/500/501/506/511/512/513/514/554	3,734,780	43,912,891
35	Disallowance of the Texas portion of the Dolet Hills Plant. (PUCT Docket 51415)	11,592,406	824,532			10,767,874
36	Texas retail share of the retired gas units: Lieberman U2, Lone Star U1, and Knox Lee U2-4 net book value regulatory asset. (PUCT Docket 51415)	3,968,864	853,468	407	1,222,369	3,599,963
37	Transmission Base Plan Funding FERC Formula Rates Under Recovery		907,418			907,418
38	SWEPCO Arkansas bad debt expense under the base rates established in Docket No. 21-070-U.		4,193,622			4,193,622
39	Surcharge for the excess winter storm expenses for Arkansas, Louisiana, and Texas.		151,179,573	182/440/442/444/557	18,775,697	132,403,876
40	Advanced Metering System (AMS) Deployment Plan for SWEPCO TX in Docket No. 52389 - O/U and Carry Charges		5,993,671	182/403/407/431	1,352,111	4,641,560
41	2021 Winter Storm carrying costs on unrecovered fuel costs related to the Arkansas portion of SWEPCO 2021 winter storm per Order 21 in APSC Docket 19-008-U.		10,039,114	182/419/431	8,125,047.05	1,914,067
42	Arkansas retail share of the Dolet Hills Net Book Value regulatory asset per APSC Docket No. 21-070-U		24,949,932	108/154/182/184/186/407/411	2,450,218.00	22,499,714
43	Disallowance of the Arkansas portion of the Dolet Hills Plant per APSC Docket No. 21-070-U		305,125	426	1,654,458.00	1,349,333
44	Amortize approved Arkansas COVID Expenses per APSC Docket No. 21-070-U over a 5 year period starting July 2022.		1,854,612	182/426/903/923	185,461.20	1,669,151
44	TOTAL	1,178,964,300	660,484,698		557,326,622	1,282,122,376

Name of Respondent:

SWEPCO

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	Agency Fees - Factored Accounts Receivable	2,973,248	38,296,019	142/184/234/426	37,389,700	3,879,567
2	Associated Business Development Billings and Deferred Projects	1,238,651	56,692,582	107/108/142/146/163/184/186/234/418/421/512/513/560/588/593/596/566/922/143	55,556,063	2,375,170
3	Unamortized Credit Line Fees Amortization period through 6/1/2022	991,216	180,664	146/234/431	510,350	661,530
4	Sabine Mine Preparation - Rusk County, TX - Amortization based on tons mined	679,462	57,478	108/151/501	704,126	32,814
5	Deferred Expenses - Disposition of Fuel	160,704	5,166,131	151/152/154/183/501/547	5,081,704	245,131
6	Deferred Expense - Underrecovery of Transsource Missouri	64,599	820,919	565	760,954	124,564
7	Deferred Rate Case Expense	78,984	669,539	107/108/146/232/431/560/580/582/583/588/591/592/593/902/903/908/921/928/931/935	659,539	88,984
8	Deferred Leased Assets	154,366	716,232	143/146/234	800,721	69,878
9	Dolet Hills Reclamation Advance	48,283,499	633,824,045	230/242/426	627,309,560	54,797,984
10	Deferred Lignite Lease
11	Minor Items < $100,000	10,424	3,104,926	107/146/151/186/236/242/408/421/426/553/569/591/597/903/908/912/925/926/930/935	3,088,975	26,375
12	Provision for refund related to overcollection of 2022 SPP revenue		14,346,014	146/ 253/565	6,998,363	7,347,651
47	Miscellaneous Work in Progress
48	Deferred Regulatroy Comm. Expenses (See pages 350 - 351)
49	TOTAL	54,635,153				69,649,648

Name of Respondent:

SWEPCO

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	Nol-State C/F-Def Tax Asset-L/T - La	41,916,137	41,993,474
3	Accrd Book Aro Expense - Sfas 143	26,953,376	33,387,770
4	Disallowed Costs-Turk Plant	12,835,379	12,808,528
5	Tax Credit C/F - Def Tax Asset	7,586,668	65,062,625
6	Nol-State C/F-Def Tax Asset-L/T - Ar	11,192,354	11,669,405
7	Other	17,032,320	899,755
8	TOTAL Electric (Enter Total of lines 2 thru 7)	117,516,234	165,821,557
9	Gas
15	Other
16	TOTAL Gas (Enter Total of lines 10 thru 15)
17.1	Other (Specify)	204,277,301	192,397,009
17	Other (Specify)
18	TOTAL (Acct 190) (Total of lines 8, 16 and 17)	(a) 321,793,535	358,218,566

Notes

Name of Respondent:

SWEPCO

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

Formula Rate uses 13 month average.



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


Acc Def Income Taxes - Federal - Hdg-CF-Int Rate	38,722	-
Non Utility Items - 190.2	1,124,658	626,557
SFAS 109-Regulatory Assets - 190.3, 190.4 & 190.6	204,537,961	190,302,081
SFAS 133	-	-
Accu Def Income Taxes Pension-OCI	(1,424,040)	1,468,371

Total	$204,277,301	$192,397,009



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

Balance at Beginning of Year		$321,793,535

(Less) Amounts Debited to:
(a) Account 410.1		(112,320,962.00)
(b) Account 410.2		(2,072,276)
(c) 1823/254/219/129/427		(36,759,592)

(Plus) Amounts Credited to:


(a) Account 411.1												160,626,284.00
(b) Account 411.2												1,574,176
(c) 1823/254/219/129/427												25,377,401

Balance at End of Year												$358,218,566

Name of Respondent:

SWEPCO

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	Common Stock (Account 201)	7,600,000	18.00		3,680	66,240
7	Total	7,600,000			3,680	66,240
8	Preferred Stock (Account 204)
9
10
11
12	Total
1	Capital Stock (Accounts 201 and 204) - Data Conversion
2
3
4
5	Total

Name of Respondent:

SWEPCO

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	280,000,000
3.1	IncreasesDecreasesFromSalesOfDonationsReceivedFromStockholders Increases (Decreases) from Sales of Donations Received from Stockholders	350,000,000
4	DonationsReceivedFromStockholders Ending Balance Amount	630,000,000
5	ReductionInParOrStatedValueOfCapitalStockAbstract Reduction in Par or Stated Value of Capital Stock (Account 209)
6	ReductionInParOrStatedValueOfCapitalStock Beginning Balance Amount
7.1	IncreasesDecreasesDueToReductionsInParOrStatedValueOfCapitalStock Increases (Decreases) Due to Reductions in Par or Stated Value of Capital Stock
8	ReductionInParOrStatedValueOfCapitalStock Ending Balance Amount
9	GainOrResaleOrCancellationOfReacquiredCapitalStockAbstract Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210)
10	GainOnResaleOrCancellationOfReacquiredCapitalStock Beginning Balance Amount	2,106,937
11.1	IncreasesDecreasesFromGainOrResaleOrCancellationOfReacquiredCapitalStock Increases (Decreases) from Gain or Resale or Cancellation of Reacquired Capital Stock
12	GainOnResaleOrCancellationOfReacquiredCapitalStock Ending Balance Amount	2,106,937
13	MiscellaneousPaidInCapitalAbstract Miscellaneous Paid-In Capital (Account 211)
14	MiscellaneousPaidInCapital Beginning Balance Amount	810,037,044
15.1	IncreasesDecreasesDueToMiscellaneousPaidInCapital (a) Increases (Decreases) Due to Miscellaneous Paid-In Capital	1,428.93
16	MiscellaneousPaidInCapital Ending Balance Amount	810,038,473
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	1,442,145,410

Name of Respondent:

SWEPCO

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: OtherPaidInCapitalDescription

Effective August 31, 2020, SWEPCo completed a reverse stock split, with each 2,048 shares of Common Stock

issued and outstanding being combined into one share. Par value remains $18/share.

Name of Respondent:

SWEPCO

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:

SWEPCO

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
3
4
5	Subtotal
6	Reacquired Bonds (Account 222)
7
8
9
10	Subtotal
11	Advances from Associated Companies (Account 223)
12
13
14
15	Subtotal
16	Other Long Term Debt (Account 224)
17	Senior Unsecured Notes Series H, 6.20%		350,000,000		3,509,108		147,000	03/15/2010	03/15/2040	03/15/2010	03/15/2040	350,000,000	21,700,000
18	(a) Senior Unsecured Notes Series I, 3.55%		275,000,000		2,145,615		1,130,250	02/03/2012	02/15/2022	02/03/2012	02/15/2022
19	Senior Unsecured Notes Series J, 3.90%		400,000,000		3,980,775		3,568,000	03/26/2015	04/01/2045	03/26/2015	04/01/2045	400,000,000	15,600,000
20	Senior Unsecured Notes Series K, 2.75%		400,000,000		2,925,034		416,000	09/29/2016	10/01/2026	09/29/2016	10/01/2026	400,000,000	11,000,000
21	Senior Unsecured Notes Series L, 3.85% FERC Authority ES17-43-000		450,000,000		4,656,209		958,500	01/22/2018	02/01/2048	01/22/2018	02/01/2048	450,000,000	17,325,000
22	Senior Unsecured Notes Series M, 4.10% FERC Authority ES18-32-000		575,000,000		4,369,257			09/13/2018	09/15/2028	09/13/2018	09/15/2028	575,000,000	23,575,000
23	Senior Unsecured - Series N, 1.65%		500,000,000		3,903,793		50,000	03/15/2021	03/15/2026	03/15/2021	03/15/2026	500,000,000	8,250,000
24	Senior Unsecured - Series O, 3.25%		650,000,000		6,790,998		2,346,500	11/01/2021	11/01/2051	11/01/2021	11/01/2051	650,000,000	21,125,000
25	Senior Unsecured Notes - Financial Hedges												106,952
26	Subtotal											3,325,000,000
33	TOTAL		3,600,000,000									3,325,000,000	118,468,048

Name of Respondent:

SWEPCO

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: ClassAndSeriesOfObligationCouponRateDescription

Senior Unsecured - Series I of $275000000 with Interest rate 3.55% was retired on 2/15/2022.

Name of Respondent:

SWEPCO

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)	290,060,102
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) 79,048,369
28	Show Computation of Tax:
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44

Name of Respondent:

SWEPCO

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


			In (000's)

Net Income for the Year per Page 117			290,060
Federal Income Taxes			(19,988)
State Income Taxes			(6,255)
Pre-Tax Book Income			263,817

Allowance for Funds Used During Construction and Other Differences:
Between Items Capitalized for Books and Expensed for Tax			(686)
Accrued Company-wide Incentive Plan			1,528
Book / Tax Unit of Property Adj			(80,518)
Capitalized Relocation Costs			(2,400)
Capitalized Software			11,563
Deferred Fuel Costs (Net)			581
Disallowed Costs - Turk Plan			(1,463)
Disallowed Costs - PUCT			2,641
Equity in Earnings of Subsidiary Companies			(1,394)
Excess Tax Vs Book Depreciation			(206,147)
Depletion			(22,822)
Mark to Market			(310)
Mine Reclamation			3,825
Pension Expenses (Net)			(76)
Premium / Loss on Reacquired Debt (Net)			600
Provision for Revenue Refund			1,992
Regulatory Assets			(8,188)
Removal Costs			(28,363)
SFAS 106 - Post Retirement Benefit Expense Accrued / Funded (Net)			(7,399)


SFAS 112 - Post Employment Benefit Expense Accrued / Funded (Net)			1,173
Unbilled Revenue			—
Others			(5,686)

Taxable Income before State Taxes			(77,732)

State & Local Current Tax			1,316

Federal Taxable Income			(79,048)

Computation of Tax:
FIT on Current Year Taxable Income @ 21%			(16,600)
Other			—
NOL Deferred Tax Asset			14,442
Tax Credits			(56,748)
Parent Savings			57,139
Alt Min			—
R and D Credit			248
Estimated Tax Currently Payable (a)			(31,681)
Adjustments of Prior Year's Accruals
Tax Expense for R/C of Net Operating Loss (Prior Yr)

Estimated Current Federal Income Taxes			(31,681)

a) Represents the allocation of 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 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:

SWEPCO

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	Federal Tax			7,568,052	0	45,701,548	40,399,245	0	12,870,355	0	37,907,895		0	7,793,653
2	Subtotal Federal Tax				7,568,052	0	45,701,548	40,399,245	0	12,870,355	0	37,907,895	0	0	7,793,653
3	State Tax	State Tax	AR	2015	436	0	0	0	0	436	0	0		0	0
4	State Tax	State Tax	AR	2017	188,896	0	0	0	0	188,896	0	0		0	0
5	State Tax	State Tax	AR	2018	72,598	0	0	0	0	72,598	0	0		0	0
6	State Tax	State Tax	AR	2019	37,628	0	0	0	0	37,628	0	0		0	0
7	State Tax	State Tax	AR	2020	3,112,111	0	0	0	0	3,112,111	0	0		0
8	State Tax	State Tax	AR	2021	683,770			2,305,802		2,989,572
9	State Tax	State Tax	AR	2022			702,583			702,583		566,267			136,316
10	State Tax	State Tax	LA	2015	12,756	0	0	0	0	12,756	0	0		0	0
11	State Tax	State Tax	LA	2017	1,332,321	0	0	0	0	1,332,321	0	0		0	0
12	State Tax	State Tax	LA	2018	637,467	0	0	0	0	637,467	0	0		0	0
13	State Tax	State Tax	LA	2019	2,769,914	0	0	0	0	2,769,914	0	0		0	0
14	State Tax	State Tax	LA	2020	9,946,087	0			0	9,946,087	0	0		0
15	State Tax	State Tax	LA	2021	290,579	0		4,182,592	0	4,473,171	0			0	0
16	State Tax	State Tax	LA	2022			902,183	790,900		1,693,083		710,584			191,599
17	State Tax	State Tax	MULTI	2019	899,200	0		0	0	899,200	0	0	0	0
18	State Tax	State Tax	MULTI	2020	2,594	0		0	0	2,594	0	0	0	0
19	State Tax	State Tax	MULTI	2021	1,115,668	0		1	0	1,115,667	0			0	0
20	State Tax	State Tax	NE	2017	0	0	0	0	0	0	0	0	0	0	0
21	State Tax	State Tax	NE	2018	8,708	0	0	0	0	8,708	0	0	0	0	0
22	State Tax	State Tax	NE	2019	8,353	0	0	0	0	8,353	0	0	0	0	0
23	State Tax	State Tax	NE	2020	2,081	0		0	0	2,081	0	0	0	0
24	State Tax	State Tax	NE	2021	9,217	0		3,217	0	6,000	0			0
25	State Tax	State Tax	NE	2022				115,500		115,500
26	State Tax	State Tax	OH	2020	3,072	0	0	0		3,072	0	0		0	0
27	State Tax	State Tax	OK	2017	8,947	0	0	0	0	8,947	0	0	0	0	0
28	State Tax	State Tax	OK	2018	574	0	0	0	0	574	0	0	0	0	0
29	State Tax	State Tax	OK	2019	17,768	0	0	0	0	17,768	0	0	0	0	0
30	State Tax	State Tax	OK	2020	9,419	0			0	9,419	0	0	0	0
31	State Tax	State Tax	OK	2021	10,922	0		8,360	0	19,282	0			0	0
32	State Tax	State Tax	OK	2022			2,687			2,687		9,280			6,593
33	State Tax	State Tax	TX	2011	5,972	0	0	0	0	5,972	0	0	0	0	0
34	State Tax	State Tax	TX	2017	0	0	0	0	0	0	0	0	0	0	0
35	State Tax	State Tax	TX	2018	12,274	0	0	0	0	12,274	0	0	0	0	0
36	State Tax	State Tax	TX	2019	821,601	0	0	0	0	821,601	0	0	0	0	0
37	State Tax	State Tax	TX	2020	298,938	0	0	0	0	298,938	0	0	0	0
38	State Tax	State Tax	TX	2021	126,467	0		428,784	0	302,317	0			0
39	State Tax	State Tax	TX	2022			152,132			152,132		456,431			304,299
40	Subtotal State Tax				7,020,158	0	1,754,211	5,999,202	0	2,775,167	0	1,724,002	0	0	30,209
41	Local Tax						0	0		0				0
42	Local Tax	Local Tax	LA	2021	2,310,912	31,303	31,303	2,310,912		0				0	31,303
43	Local Tax	Local Tax	LA	2022			10,806,341	8,472,596		2,357,112	23,367	10,837,643			31,302
44	Local Tax	Local Tax	MULTI	2019	902,128	0				902,128	0
45	Local Tax	Local Tax	OH	2018	37	0	0	0	0	37	0	0	0	0	0
46	Local Tax	Local Tax	TX	2020	0	0				0	0	0		0	0
47	Local Tax	Local Tax	TX	2021	1,752,837	0		1,752,837		0	0			0	0
48	Local Tax	Local Tax	TX	2022			9,207,499	7,443,338		1,764,161		9,207,499
49	Subtotal Local Tax				3,161,584	31,303	20,045,143	19,979,683	0	3,219,108	23,367	20,045,142	0	0	1
50	Subtotal Other Tax				0	0	0	0	0	0	0	0	0	0	0
51	Property Tax	Property Tax	AR	2020	0	0	0	0	0	0	0			0
52	Property Tax	Property Tax	AR	2021	17,350,350	0	561,376	16,788,974	0	0	0	561,376		0
53	Property Tax	Property Tax	AR	2022			18,141,210			18,141,210		17,410,748			730,462
54	Property Tax	Property Tax	CO	2020	0	0	0	0	0	0	0			0
55	Property Tax	Property Tax	CO	2021	0	0	2,411	2,411	0	0	0			0	2,411
56	Property Tax	Property Tax	LA	2017	0	0	0	0	0	0	0	125,516			125,516
57	Property Tax	Property Tax	LA	2020	0	0			0	0	0			0	0
58	Property Tax	Property Tax	LA	2021	0	0	18,362	18,362	0	0	0	18,362		0	0
59	Property Tax	Property Tax	LA	2022			41,622,070	41,079,854		542,216		41,198,545			423,525
60	Property Tax	Property Tax	MO	2021	14,948	0	14,948	0		0	0				14,948
61	Property Tax	Property Tax	MO	2022			27,100	26,310		790					27,100
62	Property Tax	Property Tax	NE	2019	0	0				0	0
63	Property Tax	Property Tax	OK	2020	0	0			0	0	0			0	0
64	Property Tax	Property Tax	OK	2021	266,410	0	17,551	248,859	0	0	0	15,579		0	33,130
65	Property Tax	Property Tax	OK	2022			5,765,839	3,537,654		2,228,185		7,765,402			1,999,563
66	Property Tax	Property Tax	TX	2020	1	0	268	267		0	0	268		0	0
67	Property Tax	Property Tax	TX	2021	14,958,914	0	1,101,748	13,857,165		1	0	1,101,748		0
68	Property Tax	Property Tax	TX	2022			24,368,545	3,174,986		21,193,559		23,431,162			937,383
69	Property Tax	Property Tax	WV	2021	0	0	8,381	8,381		0	0	0	0	0	8,381
70	Property Tax	Property Tax	WY	2020	2,059	0	2,059			0	0	0	0	0	2,059
71	Property Tax	Property Tax	WY	2021			3,900	3,603		297					3,900
72	Property Tax	Property Tax	MS	2020			19	19		0					19
73	Property Tax	Property Tax	AZ	2020	0	0	3	3		0	0	0	0	0	3
74	Subtotal Property Tax				32,592,682	0	88,259,890	78,746,314	0	42,106,258	0	88,301,922	0	0	42,032
75	UNEMPLOYMENT 2022	Unemployment Tax			15,294	0	53,063	63,891	0	4,466	0	50,182		0	2,881
76	STATE UNEMPLOYMENT 2022	Unemployment Tax	AR		3,129	0	25,371	10,731	0	17,769	0	19,676		0	5,695
77	STATE UNEMPLOYMENT 2022	Unemployment Tax	LA		718	0	3,755	3,868	0	605	0	3,755		0	0
78	STATE UNEMPLOYMENT 2022	Unemployment Tax	NE		0	0	0	0	0	0	0	0			0
79	STATE UNEMPLOYMENT 2022	Unemployment Tax	OK		0	0	0	0	0	0	0	0			0
80	STATE UNEMPLOYMENT 2022	Unemployment Tax	TX		10,967	0	34,327	38,559	0	6,735	0	22,394		0	11,933
81	Subtotal Unemployment Tax				30,108	0	116,516	117,049	0	29,575	0	96,007	0	0	20,509
82	Sales & Use Tax	Sales And Use Tax	AR	2021	1,586,640	907,600	405,342	1,084,382		0		296			405,046
83	Sales & Use Tax	Sales And Use Tax	AR	2022			11,427,437	10,350,322		1,992,915	915,800	161			11,427,276
84					0	0	0	0	0	0	0		0	0	0
85	Sales & Use Tax	Sales And Use Tax	LA	2021	603,050	0	22,512	625,562	0	0	0				22,512
86	Sales & Use Tax	Sales And Use Tax	LA	2022			8,939,791	7,737,593		1,202,198		422			8,939,369
87	Sales & Use Tax	Sales And Use Tax								0	0		0	0
88	Sales & Use Tax	Sales And Use Tax	OK	2020	1		1	0	0	0				0	1
89	Sales & Use Tax	Sales And Use Tax	OK	2021	14,263	3,796	118	10,349	0	0	0	0		0	118
90	Sales & Use Tax	Sales And Use Tax	OK	2022			116,721	111,021		9,286	3,586				116,721
91	Sales & Use Tax	Sales And Use Tax	TX	2017	361,124	0				361,124	0	0	0	0	0
92	Sales & Use Tax	Sales And Use Tax	TX	2018	459,443	0				459,443	0	0	0	0	0
93	Sales & Use Tax	Sales And Use Tax	TX	2020	0	0	1,040,400			1,040,400	0	440,000	0	0	600,400
94	Sales & Use Tax	Sales And Use Tax	TX	2021	1,096,206	0	172,663	923,543		0	0	6		0	172,669
95	Sales & Use Tax	Sales And Use Tax	TX	2022			18,810,957	18,099,880		711,077		2,649			18,813,606
96	Sales & Use Tax	Sales And Use Tax	SC	2021	43	0	43	0	0	0	0	0	0	0	43
97	Subtotal Sales And Use Tax				2,479,636	911,396	40,590,335	38,942,652	0	4,135,309	919,386	438,236	0	0	40,152,099
98	Subtotal Income Tax				0	0	0	0	0	0	0	0	0	0	0
99	Excise Tax	Excise Tax		2022	0	0	5,906	5,906	0	0	0	5,906		0	0
100	Subtotal Excise Tax				0	0	5,906	5,906	0	0	0	5,906	0	0	0
101	Subtotal Fuel Tax				0	0	0	0	0	0	0	0	0	0	0
102	FICA 2022	Federal Insurance Tax			1,245,656	0	11,386,335	14,266,657	2,837,181	1,202,515	0	6,536,124			4,850,211
103	2360104 FICA	Federal Insurance Tax			0	0	0	0	0	0	0	0			0
104	2360105 FICA CARES ACT	Federal Insurance Tax			2,837,181	0	0	0	2,837,181	0	0	0			0
105	Subtotal Federal Insurance Tax				4,082,837	0	11,386,335	14,266,657	0	1,202,515	0	6,536,124	0	0	4,850,211
106	Franchise Tax	Franchise Tax	AR	2021	155	0	155			0	0	155		0	0
107	Franchise Tax	Franchise Tax	DE	2017	15,100	0	0	0	0	15,100	0	0		0	0
108	Franchise Tax	Franchise Tax	DE	2019	17,565	0	0	0	0	17,565	0	0		0	0
109	Franchise Tax	Franchise Tax	DE	2020	17,415	0	1	0	0	17,416	0			0	1
110	Franchise Tax	Franchise Tax	DE	2021	175	0	175	0	0	0	0	175		0	0
111	Franchise Tax	Franchise Tax	LA	2005	0	0	0	0	0	0	0	0	0	0	0
112	Franchise Tax	Franchise Tax	LA	2017	378,956	0	0	0	0	378,956	0	0	0	0	0
113	Franchise Tax	Franchise Tax	LA	2018	1,176,416	0	0	0	0	1,176,416	0	0	0	0	0
114	Franchise Tax	Franchise Tax	LA	2019	3,469,591	0		0	0	3,469,591	0	0	0	0
115	Franchise Tax	Franchise Tax	LA	2020	309,946	0	0		0	309,946	0	0	0	0
116	Franchise Tax	Franchise Tax	LA	2021	4,786,871	0		4,163,000	0	623,871	0			0
117	Franchise Tax	Franchise Tax	LA	2022			4,242,594			4,242,594		4,242,594
118	Franchise Tax	Franchise Tax	OH	2005	0	0				0	0	0
119	Franchise Tax	Franchise Tax	OK	2022	0	0	20,123	20,100		23	0	20,100
120	Franchise Tax	Franchise Tax	TX	2005	0	0				0	0
121	Subtotal Franchise Tax				532,758	0	4,262,388	4,183,100	0	453,470	0	4,262,364	0	0	1
122	Other State Tax	Other State Tax	OH	2021	0	0	3	3		0	0	3		0	0
123	Other State Tax	Other State Tax	OH	2022	0	0	7	7		0	0	7		0	0
124	Subtotal Other State Tax				0	0	10	10	0	0	0	10	0	0	0
125	Subtotal Other Property Tax				0	0	0	0	0	0	0	0	0	0	0
126	Subtotal Other Use Tax				0	0	0	0	0	0	0	0	0	0	0
127	Subtotal Other Advalorem Tax				0	0	0	0	0	0	0	0	0	0	0
128	Other License And Fees Tax	Other License And Fees Tax	LA	2019	35	0	0	0	0	35	0			0	0
129	Other License And Fees Tax	Other License And Fees Tax	LA	2021	0	0			0	0	0			0	0
130	Other License And Fees Tax	Other License And Fees Tax	LA	2022			86,040	86,040		0		86,040		0
131	Other License And Fees Tax	Other License And Fees Tax	OK	2020	10	0				10	0	0	0	0	0
132	Subtotal Other License And Fees Tax				45	0	86,040	86,040	0	45	0	86,040	0	0	0
133	Subtotal Payroll Tax				0	0	0	0	0	0	0	0	0	0	0
134	Subtotal Advalorem Tax				0	0	0	0	0	0	0	0	0	0	0
135	Subtotal Other Allocated Tax				0	0	0	0	0	0	0	0	0	0	0
136	Subtotal Severance Tax				0	0	0	0	0	0	0	0	0	0	0
137	Subtotal Penalty Tax				0	0	0	0	0	0	0	0	0	0	0
138	Other Taxes & Fees	Other Taxes and Fees	AR	2021	324,000	0	324,000	648,000	0	0				0	324,000
139	Other Taxes & Fees	Other Taxes and Fees	AR	2022		0	522,000		0	522,000	0	0		0	522,000
140	Other Taxes & Fees	Other Taxes and Fees	LA	2022	0	0	600,000		0	600,000	0	0		0	600,000
141	Other Taxes & Fees	Other Taxes and Fees	LA	2021	149,967	0		671,456	0	521,489	0	0		0
142	Other Taxes & Fees	Other Taxes and Fees	TX	2021	489,000	0	498,000	987,000		0	0	0		0	498,000
143	Other Taxes & Fees	Other Taxes and Fees	TX	2022		0	7,567,243	7,058,243		509,000	0	7,058,243		0	509,000
144	Subtotal Other Taxes And Fees				962,967	0	9,511,243	9,364,699	0	1,109,511	0	7,058,243	0	0	2,453,000
40	TOTAL				28,188,801	942,699	126,808,047	119,293,663	0	35,703,239	942,753	87,198,120	0	0	39,609,927

Name of Respondent:

SWEPCO

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%
3	4%				411.4
4	7%				411.4
5	10%	965,349	411.1		411.4	530,982		434,367	43 Years
6	State DITC		411.1		411.4
7	30				411.4
8	TOTAL Electric (Enter Total of lines 2 thru 7)	965,349				530,982		434,367
9	Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
10										`
47	OTHER TOTAL
48	GRAND TOTAL	965,349						434,367

Name of Respondent:

SWEPCO

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	Insurance Liability - BREMCO	10,573	107/108/142/146/151/152/154/163/165/184/186/232/234/235/236/242/253/440/442/444/426/500/501/505/506/510/511/512/513/514/583/588/592/593/908/921/935	2,696,980	2,679,763	6,644
2	(a) Turk Power Plant Joint Ownership Deferred Credits	7,905,668	143/253/419	59,042	304,945	8,151,571
3	(b) Current Portion of Turk Power Plant Joint Ownership Deferred Credits	50,797			4,123	54,920
4	Pole Attachments	1,543,914	108/142/143/146/163/172/184/186/421/426/431/451/454/456/589/593/905	3,384,099	3,539,227	1,699,042
5	Customer Advance Receipts	6,086,774	142	6,086,775	5,959,423	5,959,422
6	Contribution in Aid of Construction	1,863,011	107/108	1,863,011	2,741,347	2,741,347
7	Refund Provision related to Turk Power Plant Prudence Review Settlement - Dec 2017 per LPSC Docket No. U-33856 (Long Term Portion)	875,000	146/234/242/440/442/444	875,000
8	Qaulity of Service/Notice of Violation Penalty	689,563				689,563
9	F.J. Doyle Salvage - Federal Super Fund Site	350,000				350,000
10	Def Lignite Lease Obligation	17,615,811	151/234/243/253	8,373,960	1,811,574	11,053,425
11	Rayburn termination proceeds for abandonment of interconnections	4,417,652	107/146/234	5,500,000	1,082,348
12	Minor Items	3,881,420	134/142/143/146/186/232/234/235/242/253/565	3,754,362	5,010,911	5,137,969
13	Provision for refund related to overcollection of 2022 SPP revenue		449		5,625,976	5,625,976
47	TOTAL	45,290,183		32,593,228	28,759,637	41,456,591

Name of Respondent:

SWEPCO

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: DescriptionOfOtherDeferredCredits

Formula Rate Uses:

SPP Independent Power Producers System Upgrade Credits By Function

YEAR 2022


Description	Balance at Beg of Year	Transmission		Generation		Balance at End of Year
		Debit	Credit	Debit	Credit

GENERATION
Generation IPP Prepayment	24,618,491				(205,944)	24,412,547
Joint Owner IPP Credits	(7,905,668)			59,042	(304,945)	(8,151,571)
Current Portion of Joint Owner Credits	(50,797)				(4,123)	(54,920)

SWEPCO Share Generation IPP Prepayment	16,662,026	—	—	59,042	(515,012)	16,206,056

Transmission IPP Credits	(24,618,491)	—	205,944			(24,412,547)

TOTAL SWEPCo Company
Total Line 3 & Line 6	(7,956,465)	—	205,944	59,042	(515,012)	(8,206,491)

(b) Concept: DescriptionOfOtherDeferredCredits

See Line 3 Footnote.

Name of Respondent:

SWEPCO

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	71,193,385	3,603,957	481,378							74,315,964
5	Other
5.1	Other (provide details in footnote):
8	TOTAL Electric (Enter Total of lines 3 thru 7)	71,193,385	3,603,957	481,378							74,315,964
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) 25,893,183					254		254	481,378	25,411,805
17	TOTAL (Acct 281) (Total of 8, 15 and 16)	45,300,202	3,603,957	481,378						481,378	48,904,159
18	Classification of TOTAL
19	Federal Income Tax	45,300,202	3,603,957	481,378						481,378	48,904,159
20	State Income Tax
21	Local Income Tax

Name of Respondent:

SWEPCO

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

Formula Rate uses 13 month average.


Description Page 272-273 Line 16	Balance at Beginning of The year	Balance End of Year
SFAS 109	(25,893,183)	(25,411,805)
Total Line 16	(25,893,183)	(25,411,805)

Name of Respondent:

SWEPCO

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	1,384,684,564	166,586,401	118,585,750					190		1,432,685,215
3	Gas
4	Other (Specify)
5	Total (Total of lines 2 thru 4)	1,384,684,564	166,586,401	118,585,750							1,432,685,215
6	Other	(a) 402,206,609					1823/254	8,478,385	1823/254	27,455,464	383,229,530
9	TOTAL Account 282 (Total of Lines 5 thru 8)	982,477,955	166,586,401	118,585,750				8,478,385		27,455,464	1,049,455,685
10	Classification of TOTAL
11	Federal Income Tax	982,477,955	166,586,401	118,585,750				8,478,385		27,455,464	1,049,455,685
12	State Income Tax
13	Local Income Tax

Name of Respondent:

SWEPCO

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: AccumulatedDeferredIncomeTaxesOtherProperty

Formula Rate uses 13 month average.


Line 6 Footnote
	Beg Bal	End Bal
Non-Utility	0	0
SFAS 109	(402,206,609)	(383,229,530)
Total Other - Line 6	(402,206,609)	(383,229,530)

Name of Respondent:

SWEPCO

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	DEFD STORM DAMAGE	31,080,647	776,333	48,710							31,808,270
4	REG ASSET-SFAS 158 - PENSIONS	15,859,833	404,211	1,614,678							14,649,366
5	ACCRUED BK PENSION EXPENSE	13,188,827	34,099	1,444,574							11,778,352
6	ACCRD SFAS 106 PST RETIRE EXP	10,003,048	5,315,215	230,136							15,088,127
7	NOL-STATE C/F-DEF TAX ASSET-L/	8,802,389	458,972	442,731							8,818,630
8	Other	10,063,216	37,068,405	25,122,197							1,882,992
9	TOTAL Electric (Total of lines 3 thru 8)	68,871,528	44,057,235	28,903,026							84,025,737
10	Gas
11
12
13
14
15
16
17	TOTAL Gas (Total of lines 11 thru 16)
18	TOTAL Other	(a) 302,840,778					1823/254	87,594,373	1823/254	49,402,237	264,648,642
19	TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)	(b) 371,712,306	44,057,235	28,903,026				87,594,373		49,402,237	348,674,379
20	Classification of TOTAL
21	Federal Income Tax	136,824,406	44,057,235	28,903,026				27,860,081		15,845,742	139,964,276
22	State Income Tax	234,887,900						59,734,292		33,556,495	208,710,103
23	Local Income Tax
NOTES

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesOther


Line 18 Other - Detail	Balance at Beginning of Year		Balance at End of Year

SFAS 109	302,430,863		302,430,864
Hedge - Cash Flow	409,915		409,915
Non Utility
Total	$	302,840,778	$	302,840,779

(b) Concept: AccumulatedDeferredIncomeTaxesOther

Formula Rate uses 13 month average.

Name of Respondent:

SWEPCO

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	FAS 109 Deferred Federal Income Tax	625,928,192	182/190/236/254/281/282/283/409/410/411	35,440,887	11,286,247	601,773,552
2	Earnings Subject to Refund under State of Texas Restructuring Legislation - Public Utility Commission of Texas (PUCT) Docket No. 29938 and Docket No. 22276; PUCT Docket 37364 alllowed Amortization of 44 years beginning in May 2010	2,327,476	407	72,000		2,255,476
3	Overrecovery of Energy Efficiency Program Expense Arkansas
4	Overrecovery of Energy Efficiency Program Expense Louisiana	2,551,847	908	2,032,259	3,055,585	3,575,173
5	Vegetation Management - Texas PUCT Docket No.40443	4,805,784	593	5,049,439	243,654
6	Arkansas Public Service Commission (APSC) Generation Recovery Rider Docket No. 09-008-U, J L Stall Over-recovery	746,833	182/440/442/444	746,833
7	Deferred Overrecovery Fuel Costs - Texas
8	Deferred Overrecovery Fuel Costs - Arkansas
9	Deferred Overrecovery Fuel Costs - Louisiana		182/440/442/557	9,768,278	11,194,579	1,426,301
10	Unrealized Gain/Loss on Forward Commitments	3,726,095	175/244/182	5,878,510	3,225,137	1,072,722
11	SWEPCo Louisiana regulatory liability related to the Net Benefit Guarantee for the North Central Wind Facilities (LPSC Docket No U-35324)	223,225	426	513,250	290,025
12	Arkansas Southwest Power Pool Transmission Cost Rider Over Recovery				2,562,502	2,562,502
41	TOTAL	640,309,452		59,501,456	31,857,729	612,665,725

Name of Respondent:

SWEPCO

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	852,716,194	856,838,777	6,538,269	6,204,614	467,453	464,800
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)	643,596,906	648,717,129	5,731,850	5,488,715	74,778	73,987
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)	437,560,153	466,258,099	5,174,144	4,682,106	6,824	6,874
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting	10,505,487	11,425,441	74,572	76,946	596	577
7	OtherSalesToPublicAuthoritiesAbstract (445) Other Sales to Public Authorities
8	SalesToRailroadsAndRailwaysAbstract (446) Sales to Railroads and Railways
9	InterdepartmentalSalesAbstract (448) Interdepartmental Sales
10	SalesToUltimateConsumersAbstract TOTAL Sales to Ultimate Consumers	1,944,378,740	1,983,239,446	17,518,835	16,452,381	549,651	546,238
11	SalesForResaleAbstract (447) Sales for Resale	318,982,799	427,607,831	6,951,551	7,578,855
12	SalesOfElectricityAbstract TOTAL Sales of Electricity	2,263,361,540	2,410,847,277	24,470,386	24,031,236	549,651	546,238
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds	11,905,582	10,408,311
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds	2,251,455,958	2,421,255,588	24,470,386	24,031,236	549,651	546,238
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts	5,322,335	4,613,036
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	(a) 1,055,598	1,089,483
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power
19	RentFromElectricProperty (454) Rent from Electric Property	9,337,226	8,900,130
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	(b) 9,670,136	8,253,115
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	158,248,618	128,035,730
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	183,633,914	150,891,494
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	2,435,089,872	2,572,147,082
Line12, column (b) includes $ 17,453,463 of unbilled revenues.
Line12, column (d) includes 204,824 MWH relating to unbilled revenues

Name of Respondent:

SWEPCO

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: MiscellaneousServiceRevenues

Customer service revenue,including connects, reconnects, disconnects, temporary services and other charges billed to customers ( Applies to current and previous year ) .

(b) Concept: OtherElectricRevenue


Account 456.0 Other Electric Revenues:	2022	2021
Royalties - Nonaffiliated	701,253	219,595
Electric Operations - Nonaffiliated	1,790,457	2,051,321
Electric Operations Transmission related - Nonaffiliated	778,516	751,296
3rd Party Plant Operations including overhead related	4,465,294	5,230,903
Sales of Renewable Energy Credits (To Non Affiliates)	1,934,616
Other Misc Revenue - Items < $250,000
Total	9,670,136	8,253,115

Name of Respondent:

SWEPCO

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:

SWEPCO

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	(a) Residential Service RS ARK	1,101,954	137,413,755	96,140	11,462	12.4700
2	Residential-Electric heating appliance ARK	152,777	17,624,232	9,811	15,572	11.5359
3	Master Metered Apartments ARK	1,212	113,250	8	151,500	9.3441
4	Lighting PL/AL/OL ARK	4,877	1,086,466	7,015	695	22.2773
5	Residential Service RS LA	3,080,262	390,811,970	206,887	14,889	12.6876
6	Residential Service RWH LA	1,382	167,622	82	16,854	12.1289
7	Master Metered Apartments LA	21,858	2,252,473	27	809,556	8.0000
8	Lighting PL/AL/OL	18,332	5,591,946	29,384	624	30.5037
9	Residential Service RS TX	2,283,273	298,939,175	154,473	14,781	13.0926
10	Deferred Fuel		9,354,981
11	Duplicate Customers			55,136
12	Master Metered Apartments TX	11,653	1,086,112	25	458,479	9.3204
13	Lighting PL/AL TX	13,486	2,378,985	18,737	720	17.6404
41	TOTAL Billed Residential Sales	6,691,066	848,111,005	467,453
42	TOTAL Unbilled Rev. (See Instr. 6)	152,797	4,605,189
43	TOTAL	6,538,269	852,716,194	467,453	13,987	13.0419

Name of Respondent:

SWEPCO

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: DescriptionOfNumberAndTitleOfRateSchedule


The estimated additional revenue billed pursuant to the fuel adjustment clause is as follows:
	Arkansas	Louisiana	Texas

Residential	52,404,966.39	145,093,046.34	75,838,344.78

Commercial	57,124,555.09	107,917,784.77	68,676,883.11

Industrial	49,157,575.27	54,654,895.41	85,377,488.28

Public Street & Highway Lighting	423,836.85	1,818,839.44	874,516.03

Name of Respondent:

SWEPCO

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	General Service GS	359,811	41,921,301	16,366	21,985	11.6509
2	Recreational Lighting ARK	3,705	346,696	100	37,050	9.3575
3	Lighting & Power Service LP LA	1,643,106	177,578,020	2,380	690,381	10.8075
4	Irrigation SVC LA	1	78	1	1,000	7.8000
5	Municipal Pumping MPS LA	82,496	8,107,370	609	135,461	9.8276
6	Municipal Service MS LA	20,048	3,155,385	1,032	19,426	15.7392
7	Lighting PL/AL/OL LA	20,844	4,724,503	12,196	1,709	22.6660
8	Lighting & Power Service LP ARK	822,012	80,461,520	1,406	584,646	9.7884
9	Large Lighting and Power Service LLP ARK	82,680	7,073,137	1	82,680,000	8.5548
10	Municipal Pumping Service MPS ARK	10,853	1,150,425	268	40,496	10.6001
11	Municipal Service MS ARK	4,882	572,377	452	10,801	11.7242
12	Lighting PL/AL/OL ARK	15,608	2,480,083	9,019	1,731	15.8898
13	Electric Sign Service ESS LA	664	101,861	315	2,108	15.3405
14	General Service GS LA	286,098	47,310,221	16,446	17,396	16.5364
15	General Lighting & Power GLP LA	198,201	27,710,025	4,415	44,893	13.9808
16	General Service GS TX	246,571	36,273,751	20,973	11,757	14.7113
17	Recreational Lighting Comm TX	6,029	542,632	155	38,897	9.0004
18	Lighting PL/AL TX	31,384	3,676,986	15,448	2,032	11.7161
19	Cotton Gin CG TX	4,347	396,583	7	621,000	9.1231
20	Lighting & Power Service LP TX	1,713,437	149,550,321	7,587	225,839	8.7281
21	Lighting & Power Service LLP TX	52,980	3,347,325	1	52,980,000	6.3181
22	Municipal Pumping MPS TX	66,290	4,569,950	606	109,389	6.8939
23	Municipal Service MS TX	26,436	2,055,914	1,568	16,860	7.7769
24	Deferred Fuel		34,003,917
25	Duplicate Customers			36,663
26	Lighting CSL TX	1,138	97,586	90	12,644	8.5752
41	TOTAL Billed Small or Commercial	5,699,621	637,207,967	74,778
42	TOTAL Unbilled Rev. Small or Commercial (See Instr. 6)	32,229	6,388,939
43	TOTAL Small or Commercial	5,731,850	643,596,906	74,778	76,652	11.2284

Name of Respondent:

SWEPCO

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	General Service GS Ark	11,059	1,395,857	352	31,418	12.6219
2	Lighting & Power Service LP Ark	806,520	76,585,799	262	3,078,321	9.4958
3	Large Lighting & Power LLP Ark	171,147	11,987,050	1	171,147,000	7.0039
4	Pulp & Paper Mill P&PM Ark	143,748	10,908,252	1	143,748,000	7.5885
5	Lighting PL/AL/OL Ark	2,243	327,187	832	2,696	14.5870
6	General Power Service GPS LA	11,154	1,967,282	997	11,188	17.6375
7	General Lighting & Power GLP LA	37,211	4,887,362	696	53,464	13.1342
8	Lighting & Power Service LP LA	846,660	77,787,806	354	2,391,695	9.1876
9	Large Lighting & Power LLP LA	283,732	22,703,120	2	141,866,000	8.0016
10	Lighting PL/AL/OL	1,321	278,371	595	2,220	21.0727
11	General Service GS TX	13,706	1,690,009	1,413	9,700	12.3304
12	Lighting & Power Service LP TX	1,143,687	84,593,935	1,282	892,112	7.3966
13	Duplicate Customers			2,668
14	Interruptible Power Service TX	71,976	3,851,500	3	23,992,000	5.3511
15	Large Lighting & Power Service LLP TX	985,333	54,403,617	5	197,066,600	5.5213
16	Large Lighting & Power Service LLP w/Bkup,Maint,AAS TX	138,998	10,925,738	2	69,499,000	7.8604
17	Metal Melting Service MMS TX	44,065	3,319,072	9	4,896,111	7.5322
18	Metal Melting Svc MMS Transmission TX	54,118	2,979,961	2	27,059,000	5.5064
19	Oilfield-Large Industrial OLI TX	362,190	22,240,887	1,443	250,998	6.1407
20	Lighting PL/AL TX	4,158	427,761	1,241	3,351	10.2877
21	Deferred Fuel		39,592,516
41	TOTAL Billed Large (or Ind.) Sales	5,133,026	432,853,082	6,824
42	TOTAL Unbilled Rev. Large (or Ind.) (See Instr. 6)	41,118	4,707,071
43	TOTAL Large (or Ind.)	5,174,144	437,560,153	6,824	758,227	8.4567

Name of Respondent:

SWEPCO

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 Commercial and Industrial Sales
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL

Name of Respondent:

SWEPCO

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	Municipal Lighting ML ARK	9,535	1,975,658	219	43,539	20.7201
2	Municipal Lighting ML LA	38,057	4,721,325	176	216,233	12.4059
3	Deferred Fuel		396,647
4	Municipal Lighting ML TX	26,940	3,361,968	201	134,030	12.4795
41	TOTAL Billed Public Street and Highway Lighting	74,532	10,455,598	596
42	TOTAL Unbilled Rev. (See Instr. 6)	40	49,889
43	TOTAL	74,572	10,505,487	596	125,121	14.0877

Name of Respondent:

SWEPCO

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		11,905,582

Name of Respondent:

SWEPCO

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	17,598,245	1,928,627,652	549,651
42	TOTAL Unbilled Rev. (See Instr. 6) - All Accounts	79,410	15,751,088
43	TOTAL - All Accounts	17,518,835	1,944,378,740	549,651

Name of Respondent:

SWEPCO

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	Corporation (AEPSC) (3)	OS	228
2	Requirements Service (RQ)
3	AEPSC (3,8)	OS	228
4	AEPSC (3,4)	OS	228				460			1,561,222	1,561,222
5	(a) City of Bentonville, Arkansas (1)	RQ	126	147.6	128.4	125.0	719,455	17,287,650	36,270,846		53,558,496
6	City of Hope, Arkansas (1)	RQ	125	49.4	40.0	38.0	241,069	6,183,091	13,021,532		19,204,623
7	Electric Reliability Council of Texas
8	(ERCOT) (6,8)	OS	NA
9	City of Minden, Louisiana (1)	RQ	128	32.1	27.9	26.8	137,958	4,140,581	7,124,365		11,264,946
10	City of Prescott, Arkansas (1)	RQ	127	14.1	13.3	10.9	80,723	1,817,165	4,289,545		6,106,710
11	Oklahoma Gas & Electric	OS	NA
12	Northeast Texas Electric	RQ	113
13	Southwest Power Pool (SPP) (7)	OS	NA				1,626,697		88,230,794	22,628,427	110,859,221
14	Cooperative, Inc (NTEC) (1)		119	120.0	120.0	120.0		15,714,641	339,667		15,374,974
15	SPP Merchant Sales (5)	SF	NA				500,436		29,015,967		29,015,967
16	ETEC/ NTEC (1)	RQ	129	113.4	220.9	212.6	3,644,753	11,510,997	60,525,643		72,036,640
17	Rayburn Country Electric Coop, Inc(1,2)	RQ	111
18	Tex-La Electric Reliability Council of Texas (ERCOT)	RQ	110
19	Tex-La of Texas Elec. Coop. of Texas, Inc	RQ	120
20	Non-RQ
21	American Electric Power Service
15	Subtotal - RQ						4,823,958	40,939,484	121,231,931		162,171,415
16	Subtotal-Non-RQ						2,127,593	15,714,641	116,907,094	24,189,649	156,811,384
17	Total						6,951,551	56,654,125	238,139,025	24,189,649	318,982,799

Name of Respondent:

SWEPCO

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

Includes customer charge

(2) Wholesale transmission

(3) Respondent is an affiliated company of American Electric Power Service Corporation

(4) Bookout margins, net

(5) Merchant sale

(6) Net trading purchases & sales within the Electric Reliability Council of Texas

(ERCOT)

(7) Net trading purchases & sales within the Southwest Power Pool (SPP)

(8) Realization System Integration Agreement Sharing

Name of Respondent:

SWEPCO

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	20,700,248	18,782,166
5	FuelSteamPowerGeneration (501) Fuel	617,230,019	940,584,853
6	SteamExpensesSteamPowerGeneration (502) Steam Expenses	22,553,517	21,556,055
7	SteamFromOtherSources (503) Steam from Other Sources
8	SteamTransferredCredit (Less) (504) Steam Transferred-Cr.
9	ElectricExpensesSteamPowerGeneration (505) Electric Expenses	9,350,725	10,270,506
10	MiscellaneousSteamPowerExpenses (506) Miscellaneous Steam Power Expenses	15,658,489	13,024,971
11	RentsSteamPowerGeneration (507) Rents		3,878
12	Allowances (509) Allowances	4,478,442	147,465
13	SteamPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 4 thru 12)	689,971,439	1,004,369,894
14	SteamPowerGenerationMaintenanceAbstract Maintenance
15	MaintenanceSupervisionAndEngineeringSteamPowerGeneration (510) Maintenance Supervision and Engineering	3,871,364	3,577,283
16	MaintenanceOfStructuresSteamPowerGeneration (511) Maintenance of Structures	5,587,787	5,844,163
17	MaintenanceOfBoilerPlantSteamPowerGeneration (512) Maintenance of Boiler Plant	25,549,381	28,353,390
18	MaintenanceOfElectricPlantSteamPowerGeneration (513) Maintenance of Electric Plant	7,341,705	8,402,546
19	MaintenanceOfMiscellaneousSteamPlant (514) Maintenance of Miscellaneous Steam Plant	6,715,651	5,621,527
20	SteamPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 15 thru 19)	49,065,888	51,798,909
21	PowerProductionExpensesSteamPower TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)	739,037,327	1,056,168,804
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		11
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)		11
41	PowerProductionExpensesNuclearPower TOTAL Power Production Expenses-Nuclear. Power (Enter Total of lines 33 & 40)		11
42	HydraulicPowerGenerationAbstract C. Hydraulic Power Generation
43	HydraulicPowerGenerationOperationAbstract Operation
44	OperationSupervisionAndEngineeringHydraulicPowerGeneration (535) Operation Supervision and Engineering
45	WaterForPower (536) Water for Power
46	HydraulicExpenses (537) Hydraulic Expenses
47	ElectricExpensesHydraulicPowerGeneration (538) Electric Expenses
48	MiscellaneousHydraulicPowerGenerationExpenses (539) Miscellaneous Hydraulic Power Generation Expenses
49	RentsHydraulicPowerGeneration (540) Rents
50	HydraulicPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 44 thru 49)
51	HydraulicPowerGenerationContinuedAbstract C. Hydraulic Power Generation (Continued)
52	HydraulicPowerGenerationMaintenanceAbstract Maintenance
53	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration (541) Mainentance Supervision and Engineering
54	MaintenanceOfStructuresHydraulicPowerGeneration (542) Maintenance of Structures
55	MaintenanceOfReservoirsDamsAndWaterways (543) Maintenance of Reservoirs, Dams, and Waterways
56	MaintenanceOfElectricPlantHydraulicPowerGeneration (544) Maintenance of Electric Plant
57	MaintenanceOfMiscellaneousHydraulicPlant (545) Maintenance of Miscellaneous Hydraulic Plant
58	HydraulicPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 53 thru 57)
59	PowerProductionExpensesHydraulicPower TOTAL Power Production Expenses-Hydraulic Power (Total of Lines 50 & 58)
60	OtherPowerGenerationAbstract D. Other Power Generation
61	OtherPowerGenerationOperationAbstract Operation
62	OperationSupervisionAndEngineeringOtherPowerGeneration (546) Operation Supervision and Engineering	1,683,158	394,828
63	Fuel (547) Fuel	21,068,588	76,365,832
64	GenerationExpenses (548) Generation Expenses	260,749	206,210
64.1	OperationOfEnergyStorageEquipment (548.1) Operation of Energy Storage Equipment
65	MiscellaneousOtherPowerGenerationExpenses (549) Miscellaneous Other Power Generation Expenses	953,766	175,836
66	RentsOtherPowerGeneration (550) Rents	4,823,059	1,424,011
67	OtherPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 62 thru 67)	28,789,320	78,566,717
68	OtherPowerGenerationMaintenanceAbstract Maintenance
69	MaintenanceSupervisionAndEngineeringOtherPowerGeneration (551) Maintenance Supervision and Engineering
70	MaintenanceOfStructures (552) Maintenance of Structures	107,244	61,574
71	MaintenanceOfGeneratingAndElectricPlant (553) Maintenance of Generating and Electric Plant	7,654,205	2,223,588
71.1	MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration (553.1) Maintenance of Energy Storage Equipment
72	MaintenanceOfMiscellaneousOtherPowerGenerationPlant (554) Maintenance of Miscellaneous Other Power Generation Plant	138,440	100,251
73	OtherPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 69 thru 72)	7,899,888	2,385,413
74	PowerProductionExpensesOtherPower TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)	36,689,209	80,952,130
75	OtherPowerSuplyExpensesAbstract E. Other Power Supply Expenses
76	PurchasedPower (555) Purchased Power	353,323,157	479,682,114
76.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations	0
77	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching	1,249,092	1,445,359
78	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	49,202,352	180,313,768
79	OtherPowerSupplyExpense TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)	403,774,601	300,813,705
80	PowerProductionExpenses TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74 & 79)	1,179,501,138	1,437,934,650
81	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
82	TransmissionExpensesOperationAbstract Operation
83	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	12,848,170	10,185,286
85	LoadDispatchReliability (561.1) Load Dispatch-Reliability	125
86	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	607,956	664,345
87	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling	369	774
88	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services	5,137,717	4,065,124
89	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development	231,133	345,861
90	TransmissionServiceStudies (561.6) Transmission Service Studies
91	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies
92	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services	946,226	938,208
93	StationExpensesTransmissionExpense (562) Station Expenses	1,071,674	995,199
93.1	OperationOfEnergyStorageEquipmentTransmissionExpense (562.1) Operation of Energy Storage Equipment
94	OverheadLineExpense (563) Overhead Lines Expenses	141,589	56,047
95	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses		4,962
96	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	126,984,644	119,720,121
97	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	2,843,585	2,837,796
98	RentsTransmissionElectricExpense (567) Rents	55,551	10,458
99	TransmissionOperationExpense TOTAL Operation (Enter Total of Lines 83 thru 98)	150,868,739	139,824,181
100	TransmissionMaintenanceAbstract Maintenance
101	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering	5,292	7,467
102	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	56,867	26,084
103	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware	8,487	7,388
104	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software	(a) 637,697	505,032
105	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment	97,270	68,835
106	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	3,228,207	2,149,798
107.1	MaintenanceOfEnergyStorageEquipmentTransmission (570.1) Maintenance of Energy Storage Equipment
108	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	15,771,832	15,811,162
109	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines	349	63
110	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant	2,238	27,392
111	TransmissionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 101 thru 110)	19,808,240	18,603,095
112	TransmissionExpenses TOTAL Transmission Expenses (Total of Lines 99 and 111)	170,676,979	158,427,276
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	1,799,650	1,546,945
122	RentsRegionalMarketExpenses (575.8) Rents
123	RegionalMarketOperationExpense Total Operation (Lines 115 thru 122)	1,799,650	1,546,945
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)	1,799,650	1,546,945
132	DistributionExpensesAbstract 4. DISTRIBUTION EXPENSES
133	DistributionExpensesOperationAbstract Operation
134	OperationSupervisionAndEngineeringDistributionExpense (580) Operation Supervision and Engineering	2,669,139	2,363,218
135	LoadDispatching (581) Load Dispatching	65,381	39,086
136	StationExpensesDistribution (582) Station Expenses	1,422,024	858,366
137	OverheadLineExpenses (583) Overhead Line Expenses	705,194	2,085,049
138	UndergroundLineExpenses (584) Underground Line Expenses	1,941,154	1,879,998
138.1	OperationOfEnergyStorageEquipmentDistribution (584.1) Operation of Energy Storage Equipment
139	StreetLightingAndSignalSystemExpenses (585) Street Lighting and Signal System Expenses	245,356	223,740
140	MeterExpenses (586) Meter Expenses	4,135,070	3,719,375
141	CustomerInstallationsExpenses (587) Customer Installations Expenses	484,464	380,631
142	MiscellaneousDistributionExpenses (588) Miscellaneous Expenses	20,264,368	17,886,759
143	RentsDistributionExpense (589) Rents	913,687	912,011
144	DistributionOperationExpensesElectric TOTAL Operation (Enter Total of Lines 134 thru 143)	32,845,836	30,348,233
145	DistributionExpensesMaintenanceAbstract Maintenance
146	MaintenanceSupervisionAndEngineering (590) Maintenance Supervision and Engineering	108,073	108,509
147	MaintenanceOfStructuresDistributionExpense (591) Maintenance of Structures	54,172	26,808
148	MaintenanceOfStationEquipment (592) Maintenance of Station Equipment	1,354,609	1,654,779
148.1	MaintenanceOfEnergyStorageEquipment (592.2) Maintenance of Energy Storage Equipment
149	MaintenanceOfOverheadLines (593) Maintenance of Overhead Lines	61,354,854	54,066,160
150	MaintenanceOfUndergroundLines (594) Maintenance of Underground Lines	710,492	461,217
151	MaintenanceOfLineTransformers (595) Maintenance of Line Transformers	133,220	78,436
152	MaintenanceOfStreetLightingAndSignalSystems (596) Maintenance of Street Lighting and Signal Systems	110,145	148,706
153	MaintenanceOfMeters (597) Maintenance of Meters	440,759	517,763
154	MaintenanceOfMiscellaneousDistributionPlant (598) Maintenance of Miscellaneous Distribution Plant	306,759	293,702
155	DistributionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 146 thru 154)	64,573,082	57,356,081
156	DistributionExpenses TOTAL Distribution Expenses (Total of Lines 144 and 155)	97,418,918	87,704,314
157	CustomerAccountsExpensesAbstract 5. CUSTOMER ACCOUNTS EXPENSES
158	CustomerAccountsExpensesOperationsAbstract Operation
159	SupervisionCustomerAccountExpenses (901) Supervision	667,424	795,458
160	MeterReadingExpenses (902) Meter Reading Expenses	2,502,598	2,430,022
161	CustomerRecordsAndCollectionExpenses (903) Customer Records and Collection Expenses	17,364,270	16,593,793
162	UncollectibleAccounts (904) Uncollectible Accounts	591,316	20,703
163	MiscellaneousCustomerAccountsExpenses (905) Miscellaneous Customer Accounts Expenses	64,586	64,734
164	CustomerAccountExpenses TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)	21,190,193	19,904,710
165	CustomerServiceAndInformationalExpensesAbstract 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166	CustomerServiceAndInformationalExpensesOperationAbstract Operation
167	SupervisionCustomerServiceAndInformationExpenses (907) Supervision	10,686,247	10,413,558
168	CustomerAssistanceExpenses (908) Customer Assistance Expenses	13,083,971	7,616,265
169	InformationalAndInstructionalAdvertisingExpenses (909) Informational and Instructional Expenses	252
170	MiscellaneousCustomerServiceAndInformationalExpenses (910) Miscellaneous Customer Service and Informational Expenses	39,889	86,245
171	CustomerServiceAndInformationExpenses TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)	23,810,359	18,116,067
172	SalesExpenseAbstract 7. SALES EXPENSES
173	SalesExpenseOperationAbstract Operation
174	SupervisionSalesExpense (911) Supervision
175	DemonstratingAndSellingExpenses (912) Demonstrating and Selling Expenses	185,684	201,346
176	AdvertisingExpenses (913) Advertising Expenses
177	MiscellaneousSalesExpenses (916) Miscellaneous Sales Expenses
178	SalesExpenses TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)	185,684	201,346
179	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
180	AdministrativeAndGeneralExpensesOperationAbstract Operation
181	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	35,195,053	34,235,474
182	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	2,352,276	1,501,298
183	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit	4,535,722	4,627,845
184	OutsideServicesEmployed (923) Outside Services Employed	10,615,639	7,184,359
185	PropertyInsurance (924) Property Insurance	3,852,216	4,327,873
186	InjuriesAndDamages (925) Injuries and Damages	4,313,559	4,432,609
187	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	5,506,516	11,623,733
188	FranchiseRequirements (927) Franchise Requirements
189	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	10,323,175	8,630,197
190	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.
191	GeneralAdvertisingExpenses (930.1) General Advertising Expenses	130,664	232,069
192	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	1,908,731	1,572,505
193	RentsAdministrativeAndGeneralExpense (931) Rents	830,618	1,216,639
194	AdministrativeAndGeneralOperationExpense TOTAL Operation (Enter Total of Lines 181 thru 193)	70,492,724	70,328,911
195	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
196	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	7,435,532	6,511,983
197	AdministrativeAndGeneralExpenses TOTAL Administrative & General Expenses (Total of Lines 194 and 196)	77,928,256	76,840,894
198	OperationsAndMaintenanceExpensesElectric TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 156, 164, 171, 178, and 197)	1,572,511,178	1,800,676,201

Name of Respondent:

SWEPCO

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: MaintenanceOfComputerSoftwareTransmission

This footnote applies to both current and prior year.

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.

Name of Respondent:

SWEPCO

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	(a) Cajun Electric Cooperative, Inc. (1)	OS	NA								4,200,000			4,200,000
2	Canadian Wind (3)	OS	NA				508,547					16,651,894		16,651,894
3	ERCOT (5)	OS	NA
4	Flat Ridge Wind Farm (3)	OS	NA				414,753					13,740,907		13,740,907
5	Majestic Wind Farm (3)	OS	NA				662,826					29,302,409		29,302,409
6	Southwest Power Pool (4)	OS	NA				5,578,653					157,260,555	131,626,503	288,887,058
7	Snider Industries (2)	OS	NA				8,878					473,212		473,212
8	VAISALA MONTHLY FORECASTING F											927		927
9	North Central Wind Facility
10	VAISALA - MAVERICK - 54.5 SWE											62,501		62,501
11	VAISALA - SUNDANCE - 54.5 SWE											6,103		6,103
15	TOTAL						7,173,657		0	0	4,200,000	217,496,654	131,626,503	353,323,157

Name of Respondent:

SWEPCO

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

C apacity

(2) Cogeneration

(3) Wind Energy

(4) Net Trading Purchases & Sales within Southwest Power Pool (SPP)

(5) Net Trading Purchases & Sales within ERCOT

Name of Respondent:

SWEPCO

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)

American Electric Power Service

Various

N/A

Various

(a)

Corporation (1, 2, 3)

56,367,627

Corporation (1, 2, 3, 6)

1,011,482

Snider Industries Inc (5)

Various

N/A

Various

840

Southwest Power Pool (2, 3, 6, 7)

Various

196

Various

7,467,709

Southwest Power Pool (2, 3, 7)

Various

196

Various

93,400,960

TOTAL

Name of Respondent:

SWEPCO

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: PaymentByCompanyOrPublicAuthority

Respondent is an affiliated company of American Electric Power Service Corporation

(2) Facility charge

(3) Southwest Power Pool base plan funding

(4) Southwest Power Pool ancillary service schedule 1

(5) Network Integrated Transmission Service (NITS)

(6) Prior Year

(7) Transmission service charge

Name of Respondent:

SWEPCO

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:

SWEPCO

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	(a) American Electric Power Service Corporation (1,2,3,4,5)	OS					73,117,417	73,117,417
2	American Electric Power Service Corporation (1,6)	AD					36,495	36,495
3	Southwest Power Pool (3, 7)	OS					56,656,764	56,656,764
4	Southwest Power Pool (3, 6)	AD					2,826,032	2,826,032
	TOTAL		0	0	0	0	126,984,644	126,984,644

FOOTNOTE DATA

(a) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers

Respondent is an affiliated company of American Electric Power Service Corporation

(2) Facility charge

(3) Southwest Power Pool base plan funding

(4) Southwest Power Pool ancillary service schedule 1

(5) Network Integrated Transmission Service (NITS)

(6) Prior year

(7) Transmission service charge

Name of Respondent:

SWEPCO

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	381,590
2	NuclearPowerResearchExpenses Nuclear Power Research Expenses
3	OtherExperimentalAndGeneralResearchExpenses Other Experimental and General Research Expenses
4	PublicationAndDistributionExpensesForSecuritiesToStockholders Pub and Dist Info to Stkhldrs...expn servicing outstanding Securities	268,740
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	450,526
7	AEP Service Corporation and Other Affiliated
8	Companies Billed to or from Respondent	745,001
9	Chamber of Commerce	36,768
10	Miscellaneous Minor items less than $5,000	26,106
46	MiscellaneousGeneralExpenses TOTAL	1,908,731

Name of Respondent:

SWEPCO

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			29,143,882		29,143,882
2	Steam Production Plant	120,653,927	1,505,178			122,159,105
3	Nuclear Production Plant
4	Hydraulic Production Plant-Conventional
5	Hydraulic Production Plant-Pumped Storage
6	Other Production Plant	27,780,843	450,952			28,231,795
7	Transmission Plant	57,866,193				57,866,193
8	Distribution Plant	72,938,279				72,938,279
9	Regional Transmission and Market Operation
10	General Plant	9,983,831	41,192			10,025,023
11	Common Plant-Electric
12	TOTAL	289,223,073	1,997,322	29,143,882		320,364,277

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.

	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 -- COAL/LIGNITE
13	311 - Flint Creek	26,999	60 years	5	3.6
14	311 - Pirkey	109,408	38 years	4	1.94
15	311- Turk	295,157	55 years	2	2.08
16	311 - Welsh	72,840	50 years	4	3.48
17	312 - Flint Creek	298,256	60 years	5	5.29
18	312 - Pirkey	385,951	38 years	4	2.39
19	312 - Turk	991,943	55 years	2	2.08
20	312 - Welsh	586,555	50 years	4	4.37
21	314 - Flint Creek	17,730	60 years	5	4.02
22	314 - Pirkey	50,951	38 years	4	1.92
23	314 - Turk	239,669	55 years	2	2.08
24	314 - Welsh	143,155	50 years	4	3.84
25	315 - Flint Creek	11,736	60 years	5	4.09
26	315 - Pirkey	18,461	38 years	4	2.25
27	315 - Turk	90,868	55 years	2	2.08
28	315 - Welsh	48,204	50 years	4	4.71
29	316 - Flint Creek	6,646	60 years	5	3.97
30	316 - Pirkey	19,608	38 years	4	2.23
31	316 - Turk	48,676	55 years	2	2.08
32	316 - Welsh	22,376	50 years	4	3.86
33	TOTAL COAL/LIGNITE	3,485,189
34	STEAM -- GAS/OIL
35	311.3-ArsenalHillStall	54,091	35 years	5	2.86
36	311.3-Arsenal Hill	6,835	65 years	15	4.26
37	311.3 - Knox Lee	10,104	65 years	45	2.72
38	311.3 - Lieberman	5,681	65 years	11	6.96
39	311.3 - Wilkes	8,468	65 years	10	2.2
40	312.3-ArsenalHillStall	87,406	35 years	5	3.01
41	312.3 - Arsenal Hill	7,310	65 years	15	4.46
42	312.3 - Knox Lee	31,758	65 years	45	3.08
43	312.3 - Lieberman	19,741	65 years	11	6.11
44	312.3 - Wilkes	56,728	65 years	10	3.02
45	314.3-ArsenalHillStall	168,783	35 years	5	3.24
46	314.3 - ArsenalHill	5,437	65 years	15	4.15
47	314.3 - Knox Lee	15,715	65 years	45	2.89
48	314.3 - Lieberman	10,770	65 years	11	5.06
49	314.3 - Wilkes	40,078	65 years	10	2.56
50	315.3-ArsenalHillStall	39,800	35 years	5	2.84
51	315.3 - Arsenal Hill	1,281	65 years	15	5.57
52	315.3 - Knox Lee	4,908	65 years	45	3.34
53	315.3 - Lieberman	3,494	65 years	11	7.19
54	315.3 - Wilkes	12,863	65 years	10	3.48
55	316.3-ArsenalHillStall	83,888	35 years	5	2.85
56	316.3 - Arsenal Hill	8,034	65 years	15	7.43
57	316.3 - Knox Lee	2,215	65 years	45	4.09
58	316.3 - Lieberman	2,320	65 years	11	9.19
59	316.3 - Wilkes	9,353	65 years	10	4.15
60	TOTAL GAS/OIL	3,490,506
61	OTHER GENERATION
62	341 - Mattison	31,453	45 years	7	2.47
63	344 - Mattison	84,529	45 years	7	2.46
64	344 - Maverick	216,481	30 years		3.34
65	344 - Sundance	155,818	30 years		3.36
66	344 - Traverse	668,547	30 years		3.37
67	345 - Mattison	8,702	45 years	7	2.59
68	346 - Mattison	1,783	45 years	7	2.66
69	TOTAL OTHER	1,167,313
70	TRANSMISSION
71	350 (Rights)	107,184	65 years		1.48	R4
72	352	48,070	70 years		1.6	R3.5
73	353	810,204	68 years	5	1.71	S0
74	353.16	18,853	68 years	5	1.73	S0
75	354	40,122	65 years	20	1.8	L3
76	355	888,038	44 years	51	3.44	S0.5
77	356	437,352	66 years	44	2.29	R2
78	356.16	47,818	66 years	44	2.21	R2
79	357	9,465	50 years		1.65	R1.5
80	358		50 years		2.42	R1.5
81	358.16	679	50 years		2.62	R1.5
82	359	132	65 years		1.19	R4
83	TOTAL TRANSMISSION	2,407,917
84	DISTRIBUTION
85	360 (Rights)	3,615	60 years		1.59	R3.5
86	361	13,907	75 years	9	1.63	R2.5
87	362	398,937	55 years	12	2.13	R0.5
88	362.16	5,066	55 years	12	2.07	R0.5
89	364	551,289	55 years	68	3.15	R0.5
90	365	545,104	45 years	38	3.13	R1
91	366	83,983	55 years		1.93	R1.5
92	367	264,745	46 years	17	2.94	R2.5
93	368	464,748	44 years	11	2.53	L0
94	369	111,802	58 years	58	3.85	R3
95	370	80,507	15 years	26	6.05	L0
96	370.16 - TX AMI	20,800	15 years	26	6.05	L0
97	370.16 AR EurekaSpringsAMI	786	15 years	26	6.05	L0
98	370.16 - LA AMI	2,712	15 years	26	6.05	L0
99	370.16 Shreveport LA AMI	553	15 years	26	6.05	L0
100	370.16 Valley LA AMI	3	15 years	26	6.05	L0
101	371	49,108	25 years	31	5.51	L0
102	373	50,752	40 years	34	4.11	L0
103	TOTAL DISTRIBUTION	2,648,417
104	GENERAL PLANT
105	390	111,500	57 years	7	2.22	L0
106	391	7,259	30 years		4.34	SQ
107	391.11	34	7 years		20.94	SQ
108	392	3,876	20 years	4	4.22	SQ
109	393	3,190	30 years	1	3.79	SQ
110	394	32,519	35 years	1	3.46	SQ
111	395	5,198	35 years	2	3.27	SQ
112	396	699	20 years		7.04	SQ
113	397	83,473	20 years		6.21	SQ
114	397.16	3,913	20 years		6.21	SQ
115	398	3,495	20 years		5.99	SQ
116	TOTAL GENERAL PLANT	255,156
117	DEPRECIABLE SUM	(a) 3,015,073

Name of Respondent:

SWEPCO

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:

SWEPCO

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	Federal Energy Regulatory Commission Annual Assessment					Electic	928
2	Rate Case Expenses Approved for Recovery in Final Orders:		2,580,172	2,580,172	3,490,153	Electic	928				2,580,172	909,982
3	Expenses incrred related to SWEPCO's 2017 Fuel Reconciliation Filing - PUCT Docket 47553		203,762	203,762		Electic	928	203,762
4	Expenses incrred related to Louisiana Public Service Commission Audit of SWEPCO		10,628	10,628		Electic	928	10,628
5	Expense incured relate to managin Formula Rates for AEP's WEST Operating Companies and Transco's		134,528	134,528		Electic	928	134,528
6	Other Miscellaneous expense related to Regulatory and Legislative Actions in the State of Louisiana		22,519	22,519		Electic	928	22,519
7	Expense incuured relate to 2018 Louisiana IRP Filing					Electic	928
8	Expense incurred relate to Texas Tax Filing					Electic	928
9	Expense incured relate to Distribution Cost Recovery Factor Filing		26,095	26,095		Electric	928	26,095
10	Expenses incrred relate to Transmission Cost Recovery Factor Filings and other Regulatory/Legislative Activies relating to Transmission		39,908	39,908		Electric	928	39,908
11	Expense incurred relate to SWEPCO's 2019 Arkansas Base Rate Case		534	534		Electric	928	534
12	Expenses incurred relate to SWEPCO's 2016 Texas Base Rate Case					Electric	928
13	Miscellaneous Minor Items		47,395	47,395		Electric	928	47,395
14	Expenses incurred relate to SWEPCO's 2020 Texas Base Rate Case		258,758	258,758		Electric	928	258,758
15	2020 SWEPCO Texas Fuel Reconciliation		49,134	49,134		Electric	928	49,134
16				0
17	Expense incurred relate to SWEPCO's 2020 Arkansas Base Rate Case		634,665	634,665		Electric	928	634,665
18	2019 SWEPCO LA Base Case Filng		9,500	9,500		Electric	928	9,500
19	2020 Generation Cost Recovery Factor (GCRF) filing					Electric	928
20	Hurricane Laura Storm Recovery		161,314	161,314		Electric	928	161,314
21	2021 SWEPCO Arkansas IRP filing		68,321	68,321		Electric	928	68,321
22	2021 SWEPCO Louisiana IRP filing		71,093	71,093		Electric	928	71,093
23	Arkansas 2021 Winter Storm		16,429	16,429		Electric	928	16,429
24	Louisiana 2021 Winter Storm Inquiry		46,951	46,951		Electric	928	46,951
25	Louisiana Winter Restoration Costs		90,806	90,806		Electric	928	90,806
26	Louisiana Winter Storm Fuel Recovery		19,672	19,672		Electric	928	19,672
27	Maverick Wind Facility		43,309	43,309		Electric	928	43,309
28	Sunchase PPA Filing		161,541	161,541		Electric	928	161,541
29	Sundance Wind Facility		30,023	30,023		Electric	928	30,023
30	SWEPCO Arkansasa PPA Filing		203,424	203,424		Electric	928	203,424
31	SWEPCO Louisiana AMI meter deployment		102,729	102,729		Electric	928	102,729
32	SWEPCO Texas AMI meter deployment		341,270	341,270		Electric	928	341,270
33	Texas 2021 Winter Storm Fuel Recovery		49,105	49,105		Electric	928	49,105
34	Regulatory Fees	2,786,494		2,786,494		Electric	928	2,786,494
35	2022 SWEPCO AR Turk Filing		185,695	185,695		Electric	928	185,695
36	2022 SWEPCO TX Fuel Recncltn		417,245	417,245		Electric	928	417,245
37	2023 SWEPCO DCRF Filing		152,965	152,965		Electric	928	152,965
38	2023 SWEPCO LA IRP		815,170	815,170		Electric	928	815,170
39	2023 SWEPCO TX TCRF Filing		103,435	103,435		Electric	928	103,435
40	23 ARSWEP Formula Rate Review		27,774	27,774		Electric	928	27,774
41	23 LASWEP Storm Securitization		21,890	21,890		Electric	928	21,890
42	23SWEPTX Fuel Surcharge Filing		23,988	23,988		Electric	928	23,988
43	AR 22 Renewable Gen from RFP		224,817	224,817		Electric	928	224,817
44	EECRF Filing - SWEPCO		29,269	29,269		Electric	928	29,269
45	LA 22 Renewable Gen from RFP		183,621	183,621		Electric	928	183,621
46	Other Miscellaneous expense related to Regulatory and Legislative Actions in the State of Arkansas		21,195	21,195		Electric	928	21,195
47	TX 22 Renewable Gen from RFP		462,655	462,655		Electric	928	462,655
48	Traverse Wind Facility		144,915	144,915		Electric	928	144,915
49	Various Rate Case Epxenses Pending Future Approval for Collection from State Commission Authorities			0	6,011,213				2,247,674			8,258,886
46	TOTAL	2,786,494	7,536,679	10,323,173	9,501,366			7,743,001	2,247,674		2,580,172	9,168,868

Name of Respondent:

SWEPCO

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				17,272	566	17,272
2		26 Items < $50,000		955,930	506, 566, 588	955,930
3		IT - EPRI Annual Research Portfolio		34,079	588	34,079
4	A. (7) Total Cost Incurred Internally		303,202			303,202
5	A. (6)(g) Research General	DTC Walnut Test Facility	3,215		506, 566	3,215
6		2 Items < $50,000	30,913		506	30,913
7		Low Carbon Resource Initiative		55,076	506	55,076
8			18,038		566, 588	18,038
9	B. Electric R&D External	5 Items < $50,000		2,509	506	2,509
10	B. Electric R&D External	5 Items < $50,000		55,075	506, 566, 588	55,075
11	B. (5) Total Cost Incurred Externally			2,193,615		2,193,615
12	A. (1) Generation
13				32,645	588	32,645
14		EPRI Research Portfolio		243,889	566	243,889
15		EPRI Environmental Science		457,921	506	457,921
16				1,639	566	1,639
17	B. (4) Research Support to Others	3 Items < $50,000		1,505	506	1,505
18	A. (6)(f) Metering	Advanced Metering Equipment (AMI) Test Bed Development	1,431		588	1,431
19	B. (4) Research Support to Others	3 Items < $50,000		17,683	506	17,683
20	B. (1) Electric Power Research Institute	EPRI Environmental Controls		78,973	506	78,973
21		Program Management
22		IT - EPRI Annual Research Portfolio		37,718	588	37,718
23				26,697	588	26,697
24		Low Carbon Resource Initiative		59,985	506	59,985
25		EPRI Environmental Science		827,971	506	827,971
26	A. (2) Transmission	RD&D Program Management	8,805		566	8,805
27		Total	136,044	1,639,882		1,775,926
28		1 Items < $50,000	8		566	8
29	A. (3) Distribution	1 Item < $50,000	10,508		588	10,508
30		26 Items < $50,000		59,950	506	59,950
31		EPRI Research Portfolio		218,982	566	218,982
32	A. (6) Other	2 Items < $50,000	14,033		506	14,033
33	A. (6)(a) Solar	Solar Field Panel Testing			0.00
34				34,111	566	34,111
35	A. (5) Environmental (other than equipment)	Environmental Science & Controls Program Management
36				529,533	506	529,533
37		3 Items < $50,000	215,694		506	215,694
38	(e) Unconventional Generation	Center for Energy Advancement Through Technological Membership	324		506	324
39	(b) Fossil-fuel Steam	Generation Asset Management
40		2 Items < $50,000	234		566	234
41				84,081	588	84,081
42		Total	303,202	2,193,615		2,496,818
43	B. (1) Electric Power Research Institute	EPRI Environmental Controls		272	506	272
44	B. (5) Total Cost Incurred Externally			1,639,882		1,639,882

Name of Respondent:

SWEPCO

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	29,179,894
4	SalariesAndWagesElectricOperationTransmission Transmission	2,637,398
5	SalariesAndWagesElectricOperationRegionalMarket Regional Market
6	SalariesAndWagesElectricOperationDistribution Distribution	13,632,688
7	SalariesAndWagesElectricOperationCustomerAccounts Customer Accounts	4,520,453
8	SalariesAndWagesElectricOperationCustomerServiceAndInformational Customer Service and Informational	3,769,997
9	SalariesAndWagesElectricOperationSales Sales
10	SalariesAndWagesElectricOperationAdministrativeAndGeneral Administrative and General	2,690,496
11	SalariesAndWagesElectricOperation TOTAL Operation (Enter Total of lines 3 thru 10)	56,430,926
12	SalariesAndWagesElectricMaintenanceAbstract Maintenance
13	SalariesAndWagesElectricMaintenanceProduction Production	13,910,694
14	SalariesAndWagesElectricMaintenanceTransmission Transmission	1,979,846
15	SalariesAndWagesElectricMaintenanceRegionalMarket Regional Market
16	SalariesAndWagesElectricMaintenanceDistribution Distribution	15,514,057
17	SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral Administrative and General	1,484,475
18	SalariesAndWagesElectricMaintenance TOTAL Maintenance (Total of lines 13 thru 17)	32,889,072
19	SalariesAndWagesElectricOperationAndMaintenanceAbstract Total Operation and Maintenance
20	SalariesAndWagesElectricProduction Production (Enter Total of lines 3 and 13)	43,090,588
21	SalariesAndWagesElectricTransmission Transmission (Enter Total of lines 4 and 14)	4,617,244
22	SalariesAndWagesElectricRegionalMarket Regional Market (Enter Total of Lines 5 and 15)
23	SalariesAndWagesElectricDistribution Distribution (Enter Total of lines 6 and 16)	29,146,745
24	SalariesAndWagesElectricCustomerAccounts Customer Accounts (Transcribe from line 7)	4,520,453
25	SalariesAndWagesElectricCustomerServiceAndInformational Customer Service and Informational (Transcribe from line 8)	3,769,997
26	SalariesAndWagesElectricSales Sales (Transcribe from line 9)
27	SalariesAndWagesElectricAdministrativeAndGeneral Administrative and General (Enter Total of lines 10 and 17)	4,174,971
28	SalariesAndWagesElectricOperationAndMaintenance TOTAL Oper. and Maint. (Total of lines 20 thru 27)	89,319,998	4,275,081	93,595,079
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)	89,319,998	4,275,081	93,595,079
66	SalariesAndWagesUtilityPlantAbstract Utility Plant
67	SalariesAndWagesUtilityPlantConstructionAbstract Construction (By Utility Departments)
68	SalariesAndWagesUtilityPlantConstructionElectricPlant Electric Plant	44,614,435	2,135,360	46,749,795
69	SalariesAndWagesUtilityPlantConstructionGasPlant Gas Plant
70	SalariesAndWagesUtilityPlantConstructionOther Other (provide details in footnote):
71	SalariesAndWagesUtilityPlantConstruction TOTAL Construction (Total of lines 68 thru 70)	44,614,435	2,135,360	46,749,795
72	SalariesAndWagesPlantRemovalAbstract Plant Removal (By Utility Departments)
73	SalariesAndWagesPlantRemovalElectricPlant Electric Plant	7,903,391	378,276	8,281,667
74	SalariesAndWagesPlantRemovalGasPlant Gas Plant
75	SalariesAndWagesPlantRemovalOther Other (provide details in footnote):
76	SalariesAndWagesPlantRemoval TOTAL Plant Removal (Total of lines 73 thru 75)	7,903,391	378,276	8,281,667
77	SalariesAndWagesOtherAccountsAbstract Other Accounts (Specify, provide details in footnote):
78	SalariesAndWagesOtherAccountsDescription Other Accounts (Specify, provide details in footnote):
79	SalariesAndWagesOtherAccountsDescription 151 - Fuel Stock	330,950		330,950
80	SalariesAndWagesOtherAccountsDescription 152 - Fuel Stock Undistributed	4,583,213		4,583,213
81	SalariesAndWagesOtherAccountsDescription 154 - Materials and Supplies
82	SalariesAndWagesOtherAccountsDescription 163 - Stores Expense Undistributed	3,927,831	3,927,831
83	SalariesAndWagesOtherAccountsDescription 165 - Other Prepayments
84	SalariesAndWagesOtherAccountsDescription 182 - Other Regulatory Assets
85	SalariesAndWagesOtherAccountsDescription 183 - Prelim Survey	7,093	7,093
86	SalariesAndWagesOtherAccountsDescription 184 - Clearing Accounts	2,867,979	2,867,979
87	SalariesAndWagesOtherAccountsDescription 185 - ODD Temporary Facilities	294,191		294,191
88	SalariesAndWagesOtherAccountsDescription 186 - Misc Deferred Debits	1,265,988		1,265,988
89	SalariesAndWagesOtherAccountsDescription 242 - Misc Current & Accrued Liab	60,230		60,230
90	SalariesAndWagesOtherAccountsDescription 254 - Ohio Reliability
91	SalariesAndWagesOtherAccountsDescription 401 - Operation Expense - Nonassociated	209		209
92	SalariesAndWagesOtherAccountsDescription 402 - Maintenance Exp
93	SalariesAndWagesOtherAccountsDescription 421 - Misc Nonoperating Income
94	SalariesAndWagesOtherAccountsDescription 426 - Political Activities	191,757		191,757
95	SalariesAndWagesOtherAccountsDescription 456 - Other Electric Revenue	42,014		42,014
95	SalariesAndWagesOtherAccounts TOTAL Other Accounts	13,473,241	6,788,717	6,684,524
96	SalariesAndWagesGeneralExpense TOTAL SALARIES AND WAGES	155,311,065		155,311,065

Name of Respondent:

SWEPCO

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:

SWEPCO

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)				49,441,744
2.1	Net Purchases (Account 555.1)
3	Net Sales (Account 447)				23,853,100
4	Transmission Rights
5	Ancillary Services				5,596,555
6	Other Items (list separately)
7	Congestion				43,579,845
8	Operating Reserves				1,079,793
9	Transmission Congestion Revenue				21,097,636
10	Transmission Losses				6,238,104
46	TOTAL				60,985,305

Name of Respondent:

SWEPCO

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
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:

SWEPCO

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	(b) 0

Name of Respondent:

SWEPCO

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

Southwestern Electric Power Company's transmission service is administered through a Regional Transmission Organization (RTO) and requested information is not available on an individual company basis.

(b) Concept: OtherService

Name of Respondent:

SWEPCO

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:

SWEPCO

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)	17,518,835
3	Steam	15,457,843	23	Requirements Sales for Resale (See instruction 4, page 311.)	4,823,958
4	Nuclear		24	Non-Requirements Sales for Resale (See instruction 4, page 311.)	2,127,593
5	Hydro-Conventional		25	Energy Furnished Without Charge
6	Hydro-Pumped Storage		26	Energy Used by the Company (Electric Dept Only, Excluding Station Use)	21,108
7	Other	2,458,004	27	Total Energy Losses	598,009
8	Less Energy for Pumping		27.1	Total Energy Stored
9	Net Generation (Enter Total of lines 3 through 8)	17,915,847	28	TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL LINE 20 UNDER SOURCES	25,089,503
10	Purchases (other than for Energy Storage)	7,173,657
10.1	Purchases for Energy Storage
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)	25,089,504

Name of Respondent:

SWEPCO

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	2,240,384	251,186	3,897	21	8
30	February	2,037,798	328,765	3,887	5	8
31	March	1,799,373	111,860	3,418	12	8
32	April	2,096,400	550,715	2,925	29	17
33	May	2,527,308	634,456	4,016	31	17
34	June	1,906,806	273,856	4,534	24	17
35	July	2,087,673	412,494	4,838	20	17
36	August	2,565,777	268,213	4,645	3	17
37	September	2,120,491	184,122	4,240	21	17
38	October	1,721,857	120,879	3,322	12	17
39	November	1,868,602	197,929	3,310	17	8
40	December	2,117,035	202,259	4,918	23	9
41	Total	25,089,504	2,164,034

Name of Respondent:

SWEPCO

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: (a) *Dolet Hills (3)	Plant Name: (b) *Flint Creek (1)	Plant Name: (c) *Pirkey (2)	Plant Name: (d) Arsenal Hill	Plant Name: Harry D Mattison	Plant Name: (e) Knox Lee	Plant Name: (f) Lieberman	Plant Name: North Central Wind	Plant Name: (g) Turk (4)	Plant Name: Welsh	Plant Name: (h) Wilkes
1	PlantKind Kind of Plant (Internal Comb, Gas Turb, Nuclear)	Steam	Steam	Steam	Steam	Gas Turbine	Steam	Steam	Wind	Steam	Steam	Steam
2	PlantConstructionType Type of Constr (Conventional, Outdoor, Boiler, etc)	Outdoor Boiler	Outdoor Boiler	Outdoor Boiler	Outdoor Boiler	No Boiler	Outdoor Boiler	Outdoor Boiler	Wind Generator	Outdoor Boiler	Outdoor Boiler	Outdoor Boiler
3	YearPlantOriginallyConstructed Year Originally Constructed	1986	1978	1985	1960	2007	1950	1947	2021	2012	1977	1964
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed	1986	1978	1985	2010	2007	1974	1959	2022	2012	1982	1971
5	InstalledCapacityOfPlant Total Installed Cap (Max Gen Name Plate Ratings-MW)	289.97	279.00	619.34	741.00	349.00	351.00	228.00	816.55	523.58	558.00	882.00
6	NetPeakDemandOnPlant Net Peak Demand on Plant - MW (60 minutes)		261	663	705	360	338	203	780	480		842
7	PlantHoursConnectedToLoad Plant Hours Connected to Load		6,246	6,470	6,952	789	2,923	1,787	1,422,830	6,913	6,498	4,524
8	NetContinuousPlantCapability Net Continuous Plant Capability (Megawatts)		258	580	619	283	335	217		477	1,053	864
9	NetContinuousPlantCapabilityNotLimitedByCondenserWater When Not Limited by Condenser Water									0
10	NetContinuousPlantCapabilityLimitedByCondenserWater When Limited by Condenser Water		258	580	619	283	335	217		477	1,053	864
11	PlantAverageNumberOfEmployees Average Number of Employees		89	103	26	5	24	24	39	112	121	30
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh	1,000	1,266,862,000	2,526,480,000	3,207,786,000	207,012,000	364,278,000	134,176,000	2,336,570,597	2,691,020,000	4,230,678,000	1,036,563,000
13	CostOfLandAndLandRightsSteamProduction Cost of Plant: Land and Land Rights		3,353,764	5,843,029	370,798	1,451,852	102,781	24,026	356,544	13,355,616	1,895,474	443,729
14	CostOfStructuresAndImprovementsSteamProduction Structures and Improvements		27,436,837	109,408,256	60,926,374	31,437,765	10,104,043	5,805,135		300,804,871	74,192,019	8,468,431
15	CostOfEquipmentSteamProduction Equipment Costs		341,673,619	474,971,404	402,168,918	95,524,335	54,603,515	36,327,794	1,041,909,386	1,371,536,093	813,784,451	123,575,335
16	AssetRetirementCostsSteamProduction Asset Retirement Costs		10,434,758	41,736,705	507,714		1,350,801	2,963,517	24,544,414	3,669,588	29,104,815	4,897,017
17	CostOfPlant Total cost (total 13 thru 20)		382,898,978	631,959,394	463,973,804	128,413,952	66,161,140	45,120,472	1,066,810,344	1,689,366,168	918,976,759	137,384,512
18	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 17/5) Including		1,372.3978	1,020.3756	626.1455	367.9483	188.4933	197.8968	1,306.4850	3,226.5674	1,646.9118	155.7648
19	OperationSupervisionAndEngineeringExpense Production Expenses: Oper, Supv, & Engr	17,893	1,866,325	4,905,605	3,108,982	106,985	456,734	229,938	2,347,497	3,907,086	4,002,336	1,428,750
20	FuelSteamPowerGeneration Fuel	2,766,003	33,354,527	132,470,886	150,246,733	21,389,185	30,264,279	11,228,238		69,457,252	112,722,764	79,925,233
21	CoolantsAndWater Coolants and Water (Nuclear Plants Only)
22	SteamExpensesSteamPowerGeneration Steam Expenses	11,657	1,019,401	5,174,460	1,039,784		470,279	3,080,629	14	6,003,086	5,413,616	351,159
23	SteamFromOtherSources Steam From Other Sources
24	SteamTransferredCredit Steam Transferred (Cr)
25	ElectricExpensesSteamPowerGeneration Electric Expenses	3,596	1,232,479	813,124	2,687,750	274,791	317	691	953,486	48,126	2,607,406	2,148,354
26	MiscellaneousSteamPowerExpenses Misc Steam (or Nuclear) Power Expenses	3,596,634	805,762	1,779,603	1,005,795	709	639,341	77,740	356,051	1,759,703	4,504,105	805,003
27	RentsSteamPowerGeneration Rents								4,823,025
28	Allowances Allowances		581,031	1,100,278	11,622	69,999	139,475	486		309,416	1,537,329	728,805
29	MaintenanceSupervisionAndEngineeringSteamPowerGeneration Maintenance Supervision and Engineering	18,812	465,694	83,059	100,203	3,947	12,117	10,508	6,123	2,755,800	129,012	286,086
30	MaintenanceOfStructuresSteamPowerGeneration Maintenance of Structures	41,392	508,449	354,122	371,066	107,244	201,075	253,726		2,653,466	556,225	648,267
31	MaintenanceOfBoilerPlantSteamPowerGeneration Maintenance of Boiler (or reactor) Plant	314,686	3,329,556	4,177,108	2,000,242	554	2,684,705	988,049		2,904,081	6,598,390	3,181,386
32	MaintenanceOfElectricPlantSteamPowerGeneration Maintenance of Electric Plant	1,571	806,038	1,051,740	875,433	1,375,221	341,638	131,243		323,067	2,242,983	1,571,719
33	MaintenanceOfMiscellaneousSteamPlant Maintenance of Misc Steam (or Nuclear) Plant	192,030	1,085,374	2,702,304	548,776		76,218	7,690		787,718	923,638	389,956
34	PowerProductionExpensesSteamPower Total Production Expenses	763,968	45,054,636	154,612,289	161,996,386	23,328,635	35,285,544	16,008,938	8,486,196	90,812,549	141,237,804	91,464,718
35	ExpensesPerNetKilowattHour Expenses per Net kWh	763.9681	0.0356	0.0612	0.0505	0.1127	0.0969	0.1193	0.0036	0.0337	0.0334	0.0882

35	FuelKindAxis Plant Name	*Dolet Hills (3)	*Dolet Hills (3)	*Dolet Hills (3)	*Flint Creek (1)	*Flint Creek (1)	*Flint Creek (1)	*Pirkey (2)	*Pirkey (2)	*Pirkey (2)	Arsenal Hill	Arsenal Hill	Harry D Mattison	Knox Lee	Knox Lee	Knox Lee	Lieberman	Lieberman	Lieberman	North Central Wind	Turk (4)	Turk (4)	Turk (4)	Welsh	Welsh	Welsh	Wilkes	Wilkes	Wilkes
36	FuelKind Fuel Kind	COMPOSITE	GAS	LIGNITE	COAL	COMPOSIT	OIL	COMPOSITE	GAS	LIGNITE	GAS	OIL	GAS	COMPOSITE	GAS	OIL	COMPOSIT	GAS	OIL	Wind	COAL	COMPOSIT	GAS	COAL	COMPOSIT	OIL	COMPOSITE	GAS	OIL
37	FuelUnit Fuel Unit				t		bbl		Mcf	t	Mcf	bbl	Mcf		Mcf	bbl		Mcf	bbl		t		Mcf	t		bbl		Mcf	bbl
38	QuantityOfFuelBurned Quantity (Units) of Fuel Burned				767,498		5,419		72,977	2,166,774	22,740,888		2,403,603		4,060,119			1,601,910			1,392,302		84,452	2,714,448		19,632		11,357,392
39	FuelBurnedAverageHeatContent Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)				8,803		139,999		1,081	6,306.000	1,032		1,023		1,011.000			1,028			8,846		1,046	8,845		140,000		1,024
40	AverageCostOfFuelPerUnitAsDelivered Avg Cost of Fuel/unit, as Delvd f.o.b. during year				35.610		109.300		7.420	58.680	6.580		8.870		7.430			6.980			45.230		9.290	41.160		116.490		7.010
41	AverageCostOfFuelPerUnitBurned Average Cost of Fuel per Unit Burned				36.200		109.300		7.420	58.860	6.580		8.870		7.430			6.980			44.780		9.290	39.790		116.490		7.010
42	AverageCostOfFuelBurnedPerMillionBritishThermalUnit Average Cost of Fuel Burned per Million BTU				2.060		18.590		6.870	4.670	6.370		8.670		7.350			6.790			2.530		8.880	2.250		19.810		6.840
43	AverageCostOfFuelBurnedPerKilowattHourNetGeneration Average Cost of Fuel Burned per kWh Net Gen				0.020		0.210		0.080	0.050	0.050		0.100		0.080			0.080			0.020		0.080	0.030		0.230		0.080
44	AverageBritishThermalUnitPerKilowattHourNetGeneration Average BTU per kWh Net Generation				10,690.000	10,691.000	11,211	10,848.000	11,030.000	10,847.000	7,316.000		11,881.000	11,267.000	11,267.000		12,275.0000	12,275.000			9,186.000	9,187.000	9,299.000	11,377.000	11,377.000	11,458.00	11,223.000	11,223.000

Name of Respondent:

SWEPCO

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: PlantName

(3) Dolet Hills Power Station is jointly owned in the percentages shown below:


Southwestern Electric Power Company	40.234	%
Central Louisiana Electric Company	50.000	%
Northeast Texas Electric Cooperative	5.860	%
Oklahoma Municipal Power Authority	3.906	%
Total	100.000	%

(b) Concept: PlantName

(1) Flint Creek Power Station is jointly owned in the percentages shown below:


Southwestern Electric Power Company	50	%
Arkansas Electric Cooperative Corporation	50	%
Total	100	%

(2) Pirkey Power Station is jointly owned in the percentages shown below:


Southwestern Electric Power Company	85.936	%
Northeast Texas Electric Cooperative	11.720	%
Oklahoma Municipal Power Authority	2.344	%
Total	100.000	%

(d) Concept: PlantName

Arsenal Hill Unit 6 (J. Lamar Stall Unit), a natural gas-fired combustion turbine combined cycle generating unit, became operational in June 2010. Unit 6 consists of 2 combustion turbines feeding one steam turbine.

(e) Concept: PlantName

Knox Lee Plant - Units 2 and 3 were retired during May 2020 business.

(f) Concept: PlantName

Lieberman Plant - Unit 2 was retired during May 2020 business.

(g) Concept: PlantName

Turk Plant, a 600MW Ultra-supercritical coal unit, became operational in December 2012.

(4) Turk Power Station is jointly owned in the percentages shown below:


Southwestern Electric Power Company	73.33	%
Arkansas Electric Cooperative Corporation	11.67	%
East Texas Electric Cooperative	8.33	%
Oklahoma Municipal Power Authority	6.67	%
Total	100.000	%

In April 2021, SWEPCo acquired a 54.5% ownership share of Sundance wind facility (199 MW total nameplate capacity) which was placed in-service in April 2021.

In September 2021, SWEPCo acquired a 54.5% ownership share of Maverick wind facility (287 MW total nameplate capacity) which was placed in-service in September 2021.

(h) Concept: PlantName

Lone Star Plant was retired during May 2020 business.

Name of Respondent:

SWEPCO

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
1	PlantKind Kind of Plant (Run-of-River or Storage)
2	PlantConstructionType Plant Construction type (Conventional or Outdoor)
3	YearPlantOriginallyConstructed Year Originally Constructed
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed
5	InstalledCapacityOfPlant Total installed cap (Gen name plate Rating in MW)
6	NetPeakDemandOnPlant Net Peak Demand on Plant-Megawatts (60 minutes)
7	PlantHoursConnectedToLoad Plant Hours Connect to Load
8	NetPlantCapabilityAbstract Net Plant Capability (in megawatts)
9	NetPlantCapabilityUnderMostFavorableOperatingConditions (a) Under Most Favorable Oper Conditions
10	NetPlantCapabilityUnderMostAdverseOperatingConditions (b) Under the Most Adverse Oper Conditions
11	PlantAverageNumberOfEmployees Average Number of Employees
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh
13	CostOfPlantAbstract Cost of Plant
14	CostOfLandAndLandRightsHydroelectricProduction Land and Land Rights
15	CostOfStructuresAndImprovementsHydroelectricProduction Structures and Improvements
16	CostOfReservoirsDamsAndWaterwaysHydroelectricProduction Reservoirs, Dams, and Waterways
17	EquipmentCostsHydroelectricProduction Equipment Costs
18	CostOfRoadsRailroadsAndBridgesHydroelectricProduction Roads, Railroads, and Bridges
19	AssetRetirementCostsHydroelectricProduction Asset Retirement Costs
20	CostOfPlant Total cost (total 13 thru 20)
21	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 20 / 5)
22	ProductionExpensesAbstract Production Expenses
23	OperationSupervisionAndEngineeringExpense Operation Supervision and Engineering
24	WaterForPower Water for Power
25	HydraulicExpenses Hydraulic Expenses
26	ElectricExpensesHydraulicPowerGeneration Electric Expenses
27	MiscellaneousHydraulicPowerGenerationExpenses Misc Hydraulic Power Generation Expenses
28	RentsHydraulicPowerGeneration Rents
29	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration Maintenance Supervision and Engineering
30	MaintenanceOfStructuresHydraulicPowerGeneration Maintenance of Structures
31	MaintenanceOfReservoirsDamsAndWaterways Maintenance of Reservoirs, Dams, and Waterways
32	MaintenanceOfElectricPlantHydraulicPowerGeneration Maintenance of Electric Plant
33	MaintenanceOfMiscellaneousHydraulicPlant Maintenance of Misc Hydraulic Plant
34	PowerProductionExpensesHydraulicPower Total Production Expenses (total 23 thru 33)
35	ExpensesPerNetKilowattHour Expenses per net kWh

Name of Respondent:

SWEPCO

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
1	PlantConstructionType Type of Plant Construction (Conventional or Outdoor)
2	YearPlantOriginallyConstructed Year Originally Constructed
3	YearLastUnitOfPlantInstalled Year Last Unit was Installed
4	InstalledCapacityOfPlant Total installed cap (Gen name plate Rating in MW)
5	NetPeakDemandOnPlant Net Peak Demaind on Plant-Megawatts (60 minutes)	0
6	PlantHoursConnectedToLoad Plant Hours Connect to Load While Generating	0
7	NetContinuousPlantCapability Net Plant Capability (in megawatts)	0
8	PlantAverageNumberOfEmployees Average Number of Employees
9	NetGenerationExcludingPlantUse Generation, Exclusive of Plant Use - kWh	0
10	EnergyUsedForPumping Energy Used for Pumping
11	NetOutputForLoad Net Output for Load (line 9 - line 10) - Kwh	0
12	CostOfPlantAbstract Cost of Plant
13	CostOfLandAndLandRightsPumpedStoragePlant Land and Land Rights
14	CostOfStructuresAndImprovementsPumpedStoragePlant Structures and Improvements	0
15	CostOfReservoirsDamsAndWaterwaysPumpedStoragePlant Reservoirs, Dams, and Waterways	0
16	CostOfWaterWheelsTurbinesAndGeneratorsPumpedStoragePlant Water Wheels, Turbines, and Generators	0
17	CostOfAccessoryElectricEquipmentPumpedStoragePlant Accessory Electric Equipment	0
18	CostOfMiscellaneousPowerPlantEquipmentPumpedStoragePlant Miscellaneous Powerplant Equipment	0
19	CostOfRoadsRailroadsAndBridgesPumpedStoragePlant Roads, Railroads, and Bridges	0
20	AssetRetirementCostsPumpedStoragePlant Asset Retirement Costs	0
21	CostOfPlant Total cost (total 13 thru 20)
22	CostPerKilowattOfInstalledCapacity Cost per KW of installed cap (line 21 / 4)
23	ProductionExpensesAbstract Production Expenses
24	OperationSupervisionAndEngineeringExpense Operation Supervision and Engineering	0
25	WaterForPower Water for Power	0
26	PumpedStorageExpenses Pumped Storage Expenses	0
27	ElectricExpensesPumpedStoragePlant Electric Expenses	0
28	MiscellaneousPumpedStoragePowerGenerationExpenses Misc Pumped Storage Power generation Expenses	0
29	RentsPumpedStoragePlant Rents	0
30	MaintenanceSupervisionAndEngineeringPumpedStoragePlant Maintenance Supervision and Engineering	0
31	MaintenanceOfStructuresPumpedStoragePlant Maintenance of Structures	0
32	MaintenanceOfReservoirsDamsAndWaterwaysPumpedStoragePlant Maintenance of Reservoirs, Dams, and Waterways	0
33	MaintenanceOfElectricPlantPumpedStoragePlant Maintenance of Electric Plant	0
34	MaintenanceOfMiscellaneousPumpedStoragePlant Maintenance of Misc Pumped Storage Plant	0
35	PowerProductionExpenseBeforePumpingExpenses Production Exp Before Pumping Exp (24 thru 34)
36	PumpingExpenses Pumping Expenses
37	PowerProductionExpensesPumpedStoragePlant Total Production Exp (total 35 and 36)
38	ExpensesPerNetKilowattHour Expenses per kWh (line 37 / 9)
39	ExpensesPerNetKilowattHourGenerationAndPumping Expenses per KWh of Generation and Pumping (line 37/(line 9 + line 10))	0

Name of Respondent:

SWEPCO

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.	PlantName Name of Plant (a)	YearPlantOriginallyConstructed Year Orig. Const. (b)	InstalledCapacityOfPlant Installed Capacity Name Plate Rating (MW) (c)	NetPeakDemandOnPlant Net Peak Demand MW (60 min) (d)	NetGenerationExcludingPlantUse Net Generation Excluding Plant Use (e)	CostOfPlant Cost of Plant (f)	PlantCostPerMw Plant Cost (Incl Asset Retire. Costs) Per MW (g)	OperatingExpensesExcludingFuel Operation Exc'l. Fuel (h)	FuelProductionExpenses Fuel Production Expenses (i)	MaintenanceProductionExpenses Maintenance Production Expenses (j)	FuelKind Kind of Fuel (k)	FuelCostPerMmbtus Fuel Costs (in cents (per Million Btu) (l)	GenerationType Generation Type (m)
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

Name of Respondent:

SWEPCO

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:

SWEPCO

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	TL367 Layfield Extension		500.00	500.00	1	0.08	0	1	3-1272 ACSR
2	345 kV in AR	345 kV in AR	0	0		0.00	0	0
3	TL175 Chamber Springs	Clarksville 345	345	345	1	6.85	0	1	2x795.0 ACSR
4	TL149 Flint Creek	GRDA GRDA 1 (Interconnect)	345	345	2	3.04	0	1	2x1431.0 ACSR
5	TL149 Flint Creek	CUS Brookline (Interconnect	345	345	3	17.92	0	1	2156.0 ACSR
6	TL288 Chambers Spring	Tontitown	345.00	345.00	1	11.53	0	1	2x795.0 ACSR
7	TL327 Turk (AR)	NW Texarkana	345.00	345.00	2	22.15	0	1	954.0 ACSR
8	TL344 Flint Creek	Shipe Road	345.00	345.00	1	14.40	0	1	2x954.0 ACSR
9	345 kV in LA	345 kV in LA	0.00	0.00		0.00	0	0
10	TL134 Diana	Southwest Shreveport	345.00	345.00	3	3.30	8	1	2156.0 ACSR
11	TL134 Diana	Southwest Shreveport	0.00	0.00		0.00	0	0	2x795.0 ACSR
12	TL133 Southwest Shreveport	CLECO Dolet Hills	345.00	345.00	3	34.60	0	1	2156.0 ACSR
13	TL135 Longwood	Entergy El Dorado	345.00	345.00	2	37.72	0	1	2x1024.0 ACAR
14	TL134 Longwood	Southwest Shreveport	345.00	345.00	1	19.02	0	1	2x795.0 ACSR
15	TL135 Longwood	Wilkes	345.00	345.00	3	3.06	0.00	1	2x1024.0 ACAR
16	345 kV in OK	345 kV in OK	0.00	0.00		0.00	0.00	0
17	TL251 Chamber Springs	Clarksville 345	345.00	345.00	1	61.57	0.00	1	2x795.0 ACSR
18	345 kV in TX	345 kV in TX	0.00	0.00		0.00	0.00	0
19	TL273 Crockett	Entergy Grimes	345.00	345.00	3	26.40	0.00	1	2x1024.0 ACAR
20	TL273 Diana	Pirkey	345.00	345.00	3	24.70	0.00	1	2x1024.0 ACAR
21	TL273 Crockett	Tenaska Rusk County	345.00	345.00	3	67.14	0.00	1	2x1024.0 ACAR
22	TL273 Lebrock	Tenaska Rusk County	345.00	345.00	3	29.31	0.00	0	2x1024.0 ACAR
23	TL273 Lebrock	Tenaska Rusk County	345.00	345.00	3	8.70	0.00	0	2x1272.0 ACSR
24	TL281 Lebrock	Pirkey	345.00	345.00	1	5.21	0.00	1	2x1272.0 ACSR
25	TL281 Lebrock	Pirkey	0.00	0.00	2	0.90	0.00	0
26	TL272 Diana	Southwest Shreveport	345.00	345.00	3	46.45	0.00	1	2156.0 ACSR
27	TL275 Diana	Welsh Ckt 1	345.00	345.00	3	23.69	0.00	1	2156.0 ACSR
28	TL275 Diana	Welsh Ckt 2	345.00	345.00	3	23.60	0.00	1	2156.0 ACSR
29	TL271 Longwood	Wilkes	345.00	345.00	2	0.23	0.00	1	2x1024.0 ACAR
30	TL271 Longwood	Wilkes	345.00	345.00	3	35.11	0.00	0	2x1024.0 ACAR
31	TL271 Welsh	Wilkes	345.00	345.00	3	30.61	0.00	1	2x795 ACSR
32	TL271 Welsh	Lydia	345.00	345.00	1	0.16	0.00	1	2x795 ACSR
33	TL271 Welsh	Lydia	345.00	345.00	3	23.74	0.00	0	2156.0 ACSR
34	TL271 Lydia	Valliant	345.00	345.00	1	0.16	0.00	1	2x795 ACSR
35	TL271 Lydia	Valliant	345.00	345.00	3	22.45	0.00	0	2x795 ACSR
36	TL199 Welsh	Monticello	345.00	345.00	3	16.00	0.00	1	2156 ACSR
37	TL199 Welsh	Welsh DC	345.00	345.00	3	0.48	0.00	0	2156.0 ACSR
38	TL274 Northwest Texarkana	Welsh	345.00	345.00	3	51.68	12.00	1	2156.0 ACSR
39	TL274 Northwest Texarkana	Welsh	0.00	0.00	2	0.31	0.00	0	2156.0 ACSR
40	TL274 Northwest Texarkana	Welsh	0.00	0.00	1	1.31	0.00	0	2156.0 ACSR
41	TL270 Lydia	NW Texarkana	345.00	345.00	1	0.14	0.00	1	2156.0 ACSR
42	TL270 Lydia	NW Texarkana	345.00	345.00	3	31.20	0.00	1	2156.0 ACSR
43	TL90928 Valliant	NW Texarkana (TX Portion)	345.00	345.00	1	43.48	0.00	1	2-954 ACSR
44	TL328 Turk (TX)	NW Texarkana	345.00	345.00	2	7.43	0.00	1	954.0 ACSR
45	161 kV in AR	161 kV in AR	0.00	0.00		0.00	0.00	0
46	TL179 Chambers Spring	South Fayetteville	161.00	161.00	1	10.36	0.00	1	2156 ACSR
47	TL179 Chambers Spring	South Fayetteville	0.00	0.00	2	5.70	0.00	0	2x397.0 ACSR
48	TL189 Dyess	Beaver Dam	161.00	161.00	1	6.84	0.00	1	2156.0 ACSR
49	TL189 Dyess	Beaver Dam	0.00	0.00	2	30.23	0.00	1	666.0 ACSR
50	TL189 Dyess	Beaver Dam	0.00	0.00	2	11.70	0.00	1	1020.0 ACCC/TW
51	TL189 Dyess	Beaver Dam	0.00	0.00	2	0.66	0.00	2	2156.0 ACSR
52	TL190 South Fayetteville	South Springdale - Dyess	161.00	161.00	1	5.50	0.00	1	1272.0 AAC
53	TL190 South Fayetteville	South Springdale - Dyess	161.00	161.00	1	0.02	0.00	1	1272.0 ACSR
54	TL190 South Fayetteville	South Springdale - Dyess	161.00	161.00	2	8.83	0.00	1	2x397.0 ACSR
55	TL190 South Fayetteville	South Springdale - Dyess	161.00	161.00	1	0.78	0.00	2	2x397.0 ACSR
56	TL180 Flint Creek	East Centerton	161.00	161.00	1	7.99	0.00	1	1272.0 ACSR
57	TL180 Flint Creek	East Centerton	161.00	161.00	1	1.31	0.00	1	1590.0 ACSR
58	TL180 Flint Creek	East Centerton	161.00	161.00	1	10.40	0.00	1	2156.0 ACSR
59	TL180 Flint Creek	East Centerton	161.00	161.00	1	8.07	0.00	1	1590.0 ACSR
60	TL180 Flint Creek	East Centerton	161.00	161.00	1	0.40	0.00	1	1020 ACCC
61	TL187 SPA Eur Spr	Eureka Springs Double Circu	161.00	161.00	2	1.25	0.00	1	795.0 ACSR
62	TL188 Eureka Springs	AP&L Interconnection	161.00	161.00	1	0.94	0.00	1	666.0 ACSR
63	TL188 Eureka Springs	AP&L Interconnection	161.00	161.00	2	4.40	0.00	1	666.0 ACSR
64	TL187 SPA	Eureka Springs Double Circu	161.00	161.00	2	1.25	0.00	1	795.0 ACSR
65	TL178 Flint Creek	Siloam Springs Substation	161.00	161.00	1	5.44	0.00	1	2x397.0 ACSR
66	TL178 Flint Creek	Siloam Springs Substation	161.00	161.00	2	1.68	0.00	1	2x397.0 ACSR
67	TL190 South Fayetteville	South Springdale - Dyess	161.00	161.00	1	2.11	0.00	1	2x397.0 ACSR
68	TL176 OG&E	Fort Smith - Bonanza - Nort	161.00	161.00	2	13.10	0.00	1	397.0 ACSR
69	TL176 OG&E	Fort Smith - Bonanza - Nort	161.00	161.00	2	0.24	0.00	1	1590.0 ACSR
70	TL162 Midland	Huntington - REA - Boonevil	161.00	161.00	1	12.70	0.00	1	397.0 ACSR
71	TL162 Midland	Huntington - REA - Boonevil	161.00	161.00	1	6.80	0.00	2	477.0 ACSR & 397.
72	TL337 North Magazine	Danville (Entergy)	161.00	161.00	1	25.95	0.00	1	1272.0 ACSR
73	TL425 Branch	North Magazine	161.00	161.00	2	9.01	0.00	1	250.0 CW
74	TL172 Siloam Springs	West Siloam Springs (GRDA)	161.00	161.00	1	2.06	0.00	1	1272.0 ACSR
75	TL190 South Fayetteville	South Springdale - Dyess	161.00	161.00	1	2.96	0.00	1	2x397.0 ACSR
76	TL162 Midland	Huntington - REA - Boonevil	161.00	161.00	1	13.96	0.00	1	397.0 ACSR
77	TL179 Flint Creek	South Fayetteville Substati	161.00	161.00	1	0.22	0.00	1	1272.0 ACSR
78	TL179 Flint Creek	South Fayetteville Substati	161.00	161.00	2	2.24	0.00	2	2x397.0 ACSR
79	TL179 Flint Creek	South Fayetteville Substati	161.00	161.00	1	3.45	0.00	1	2x397.0 ACSR
80	TL179 Flint Creek	South Fayetteville Substati	161.00	161.00	2	7.74	0.00	1	2x397.0 ACSR
81	TL283 Tontitown	Lowell	161.00	161.00	1	11.59	0.00	1	1590.0 ACSR
82	TL283 Tontitown	Lowell	161.00	161.00	1	0.40	0.00	2	1590.0 ACSR
83	TL283 Tontitown	Lowell	161.00	161.00	1	0.40	0.00	2	2156 ACSR
84	TL154 VBI	Rogers/Loop Thru Springdale (TLN194:0154G)	161.00	161.00	1	4.40	0.00	1	1590.0 ACSR
85	TL282 East Rogers	Rogers	161.00	161.00	1	1.25	0.00	1	1272.0 ACSR
86	TL282 East Rogers	Rogers	161.00	161.00	1	3.92	0.00	1	1590 ACSR
87	TL285 Siloam Springs	Chambers Spring	161.00	161.00	1	7.56	0.00	1	1590.0 ACSR
88	TL340 Van Asche	Dyess	161.00	161.00	1	5.97	0.00	1	1590.0 ACSR
89	TL342 Fayetteville	Van Asche	161.00	161.00	1	4.18	0.00	1	1590.0 ACSR
90	TL341 Fayetteville	S Fayetteville	161.00	161.00	1	1.98	0.00	1	1590.0 ACSR
91	TL177 Flint Creek	Dyess Substation	161.00	161.00	1	5.63	0.00	2	2x397.0 ACSR
92	TL177 Flint Creek	Dyess Substation	161.00	161.00	2	10.59	0.00	1	2x397.0 ACSR
93	TL177 Flint Creek	Dyess Substation	161.00	161.00	1	5.46	0.00	1	2156 ACSR
94	TL177 Flint Creek	Dyess Substation	161.00	161.00	1	1.60	0.00	1	1590 ACSR
95	TL177 Flint Creek	Dyess Substation	161.00	161.00	1	5.63	0.00	2	1020 ACCC
96	TL343 East Centerton	Shipe Road	161.00	161.00	1	6.79	0.00	1	2156 ACSR
97	TL360 Osburn Tap		161.00	161.00	1	1.61	0.00	2	1272.0 ACSR
98	TL389 Greenland	VBI	69.00	161.00	1	40.70	0.00	1	1272 ACSR
99	138 kV in AR	138 kV in AR	0.00	0.00		0.00	0.00	0
100	TL159 DeQueen	Craig Junction	138.00	138.00	1	8.21	0.00	1	1272 ACSR
101	TL183 North New Boston	Patterson	138.00	138.00	2	0.10	0.00	1	2x203.2 ACSR
102	TL183 North New Boston	Patterson	138.00	138.00	2	17.09	0.00	1	666.0 ACSR
103	TL182 Patterson	Craig Junction	138.00	138.00	1	26.47	0.00	1	1272.0 ACSR
104	TL182 Patterson	Craig Junction	138.00	138.00	2	0.48	0.00	1	1272.0 ACSR
105	TL182 Patterson	Craig Junction	138.00	138.00	1	0.18	0.00	2	1590.0 ACSR
106	TL181 Northwest Texarkana	Patterson	138.00	138.00	2	8.26	0.00	1	1024.0 ACAR
107	TL181 Northwest Texarkana	Patterson (TLN194:00181)	138.00	138.00	1	0.40	0.00	2	1590 ACSR
108	TL181 Northwest Texarkana	Patterson (TLN194:00181A)	138.00	138.00	2	1.64	0.00	2	1272.0 ACSR
109	TL181 Northwest Texarkana	Patterson (TLN194:00181A)	138.00	138.00	1	8.16	0.00	1	1272.0 ACSR
110	TL181 Northwest Texarkana	Patterson (TLN194:00181A)	138.00	138.00	1	0.24	0.00	2	1590 ACSR
111	TL181 Northwest Texarkana	Patterson (TLN194:00181A)	138.00	138.00	1	0.07	0.00	1	1590 ACSR
112	TL181 Northwest Texarkana	Patterson (TLN194:00181A)	138.00	138.00	2	9.48	0.00	1	4/0 CU
113	TL181 Northwest Texarkana	Patterson (TLN194:00181A)	138.00	138.00	2	5.68	0.00	1	336 ACSR
114	TL181 Northwest Texarkana	Patterson (TLN194:00181B)	138.00	138.00	1	0.04	0.00	1	1272 ACSR
115	TL181 Northwest Texarkana	Patterson (TLN194:00181B)	138.00	138.00	2	18.01	0.00	1	4/0 CU
116	TL235 Northwest Texarkana	Northeast Texarkana (Sugarhill)	138.00	138.00	1	0.50	0.00	2	1272.0 ACSR
117	TL184 South Dierks	Patterson	138.00	138.00	1	2.28	0.00	1	2x397.0 ACSR
118	TL184 South Dierks	Patterson	138.00	138.00	2	19.09	0.00	1	2x397.0 ACSR
119	TL184 South Dierks	Patterson	138.00	138.00	2	10.90	0.00	1	397.0 ACSR
120	TL184 South Dierks	Patterson	138.00	138.00	1	0.07	0.00	1	1590 ACSR
121	TL227 Bann	Southeast Texarkana	138.00	138.00	1	0.20	0.00	2	1272.0 ACSR
122	TL227 Bann	Southeast Texarkana	138.00	138.00	1	0.18	0.00	1	1272.0 ACSR
123	TL280 Mena	Craig Jct.	138.00	138.00	1	28.22	0.00	1	795.0 ACSR
124	TL325 Turk	Sugar Hill	138.00	138.00	1	21.70	0.00	1	1590 ACSR
125	TL330 Turk	Southeast Texarkana	138.00	138.00	1	24.95	0.00	1	1590 ACSR/AW
126	TL330 Turk	Southeast Texarkana	138.00	138.00	1	1.84	0.00	2	1590 ACSR/AW
127	TL330 Turk	Southeast Texarkana	138.00	138.00	1	1.84	0.00	2	T2-397.5 ACSR
128	TL345 Turk	Hope	115.00	138.00	1	1.04	0.00	2	1590 ACSR
129	TL345 Turk	Hope	115.00	138.00	1	5.04	0.00	1	1590 ACSR
130	TL403 Wilkes 138kV Bus Tie		138.00	138.00	1	0.06	0.00	1	2x795 ACSS
131	138 kV in LA	138 kV in LA	0.00	0.00		0.00	0.00	0
132	TL110 Shreveport 138kV Loop	(TLN194:00110)	138.00	138.00	1	2.72	0.00	1	2156 ACSR
133	TL110 Shreveport 138kV Loop	(TLN194:00110)	138.00	138.00	1	0.62	0.00	2	2156 ACSR
134	TL110 Shreveport 138kV Loop	(TLN194:00110)	138.00	138.00	1	0.62	0.00	2	666.6 ACSR
135	TL128 Arsenal Hill	Lieberman	138.00	138.00	1	0.12	0.00	1	1272 ACSR
136	TL128 Arsenal Hill	Lieberman	138.00	138.00	2	10.93	0.00	1	666.6 ACSR
137	TL128 Arsenal Hill	Lieberman	138.00	138.00	1	1.94	0.00	1	959.6 ACSR/TW
138	TL128 Arsenal Hill	Lieberman	138.00	138.00	1	2.00	0.00	1	666.6 ACSR
139	TL128 Arsenal Hill	Lieberman	138.00	138.00	2	6.43	0.00	1	2-266 ACSR
140	TL128 Arsenal Hill	Lieberman	138.00	138.00	3	0.00	0.00	1	666.6 ACSR
141	TL110 Shreveport 138kV Loop	(TLN194:0110A)	138.00	138.00	1	2.91	0.00	1	1272.0 AAC
142	TL110 Shreveport 138kV Loop	(TLN194:0110A)	138.00	138.00	1	2.12	0.00	0	1272.0 ACSR
143	TL127 Arsenal Hill	Longwood	138.00	138.00	1	15.06	0.00	1	1272 ACSR
144	TL127 Arsenal Hill	Longwood	138.00	138.00	1	1.41	0.00	1	1233.6 ACSR
145	TL127 Arsenal Hill	Longwood	138.00	138.00	3	0.65	0.00	2	1024 ACAR
146	TL112 Center	Logansport	138.00	138.00	1	0.60	0.00	1	755.0 ACAR
147	TL130 South Shreveport - We	Flournoy - Longwood (TLN194:00130)	138.00	138.00	1	0.58	0.00	1	666.0 ACSR
148	TL130 South Shreveport - We	Flournoy - Longwood (TLN194:00130)	138.00	138.00	2	0.98	0.00	0	795.0 ACSR
149	TL130 South Shreveport - We	Flournoy - Longwood (TLN194:0130A)	138.00	138.00	2	12.22	0.00	1	666.0 ACSR
150	TL110 Shreveport 138kV Loop	(TLN194:0110B)	138.00	138.00	1	8.90	0.00	1	1272.0 AAC
151	TL110 Shreveport 138kV Loop	(TLN194:0110B)	138.00	138.00	1	1.50	0.00	2	1272.0 AAC & 666.6 ACSR
152	TL130 South Shreveport - We	Flournoy - Longwood (TLN194:0130B)	138.00	138.00	1	1.28	0.00	1	666.0 ACSR
153	TL130 South Shreveport - We	Flournoy - Longwood (TLN194:0130B)	138.00	138.00	2	3.06	0.00	0	795.0 ACSR
154	TL242 Jefferson Switching S	Lieberman (TLN194:00126)	138.00	138.00	1	0.72	0.00	1	2156.0 ACSR
155	TL242 Jefferson Switching S	Lieberman (TLN194:00126)	138.00	138.00	2	6.48	0.00	0	336.4 ACSR
156	TL132 Dixie Tee - North Benton	Red Point	138.00	138.00	1	9.16	0.00	1	2x397.0 ACSR
157	TL132 Dixie Tee - North Benton	Red Point	138.00	138.00	2	23.80	0.00	1	2x397.0 ACSR
158	TL132 Dixie Tee - North Benton	Red Point	138.00	138.00	1	0.58	0.00	2	1272 ACSR
159	TL132 Dixie Tee - North Benton	Red Point	138.00	138.00	3	0.80	0.00	1	1272 ACSR
160	TL127 Marshall - Longwood - Arsenal Hill	Longwood - Lieberman (TLN194:0127A)	138.00	138.00	1	1.83	0.00	1	2156.0 ACSR
161	TL127 Marshall - Longwood - Arsenal Hill	Longwood - Lieberman (TLN194:0127A)	138.00	138.00	2	7.80	0.00	0	2x266.8 ACSR
162	TL110 Shreveport 138kV Loop	(TLN194:0110C)	138.00	138.00	1	2.45	0.00	1	1533.3 ACSR/TW
163	TL109 SW Shreveport - Powel	Linwood Substation	138.00	138.00	1	2.27	0.00	1	1272.0 AAC
164	TL109 SW Shreveport - Powel	Linwood Substation	138.00	138.00	2	0.26	0.00	1	1272.0 ACSR
165	TL109 SW Shreveport - Powel	Linwood Substation	138.00	138.00	1	6.80	0.00	1	1703.0 ACAR
166	TL122 Logansport	Rock Hill (LA)	138.00	138.00	2	4.35	0.00	1	755.0 ACAR
167	TL107 Western Electric Tee	Texas Station	138.00	138.00	1	9.74	0.00	1	1272.0 ACSR
168	TL107 Western Electric Tee	Texas Station	138.00	138.00	1	12.80	0.00	1	795.0 ACSR
169	TL107 Western Electric Tee	Texas Station (TLN194:0107A)	138.00	138.00	1	8.00	0.00	1	1272.0 ACSR
170	TL336 Longwood	Scottsville	138.00	138.00	1	3.88	0.00	1	1590 ACSR
171	TL119 Minden Road Tee - Whi	Bodcau - Red Point (TLN194:00119)	138.00	138.00	1	6.86	0.00	1	2x397.0 ACSR
172	TL129 Knox Lee - Rock Hill	South Shreveport/Tap - SW Shreveport (TLN194:00129)	138.00	138.00	1	6.90	0.00	1	1590.0 ACSR
173	TL129 Knox Lee - Rock Hill	South Shreveport/Tap - SW Shreveport (TLN194:0129A)	138.00	138.00	1	2.30	0.00	2	2-1590.0 ACSR
174	TL129 Knox Lee - Rock Hill	South Shreveport/Tap - SW Shreveport (TLN194:00129)	138.00	138.00	1	10.78	0.00	1	1272.0 ACSR
175	TL129 Knox Lee - Rock Hill	South Shreveport/Tap - SW Shreveport (TLN194:00129)	138.00	138.00	2	0.02	0.00	1	2x397.0 ACSR
176	TL129 Knox Lee - Rock Hill	South Shreveport/Tap - SW Shreveport (TLN194:00129)	138.00	138.00	1	4.25	0.00	1	1926.9 ACSR
177	TL131 South Shreveport	Frierson (Cleco Interconnection) (TLN194:00131)	138.00	138.00	2	11.18	0.00	1	666.0 ACSR
178	TL130 South Shreveport - We	Flournoy - Longwood (TLN194:0130C)	138.00	138.00	1	1.40	0.00	1	2x397.0 ACSR
179	TL130 South Shreveport - We	Flournoy - Longwood (TLN194:0130C)	138.00	138.00	2	4.91	0.00	1	2x397.0 ACSR
180	TL130 South Shreveport - We	Flournoy - Longwood (TLN194:0130D)	138.00	138.00	1	1.48	0.00	1	2x795.0 ACSR
181	TL130 South Shreveport - We	Flournoy - Longwood (TLN194:0130D)	138.00	138.00	2	3.40	0.00	1	2x795.0 ACSR
182	TL119 Minden Road Tee - Whi	Bodcau - Red Point (TLN194:0119A)	138.00	138.00	1	4.51	0.00	1	2x397.0 ACSR
183	TL131 South Shreveport	Frierson (Cleco Interconnection) (TLN194:0131A)	138.00	138.00	2	6.86	0.00	1	666.0 ACSR
184	TL292 Finney Tap	Port Robson	138.00	138.00	1	3.25	0.00	1	1590.0 ACSR
185	TL332 Wallace Lake	Finney Tap	138.00	138.00	1	2.63	0.00	2	397.5 ACSR & 1590
186	TL333 Caplis	Port Robson	138.00	138.00	1	1.29	0.00	1	1590.0 ACSR
187	TL333 Caplis	Port Robson	138.00	138.00	1	2.92	0.00	1	1590.0 ACSR
188	TL339 Bean 138kV Loop		138.00	138.00	1	0.72	0.00	2	1590 ACSR
189	TL331 Caplis	McDade	138.00	138.00	2	7.87	0.00	0
190	TL335 Haughton	Red Point	138.00	138.00	2	2.95	0.00	1	1590.0 ACSR
191	TL334 Haughton	McDade	138.00	138.00	2	11.30	0.00	1	4/0 ACSR
192	TL364 Port Robson	Benteler 1	138.00	138.00	1	4.10	0.00	1	1533 ACSR
193	TL365 Port Robson	Benteler 2	138.00	138.00	1	3.17	0.00	1	1533 ACSR
194	TL374 Ellerbe Road	Lucas	69.00	138.00	1	3.18	0.00	1	1272.0 ACSR
195	TL384 Mount Pleasant New Bos	New Boston	69.00	138.00	1	19.50	0.00	1	1272 ACSR
196	TL428 Flournoy	Pines Road-Hardy St	69.00	138.00	1	4.90	0.00	1	795 ACSR
197	138 kV in OK	138 kV in OK	0.00	0.00		0.00	0.00	0
198	TL257 DeQueen	Craig Junction	138.00	138.00	1	9.98	0.00	1	1272.0 ACSR
199	TL256 Patterson	Craig Junction	138.00	138.00	1	9.41	0.00	1	1272.0 ACSR
200	TL280 Mena	Craig Junction (TLN194:0280A)	138.00	138.00	1	17.82	0.00	1	2x397.0 ACSR
201	138 kV in TX	138 kV in TX	0.00	0.00		0.00	0.00	0
202	TL204 Center	Logansport	138.00	138.00	1	16.38	0.00	1	755.0 ACAR
203	TL241 AP&L-Patterson-Jeffer	Marshall-Knox Lee-Overton (TLN194:0241A)	138.00	138.00	1	11.31	0.00	1	1590 ACSR
204	TL241 AP&L-Patterson-Jeffer	Marshall-Knox Lee-Overton (TLN194:0241B)	138.00	138.00	2	0.20	0.00	1	2156.0 ACSR
205	TL241 AP&L-Patterson-Jeffer	Marshall-Knox Lee-Overton (TLN194:0241B)	138.00	138.00	1	3.14	0.00	1	1590 ACSR
206	TL241 AP&L-Patterson-Jeffer	West Atlanta w/tap to IPC (TLN194:0241D)	138.00	138.00	1	2.40	0.00	1	795 ACAR
207	TL241 AP&L-Patterson-Jeffer	Marshall-Knox Lee-Overton (TLN194:0241,C,D)	138.00	138.00	2	5.96	0.00	0	397.0 ACSR
208	TL241 AP&L-Patterson-Jeffer	West Atlanta w/tap to IPC (TLN194:0241D)	138.00	138.00	2	16.22	0.00		1024.0 ACAR
209	TL241 AP&L-Patterson-Jeffer	West Atlanta w/tap to IPC (TLN194:0241D)	138.00	138.00	2	0.08	0.00	2	1272.0 ACSR
210	TL241 AP&L-Patterson-Jeffer	Marshall-Knox Lee-Overton (TLN194:0241E)	138.00	138.00	2	16.60	0.00	1	1024.0 ACAR
211	TL241 AP&L-Patterson-Jeffer	Marshall-Knox Lee-Overton (TLN194:00241F)	138.00	138.00	1	23.91	0.00	1	2x397.0 ACSR
212	TL241 AP&L-Patterson-Jeffer	Marshall-Knox Lee-Overton (TLN194:00241G)	138.00	138.00	2	13.54	0.00	1	2x1033.5 ACSR
213	TL200 Center	Carthage Tee	138.00	138.00	1	0.50	0.00	1	795.0 ACSR
214	TL200 Center	Carthage Tee	138.00	138.00	1	1.36	0.00	2	1272 ACSR & 397 ACSR
215	TL200 Center	Carthage Tee	138.00	138.00	1	17.85	0.00	1	1272 ACSR
216	TL200 Center	Carthage Tee	138.00	138.00	1	10.60	0.00	1	397 ACSR
217	TL249 Whitney-Pliler	Diana-Lone Star South (TLN194:00249)	138.00	138.00	1	0.12	0.00	1	2x336.0&397.0 ACS
218	TL249 Whitney-Pliler	Diana-Lone Star South (TLN194:00249)	138.00	138.00	2	12.38	0.00	1	2x666.0&795.0 ACS
219	TL249 Whitney-Pliler	Diana-Lone Star South (TLN194:00249)	138.00	138.00	1	0.13	0.00	1	2x397.0 ACSR
220	TL238 Diana	Perdue	138.00	138.00	2	21.85	0.00	1	2x397.0 ACSR
221	TL249 Whitney-Pliler	Diana-Lone Star South (TLN194:0249A)	138.00	138.00	1	2.42	3.00	1	1272.0 ACSR
222	TL249 Whitney-Pliler	Diana-Lone Star South (TLN194:0249A)	138.00	138.00	2	11.86	0.00	0	2x336.0&397.0 ACS
223	TL249 Whitney-Pliler	Diana-Lone Star South (TLN194:0249A)	138.00	138.00		0.00	0.00	0	336.4 ACSR
224	TL237 Knox Lee	Perdue (TLN194:00237)	138.00	138.00	2	12.87	3.00	1	1272.0 ACSR
225	TL237 Knox Lee	Perdue (TLN194:00237)	0.00	0.00		0.00	0.00	0	2x397.0 ACSR
226	TL237 Knox Lee	Perdue (TLN194:00237A)	138.00	138.00	1	2.76	0.00	1	1272.0 ACSR
227	TL237 Knox Lee	Perdue (TLN194:00237A)	0.00	0.00	2	22.08	0.00	0	2x397.0 ACSR
228	TL237 Knox Lee	Perdue (TLN194:00237A)	0.00	0.00		0.00	0.00	0	397.0 ACSR
229	TL242 Jefferson Switching S	Lieberman (TLN194:0242A)	138.00	138.00	2	19.80	0.00	1	336.4 ACSR
230	TL242 Jefferson Switching S	Lieberman (TLN194:0242A)	0.00	0.00		0.00	0.00	0	397.0 ACSR
231	TL242 Jefferson Switching S	Lieberman (TLN194:0242)	138.00	138.00	1	1.42	0.00	1	795.0 ACSR
232	TL278 Diana-Spring Hill	Lake Lamond (TLN194:00278)	138.00	138.00	1	22.98	0.00	1	1590.0 ACSR
233	TL240 Wilkes Plant	Jefferson Switching Station	138.00	138.00	2	11.10	0.00	1	1024.0 ACAR
234	TL239 Knox Lee	North Henderson	138.00	138.00	1	7.10	0.00	1	1272.0 ACSR
235	TL239 Knox Lee	North Henderson	138.00	138.00	2	10.78	0.00	0	2x397.0 ACSR
236	TL245 Knox Lee	South Shreveport (TLN194:00245)	138.00	138.00	1	2.69	0.00	1	666.0 ACSR
237	TL245 Knox Lee	South Shreveport (TLN194:00245)	138.00	138.00	2	10.01	0.00	0	795.0 ACSR
238	TL245 Knox Lee	South Shreveport (TLN194:00245)	138.00	138.00	1	2.21	0.00	0	795.0 ACSR
239	TL243 Knox Lee	South Texas Eastman (TLN194:0243D)	138.00	138.00	2	6.47	0.00	1	2x336.0 ACSR
240	TL243 Knox Lee	South Texas Eastman (TLN194:0243D)	138.00	138.00	2	0.97	0.00	1	2x795.0 ACSR
241	TL230 Logansport	Rock Hill (TX)	138.00	138.00	1	4.21	0.00	1	1272.0 ACSR
242	TL230 Logansport	Rock Hill (TX)	138.00	138.00	2	17.78	0.00	1	755.0 ACAR
243	TL409 HILL LAKE EXTENSION		138.00	138.00	1	0.25	0.00	2	1272.0 ACSR
244	TL220 Lone Star South	Pittsburg	138.00	138.00	1	17.67	0.00	1	1590.0 ACSR
245	TL248 Lone Star South	Wilkes Plant	138.00	138.00	1	0.12	0.00	1	2x666.0&795.0 ACS
246	TL248 Lone Star South	Wilkes Plant	138.00	138.00	2	10.87	0.00	0	2x795.0 ACSR
247	TL249 Whitney-Pliler	Diana-Lone Star South (TLN194:00249A)	138.00	138.00	1	3.23	0.00	1	1272.0 ACSR
248	TL249 Whitney-Pliler	Diana-Lone Star South (TLN194:00249C)	138.00	138.00	2	9.76	0.00	0	2x336.0&397.0 ACS
249	TL249 Whitney-Pliler	Diana-Lone Star South (TLN194:00249C)	138.00	138.00		0.00	0.00	0	2x397.0 ACSR
250	TL244 Longwood	Scottsville (TLN194:00244)	138.00	138.00	1	12.19	0.00	1	1590.0 ACSR
251	TL243 Marshall	Pirkey (TLN194:0243E)	138.00	138.00	2	6.53	2.00	1	2x1033.5 ACSR
252	TL198 North Mineola	Morton Tap (WCEC)	138.00	138.00	1	7.26	0.00	1	1272.0 ACSR
253	TL198 North Mineola	Morton Tap (WCEC)	138.00	138.00	1	7.26	0.00	2	1272.0&759 ACSR
254	TL236 North Mineola	Perdue	138.00	138.00	2	16.88	0.00	1	2x397.0 ACSR
255	TL236 North Mineola	Perdue	138.00	138.00	1	0.37	0.00	0	1272.0 ACSR
256	TL236 North Mineola	Perdue	138.00	138.00	1	2.13	0.00	0	2x397.0 ACSR
257	TL228 Bann	North New Boston	138.00	138.00	1	1.50	0.00	2	1272.0 ACSR
258	TL228 Bann	North New Boston	138.00	138.00	1	2.20	0.00	1	2x477.0 ACSR
259	TL228 Bann	North New Boston	138.00	138.00	1	14.80	0.00	1	477.0 ACSR
260	TL228 Bann	North New Boston	138.00	138.00	1	0.07	0.00	1	1272.0 ACSR
261	TL228 Bann	North New Boston	138.00	138.00	1	0.04	0.00	1	2156.0 ACSR
262	TL246 North New Boston	Patterson	138.00	138.00	2	5.41	0.00	1	666.0 ACSR
263	TL246 North New Boston	Wilkes	138.00	138.00	2	46.73	0.00	1	666.0 ACSR
264	TL246 North New Boston	Wilkes	138.00	138.00	2	0.15	0.00	1	795.0 ACSR
265	TL246 North New Boston	Wilkes	138.00	138.00	1	0.06	0.00	2	1272.0 ACSR
266	TL243 Eastex Switching	Whitney (TLN194:0243C)	138.00	138.00	1	3.27	0.00	1	2x336.0 ACSR
267	TL243 Eastex Switching	Whitney (TLN194:0243B)	138.00	138.00	2	0.83	0.00	0	2x795.0 ACSR
268	TL243 Eastex Switching	Whitney (TLN194:243A1)	138.00	138.00	2	0.83	0.00	0	2x795.0 ACSR
269	TL243 Eastex Switching	Whitney (TLN194:243A1)	138.00	138.00	1	0.30	0.00	0	2x795.0 ACSR
270	TL215 Turnertown-Overton-Po	Beckville-Marshall (TLN194:00215E)	138.00	138.00	1	7.22	0.00	1	2x397.0 ACSR
271	TL215 Turnertown-Overton-Po	Beckville-Marshall (TLN194:00215E)	138.00	138.00	2	5.96	0.00	1	2x397.0 ACSR
272	TL181 Northwest Texarkana	Patterson	138.00	138.00	1	0.19	0.00	1	1024.0 ACAR
273	TL181 Northwest Texarkana	Patterson	138.00	138.00	2	6.55	0.00	0	1272.0 SD
274	TL181 Northwest Texarkana	Patterson	138.00	138.00	3	0.90	0.00	0	2156.0 ACSR
275	TL235 Northwest Texarkana	Northeast Texarkana (Sugarhill)	138.00	138.00	1	10.34	0.00	1	1272.0 ACSR
276	TL218 Mt Pleasant-Pittsburg	Henderson Manufacturing Company (TLN194:0218B)	138.00	138.00	1	9.07	0.00	1	1272.0 ACSR
277	TL250 Wilkes Plant	Petty	138.00	138.00	1	0.06	0.00	1	1272 ACSR
278	TL250 Wilkes Plant	Petty	138.00	138.00	1	34.01	0.00	1	2-397 ACSR
279	TL244 Pirkey	Scottsville (TLN194:0244A)	138.00	138.00	1	0.09	0.00	1	1272.0 ACSR
280	TL244 Pirkey	Scottsville (TLN194:0244A)	138.00	138.00	2	17.21	0.00	1	2x397.0 ACSR
281	TL244 Pirkey	Scottsville (TLN194:0244A)	138.00	138.00	2	0.88	0.00	1	2x477.0 ACSR
282	TL243 Pirkey	Whitney (TLN194:0243F)	138.00	138.00	2	15.52	0.00	1	2x1033.5 ACSR
283	TL243 Pirkey	Whitney (TLN194:0243F)	138.00	138.00	2	0.08	0.00	1	2x1272 ACSR
284	TL245 Rock Hill	Southwest Shreveport	138.00	138.00	2	23.31	0.00	1	397.0 ACSR
285	TL247 Wilkes Plant	Jefferson Switching Station	138.00	138.00	1	1.15	0.00	1	1033 ACAR
286	TL247 Wilkes Plant	Jefferson Switching Station	138.00	138.00	1	0.16	0.00	1	1024.0 ACAR
287	TL247 Wilkes Plant	Jefferson Switching Station	0.00	0.00	2	31.68	0.00	0	666.0 ACSR
288	TL221 Carthage	Rock Hill	69.00	138.00	1	11.40	0.00	1	1533 ACSR/TW
289	TL227 Bann	Southeast Texarkana	138.00	138.00	1	11.34	0.00	1	1272.0 ACSR
290	TL277 Eastex	Harrison Road	138.00	138.00	1	9.57	0.00	1	1272.0 ACSR
291	TL243 Eastex Switching Stat	South Texas Eastman (TLN194:0243A2)	138.00	138.00	2	0.83	0.00	1	2x795.0 ACSR
292	TL286 Pittsburg	Winnsboro	138.00	138.00	1	20.32	1.00	1	1590 ACSR
293	TL295 Lake Pauline	Russell	138.00	138.00	2	14.22	0.00	1	477.0 ACSR
294	TL287 North Mineola	Winnsboro	138.00	138.00	1	25.05	0.00	2	1590 ACSR & 477 ACSR
295	TL287 North Mineola	Winnsboro	138.00	138.00	1	0.07	0.00	1	1590 ACSR
296	TL236 North Mineola	Perdue	138.00	138.00	1	0.36	0.00	1	1272.0 ACSR
297	TL236 North Mineola	Perdue	138.00	138.00	1	1.62	0.00	0	2x397.0 ACSR
298	TL236 North Mineola	Perdue	138.00	138.00	2	10.31	0.00	0	2x397.0 ACSR
299	TL294 Childress-Shamrock	Gray County Line	138.00	138.00	1	4.92	0.00	1	477.0 ACSR
300	TL294 Childress-Shamrock	Gray County Line	138.00	138.00	2	51.35	0.00	1	477.0 ACSR
301	TL300 Lake Pauline	West Childress	138.00	138.00	2	35.14	0.00	1	477.0 ACSR
302	TL384 Mount Pleasant	New Boston	69.00	138.00	1	19.50	0.00	1	1272 ACSR
303	TL392 West Mount Pleasant T		69.00	138.00	1	0.70	0.00	1	1272.0 ACSR
304	TL410 Naples Tap		69.00	138.00	1	6.40	0.00	1	1272.0 ACSR
305	TL411 Cookville Tap		69.00	138.00	1	1.93	0.00	1	1272.0 ACSR
306	115 kV in AR		0.00	0.00		0.00	0.00	0
307	TL171 Okay	AP&L Co Interconnect (TLN194:0171A)	115.00	115.00	2	0.01	0.00	1	1272.0 AAC
308	TL171 Okay	AP&L Co Interconnect (TLN194:0171)	115.00	138.00	1	15.50	0.00	1	1591 ACSR
309	TL326 Okay	Patterson	115.00	138.00	1	19.31	0.00	1	1590 ACSR
310	TL326 Okay	Patterson	115.00	138.00	1	0.35	0.00	2	1590 ACSR
311	TL171 Okay	AP&L Co Interconnect (TLN194:0171A)	115.00	115.00	2	7.10	0.00	1	1272.0 ACSR
312	115 kV in LA	115 kV in LA	0.00	0.00		0.00	0.00	0
313	TL357 Interconnect	Jeld-Wen	115.00	115.00		0.64	0.00	1	336.4 kCM ACSR
314	115 kV in TX	115 kV in TX	0.00	0.00		0.00	0.00	0
315	TL296 Shamrock	Gray County Line	115.00	115.00	1	14.24	0.00	1	4/0 ACSR
316	69 kV in AR	69 kV in AR	0.00	0.00		0.00	0.00	0
317	TL158 Texarkana Plant-Washi	12th St-Patterson/tap-Co-Oper Tire (TLN194:158A1)	69.00	69.00	1	0.81	0.00	1	2x397.0 ACSR
318	TL158 Texarkana Plant-Washi	12th St-Patterson/tap-Co-Oper Tire (TLN194:158A1)	69.00	69.00	1	0.25	0.00	2	1590 ACSR
319	TL158 Texarkana Plant-Washi	12th St-Patterson/tap-Co-Oper Tire (TLN194:158A1)	69.00	69.00	1	0.30	0.00	1	1272 ACSR
320	TL158 Texarkana Plant-Washi	12th St-Patterson/tap-Co-Oper Tire (TLN194:158A1)	69.00	69.00	1	0.02	0.00	1	1590 ACSR
321	TL158 Texarkana Plant-Washi	12th St-Patterson/tap-Co-Oper Tire (TLN194:158A)	69.00	69.00	1	1.73	0.00	1	1272.0 ACSR
322	TL158 Texarkana Plant-Washi	12th St-Patterson/tap-Co-Oper Tire (TLN194:158A)	69.00	69.00	1	0.07	0.00	1	795 ACSR
323	TL158 Texarkana Plant-Washi	12th St-Patterson/tap-Co-Oper Tire (TLN194:158A)	69.00	69.00	1	12.50	0.00	1	2x397.0 ACSR
324	TL158 Texarkana Plant-Washi	12th St-Patterson/tap-Co-Oper Tire (TLN194:158A)	69.00	69.00	3	0.65	0.00	1	2x397.0 ACSR
325	TL158 Texarkana Plant-Washi	12th St-Patterson/tap-Co-Oper Tire (TLN194:158A)	69.00	69.00	2	5.25	0.00	1	2x397.0 ACSR
326	TL158 Texarkana Plant-Washi	12th St-Patterson/tap-Co-Oper Tire (TLN194:158D)	69.00	69.00		0.00	0.00	0	1272.0 ACSR
327	TL151 Dixie Tee	Belcher-Texarkana Plant (TLN194:0151C)	69.00	69.00	2	0.25	0.00	1	397.0 ACSR
328	TL165 Southeast Texarkana	Texarkana Plant	69.00	69.00	1	0.24	0.00	1	1272.0 ACSR
329	TL213 Texarkana Plant - Ban	De Kalb - Mt Pleasant/taps (TLN194:0213K)	69.00	69.00	1	0.53	0.00	1	1272.0 ACSR
330	TL151 Dixie Tee	Belcher-Texarkana Plant (TLN194:0151A)	69.00	69.00	1	0.50	0.00	1	266.8 ACSR
331	TL151 Dixie Tee	Belcher-Texarkana Plant (TLN194:0151A)	69.00	69.00	2	8.45	0.00	0
332	TL151 Dixie Tee	Belcher-Texarkana Plant (TLN194:0151)	69.00	69.00	1	1.33	0.00	1	266.8 ACSR
333	TL151 Dixie Tee	Belcher-Texarkana Plant (TLN194:0151)	69.00	69.00	2	18.49	0.00	1	4/0 ACSR
334	TL151 Dixie Tee	Belcher-Texarkana Plant (TLN194:0151B)	69.00	69.00	1	0.05	0.00	1	266.8 ACSR
335	TL151 Dixie Tee	Belcher-Texarkana Plant (TLN194:0151D)	69.00	69.00	1	0.52	0.00	1	266.8 ACSR
336	TL162 Midland-Huntington-RE	Booneville-Branch/Tap-Magazine-North Magazine (TLN194:0162A)	69.00	69.00	1	2.64	0.00	1	4/0 ACSR
337	TL152 Mena-DeQueen-Nashvill	Narrows Dame/Tap-Murfreesboro (TLN194:00152)	69.00	69.00	1	5.63	0.00	1	795.0 ACSR
338	TL152 Mena-DeQueen-Nashvill	Narrows Dame/Tap-Murfreesboro (TLN194:00152)	69.00	69.00	2	34.52	0.00	1	795 ACSR
339	TL152 Mena-DeQueen-Nashvill	Narrows Dame/Tap-Murfreesboro (TLN194:00152)	69.00	69.00	2	1.80	0.00	2	795 ACSR
340	TL152 Mena-DeQueen-Nashvill	Narrows Dame/Tap-Murfreesboro (TLN194:00152A)	69.00	69.00	1	0.04	0.00	1	4/0 ACSR
341	TL152 Mena-DeQueen-Nashvill	Narrows Dame/Tap-Murfreesboro (TLN194:00152A)	69.00	69.00	2	28.75	0.00	0
342	TL155 Patterson-Foreman	DeQueen/Tap-Magnolia Pump Station (TLN194:00155)	69.00	69.00	1	1.56	0.00	1	2/0 ACSR
343	TL155 Patterson-Foreman	DeQueen/Tap-Magnolia Pump Station (TLN194:00155)	69.00	69.00	2	37.38	0.00	1	4/0 ACSR
344	TL155 Patterson-Foreman	DeQueen/Tap-Magnolia Pump Station (TLN194:00155)	69.00	69.00	1	0.13	0.00	1	795 ACSR
345	TL167 Mena-Murfreesboro	Dierks (TLN194:0167C)	69.00	69.00	1	2.50	0.00	1	397.0 ACSR
346	TL167 Mena-Murfreesboro	Dierks (TLN194:00167)	69.00	69.00	2	30.50	0.00	1	477.0 ACSR
347	TL167 Mena-Murfreesboro	Dierks (TLN194:00167)	69.00	69.00	1	7.70	0.00	1	477.0 ACSR
348	TL160 Dierks	South Dierks	69.00	69.00	1	1.25	0.00	1	397.0 ACSR
349	TL160 Dierks	South Dierks	69.00	69.00	2	0.61	0.00	1	397.0 ACSR
350	TL167 Mena-Murfreesboro	Dierks (TLN194:0167B)	69.00	69.00	1	18.77	0.00	1	266.8 ACSR
351	TL154 VBI-Rogers/Loop Thru	SEFOR Project (TLN194:0154B)	69.00	69.00	1	3.07	0.00	1	336.4 ACSR
352	TL154 VBI-Rogers/Loop Thru	SEFOR Project (TLN194:0154B)	69.00	69.00	1	2.46	0.00	1	666.0 ACSR
353	TL154 VBI-Rogers/Loop Thru	SEFOR Project (TLN194:0154D)	69.00	69.00	2	1.99	0.00	1	2x397.0 ACSR
354	TL161 Centerton	Rogers (TLN194:0161A)	69.00	69.00	1	9.90	0.00	1	1272.0 AAC
355	TL169 East Rogers	North Rogers	69.00	69.00	1	1.95	0.00	1	2x397.0 ACSR
356	TL164 Siloam Springs - Prai	Greenland (TLN194:00164)	69.00	69.00	2	8.04	0.00	1	477.0 ACSR
357	TL164 Siloam Springs - Prai	Greenland (TLN194:00164)	69.00	69.00	2	0.52	0.00	2	477.0 ACSR & 336.4 ACSR
358	TL154 VBI-Rogers/Loop Thru	SEFOR Project (TLN194:0154F)	69.00	69.00	1	0.22	0.00	1	336.4 ACSR
359	TL154 VBI-Rogers/Loop Thru	SEFOR Project (TLN194:0154F)	69.00	69.00	2	3.72	0.00	1	336.4 ACSR
360	TL154 VBI-Rogers/Loop Thru	SEFOR Project (TLN194:0154H)	69.00	69.00	2	2.50	0.00	1	1272 ACSR
361	TL156 PSO-Midland	State Line (TLN194:00156)	69.00	69.00	1	9.44	0.00	1	2/0 ACSR
362	TL369 Midland	North Huntington (TLN194:00369)	69.00	161.00	2	4.76	0.00	0	1233.6 ACSR
363	TL152 Mena - Dequeen - Nash	Murfreesboro (TLN194:0152B)	69.00	69.00	1	2.04	0.00	1	2/0 ACSR
364	TL152 Mena - Dequeen - Nash	Murfreesboro (TLN194:0152D)	69.00	69.00	2	10.73	0.00	0	4/0 ACSR
365	TL168 Radial Patterson	Nekoosa - Edwards	69.00	138.00	1	5.09	0.00	1	1272.0 ACSR
366	TL370 Midland	Leflore County (State Line) (TLN194:00370)	69.00	161.00	2	7.00	0.00	1	4/0 ACSR
367	TL213 Texarkana Plant - Ban	De Kalb - Mt Pleasant/taps (TLN194:0213M)	69.00	69.00	1	0.34	0.00	1	1272.0 ACSR
368	TL158 Texarkana Plant - Was	12th St - Patterson/tap - Co-Oper Tire (TLN194:0158E)	69.00	69.00	1	2.80	0.00	1	2x336.0 ACSR
369	TL158 Texarkana Plant - Was	12th St - Patterson/tap - Co-Oper Tire (TLN194:0158B)	69.00	69.00	1	0.32	0.00	1	4/0 ACSR
370	TL152 Mena - Dequeen - Nash	Narrows Dam/Tap - Murfreesboro (TLN194:0152C)	69.00	69.00	1	2.83	0.00	1	4/0 ACSR
371	TL152 Mena - Dequeen - Nash	Narrows Dam/Tap - Murfreesboro (TLN194:0152C)	69.00	69.00	2	3.87	0.00	1	4/0 ACSR
372	TL389 Greenland	VBI	69.00	161.00	1	0.04	0.00	1	1272 ACSR
373	TL153 Nashville	Okay	69.00	69.00	2	13.76	0.00	1	559.0 ACAR
374	TL153 Nashville	Okay	69.00	69.00	1	0.37	0.00	1	559.0 ACAR
375	TL388 North Huntington	Waldron	69.00	161.00	1	18.53	0.00	1	795 ACSR
376	TL164 Siloam Springs	Prairie Grove - Greenland (TLN194:0164A)	69.00	69.00	1	1.19	0.00	1	477.0 ACSR
377	TL164 Siloam Springs	Prairie Grove - Greenland (TLN194:0164A)	69.00	69.00	2	19.37	0.00	1	477.0 ACSR
378	TL142 Abbott Tee	Waldron	69.00	69.00	1	14.21	0.00	1	477.0 ACSR
379	69 kV in LA	69 kV in LA	0.00	0.00		0.00	0.00	0
380	TL114 Shreveport 69KV Loop	(TLN194:00114)	69.00	69.00	1	1.77	0.00	1	2x397.0 ACSR
381	TL408 Broadmoor	Fort Humbug	69.00	138.00	1	1.36	1.00	1	1233.6 ACSR/TW
382	TL114 Shreveport 69KV Loop	(TLN194:0114A)	69.00	69.00	1	2.20	0.00	1	1272.0 ACSR
383	TL114 Shreveport 69KV Loop	(TLN194:0114B)	69.00	138.00	1	2.55	0.00	1	1272.0 ACSR
384	TL115 Bossier City (AH - Ft Humbug) 69KV Loop	(TLN194:00115)	69.00	69.00	4	0.60	0.00	1	2500.0 CU
385	TL115 Bossier City (AH - Ft Humbug) 69KV Loop	(TLN194:00115)	69.00	69.00	1	0.50	0.00	1	1272.0 ACSR
386	TL115 Bossier City (AH - Ft Humbug) 69KV Loop	(TLN194:00115)	69.00	69.00	1	1.50	0.00	1	2x397.5 ACSR
387	TL111 Dixie Tee (Disconnect	Texarkana Plant (TLN194:0111A)	69.00	69.00	2	12.00	0.00	1	266.8 ACSR
388	TL114 Shreveport 69KV Loop	(TLN194:0114D)	69.00	69.00	1	0.00	0.00	2	795 ACSR
389	TL114 Shreveport 69KV Loop	(TLN194:0114D)	69.00	69.00	1	0.33	0.00	1	666.6 ACSR
390	TL114 Shreveport 69KV Loop	(TLN194:0114D)	69.00	69.00	1	0.00	0.00	2	666.6 ACSR
391	TL114 Shreveport 69KV Loop	(TLN194:0114J)	69.00	69.00	1	0.26	0.00	1	666.6 ACSR
392	TL376 Brooks Street	Edwards Street	69.00	138.00	1	0.85	0.00	1	1233.6 ACSR/TW
393	TL116 North Market-Brownlee	Minden Road (TLN194:00116)	69.00	69.00	1	4.37	0.00	1	666.6 ACSR
394	TL405 Brownlee Road	North Market	69.00	138.00	1	0.21	0.00	2	1233.6 ACSR
395	TL405 Brownlee Road	North Market	69.00	138.00	1	4.49	0.00	1	1233.6 ACSR
396	TL114 Shreveport 69KV Loop	(TLN194:0114F)	69.00	69.00	1	0.89	1.00	1	666.0 ACSR
397	TL114 Shreveport 69KV Loop	(TLN194:0114G)	69.00	69.00	1	1.81	0.00	1	2x397.5 ACSR
398	TL114 Shreveport 69KV Loop	(TLN194:0114G)	69.00	69.00	1	0.56	0.00	2	666.6 ACSR
399	TL114 Shreveport 69KV Loop	(TLN194:0114H)	69.00	138.00	1	3.02	0.00	1	1233.6 ACSR
400	TL114 Shreveport 69KV Loop	(TLN194:0114K)	69.00	69.00	1	0.15	0.00	1	666.6 ACSR
401	TL125 Flournoy-Pines Road	Hardy St	69.00	69.00	1	5.29	0.00	1	397.5 ACSR
402	TL125 Flournoy-Pines Road	Hardy St	69.00	69.00	2	0.40	0.00	1	397.5 ACSR
403	TL120 Summer Grove-Flournoy	REA & Bingham Pump Plant (TLN194:0120A)	69.00	69.00	1	6.70	0.00	1	397.0 ACSR
404	TL120 Summer Grove-Flournoy	REA & Bingham Pump Plant (TLN194:0120A)	69.00	69.00	1	2.55	0.00	1	477.0 ACSR
405	TL120 Summer Grove-Flournoy	REA & Bingham Pump Plant (TLN194:0120B)	69.00	69.00	1	9.47	0.00	1	4/0 ACSR
406	TL114 Shreveport 69KV Loop	(TLN194:0114L)	69.00	69.00	1	1.17	0.00	1	666.0 ACSR
407	TL114 Shreveport 69KV Loop	(TLN194:0114M)	69.00	138.00	1	1.64	0.00	1	1233.6 ACSR
408	TL102 Hosston - Plain Deali	North Benton	69.00	69.00	1	0.99	0.00	1	477 ACSR
409	TL102 Hosston - Plain Deali	North Benton	69.00	69.00	1	26.63	0.00	1	397.0 ACSR
410	TL111 Dixie Tee (Disconnect	Texarkana Plant (TLN194:00111)	69.00	69.00	2	9.72	0.00	1	266.8 ACSR
411	TL117 Leiberman - Superior	Vivian - Hosston	69.00	69.00	1	6.65	0.00	1	336.4 ACSR
412	TL117 Leiberman - Superior	Vivian - Hosston	69.00	69.00	1	3.80	0.00	1	4/0 ACSR
413	TL113 Gilliam	Marshall (TLN194:0113B)	69.00	69.00	2	3.57	0.00	1	266.8 ACSR
414	TL113 Gilliam	Marshall (TLN194:0113B)	69.00	69.00	2	6.60	0.00	1	4/0 ACSR
415	TL108 Logansport	Stanley Tap	69.00	69.00	1	7.00	0.00	1	2/0 ACSR
416	TL108 Logansport	Stanley Tap	69.00	69.00	1	2.67	0.00	1	1/0 ACSR
417	TL118 Ellerbe Road - Finney	Wallace lake (TLN194:0118B)	69.00	69.00	1	5.18	0.00	1	397.5 ACSR
418	TL358 Marthaville	Robeline	69.00	69.00	1	8.26	0.00	1	336.4 ACSR
419	TL112 Center-Powell Street-	Panola Harrsion Rural Electric Association (TLN194:0112B)	69.00	69.00	1	3.88	0.00	1	666.0 ACSR
420	TL112 Center-Powell Street-	Panola Harrsion Rural Electric Association (TLN194:0112B)	69.00	69.00	1	0.54	0.00	1	795 ACSR
421	TL115 Bossier City (AH-Ft H	(TLN194:0115A)	69.00	69.00	1	1.70	0.00	1	2x397.0 ACSR
422	TL104 Red Point-Dogwood-Bel	Bellevue Oilfield (TLN194:00104)	69.00	69.00	1	8.80	0.00	1	4/0 ACSR
423	TL104 Red Point-Dogwood-Bel	Bellevue Oilfield (TLN194:0104A)	69.00	69.00	1	3.41	0.00	1	4/0 ACSR
424	TL104 Red Point-Dogwood-Bel	Bellevue Oilfield (TLN194:0104B)	69.00	69.00	2	2.17	0.00	1	4/0 ACSR
425	TL124 Red Point-Calumet-JD	Texaco Oil-Getty Oil (TLN194:00124)	69.00	69.00	1	4.29	0.00	1	266.8 ACSR
426	TL124 Red Point-Calumet-JD	Texaco Oil-Getty Oil (TLN194:0124A)	69.00	69.00	1	4.78	0.00	1	266.8 ACSR
427	TL124 Red Point-Calumet-JD	Texaco Oil-Getty Oil (TLN194:0124B)	69.00	69.00	1	0.37	0.00	1	2/0 ACSR
428	TL121 Leiberman-Blanchard	North Market (TLN194:00121)	69.00	69.00	1	6.23	0.00	1	666.6 ACSR
429	TL121 Leiberman-Blanchard	North Market (TLN194:00121)	69.00	69.00	2	0.60	0.00	1	666.6 ACSR
430	TL121 Leiberman-Blanchard	North Market (TLN194:00121)	69.00	69.00	3	0.07	0.00	1	666.6 ACSR
431	TL121 Leiberman-Blanchard	North Market (TLN194:0121A)	69.00	69.00	1	11.75	0.00	1	477.0 ACSR
432	TL121 Leiberman-Blanchard	North Market (TLN194:0121A)	69.00	69.00	1	1.06	0.00	1	959.6 ACSR
433	TL349 Many	Belmont	69.00	69.00	1	3.80	0.00	1	795 kCM ACSR
434	TL349 Many	Belmont	69.00	69.00	2	6.66	0.00	2	795 kCM ACSR
435	TL351 Noble	Mount Zion	69.00	69.00	1	11.25	0.00	1	795 kCM ACSR
436	TL351 Noble	Mount Zion	69.00	69.00	2	0.87	0.00	1	795 kCM ACSR
437	TL350 Many	Negreet	69.00	69.00	2	3.97	0.00	1	795 kCM ACSR
438	TL350 Many	Negreet	69.00	69.00	1	8.66	0.00	1	795 kCM ACSR
439	TL352 Hornbeck	N Leesville	69.00	69.00	1	13.00	0.00	1	336.4 kCM ACSR
440	TL353 Belmont	Marthaville	69.00	69.00	2	1.84	0.00	1	336.4 kCM ACSR
441	TL348 E Leesville	N Leesville	69.00	69.00	1	3.20	0.00	1	336.4 kCM ACSR
442	TL347 E Leesville	Hicks	69.00	69.00	1	16.38	0.00	1	336.4 kCM ACSR
443	TL355 Montgomery	Verda	13.80	69.00	1	3.20	0.00	1	336.4 kCM ACSR
444	TL354 Bayou-Pierre	Kingston	69.00	69.00	1	13.60	0.00	1	336.4 ACSR
445	TL377 Leaside Way	Summer Grove	69.00	69.00	1	1.68	0.00	1	477.0 ACSR
446	69 kV in TX	69 kV in TX	0.00	0.00		0.00	0.00	0
447	TL203 Bloomburg	Atlanta	69.00	69.00	2	6.75	0.00	1	397.0 ACSR
448	TL203 Bloomburg	Atlanta	69.00	69.00	1	1.00	0.00	1	397.0 ACSR
449	TL201 Atlanta	Hughes Springs (TLN194:00201)	69.00	69.00	1	1.50	0.00	1	397.0 ACSR
450	TL201 Atlanta	Hughes Springs (TLN194:00201)	69.00	69.00	2	12.00	0.00	1	397.0 ACSR
451	TL213 Texarkana Plant	Bann-De Kalb-Mt Pleasant (TLN194:00213)	69.00	69.00	1	8.50	0.00	1	397.0 ACSR
452	TL213 Texarkana Plant	Bann-De Kalb-Mt Pleasant (TLN194:0213H)	69.00	69.00	1	0.37	0.00	1	477 ACSR
453	TL213 Texarkana Plant	Bann-De Kalb-Mt Pleasant (TLN194:00213)	69.00	69.00	1	7.14	0.00	1	1272 ACSR
454	TL213 Texarkana Plant	Bann-De Kalb-Mt Pleasant (TLN194:0213E)	69.00	69.00	1	1.07	0.00	1	2/0 ACSR
455	TL223 Taylor Street	Bann	69.00	69.00	1	9.50	0.00	1	666.0 ACSR
456	TL387 Bann	Thirty Ninth Street	69.00	138.00	1	8.86	0.00	1	1272.0 ACSR
457	TL202 Beckville - Cathage	Center (TLN194:00202)	69.00	69.00	2	6.60	0.00	1	397.0 ACSR
458	TL215 Turnertown-Overton-Poynter	Beckville-Marshall (215)	69.00	69.00	2	16.62	0.00	1	4/0 ACSR
459	TL215 Turnertown-Overton-Poynter	Beckville-Marshall (215)	69.00	69.00	1	6.08	0.00	1	4/0 ACSR
460	TL215 Turnertown-Overton-Poynter	Beckville-Marshall (215)	69.00	69.00	1	0.03	0.00	1	397.0 ACSR
461	TL215 Turnertown-Overton-Poynter	Beckville-Marshall (215A)	69.00	69.00	2	4.10	0.00	1	666.0 ACSR
462	TL232 Bloomburg	Texarkana Tap - IPC	69.00	69.00	1	1.85	0.00	1	266.8 ACSR
463	TL151 Dixie Tee	Belcher-Texarkana Plant (TLN194:0151D)	69.00	69.00	1	1.81	0.00	1	266.8 ACSR
464	TL202 Beckville - Cathage	Center (TLN194:0202A)	69.00	69.00	2	1.55	0.00	1	397.0 ACSR
465	TL202 Beckville - Cathage	Center (TLN194:0202A)	69.00	69.00	1	0.80	0.00	1	397.0 ACSR
466	TL202 Beckville - Cathage	Center (TLN194:0202B)	69.00	69.00	1	2.58	0.00	1	397.0 ACSR
467	66-027 Clarksville	Greggton w/taps to MidVally	69.00	69.00	1	8.49	0.00	1	2/0 ACSR
468	66-027 Clarksville	& Texoma	0.00	0.00		0.00	0.00	0	755.0 ACAR
469	66-028 Clarksville	Sabine w/tap to Service	69.00	69.00	1	1.85	0.00	1	2/0 ACSR
470	66-028 Clarksville	Pipeline	0.00	0.00	2	7.11	0.00	0	397.0 ACSR
471	66-029 Clarksville	Perdue	69.00	69.00	1	7.29	0.00	1	477.0 ACSR
472	66-030 Clarksville	Perdue	69.00	69.00	1	6.32	0.00	1	2x397.0 ACSR
473	66-030 Clarksville	Perdue	0.00	0.00	2	0.65	0.00	0
474	TL290 Daingerfield	Hughes Springs	69.00	69.00	1	6.08	0.00	1	1272 ACSR
475	TL209 Daingerfield	Mount Pleasant	69.00	69.00	1	1.44	0.00	1	397.0 ACSR
476	TL209 Daingerfield	Mount Pleasant	0.00	0.00	2	1.30	0.00	1	1272 ACSR
477	TL209 Daingerfield	Mount Pleasant	0.00	0.00	2	14.25	0.00	1	397.0 ACSR
478	TL373 Evenside	Northwest Henderson	69.00	138.00	1	6.40	0.00	1	1272 ACSR
479	66-049 Evenside	Poynter	69.00	69.00	1	3.66	0.00	1	477.0 ACSR
480	66-050 Evenside	Sawmill w/taps to Sohio	69.00	69.00	1	14.89	0.00	1	2/0 ACSR
481	66-050 Evenside	Pump & North Laneville	0.00	0.00		0.00	0.00	0	266.8 ACSR
482	66-056 Flournoy	Woodlawn w/taps to Karnack	69.00	69.00	1	33.22	0.00	1	# 2 CU (7 Strand)
483	TL208 Gladewater - Greggton - Lake Lamond	Longview Heights - Marshall (TLN194:0208E)	0.00	0.00	1	2.87	0.00	1	2/0 ACSR
484	TL208 Gladewater - Greggton - Lake Lamond	Longview Heights - Marshall (TLN194:0208E)	0.00	0.00		0.00	0.00	0	336.4 ACSR
485	TL208 Gladewater - Greggton - Lake Lamond	Longview Heights - Marshall (TLN194:0208E)	0.00	0.00		0.00	0.00	0	4/0 ACSR
486	66-057 Gilmer	Perdue	69.00	69.00	1	11.44	0.00	1	397.0 ACSR
487	66-058 Gilmer	Pittsburg w/tap to	69.00	69.00	1	24.47	0.00	1	2/0 ACSR
488	66-058 Gilmer	Pittsburg Steel	0.00	0.00		0.00	0.00	0	336.4 ACSR
489	66-059 Grand Saline	Mineola	69.00	69.00	1	6.81	7.00	1	4/0 ACSR
490	TL214 Mineola - Grand Salin	Westwood - Quitman	69.00	69.00	1	20.16	0.00	1	336.4 ACSR
491	TL214 Mineola - Grand Salin	Westwood - Quitman	69.00	69.00	1	0.05	0.00	1	556 ACSR
492	TL214 Mineola - Grand Salin	Westwood - Quitman	69.00	69.00	1	0.35	0.00	1	397.0 ACSR
493	TL214 Mineola - Grand Salin	Westwood - Quitman	69.00	69.00	1	4.10	0.00	0	795.0 ACSR
494	66-064 Greggton	Lake Lamond	69.00	69.00	1	2.66	0.00	1	1272 ACSR
495	66-068 Hawkins	Mineola	69.00	69.00	1	1.24	0.00	1	477.0 ACSR
496	66-068 Hawkins	Mineola	0.00	0.00	2	17.42	0.00	1	477.0 ACSR
497	TL211 Mineola	Gladewater/tap - Pump Stati	69.00	69.00	1	0.24	0.00	1	477.0 ACSR
498	66-069 Hawkins	Perdue	69.00	69.00	1	10.90	0.00	1	477.0 ACSR
499	66-073 Hughes Springs	Linden	69.00	69.00	1	0.25	0.00	1	397.0 ACSR
500	66-073 Hughes Springs	Linden	0.00	0.00	2	15.45	0.00	0
501	TL216 Hughes Springs	Lone Star Steel (TLN194:00216)	69.00	69.00	1	0.12	0.00	1	1272 ACSR
502	TL216 Hughes Springs	Lone Star Steel (TLN194:0216A)	69.00	69.00	1	8.23	0.00	1	1272 ACSR
503	TL216 Hughes Springs	Lone Star Steel (TLN194:0216B)	69.00	69.00	1	6.88	0.00	1	1272 ACSR
504	TL216 Hughes Springs	Lone Star Steel (TLN194:0216C)	69.00	69.00	1	1.04	1.00	1	397.5 ACSR
505	TL216 Hughes Springs	Lone Star Steel (TLN194:0216C)	69.00	69.00	1	0.80	1.00	2	1590&337 ACSR
506	TL216 Hughes Springs	Lone Star Steel (TLN194:0216D)	69.00	69.00	1	2.21	0.00	1	1272 ACSR
507	TL205 Gilliam - Marshall With Tap	Karnack Plant (TLN194:0205A)	69.00	69.00	1	12.75	0.00	1	1272 ACSR
508	TL205 Gilliam - Marshall With Tap	Karnack Plant (TLN194:0205B)	69.00	69.00	1	0.03	0.00	1	795 ACSR
509	TL205 Gilliam - Marshall With Tap	Karnack Plant (TLN194:0205B)	69.00	69.00	2	18.27	0.00	1	267 ACSR
510	66-077 Kilgore	Overton	69.00	69.00	1	4.72	0.00	1	336.4 ACSR
511	66-077 Kilgore	Overton	0.00	0.00	2	7.70	0.00	0	477.0 ACSR
512	66-078 Kilgore	Sabine	69.00	69.00	1	3.49	1.00	1	4/0 ACSR
513	66-078 Kilgore	Sabine	0.00	0.00	2	2.12	0.00	0
514	TL210 Longview - Whitney	Kilgore - Overton (TLN194:0210A)	69.00	69.00	1	8.94	1.00	1	336.4 ACSR
515	TL210 Longview - Whitney	Kilgore - Overton (TLN194:0210A)	69.00	69.00	2	7.40	0.00	1	336.4 ACSR
516	66-080 Knox Lee	Southeast Longview	69.00	69.00	1	5.87	0.00	1	2x477.0 ACSR
517	66-080 Knox Lee	Southeast Longview	0.00	0.00		0.00	0.00	0	2x795.0 ACSR
518	66-081 Lake Lamond	Longview	69.00	69.00	1	3.14	0.00	1	755.0 ACAR
519	66-082 Lake Lamond	Southeast Longview w/tap to	69.00	69.00	1	8.66	0.00	1	2x336.0&397.0 ACS
520	66-082 Lake Lamond	Big Three	0.00	0.00		0.00	0.00	0	397.0 ACSR
521	66-083 Lake Lamond	Longview Heights	69.00	69.00	1	7.16	3.00	1	477.0 ACSR
522	66-083 Lake Lamond	Longview Heights	0.00	0.00		0.00	0.00	0	795.0 ACSR
523	Plant	Plant	0.00	0.00		0.00	0.00	0
524	66-088 Longview	Whitney	69.00	69.00	1	2.59	0.00	1	2x336.0 ACSR
525	66-088 Longview	Whitney	0.00	0.00		0.00	0.00	0	2x397.0 ACSR
526	TL208 Longview Heights	Whitney	69.00	69.00	1	4.18	0.00	1	666.0 ACSR
527	TL208 Longview Heights	Marshall 69	69.00	138.00	1	0.04	0.00	1	1590 ACSR
528	TL371 Longview Heights	Hallsville	69.00	138.00	1	6.54	0.00	1	954 ACSR
529	TL372 Hallsville	Marshall	69.00	138.00	1	11.15	0.00	1	954 ACSR
530	TL118A (Radial) Finney Tap		69.00	69.00	1	0.40	0.00	1	2/0 ACSR
531	66-094 Marshall	North Marshall	69.00	69.00	2	3.49	0.00	1	1272.0 ACSR
532	TL215 Turnertown-Overton-Poynter	Beckville-Marshall (TLN194:0215C)	69.00	69.00	1	15.50	0.00	1	1272.0 ACSR
533	TL215 Turnertown-Overton-Poynter	Beckville-Marshall (TLN194:0215C)	69.00	69.00	2	0.50	0.00	1	1272.0 ACSR
534	TL215 Turnertown-Overton-Poynter	Beckville-Marshall (TLN194:0215C)	69.00	69.00	1	0.32	0.00	2	1272.0 ACSR & 2x397 ACSR
535	TL212 Mineola	North Mineola	69.00	69.00	1	0.74	1.00	1	477.0 ACSR
536	TL212 Mineola	North Mineola	0.00	0.00	2	0.69	0.00	0
537	TL384 Mount Pleasant	New Boston	69.00	138.00	1	33.30	0.00	1	1272.0 ACSR
538	TL384 Mount Pleasant	New Boston	69.00	138.00	1	13.50	0.00	1	1233.6 ACSR/TW
539	TL213 Texarkana Plant	Bann-De Kalb-Mt Pleasant (TLN194:0213G)	69.00	69.00	1	1.30	0.00	1	666.0 ACSR
540	TL212 Mt Pleasant - Mineola	Magnolia Pump Station, Mt Vernon, & Petty (TLN194:0212G)	69.00	69.00	1	1.55	0.00	1	1272.0 AAC
541	TL390 Pilgrims Pride	Winfield	69.00	138.00	1	8.07	0.00	1	1272.0 ACSR
542	TL219 Southeast Longview	Whitney w/tap to Letoureau	69.00	69.00	1	4.35	0.00	1	1024.0 ACAR
543	TL219 Southeast Longview	Whitney w/tap to Letoureau	0.00	0.00		0.00	0.00	0	2/0 ACSR
544	TL219 Southeast Longview	Whitney w/tap to Letoureau	0.00	0.00		0.00	0.00	0	2x795.0 ACSR
545	TL213 Texarkana Plant	Bann-De Kalb-Mt Pleasant (TLN194:0213M)	69.00	69.00	1	2.70	0.00	1	1272.0 ACSR
546	TL213 Texarkana Plant	Bann-De Kalb-Mt Pleasant (TLN194:0213N)	69.00	69.00	1	2.40	0.00	1	2x397.0 ACSR
547	TL213 Texarkana Plant	Bann-De Kalb-Mt Pleasant (TLN194:0213K)	69.00	69.00	1	0.54	0.00	1	1272 ACSR
548	66-128 Winfield	Winnsboro w/taps to Mount	69.00	69.00	1	18.69	3.00	1	2/0 ACSR
549	66-128 Winfield	Vernon & Texoma	0.00	0.00	2	12.90	0.00	0	336.4 ACSR
550	66-128 Winfield	Vernon & Texoma	0.00	0.00		0.00	0.00	0	477.0 ACSR
551	66-203 Mount Pleasant	Petty	69.00	69.00	1	2.06	0.00	1	755.0 ACAR
552	TL378 Mount Pleasant	West Mount Pleasant	69.00	138.00	1	3.04	0.00	1	1533.3 ACSR
553	TL212 Mt Pleasant - Mineola/Taps	Magnolia Pump Station, Mt Vernon, & Petty (TLN194:0212F)	69.00	69.00		0.20	0.00	1	477 ACSR
554	TL212 Mt Pleasant - Mineola/Taps	Magnolia Pump Station, Mt Vernon, & Petty (TLN194:0212F)	69.00	69.00		0.60	0.00	1	556 ACSR
555	TL215 Turnertown-Overton-Poynter	Beckville-Marshall (TLN194:0215D)	69.00	138.00	1	2.72	0.00	1	1272 ACSR
556	TL215 Turnertown-Overton-Poynter	Beckville-Marshall (TLN194:0215D)	69.00	138.00	1	0.63	0.00	2	1272 ACSR
557	TL215 Turnertown-Overton-Poynter	Beckville-Marshall (TLN194:0215F)	69.00	69.00	1	6.02	0.00	1	2/0 ACSR
558	TL215 Turnertown-Overton-Poynter	Beckville-Marshall (TLN194:0215F)	69.00	69.00	1	0.00	2.00	1	2/0 ACSR
559	66-217 Pittsburg	Winnsboro w/tap to Ferndale	69.00	69.00	1	23.17	1.00	1	266.8 ACSR
560	66-217 Pittsburg	Lake	0.00	0.00		0.00	0.00	0	477.0 ACSR
561	TL212 Mt Pleasant - Mineola/Taps	Magnolia Pump Station, Mt Vernon, & Petty (TLN194:0212J)	69.00	69.00	1	0.55	0.00	1	477.0 ACSR
562	66-330 Carthage	Murvaul REC	69.00	69.00	1	2.62	1.00	1	336.4 ACSR
563	66-330 Carthage	Murvaul REC	0.00	0.00		0.00	0.00	0	397.0 ACSR
564	TL293 Vernon	Red River (Interconnect PSO)	69.00	69.00	1	7.53	0.00	1	556 ACSR
565	66-633 Marshall 138	Marshall 69	69.00	69.00	1	0.11	0.00	1	2x1272.0 AAC
566	TL297 Clarendon	Jericho	69.00	69.00	1	6.22	0.00	1	336.4 ACSR
567	TL297 Clarendon	Jericho	0.00	0.00	1	12.50	0.00	1	477 ACSR
568	TL301 West Childress	Estelline	69.00	69.00	1	17.27	0.00	1	T2 477 ACSR
569	66-803 (21176) Vernon Main	WFEC Russell (Interconnect)	69.00	69.00	2	4.32	0.00	1	477.0 ACSR
570	TL302 Vernon Main St	North Vernon	69.00	69.00	1	0.02	0.00	1	477.0 ACSR
571	66-804 (21200) Shamrock	SPS Magic City	69.00	69.00	1	0.85	0.00	1	2/0 ACSR
572	66-804 (21200) Shamrock	(Interconnect)	0.00	0.00	2	16.92	0.00	0
573	TL381 Clarendon	Memphis	69.00	69.00	1	14.51	0.00	1	T2 477 ACSR
574	TL382 Memphis	Estelline	69.00	69.00	1	14.20	0.00	1	477 ACSR
575	TL375 Marshall	Rockhill	69.00	138.00	1	2.25	0.00	1	1272.0 ACSR
576	TL379 Blocker Tap		69.00	138.00	1	0.13	0.00	1	397 ACSR
577	TL396 Childress Amoco Tap		69.00	69.00	1	1.58	0.00	1	477 ACSR
578	TL421 Wickes REC Tap	Wickes (SWAEC)	69.00	69.00	1	0.01	0.00	1	795 ACSR
579	TL422 Quitman	Quitman (WCEC)	69.00	69.00	1	0.18	0.00	1	556 ACSR
580							0.00
581	Line Costs and expenses are	not available by individual								109,314,534	1,402,314,702	1,511,629,236	141,589	15,772,181		15,913,770
582	transmission line.	Total shown in Column j-p
583					TOTAL	4,021.22	53.00	539		109,314,534.00	1,402,314,702.00	1,511,629,236.00	141,589.00	15,772,181.00	0.00	15,913,770.00
36	TOTAL

Name of Respondent:

SWEPCO

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)

Nothing to Report

TOTAL

Name of Respondent:

SWEPCO

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	ABBOTT - AR	Distribution		34.50	12.47		2.50	1			0	0.00
2	ASHDOWN 69/12 - AR	Distribution		69.00	12.47		21.20	2			0	0.00
3	BLOOMBURG - AR	Distribution		69.00	12.47		2.00	1			0	0.00
4	BONANZA - AR	Transmission		34.50	0.00	0.00	0.00			STATCAP	1	6.00
5	BONANZA - AR	Transmission		34.50	12.47		10.00	4			0	0.00
6	BONANZA - AR	Transmission		161.00	34.50		12.00	1			0	0.00
7	BOONEVILLE - AR	Distribution		69.00	12.47		24.00	2			0	0.00
8	CENTERTON - AR	Distribution		161.00	12.47		12.00	1			0	0.00
9	CHAMBERS SPRING - AR	Transmission		345.00	161.00	13.80	405.00	1			0	0.00
10	DEQUEEN - AR	Transmission		12.00	0.00	0.00	0.00			STATCAP	1	6.00
11	DEQUEEN - AR	Transmission		69.00	34.50		7.50	1			0	0.00
12	DEQUEEN - AR	Transmission		138.00	72.60	11.98	80.00	1			0	0.00
13	DEQUEEN - AR	Transmission		69.00	12.47		40.00	2			0	0.00
14	DEQUEEN - AR	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	21.60
15	DIERKS - AR	Distribution		7.62	0.00	0.00	0.00			STATCAP	1	3.20
16	DIERKS - AR	Distribution		69.00	12.47		15.60	2			0	0.00
17	DIXIELAND - AR	Distribution		161.00	13.09		15.00	0	1		0	0.00
18	DIXIELAND - AR	Distribution		69.00	12.47		32.00	2			0	0.00
19	DYESS - AR	Transmission		69.00	12.47		15.00	2			0	0.00
20	DYESS - AR	Transmission		161.00	69.00	7.62	80.00	1			0	0.00
21	DYESS - AR	Transmission		161.00	69.00	13.09	78.00	1			0	0.00
22	EAST CENTERTON - AR	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	43.20
23	EAST CENTERTON - AR	Transmission		161.00	69.00	12.47	156.00	2			0	0.00
24	EAST ROGERS - AR	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	43.20
25	EAST ROGERS - AR	Transmission			0.00	0.00	0.00			Air Core Reactor	3
26	EAST ROGERS - AR	Transmission		161.00	69.00	13.90	80.00	1			0	0.00
27	EAST ROGERS - AR	Transmission		161.00	0.00	0.00	0.00			Air Core Reactor	1
28	EUREKA SPRINGS 161KV - AR	Transmission		161.00	34.50		12.00	0	1		0	0.00
29	EUREKA SPRINGS 161KV - AR	Transmission		161.00	34.50		12.00	1			0	0.00
30	FARMINGTON - AR	Distribution		161.00	12.47		12.00	1			0	0.00
31	FAYETTEVILLE (SW) - AR	Distribution		161.00	12.47		48.00	2			0	0.00
32	FAYETTEVILLE (SW) - AR	Distribution		12.00	0.00	0.00	0.00			STATCAP	2	12.45
33	FLINT CREEK SUB - AR	Transmission		345.00	161.00	13.80	480.00	2			0	0.00
34	FOREMAN - AR	Distribution		69.00	12.47		8.40	2			0	0.00
35	FOREMAN-MAGNOLIA - AR	Distribution		69.00	2.40		3.75	1			0	0.00
36	GREENLAND - AR	Distribution		69.00	12.47		15.00	2			0	0.00
37	GREENWOOD - AR	Distribution		34.50	7.56		8.40	3			0	0.00
38	GREGG STREET - AR	Distribution		161.00	12.47		24.00	1			0	0.00
39	HUNTINGTON - AR	Transmission		69.00	34.50		10.10	1			0	0.00
40	HUNTINGTON - AR	Transmission		69.00	13.09		5.00	1			0	0.00
41	HYLAND - AR	Distribution		161.00	12.47		20.00	1			0	0.00
42	HYLAND - AR	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
43	JENNY LIND - AR	Distribution		34.50	7.20		1.68	1			0	0.00
44	JENNY LIND - AR	Distribution		34.50	7.20		1.68	0	1		0	0.00
45	LOCKESBURG (NEW) - AR	Distribution		69.00	12.47		2.00	1			0	0.00
46	LOCKESBURG (NEW) - AR	Distribution		69.00	12.00		2.00	1			0	0.00
47	LOWELL (SEP) - AR	Distribution		161.00	12.47		30.00	2			0	0.00
48	MENA - AR	Transmission		12.00	0.00	0.00	0.00			STATCAP	1	6.00
49	MENA - AR	Transmission		69.00	12.47		24.00	2			0	0.00
50	MENA - AR	Transmission		69.00	34.50		10.00	1			0	0.00
51	MENA - AR	Transmission		138.00	69.00	13.80	50.00	1			0	0.00
52	MENA - AR	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	6.60
53	MIDLAND (SW) - AR	Distribution		69.00	12.47		7.50	1			0	0.00
54	MURFREESBORO UPTOWN - AR	Distribution		69.00	11.95		5.04	3			0	0.00
55	MURFREESBORO WEST - AR	Distribution		69.00	13.09		7.50	1			0	0.00
56	NASHVILLE 69KV - AR	Distribution		69.00	12.47		7.50	1			0	0.00
57	NASHVILLE 69KV - AR	Distribution		12.47	0.00	0.00	0.00			STATCAP	1	6.00
58	NASHVILLE 69KV - AR	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	21.60
59	NASHVILLE 69KV - AR	Distribution		69.00	36.29		5.00	2			0	0.00
60	NASHVILLE 69KV - AR	Distribution		69.00	36.00		2.50	1			0	0.00
61	NORTH HUNTINGTON - AR	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	21.60
62	NORTH HUNTINGTON - AR	Transmission		161.00	69.00		50.00	1			0	0.00
63	NORTH HUNTINGTON - AR	Transmission		161.00	69.00	12.00	50.00	1			0	0.00
64	NORTH ROGERS - AR	Distribution		69.00	12.47		40.00	2			0	0.00
65	NORTH ROGERS - AR	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
66	OKAY - AR	Transmission		138.00	70.50	13.09	54.00	1			0	0.00
67	OKAY - AR	Transmission		69.00	12.47		2.00	1			0	0.00
68	OKAY - AR	Transmission		69.00	34.50		5.00	1			0	0.00
69	OSBURN - AR	Distribution		161.00	13.09		24.00	1			0	0.00
70	PATTERSON - AR	Transmission		138.00	70.50	13.09	910.00	9			0	0.00
71	PATTERSON - AR	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	57.60
72	PLEASANT HILL - AR	Distribution		69.00	13.09		5.00	1			0	0.00
73	PRAIRIE GROVE - AR	Distribution		69.00	13.09		15.00	1			0	0.00
74	REEVES ROAD - AR	Distribution		161.00	34.50		12.00	1			0	0.00
75	REEVES ROAD - AR	Distribution		161.00	13.09		7.50	0	1		0	0.00
76	REEVES ROAD - AR	Distribution		161.00	13.09		7.50	1			0	0.00
77	ROGERS - AR	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
78	ROGERS - AR	Distribution		161.00	12.47		48.00	2			0	0.00
79	SHIPE ROAD - AR	Transmission		345.00	161.00	13.80	405.00	1			0	0.00
80	SILOAM SPRINGS 161KV - AR	Transmission		161.00	69.00	13.20	80.00	1			0	0.00
81	SILOAM SPRINGS 161KV - AR	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	21.60
82	SOUTH DIERKS - AR	Transmission		138.00	72.60	13.20	50.00	1			0	0.00
83	SOUTH FAYETTEVILLE - AR	Transmission		161.00	69.00	13.80	80.00	1			0	0.00
84	SOUTH FAYETTEVILLE - AR	Transmission		161.00	0.00	0.00	0.00			STATCAP	1	54.00
85	SOUTH FAYETTEVILLE - AR	Transmission		161.00	69.00	12.47	80.00	0	1		0	0.00
86	SOUTH FAYETTEVILLE - AR	Transmission		12.00	0.00	0.00	0.00			STATCAP	1	6.00
87	SOUTH FAYETTEVILLE - AR	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	43.20
88	SOUTH FAYETTEVILLE - AR	Transmission		161.00	12.47		40.00	2			0	0.00
89	SOUTH NASHVILLE - AR	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	6.00
90	SOUTH NASHVILLE - AR	Distribution		138.00	12.47		24.00	2			0	0.00
91	SOUTH SPRINGDALE - AR	Distribution		161.00	12.50		20.00	1			0	0.00
92	SOUTH SPRINGDALE - AR	Distribution		161.00	12.47		20.00	1			0	0.00
93	SOUTHEAST FAYETTEVILLE - AR	Distribution		161.00	12.47		24.00	0	1		0	0.00
94	SOUTHEAST FAYETTEVILLE - AR	Distribution		161.00	12.50		20.00	1			0	0.00
95	SOUTHEAST TEXARKANA - AR	Transmission		138.00	72.60	13.20	80.00	1			0	0.00
96	SPRINGDALE - AR	Distribution		12.00	0.00	0.00	0.00			STATCAP	1
97	SPRINGDALE - AR	Distribution		69.00	12.47		48.00	2			0	0.00
98	SUGAR HILL (SW) - AR	Transmission		138.00	12.47		12.00	1			0	0.00
99	SUGAR HILL (SW) - AR	Transmission		138.00	72.60	12.47	80.00	1			0	0.00
100	TEXARKANA PLANT - AR	Distribution		69.00	12.47		40.00	2			0	0.00
101	TONTITOWN - AR	Transmission		161.00	0.00	0.00	0.00			STATCAP	1	59.40
102	TONTITOWN - AR	Transmission		161.00	0.00	0.00	0.00			Air Core Reactor	3
103	TONTITOWN - AR	Transmission		345.00	161.00	13.80	405.00	0	1		0	0.00
104	TONTITOWN - AR	Transmission		345.00	161.00	13.80	405.00	1			0	0.00
105	TURK - AR	Transmission		345.00	138.00	34.50	405.00	1			0	0.00
106	TURK - AR	Transmission		138.00	115.00	13.20	100.00	0	1		0	0.00
107	TURK - AR	Transmission		138.00	115.00	13.20	100.00	1			0	0.00
108	TWELFTH STREET (SW) - AR	Distribution		69.00	12.47		24.00	2			0	0.00
109	U.S. MOTORS - AR	Distribution		69.00	4.16	2.40	5.60	1			0	0.00
110	VAN ASCHE - AR	Distribution		161.00	12.47		48.00	2			0	0.00
111	VAN ASCHE - AR	Distribution		12.47	0.00	0.00	0.00			STATCAP	1	7.20
112	WALDRON - AR	Distribution		69.00	12.47		7.50	1			0	0.00
113	WALDRON - AR	Distribution		69.00	13.09		7.50	1			0	0.00
114	WALDRON - AR	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
115	WEST BOONEVILLE - AR	Transmission		161.00	69.00	11.75	40.00	1			0	0.00
116	ARSENAL HILL - LA	Transmission		138.00	70.50	12.47	400.00	2			0	0.00
117	ARSENAL HILL - LA	Transmission		69.00	12.47		84.00	2			0	0.00
118	ARSENAL HILL - LA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	43.20
119	ARSENAL HILL - LA	Transmission		138.00	0.00	0.00	0.00			Air Core Reactor	3	0.00
120	ARSENAL HILL - LA	Transmission		12.00	0.00	0.00	0.00			STATCAP	1	6.00
121	BAYOU PIERRE - LA	Distribution		69.00	13.20		7.00	1			0	0.00
122	BEAN - LA	Distribution		138.00	12.47		40.00	1			0	0.00
123	BEAN - LA	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	7.20
124	BELCHER - LA	Distribution		69.00	12.47		6.25	1			0	0.00
125	BELLEVUE - LA	Distribution		69.00	12.47		12.50	1			0	0.00
126	BELLEVUE OIL FIELD - LA	Distribution		69.00	12.47		5.00	1			0	0.00
127	BELMONT (SEP) - LA	Distribution		69.00	13.20		14.00	1			0	0.00
128	BLANCHARD - LA	Distribution		69.00	13.09		25.00	1			0	0.00
129	BLANCHARD - LA	Distribution		69.00	12.47		18.75	2			0	0.00
130	BODCAU ROAD - LA	Distribution		138.00	12.47		40.00	2			0	0.00
131	BOSSIER CITY - LA	Distribution		69.00	12.47		70.00	2			0	0.00
132	BROADMOOR - LA	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
133	BROADMOOR - LA	Distribution		69.00	12.50		20.00	1			0	0.00
134	BROADMOOR - LA	Distribution		69.00	13.09		25.00	1			0	0.00
135	BROOKS STREET (SW) - LA	Distribution		69.00	12.50		40.00	2			0	0.00
136	BROOKS STREET (SW) - LA	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	3,600.00
137	BROWNLEE - LA	Distribution		69.00	12.47		25.00	2			0	0.00
138	BROWNLEE - LA	Distribution		69.00	34.50		14.00	1			0	0.00
139	CALUMET - LA	Distribution		69.00	12.47		6.25	1			0	0.00
140	CANE RIVER (SEP) - LA	Distribution		34.50	13.20		7.00	0	1		0	0.00
141	CANE RIVER (SEP) - LA	Distribution		115.00	13.20		53.00	2			0	0.00
142	CAPLIS - LA	Distribution		138.00	36.20		30.00	1			0	0.00
143	CAPLIS - LA	Distribution		138.00	12.47		25.00	1			0	0.00
144	CARROLL (SEP) - LA	Distribution		34.50	13.20		3.50	1			0	0.00
145	CEDAR GROVE (SW) - LA	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	57.60
146	CRESTON - LA	Distribution		34.50	13.20		7.00	1			0	0.00
147	DERRY - LA	Distribution		34.50	13.20		10.50	1			0	0.00
148	DOGWOOD - LA	Distribution		69.00	12.47		10.50	1			0	0.00
149	DOGWOOD - LA	Distribution		69.00	13.09		9.38	1			0	0.00
150	EDWARDS STREET - LA	Distribution		69.00	12.50		20.00	1			0	0.00
151	ELLERBE ROAD - LA	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
152	ELLERBE ROAD - LA	Distribution		69.00	12.47		56.00	2			0	0.00
153	FERN STREET - LA	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
154	FERN STREET - LA	Distribution		69.00	12.50		40.00	2			0	0.00
155	FINNEY - LA	Distribution		69.00	4.36		6.25	1			0	0.00
156	FINNEY - LA	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	0.60
157	FLOURNOY - LA	Transmission		69.00	12.50		40.00	2			0	0.00
158	FLOURNOY - LA	Transmission		138.00	69.00	7.20	133.00	1			0	0.00
159	FORD - LA	Distribution		69.00	12.50		40.00	2			0	0.00
160	FORT HUMBUG - LA	Transmission		138.00	70.50	13.09	130.00	1			0	0.00
161	FORT HUMBUG - LA	Transmission		12.00	0.00	0.00	0.00			STATCAP	1	6.00
162	GAHAGAN - LA	Distribution		34.50	13.20		10.50	1			0	0.00
163	GENERAL MOTORS - LA	Distribution		138.00	13.80		90.00	2			0	0.00
164	GEORGIA PACIFIC (SW) - LA	Distribution		138.00	12.47		7.00	1			0	0.00
165	GILLIAM - LA	Distribution		69.00	12.47		5.00	1			0	0.00
166	GRAND ECORE - LA	Distribution		34.50	13.20		14.00	1			0	0.00
167	GRAVEL POINT - LA	Distribution		69.00	26.40		14.00	1			0	0.00
168	HARDY STREET - LA	Distribution		69.00	12.47		26.50	2			0	0.00
169	HARTS ISLAND - LA	Distribution		138.00	34.50		100.00	2			0	0.00
170	HARTS ISLAND - LA	Distribution		34.50	0.00	0.00	0.00			STATCAP	2	18.00
171	HAUGHTON - LA	Distribution		138.00	12.47		10.50	1			0	0.00
172	HAUGHTON - LA	Distribution		138.00	13.09		25.00	1			0	0.00
173	HICKS - LA	Distribution		69.00	13.20		14.00	1			0	0.00
174	HORNBECK - LA	Distribution		69.00	24.90		28.00	1			0	0.00
175	HOSSTON - LA	Distribution		69.00	13.09		12.50	1			0	0.00
176	KINGSTON - LA	Distribution		69.00	24.90		28.00	1			0	0.00
177	KURTHWOOD - LA	Distribution		34.50	13.20		2.58	1			0	0.00
178	LAYFIELD 500KV - LA	Transmission		500.00	230.00	13.80	750.00	3			0	0.00
179	LIEBERMAN - LA	Transmission		138.00	69.00	13.20	50.00	2			0	0.00
180	LIEBERMAN - LA	Transmission		138.00	69.00	13.00	50.00	1			0	0.00
181	LIEBERMAN 12KV - LA	Distribution		69.00	12.47		14.00	2			0	0.00
182	LINTON ROAD - LA	Distribution		138.00	13.09		40.00	2			0	0.00
183	LINWOOD (SW) - LA	Distribution		138.00	12.47		66.00	2			0	0.00
184	LINWOOD (SW) - LA	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
185	LOGANSPORT - LA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	28.80
186	LOGANSPORT - LA	Transmission		69.00	12.47		7.00	1			0	0.00
187	LOGANSPORT - LA	Transmission		138.00	69.00	13.80	56.00	1			0	0.00
188	LOGANSPORT - LA	Transmission		138.00	69.00	13.20	33.30	1			0	0.00
189	LOGANSPORT - LA	Transmission		69.00	13.09		12.50	1			0	0.00
190	LONGWOOD (SW) - LA	Transmission		345.00	138.00	12.50	298.00	2			0	0.00
191	LONGWOOD (SW) - LA	Transmission		12.00						REACTOR	2	50.00
192	LONGWOOD (SW) - LA	Transmission		345.00	138.00	13.80	149.00	1			0	0.00
193	LUCAS - LA	Distribution		69.00	13.09		80.00	2			0	0.00
194	LUCAS - LA	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	4.50
195	MANSFIELD - LA	Distribution		34.50	13.20		5.00	1			0	0.00
196	MANY - LA	Distribution		69.00	13.20		28.00	1			0	0.00
197	MARTHAVILLE - LA	Distribution		69.00	13.20		14.00	1			0	0.00
198	MARTIN (SW) - LA	Distribution		34.50	12.00		6.20	1			0	0.00
199	MARTIN (SW) - LA	Distribution		69.00	12.47		12.50	0	1		0	0.00
200	MCDADE - LA	Distribution		138.00	12.47		30.50	2			0	0.00
201	MCWILLIE STREET - LA	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	3.00
202	MCWILLIE STREET - LA	Distribution		138.00	12.47		66.30	2			0	0.00
203	MIDWAY (SW) - LA	Distribution		69.00	12.47		94.00	4			0	0.00
204	MINDEN ROAD - LA	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	5.85
205	MINDEN ROAD - LA	Distribution		69.00	12.47		40.00	2			0	0.00
206	MOTT - LA	Distribution		26.00	12.00		5.60	6			0	0.00
207	MOTT - LA	Distribution		69.00	24.90		14.00	1			0	0.00
208	NEGREET - LA	Distribution		69.00	24.90		14.00	1			0	0.00
209	NOBLE (SEP) - LA	Distribution		69.00	24.90		28.00	2			0	0.00
210	NOBLE (SEP) - LA	Distribution		69.00	26.40		25.00	0	1		0	0.00
211	NORTH BENTON - LA	Transmission		138.00	12.47		14.00	0	1		0	0.00
212	NORTH BENTON - LA	Transmission		138.00	69.00	13.20	42.00	1			0	0.00
213	NORTH BENTON - LA	Transmission		138.00	12.47		14.00	1			0	0.00
214	NORTH LEESVILLE - LA	Distribution		69.00	24.90		25.00	1			0	0.00
215	NORTH MARKET - LA	Distribution		69.00	12.50		40.00	2			0	0.00
216	OIL CITY - LA	Distribution		69.00	12.47		7.00	1			0	0.00
217	PIERREMONT - LA	Distribution		138.00	12.47		9.38	1			0	0.00
218	PIERREMONT - LA	Distribution		138.00	34.50		50.00	1			0	0.00
219	PIERREMONT - LA	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	3.00
220	PINES ROAD - LA	Distribution		69.00	12.47		20.00	1			0	0.00
221	PINES ROAD - LA	Distribution		69.00	12.50		20.00	1			0	0.00
222	PLAIN DEALING - LA	Distribution		69.00	12.47		10.50	1			0	0.00
223	PLAIN DEALING - LA	Distribution		69.00	13.09		9.38	1			0	0.00
224	PORT ROBSON - LA	Distribution		138.00	12.47		25.00	1			0	0.00
225	POWELL STREET - LA	Distribution		138.00	12.47		66.00	2			0	0.00
226	POWELL STREET - LA	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	3.60
227	POWHATAN (SEP) - LA	Distribution		34.50	13.20		3.13	1			0	0.00
228	PROVENCAL - LA	Distribution		115.00	13.20		56.00	2			0	0.00
229	RAINES - LA	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
230	RED OAK (SEP) - LA	Distribution		34.50	13.20		7.00	1			0	0.00
231	RED POINT - LA	Transmission		138.00	13.09		25.00	1			0	0.00
232	RED POINT - LA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	43.20
233	RED POINT - LA	Transmission		138.00	66.00	13.80	50.00	1			0	0.00
234	RED POINT - LA	Transmission		138.00	72.60	13.20	42.00	1			0	0.00
235	ROBELINE - LA	Distribution		69.00	13.09		9.38	1			0	0.00
236	SHED ROAD - LA	Distribution		69.00	12.47		14.00	1			0	0.00
237	SHED ROAD - LA	Distribution		69.00	13.09		10.00	1			0	0.00
238	SHED ROAD - LA	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
239	SOUTH SHREVEPORT - LA	Transmission		138.00	72.60	13.20	166.00	2			0	0.00
240	SOUTH SHREVEPORT - LA	Transmission		12.00	0.00	0.00	0.00			STATCAP	1	6.00
241	SOUTH SHREVEPORT - LA	Transmission		138.00	12.47		44.80	2			0	0.00
242	SOUTHWEST SHREVEPORT - LA	Transmission		345.00	138.00	13.80	600.00	0	1		0	0.00
243	SOUTHWEST SHREVEPORT - LA	Transmission		345.00	138.00	34.50	1350.00	2			0	0.00
244	SOUTHWEST SHREVEPORT - LA	Transmission		34.50	0.00	0.00	0.00			Air Core Reactor	3	25.02
245	STONEWALL - LA	Distribution		138.00	34.50		20.00	1			0	0.00
246	SUMMER GROVE - LA	Distribution		69.00	12.47		7.00	1			0	0.00
247	SUMMER GROVE - LA	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	4.80
248	SUMMER GROVE - LA	Distribution		69.00	12.47	7.20	7.00	1			0	0.00
249	SUPERIOR (SW) - LA	Distribution		69.00	12.47		20.88	2			0	0.00
250	TRICHEL STREET - LA	Distribution		138.00	12.47		42.00	1			0	0.00
251	TRICHEL STREET - LA	Distribution		138.00	13.09		40.00	1			0	0.00
252	TRICHEL STREET - LA	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	4.20
253	VIVIAN - LA	Distribution		69.00	12.47		18.75	2			0	0.00
254	WALLACE LAKE - LA	Transmission		138.00	69.00	13.00	83.00	1			0	0.00
255	WALLACE LAKE - LA	Transmission		138.00	34.50		30.00	1			0	0.00
256	WATERWORKS (SW) - LA	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
257	WATERWORKS (SW) - LA	Distribution		69.00	12.50		40.00	2			0	0.00
258	WATERWORKS (SW) - LA	Distribution		69.00	12.47		14.00	1			0	0.00
259	WESTERN ELECTRIC - LA	Distribution		34.50	0.00	0.00	0.00			STATCAP	2	18.00
260	WESTERN ELECTRIC - LA	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
261	WESTERN ELECTRIC - LA	Distribution		138.00	36.20		18.00	0	1		0	0.00
262	WESTERN ELECTRIC - LA	Distribution		138.00	12.47		40.00	2			0	0.00
263	WESTERN ELECTRIC - LA	Distribution		138.00	34.50		144.00	2			0	0.00
264	WHITEHURST - LA	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
265	WHITEHURST - LA	Distribution		138.00	34.50		121.70	2			0	0.00
266	WHITEHURST - LA	Distribution		138.00	12.47		20.00	1			0	0.00
267	AIR PRODUCTS (SW) - TX	Distribution		69.00	12.00		7.00	1			0	0.00
268	AIRLINE - TX	Distribution		69.00	12.50		20.00	1			0	0.00
269	AIRLINE - TX	Distribution		69.00	12.47		20.00	1			0	0.00
270	ALBA - TX	Distribution		69.00	12.00		5.00	1			0	0.00
271	ALUMAX - TX	Distribution		138.00	13.80		40.00	2			0	0.00
272	ATLANTA - TX	Distribution		69.00	12.47		66.00	2			0	0.00
273	ATLANTA - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
274	BALDWIN - TX	Distribution		69.00	13.09		25.00	4			0	0.00
275	BALDWIN - TX	Distribution		69.00	12.00		5.00	1			0	0.00
276	BANN - TX	Transmission		138.00	72.60	13.80	133.00	1			0	0.00
277	BANN - TX	Transmission		138.00	72.60	12.00	133.00	1			0	0.00
278	BECKVILLE - TX	Distribution		69.00	13.09		6.25	1			0	0.00
279	BIG SANDY (SW) - TX	Distribution		69.00	13.09		9.38	1			0	0.00
280	BRYANS MILL - TX	Transmission		138.00	12.47		9.38	1			0	0.00
281	CAREY - TX	Distribution		69.00	7.20		1.50	3			0	0.00
282	CARTHAGE - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	2	12.30
283	CARTHAGE - TX	Distribution		69.00	12.50		40.00	2			0	0.00
284	CENTER - TX	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	31.20
285	CENTER - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
286	CENTER - TX	Distribution		138.00	12.47		84.00	2			0	0.00
287	CHILDRESS AIRPORT PRISON - TX	Distribution		69.00	13.09		2.49	3			0	0.00
288	CHILDRESS AMOCO - TX	Distribution		69.00	4.16	2.40	7.50	1			0	0.00
289	CHILDRESS WEST (SEP) - TX	Transmission		7.62	0.00	0.00	0.00			Air Core Reactor	3	19.97
290	CHILDRESS WEST (SEP) - TX	Transmission		138.00	69.00	12.47	50.00	1			0	0.00
291	CHILDRESS WEST (SEP) - TX	Transmission		0.00	0.00	0.00	0.00			STATCAP	1	6.60
292	CITY LAKE SUB - TX	Distribution		69.00	13.09		50.00	2			0	0.00
293	CLARENDON - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	3.60
294	CLARENDON - TX	Distribution		69.00	7.56		6.90	3			0	0.00
295	CLARKSVILLE - TX	Distribution		69.00	12.47		20.00	1			0	0.00
296	CLARKSVILLE - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	2	6.80
297	CLARKSVILLE - TX	Distribution		69.00	12.50		20.00	1			0	0.00
298	COOKVILLE (SW) - TX	Distribution		69.00	12.47		4.66	1			0	0.00
299	CROCKETT - TX	Transmission		345.00	138.00	13.80	300.00	2			0	0.00
300	DAINGERFIELD - TX	Distribution		69.00	12.47		42.40	2			0	0.00
301	DEKALB - TX	Distribution		69.00	12.47		18.75	2			0	0.00
302	DIANA - TX	Transmission		345.00	138.00	13.80	300.00	0	1		0	0.00
303	DIANA - TX	Transmission		345.00	138.00	13.80	1050.00	3			0	0.00
304	ESTELLINE - TX	Distribution		69.00	13.09		2.49	3			0	0.00
305	EVENSIDE - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
306	EVENSIDE - TX	Distribution		69.00	12.50		40.00	2			0	0.00
307	FERNDALE LAKE - TX	Distribution		69.00	12.47		2.30	1			0	0.00
308	FRIARS SWITCH - TX	Distribution		138.00	12.47		28.00	2			0	0.00
309	GATES - TX	Distribution		69.00	12.50		20.00	1			0	0.00
310	GILMER - TX	Distribution		69.00	12.50		40.00	2			0	0.00
311	GRAND SALINE - TX	Distribution		69.00	12.47		18.75	2			0	0.00
312	GRAND SALINE - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6,000.00
313	GREGGTON - TX	Distribution		69.00	12.50		40.00	2			0	0.00
314	GREGGTON - TX	Distribution		69.00	12.00		4.69	1			0	0.00
315	HALLSVILLE - TX	Distribution		138.00	13.09		125.00	5			0	0.00
316	HARRISON ROAD - TX	Distribution		138.00	34.50		133.00	2			0	0.00
317	HAWKINS - TX	Distribution		69.00	12.47		25.00	2			0	0.00
318	HEDLEY - TX	Distribution		69.00	12.50		2.49	3			0	0.00
319	HOOKS - TX	Distribution		69.00	12.47		21.00	2			0	0.00
320	HOWELL - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
321	HOWELL - TX	Distribution		69.00	12.47		33.00	1			0	0.00
322	HUGHES SPRINGS - TX	Distribution		69.00	12.47	4.16	21.00	2			0	0.00
323	IPC 138KV - TX	Transmission		138.00	13.09		9.38	1			0	0.00
324	IPC 138KV - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	28.80
325	IPC-DOMINO - TX	Distribution		138.00	12.47		7.00	1			0	0.00
326	IPC-JEFFERSON - TX	Distribution		138.00	12.47		28.00	2			0	0.00
327	JEFFERSON - TX	Distribution		69.00	12.47		18.75	2			0	0.00
328	JERICHO - TX	Transmission		115.00	69.00	8.30	41.70	1			0	0.00
329	KILGORE - TX	Distribution		69.00	12.50		20.00	1			0	0.00
330	KILGORE - TX	Distribution		69.00	12.47		40.00	2			0	0.00
331	KILGORE - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	4.50
332	KINGS HIGHWAY - TX	Distribution		69.00	12.50		40.00	2			0	0.00
333	KNOX LEE - TX	Transmission		138.00	69.00	0.00	133.00	1			0	0.00
334	KNOX LEE - TX	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	21.60
335	KNOX LEE - TX	Transmission		69.00	13.09		9.38	1			0	0.00
336	LAKE LAMOND - TX	Distribution		69.00	12.47		60.00	3			0	0.00
337	LAKE LAMOND - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	2	12.00
338	LAKE LAMOND - TX	Distribution		138.00	69.00	13.80	133.00	1			0	0.00
339	LAKE PAULINE (SEP) - TX	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	9.60
340	LAKE PAULINE (SEP) - TX	Transmission		138.00	69.00	14.40	62.50	1			0	0.00
341	LETOURNEAU 69/12 - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	16.20
342	LETOURNEAU 69/12 - TX	Distribution		69.00	12.47		25.00	1			0	0.00
343	LEVERETTS CHAPEL - TX	Distribution		138.00	12.47		9.38	1			0	0.00
344	LIBERTY CITY - TX	Distribution		138.00	12.47		11.22	6			0	0.00
345	LINDEN - TX	Distribution		69.00	12.47		13.25	2			0	0.00
346	LONDON (SW) - TX	Distribution		138.00	12.47		28.00	2			0	0.00
347	LONE STAR (SEP) - TX	Transmission		69.00	13.09		6.25	1			0	0.00
348	LONE STAR SHELL ORDNANCE - TX	Distribution		69.00	12.47		10.00	2			0	0.00
349	LONE STAR SOUTH - TX	Transmission		138.00	69.00	12.47	133.00	1			0	0.00
350	LONGVIEW - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	2.70
351	LONGVIEW - TX	Distribution		69.00	12.50		20.00	1			0	0.00
352	LONGVIEW - TX	Distribution		69.00	13.09		25.00	1			0	0.00
353	LONGVIEW HEIGHTS - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
354	LONGVIEW HEIGHTS - TX	Distribution		138.00	12.47		40.00	2			0	0.00
355	LOUISIANA PACIFIC - TX	Distribution		69.00	12.50		40.00	2			0	0.00
356	MARSHALL 138KV - TX	Transmission		138.00	69.00	13.00	133.00	1			0	0.00
357	MARSHALL 138KV - TX	Transmission		138.00	69.00	7.20	133.00	1			0	0.00
358	MARSHALL 69KV - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	3.60
359	MARSHALL 69KV - TX	Distribution		69.00	12.47		9.38	1			0	0.00
360	MARSHALL 69KV - TX	Distribution		69.00	13.09		20.00	1			0	0.00
361	MEMPHIS - TX	Distribution		69.00	13.00		12.60	3			0	0.00
362	MEMPHIS - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	3.60
363	MEMPHIS NW - TX	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	2.40
364	MID-VALLEY - TX	Distribution		69.00	2.40		9.38	1			0	0.00
365	MID-VALLEY LONGVIEW - TX	Distribution		69.00	2.40		7.00	1			0	0.00
366	MINEOLA - TX	Distribution		69.00	13.09		45.00	2			0	0.00
367	MINEOLA - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	21.60
368	MINEOLA - TX	Distribution			0.00	0.00	0.00			STATCAP	1	21.60
369	MONROE CORNERS - TX	Distribution		69.00	12.47		7.00	1			0	0.00
370	MOUNT PLEASANT - TX	Distribution		69.00	12.47		26.50	2			0	0.00
371	MOUNT PLEASANT - TX	Distribution		69.00	13.09		14.00	1			0	0.00
372	MOUNT VERNON (SW) - TX	Distribution		69.00	12.47		28.00	2			0	0.00
373	NAPLES - TX	Distribution		69.00	12.47		11.25	2			0	0.00
374	NASH - TX	Distribution		138.00	12.47		50.00	2			0	0.00
375	NETTLETON - TX	Distribution		69.00	2.40		2.50	1			0	0.00
376	NEW BOSTON - TX	Distribution		69.00	12.50		40.00	2			0	0.00
377	NEW BOSTON - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
378	NEW GLADEWATER - TX	Distribution		138.00	12.47		33.30	1			0	0.00
379	NEW GLADEWATER - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
380	NEW HOPE (SW) - TX	Distribution		69.00	12.47		18.75	2			0	0.00
381	NORTH LANEVILLE - TX	Distribution		69.00	34.50		5.00	1			0	0.00
382	NORTH MARSHALL - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
383	NORTH MARSHALL - TX	Distribution		69.00	12.47		28.00	2			0	0.00
384	NORTH MINEOLA - TX	Transmission		69.00	12.47		9.38	1			0	0.00
385	NORTH MINEOLA - TX	Transmission		138.00	69.00	0.00	133.00	1			0	0.00
386	NORTH MINEOLA - TX	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	21.60
387	NORTH NEW BOSTON - TX	Transmission		138.00	72.60	13.20	83.00	1			0	0.00
388	NORTHWEST HENDERSON - TX	Transmission		138.00	69.00	13.20	166.00	2			0	0.00
389	NORTHWEST TEXARKANA - TX	Transmission		345.00	138.00	13.80	1200.00	2			0	0.00
390	NORTHWEST TEXARKANA - TX	Transmission		12.00						REACTOR	1	25.00
391	OVERTON - TX	Transmission		138.00	72.60	13.20	84.00	2			0	0.00
392	OVERTON - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	31.20
393	PERDUE - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	86.40
394	PERDUE - TX	Transmission		138.00	70.50	13.09	130.00	1			0	0.00
395	PETTY - TX	Transmission		69.00	12.47		9.38	1			0	0.00
396	PETTY - TX	Transmission		138.00	69.00	0.00	267.00	2			0	0.00
397	PETTY - TX	Transmission		69.00	13.09		9.38	1			0	0.00
398	PILGRIMS PRIDE - TX	Distribution		69.00	12.50		40.00	2			0	0.00
399	PIRKEY - TX	Transmission		345.00	138.00	34.50	675.00	1			0	0.00
400	PIRKEY - TX	Transmission		345.00	138.00	13.80	600.00	1			0	0.00
401	PITTSBURG (SW) - TX	Transmission		138.00	72.60	0.00	133.00	1			0	0.00
402	PITTSBURG (SW) - TX	Transmission		69.00	12.50		40.00	2			0	0.00
403	PITTSBURG STEEL - TX	Distribution		69.00	12.00		6.25	1			0	0.00
404	PLILER ROAD - TX	Distribution		138.00	34.50		100.00	2			0	0.00
405	POYNTER - TX	Distribution		69.00	12.47		26.50	2			0	0.00
406	POYNTER - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
407	RED RIVER ARSENAL - TX	Distribution		69.00	12.47		12.50	1			0	0.00
408	RICHMOND ROAD - TX	Distribution		69.00	12.47		33.00	1			0	0.00
409	RICHMOND ROAD - TX	Distribution		69.00	12.50		33.00	1			0	0.00
410	ROCK HILL - TX	Transmission		138.00	70.50	13.09	180.00	2			0	0.00
411	ROSBOROUGH - TX	Distribution		69.00	12.47		2.00	1			0	0.00
412	SABINE - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	3.60
413	SABINE - TX	Distribution		69.00	12.47		20.00	1			0	0.00
414	SCOTTSVILLE (SW) - TX	Distribution		138.00	12.47		40.00	2			0	0.00
415	SERVICE PIPELINE - TX	Distribution		69.00	2.40		3.13	1			0	0.00
416	SHAMROCK (SEP) - TX	Transmission		138.00	69.00	6.10	62.50	1			0	0.00
417	SHAMROCK (SEP) - TX	Transmission		69.00	13.09		11.10	3			0	0.00
418	SHAMROCK (SEP) - TX	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	7.20
419	SHAMROCK (SEP) - TX	Transmission		115.00	69.00	14.40	62.50	1			0	0.00
420	SOHIO - TX	Distribution		69.00	2.40		2.00	1			0	0.00
421	SOUTHEAST LONGVIEW - TX	Distribution		69.00	12.47		41.67	1			0	0.00
422	SOUTHEAST LONGVIEW - TX	Distribution		69.00	12.50		42.00	1			0	0.00
423	SOUTHEAST MARSHALL - TX	Distribution		138.00	12.47		66.00	2			0	0.00
424	SPRINGHILL - TX	Distribution		138.00	12.47		22.40	1			0	0.00
425	TATUM - TX	Distribution		138.00	12.47		9.38	1			0	0.00
426	TAYLOR STREET - TX	Distribution		69.00	12.47		66.00	2			0	0.00
427	TAYLOR STREET - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
428	TENAHA - TX	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	31.20
429	TENAHA - TX	Distribution		138.00	12.47		9.38	1			0	0.00
430	TEXARKANA OPERATIONS CENTER - TX	Distribution		69.00	12.47		20.00	1			0	0.00
431	TEXARKANA OPERATIONS CENTER - TX	Distribution		69.00	12.50		20.00	1			0	0.00
432	TEXARKANA OPERATIONS CENTER - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
433	TEXAS EASTERN - TX	Distribution		69.00	2.30		7.50	2			0	0.00
434	THIRTY-NINTH STREET - TX	Distribution		69.00	12.47		33.00	1			0	0.00
435	THIRTY-NINTH STREET - TX	Distribution		69.00	12.50		20.00	1			0	0.00
436	THIRTY-NINTH STREET - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	5.85
437	TURNERTOWN - TX	Distribution		69.00	13.09		9.38	1			0	0.00
438	TURNERTOWN - TX	Distribution		69.00	12.47		9.38	1			0	0.00
439	WASKOM - TX	Distribution		69.00	13.09		26.00	2			0	0.00
440	WELLINGTON - TX	Distribution		138.00	7.56		14.01	3			0	0.00
441	WELSH HVDC CONVERTER - TX	Transmission		345.00	69.00		296.00	1			0	0.00
442	WELSH HVDC CONVERTER - TX	Transmission		345.00	0.00	0.00	0.00			STATCAP	1	100.00
443	WELSH HVDC CONVERTER - TX	Transmission		345.00	69.80	69.80	1020.00	4			0	0.00
444	WELSH HVDC CONVERTER - TX	Transmission		345.00	69.80	69.80	293.00	1			0	0.00
445	WEST ATLANTA - TX	Transmission		138.00	70.50	13.09	90.00	1			0	0.00
446	WEST ATLANTA - TX	Transmission		138.00	69.00	12.50	41.66	1			0	0.00
447	WEST MOUNT PLEASANT - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	6.00
448	WEST MOUNT PLEASANT - TX	Distribution		69.00	12.47		9.38	1			0	0.00
449	WESTWOOD - TX	Distribution		69.00	13.09		9.38	1			0	0.00
450	WHITNEY - TX	Transmission		138.00	69.00	12.47	133.00	1			0	0.00
451	WHITNEY - TX	Transmission		69.00	12.47		60.00	3			0	0.00
452	WHITNEY - TX	Transmission		138.00	70.50	13.09	208.00	2			0	0.00
453	WHITNEY - TX	Transmission		12.00	0.00	0.00	0.00			STATCAP	1	6.00
454	WHITNEY - TX	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	43.20
455	WILKES - TX	Transmission		12.00						REACTOR	2	50.00
456	WILKES - TX	Transmission		345.00	138.00	13.80	447.00	3			0	0.00
457	WINFIELD - TX	Distribution		69.00	12.47		9.37	2			0	0.00
458	WINNSBORO - TX	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	57.60
459	WINNSBORO - TX	Distribution		69.00	12.50		20.00	1			0	0.00
460	WINNSBORO - TX	Distribution		138.00	70.50	12.47	130.00	1			0	0.00
461	WINNSBORO - TX	Distribution		69.00	12.00		20.00	1			0	0.00
462	WOODLAWN (SW) - TX	Distribution		69.00	12.47		6.25	1			0	0.00
463	TotalTransmissionSubstationMember											11,238.54
464	Total											11,238.54

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, Assistant Controller 212 East Sixth StreetTulsa, Oklahoma 74119
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. Public Utility engaged in generating, purchasing, transmitting, distributing and selling electric energy.Qualified to do business in the states of Arkansas, Louisiana, Oklahoma and Texas. The Company owns transmission facilities but provides no electric service at retail in Oklahoma.
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	Southwest Arkansas	Aid in Right of Way	100
2		Acquisition
3	Dolet Hills Lignite Company	Lignite Mine Operator	100
4	Sabine Mining COmpany	Lignite Mine Operatore		1
5	Oxbow Lignite Company, LLC	Lignite Mine Reserves	50	2
6	Mutual Energy SWEPCO, LLC	Energy Company	100
7	Footnote 1-
8	Accounting guidance for Variable Interest
9	Entities - Respondent contracts to
10	Purchase 100% of the lignite mined
11	Footnote 2-
12	Ownership of the Oxbow Mining Company is held
13	Jointly with Cleco Power Company LLC

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,Chief Executive Officer	Columbus. Ohio
2	Lisa M. Barton, Vice President	Columbus. Ohio
3	Charles R Patton, Vice President	Columbus. Ohio
4	Paul Chodak, Vice President	Columbus. Ohio
5	David M. Feinberg, Secretary and Vice President	Columbus, Ohio
6	Ann P. Kelly, Chief Financial Officer and Vice President	Columbus, Ohio
7	Therace M. Risch, Vice President	Columbus, Ohio
8	Julia A.Sloat, Chief Financial Officer and Vice President	Columbus, Ohio
9	A Malcolm. Smoak,, President and Chief Operating Officer	Columbus, Ohio
10	Toby L. Thomas, Vice President	Columbus, Ohio
11	Phillip R. Ulrich, Vice President	Columbus, Ohio
12	Christian T. Beam, Executive Vice President	Columbus, Ohio
13	Peggy I. Simmons, Executive Vice President	Columbus, Ohio
14	Rajagopalan, Sundararajan, Executive Vice President	Columbus, Ohio
15	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., a registered holding company, owns 100% of the Respondent's outstanding shares of 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	Rate Schedule 119	ER19-159-000
2	Rate Schedule 125	ER18-2374-000
3	Rate Schedule 126	ER18-2349-000
4	Rate Schedule 127	ER18-1824-000
5	Rate Schedule 128	ER18-1774-000
6	Rate Schedule 129	ER19-171-000
7	SPP FERC Electric Tariff 6th Revision Vol. No. 1	ER07-1069
8	Addendum 4 to Attachment H, Parts 1 and 2
9	SPP FERC Electric Tariff Vol. No. 1	ER18-195
10	Attachment H, Parts 1 and 2

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 (Checked by default - Not explicitly defined)
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	20090526-5302	05/26/2009	ER09-1198-000	AEP SPP 2009 Trans FR Update	SPP OATT Att. H-4
2	20090831-5276	08/31/2009	ER09-1198-000	Errata of 2009 Update	SPP OATT Att. H-4
3	20100525-5109	05/25/2010	ER10-355-000	AEP SPP 2010 Trans FR Update	SPP OATT Att. H-4
4	20110928-5123	09/28/2011	ER11-4671-000	AEP SPP 2011 Trans FR Update	SPP OATT Att. H-4
5	20111221-5253	12/21/2011	ER11-1069-000	Errata of 2011 Update	SPP OATT Att. H-4
6	20120523-5024	05/23/2012	ER07-1069-000	AEP SPP 2012 Trans FR Update	SPP OATT Att. H-4
7	20130910-3004	05/24/2013	ER13-1606-000	AEP SPP 2013 Trans FR Update	SPP OATT Att. H-4
8	20141208-5379	12/08/2014	ER07-1069-000	AEP SPP 2014 Trans FR Update	SPP OATT Att. H-4
9	20150604-5186	05/14/2015	ER07-1069-000	AEP SPP 2015 Trans FR Update	SPP OATT Att. H-4
10	20160523-5233	05/23/2016	ER07-1069-000	AEP SPP 2016 Trans FR Update	SPP OATT Att. H-4
11	20160630-5407	06/30/2016	ER07-1069-000	Errata of 2016 Update	SPP OATT Att. H-4
12	20170525-5337	05/25/2017	ER07-1069-000	AEP SPP 2017 Trans FR Update	SPP OATT Att. H-4
13	20171031-5311	10/31/2017	ER18-195-000	AEP SPP OATT Projected Revenue Requirement	SPP OATT Att. H-4
14	20180525-5243	05/25/2018	ER18-195-000	AEP SPP 2018 Trans FR Update	SPP OATT Att. H-4
15	20181101-5217	11/01/2018	ER18-195-000	AEP SPP OATT Projected Revenue Requirement	SPP OATT Att. H-4
16	20181213-5182	12/13/2018	ER18-195-000	AEP SPP OATT Projected Revenue Requirement	SPP OATT Att. H-4
17	20190528-5199	05/28/2019	ER18-195-000	AEP SPP 2019 Trans FR Update	SPP OATT Att. H-4
18	20190723-5114	07/23/2019	ER18-195-000	AEP SPP OATT Projected Revenue Requirement	SPP OATT Att. H-4
19	20190724-5030	07/24/2019	ER18-195-000	AEP SPP OATT Projected Revenue Requirement	SPP OATT Att. H-4
20	20190731-5132	07/31/2019	ER18-195-000	AEP SPP OATT Projected Revenue Requirement	SPP OATT Att. H-4
21	20191031-5138	10/31/2019	ER18-195-000	AEP SPP OATT Projected Revenue Requirement	SPP OATT Att. H-4
22	20200526-5243	05/26/2020	ER18-195-000	AEP SPP 2020 Trans FR Update	SPP OATT Att. H-4
23	02200609-5107	06/09/2020	ER18-195-000	AEP SPP 2020 Trans FR Update	SPP OATT Att. H-4
24	20201102-5246	11/02/2020	ER18-195-000	AEP SPP OATT Projected Revenue Requirement	SPP OATT Att. H-4
25	20210525-5227	05/25/2021	ER18-195-000	AEP SPP 2021 Trans FR Update	SPP OATT Att. H-4
26	20211101-5258	11/01/2021	ER18-195-000	AEP SPP OATT Projected Revenue Requirement	SPP OATT Att. H-4
27	20220525-5165	05/25/2022	ER18-195-000	AEP SPP 2022 Trans FR Update	SPP OATT Att. H-4
28	20220602-5172	06/02/2022	ER18-195-000	AEP SPP 2022 Trans FR Update	SPP OATT Att. H-4
29	20221101-5102	11/01/2022	ER18-195-000	AEP SPP OATT Projected Revenue Requirement	SPP OATT Att. H-4

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
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

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

Community of Scottsville renewed on 11/01/2022 for 30 years with no consideration
None
Lone Star Plant (retired) sale – November 2022
None
None
None
None
Wage agreements, effective January 1, 2022, resulted in general increase of 2% settlement for certain represented employees. Wage agreements, effective September 1, 2022, resulted in general increase of 3.5% + adders to settlement for certain journey level employees . Wage agreements, effective October 1, 2022, resulted in Market adjustment for certain classifications employees .
None
None
Not Used
Sundararajan Rajagopalan, elected as Director effective on 07-02-2022 Feinberg M David, elected as Vice President effective on 08-25-2022 Simmons I Peggy, elected as Director effective on 09-22-2022 Beam T Christian, elected as Director effective on 09-22-2022 Ulrich R Phillip, elected as Director effective on 09-22-2022 Ulrich R Phillip, elected as Vice President effective on 09-14-2022 Barton M Lisa, resigned as Director effective on 09-20-2022 Patton R Charles, resigned as Director effective on 07-02-2022 Ann P Kelly, elected as Vice President and Chief Financial Officer effective on 11-29-2022 Ann P Kelly, elected as Director effective on 12-14-2022 Joel H Jansen, elected as Vice President effective on 10-28-2022 Julia A Sloat, resigned as Chief Financial Officer and Vice President effective on 11-29-2022 Nicholas K Akins, resigned as Director, Chairman of the Board,Chief Executive Officer effective on12-31-2022 Lisa M Barton, resigned as Vice President effective on 11-01-2022 A Malcolm Smoak, resigned as Director, President, Chief Operating Officer effective on 12-31-2022
Proprietary capital ratio exceeds 30%

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	11,404,522,259	10,263,469,551
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	372,772,642	241,510,675
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		11,777,294,901	10,504,980,226
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	3,419,289,601	3,195,141,719
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		8,358,005,300	7,309,838,507
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)		8,358,005,300	7,309,838,507
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)		89,761,839	88,583,108
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)
17	OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS
18	NonutilityProperty Nonutility Property (121)		1,887,251	1,945,738
19	AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Prov. for Depr. and Amort. (122)		65	65
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224	12,199,879	35,579,087
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances	228
24	OtherInvestments Other Investments (124)		1,025,469	1,025,469
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)		47,891,091	71,447,741
30	DerivativeInstrumentAssetsLongTerm Long-Term Portion of Derivative Assets (175)			1,123,619
31	DerivativeInstrumentAssetsHedgesLongTerm Long-Term Portion of Derivative Assets - Hedges (176)
32	OtherPropertyAndInvestments TOTAL Other Property and Investments (Lines 18-21 and 23-31)		63,003,755	111,121,720
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)		4,161,626	1,293,442
36	SpecialDeposits Special Deposits (132-134)		16,504,298	9,940,018
37	WorkingFunds Working Fund (135)
38	TemporaryCashInvestments Temporary Cash Investments (136)
39	NotesReceivable Notes Receivable (141)
40	CustomerAccountsReceivable Customer Accounts Receivable (142)		37,133,018	34,201,864
41	OtherAccountsReceivable Other Accounts Receivable (143)		11,046,796	14,015,337
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		34,184	311
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)			153,842,244
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)		61,529,721	35,285,927
45	FuelStock Fuel Stock (151)	227	(a) 64,682,162	67,208,288
46	FuelStockExpensesUndistributed Fuel Stock Expenses Undistributed (152)	227	2,463,830	1,935,438
47	Residuals Residuals (Elec) and Extracted Products (153)	227
48	PlantMaterialsAndOperatingSupplies Plant Materials and Operating Supplies (154)	227	(b) 85,132,769	69,905,257
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	2,725,866	65,592
53	NoncurrentPortionOfAllowances (Less) Noncurrent Portion of Allowances	228
54	StoresExpenseUndistributed Stores Expense Undistributed (163)	227	1,700	1,700
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)		(c) 36,695,215	31,072,454
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)
60	RentsReceivable Rents Receivable (172)		1,699,945	1,642,274
61	AccruedUtilityRevenues Accrued Utility Revenues (173)		48,996,691	31,543,228
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)		9,143	9,143
63	DerivativeInstrumentAssets Derivative Instrument Assets (175)		16,439,806	10,898,756
64	DerivativeInstrumentAssetsLongTerm (Less) Long-Term Portion of Derivative Instrument Assets (175)			1,123,619
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)		389,170,115	461,718,745
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		21,474,923	23,621,291
70	ExtraordinaryPropertyLosses Extraordinary Property Losses (182.1)	230a
71	UnrecoveredPlantAndRegulatoryStudyCosts Unrecovered Plant and Regulatory Study Costs (182.2)	230b
72	OtherRegulatoryAssets Other Regulatory Assets (182.3)	232	1,282,122,376	1,178,964,300
73	PreliminarySurveyAndInvestigationCharges Prelim. Survey and Investigation Charges (Electric) (183)		2,208,444	4,314,504
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)		4,300	4,300
77	TemporaryFacilities Temporary Facilities (185)
78	MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186)	233	69,649,648	54,635,153
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)		4,748,153	5,347,929
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	358,218,566	(d) 321,793,535
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		1,738,426,411	1,588,681,012
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		10,458,843,742	9,382,776,876

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	66,240	66,240
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	1,442,145,410	1,092,143,981
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	2,190,847,304	2,007,181,143
12	UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1)	118	45,220,224	43,826,284
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)	4,211,969	6,753,503
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		(a) 3,674,067,209	3,149,971,151
17	LongTermDebtAbstract LONG-TERM DEBT
18	Bonds Bonds (221)	256
19	ReacquiredBonds (Less) Reaquired Bonds (222)	256
20	AdvancesFromAssociatedCompanies Advances from Associated Companies (223)	256
21	OtherLongTermDebt Other Long-Term Debt (224)	256	3,325,000,000	3,325,000,000
22	UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225)
23	UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Debit (226)		5,941,480	6,283,263
24	LongTermDebt Total Long-Term Debt (lines 18 through 23)		(b) 3,319,058,520	3,318,716,737
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		143,340,592	102,739,605
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)		745,200	944,496
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		274,628	398,942
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		27,665,926	16,781,899
30	AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4)
31	AccumulatedProvisionForRateRefunds Accumulated Provision for Rate Refunds (229)		9,878,255	6,646,158
32	LongTermPortionOfDerivativeInstrumentLiabilities Long-Term Portion of Derivative Instrument Liabilities
33	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges Long-Term Portion of Derivative Instrument Liabilities - Hedges
34	AssetRetirementObligations Asset Retirement Obligations (230)		158,989,379	128,349,409
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		340,893,980	253,971,517
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)
38	AccountsPayable Accounts Payable (232)		212,249,363	162,396,555
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)		310,656,994
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		136,287,585	93,483,413
41	CustomerDeposits Customer Deposits (235)		65,371,614	62,433,820
42	TaxesAccrued Taxes Accrued (236)	262	35,703,239	28,188,801
43	InterestAccrued Interest Accrued (237)		34,795,018	34,701,363
44	DividendsDeclared Dividends Declared (238)
45	MaturedLongTermDebt Matured Long-Term Debt (239)
46	MaturedInterest Matured Interest (240)
47	TaxCollectionsPayable Tax Collections Payable (241)		8,543,821	6,301,277
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		204,579,550	171,072,349
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		13,671,720	13,418,776
50	DerivativesInstrumentLiabilities Derivative Instrument Liabilities (244)		1,374,224	2,065,670
51	LongTermPortionOfDerivativeInstrumentLiabilities (Less) Long-Term Portion of Derivative Instrument Liabilities
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)		1,023,233,127	574,062,023
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)
57	AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255)	266	434,367	965,349
58	DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256)
59	OtherDeferredCredits Other Deferred Credits (253)	269	41,456,591	45,290,183
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	612,665,725	640,309,452
61	UnamortizedGainOnReacquiredDebt Unamortized Gain on Reaquired Debt (257)
62	AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty Accum. Deferred Income Taxes-Accel. Amort.(281)	272	48,904,159	45,300,202
63	AccumulatedDeferredIncomeTaxesOtherProperty Accum. Deferred Income Taxes-Other Property (282)		1,049,455,685	982,477,955
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		348,674,379	(c) 371,712,306
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		2,101,590,906	2,086,055,447
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		10,458,843,742	9,382,776,875

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	2,435,089,872	2,572,147,082			2,435,089,872	2,572,147,082
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	1,423,728,545	1,664,020,710			1,423,728,545	1,664,020,710
5	MaintenanceExpense Maintenance Expenses (402)	320	148,782,630	136,655,492			148,782,630	136,655,492
6	DepreciationExpense Depreciation Expense (403)	336	289,223,073	265,954,178			289,223,073	265,954,178
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336	1,997,322	1,559,584			1,997,322	1,559,584
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	29,143,882	26,396,084			29,143,882	26,396,084
9	AmortizationOfElectricPlantAcquisitionAdjustments Amort. of Utility Plant Acq. Adj. (406)	336
10	AmortizationOfPropertyLossesUnrecoveredPlantAndRegulatoryStudyCosts Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
11	AmortizationOfConversionExpenses Amort. of Conversion Expenses (407.2)
12	RegulatoryDebits Regulatory Debits (407.3)		4,954,396	1,533,131			4,954,396	1,533,131
13	RegulatoryCredits (Less) Regulatory Credits (407.4)		72,000	72,000			72,000	72,000
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	126,830,017	115,472,123			126,830,017	115,472,123
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	37,907,895	20,904,546			37,907,895	20,904,546
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	1,724,002	328,909			1,724,002	328,909
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	326,568,555	367,658,822			326,568,555	367,658,822
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	308,596,438	344,586,328			308,596,438	344,586,328
19	InvestmentTaxCreditAdjustments Investment Tax Credit Adj. - Net (411.4)	266	530,982	865,243			530,982	865,243
20	GainsFromDispositionOfPlant (Less) Gains from Disp. of Utility Plant (411.6)			1,398				1,398
21	LossesFromDispositionOfServiceCompanyPlant Losses from Disp. of Utility Plant (411.7)			25,971				25,971
22	GainsFromDispositionOfAllowances (Less) Gains from Disposition of Allowances (411.8)		207	157,645			207	157,645
23	LossesFromDispositionOfAllowances Losses from Disposition of Allowances (411.9)			4,318				4,318
24	AccretionExpense Accretion Expense (411.10)		3,701,231	2,835,031			3,701,231	2,835,031
25	UtilityOperatingExpenses TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)		2,006,098,128	2,215,857,194			2,006,098,127	2,215,857,194
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		428,991,744	356,289,888			428,991,745	356,289,888
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)		141	248
35	NonoperatingRentalIncome Nonoperating Rental Income (418)		867	376
36	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1)	119	1,393,940	3,387,890
37	InterestAndDividendIncome Interest and Dividend Income (419)		17,354,919	9,190,207
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		4,918,057	7,005,488
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		772,113	679,707
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)		12,350
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		24,452,105	20,263,420
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)		62,897	23,683
44	MiscellaneousAmortization Miscellaneous Amortization (425)		25
45	Donations Donations (426.1)		9,053,468	150,534
46	LifeInsurance Life Insurance (426.2)
47	Penalties Penalties (426.3)		72,699	20,001
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		1,010,930	924,819
49	OtherDeductions Other Deductions (426.5)		25,890,660	20,243,868
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		36,090,680	21,362,904
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262	10,308	10,168
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262	4,520,013	2,496,182
54	IncomeTaxesOther Income Taxes-Other (409.2)	262	30,210	82,089
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272	2,072,277	776,599
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272	1,574,176	1,351,895
57	InvestmentTaxCreditAdjustmentsNonutilityOperations Investment Tax Credit Adj.-Net (411.5)
58	InvestmentTaxCredits (Less) Investment Tax Credits (420)
59	TaxesOnOtherIncomeAndDeductions TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)		4,041,814	2,979,221
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		7,596,761	1,879,736
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		118,468,048	112,146,729
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		2,843,877	2,788,715
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)		274,114	310,911
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)		4,864,538	329,296
68	OtherInterestExpense Other Interest Expense (431)		9,162,861	6,585,299
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		4,278,557	2,997,814
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		131,334,881	119,163,136
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		290,060,102	239,006,488
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	0
77	ExtraordinaryItemsAfterTaxes Extraordinary Items After Taxes (line 75 less line 76)
78	NetIncomeLoss Net Income (Total of line 71 and 77)		290,060,102	239,006,488

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		2,007,181,143	1,771,562,546
2	ChangesAbstract Changes
3	AdjustmentsToRetainedEarningsAbstract Adjustments to Retained Earnings (Account 439)
4	AdjustmentsToRetainedEarningsCreditAbstract Adjustments to Retained Earnings Credit
9	AdjustmentsToRetainedEarningsCredit TOTAL Credits to Retained Earnings (Acct. 439)
10	AdjustmentsToRetainedEarningsDebitAbstract Adjustments to Retained Earnings Debit
10.1	AdjustmentsToRetainedEarningsDebit Adj to Retained Earnings
15	AdjustmentsToRetainedEarningsDebit TOTAL Debits to Retained Earnings (Acct. 439)
16	BalanceTransferredFromIncome Balance Transferred from Income (Account 433 less Account 418.1)		288,666,161	235,618,597
17	AppropriationsOfRetainedEarningsAbstract Appropriations of Retained Earnings (Acct. 436)
22	AppropriationsOfRetainedEarnings TOTAL Appropriations of Retained Earnings (Acct. 436)
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 $18 par value - 7,536,640 shares outstanding		105,000,000
30.2	DividendsDeclaredCommonStock Total Dividends Decl - Common Stk (438)
36	DividendsDeclaredCommonStock TOTAL Dividends Declared-Common Stock (Acct. 438)		105,000,000
37	TransfersFromUnappropriatedUndistributedSubsidiaryEarnings Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
38	UnappropriatedRetainedEarnings Balance - End of Period (Total 1,9,15,16,22,29,36,37)		2,190,847,304	2,007,181,143
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)
47	AppropriatedRetainedEarningsIncludingReserveAmortization TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
48	RetainedEarnings TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)		2,190,847,304	2,007,181,143
	UnappropriatedUndistributedSubsidiaryEarningsAbstract UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49	UnappropriatedUndistributedSubsidiaryEarnings Balance-Beginning of Year (Debit or Credit)		43,826,284	40,438,394
50	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings for Year (Credit) (Account 418.1)		1,393,940	3,387,890
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)		45,220,224	43,826,284

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)	290,060,102	239,006,488
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	320,364,278	293,909,846
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of Regulatory Debits and Credits (Net)	4,882,396	1,461,131
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	18,470,218	22,497,198
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)	530,982	865,243
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	26,230,204	20,728,775
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	13,317,297	93,220,534
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory	2,660,274	63,633
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	64,496,921	15,624,756
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	83,377,826	645,508,243
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	3,417,087	31,837,513
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	4,918,057	7,005,488
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies	1,393,940	3,387,888
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription (a) Other (provide details in footnote):	21,004,657	52,145,129
18.2	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Mark-to-Market of Risk Management Contracts	6,232,496	7,294,516
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	535,191,095	1,173,783
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)	594,751,454	422,809,333
27	GrossAdditionsToNuclearFuelInvestingActivities Gross Additions to Nuclear Fuel
28	GrossAdditionsToCommonUtilityPlantInvestingActivities Gross Additions to Common Utility Plant
29	GrossAdditionsToNonutilityPlantInvestingActivities Gross Additions to Nonutility Plant
30	AllowanceForOtherFundsUsedDuringConstructionInvestingActivities (Less) Allowance for Other Funds Used During Construction	4,918,057	7,005,488
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
31.1	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Acquired Assets	658,466,665	356,799,495
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	1,248,300,062	772,603,340
36	AcquisitionOfOtherNoncurrentAssets Acquisition of Other Noncurrent Assets (d)
37	ProceedsFromDisposalOfNoncurrentAssets Proceeds from Disposal of Noncurrent Assets (d)	986,915	581,644
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	3,981,277	3,125,779
53.2	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription (Increase) Decrease in Other Special Deposits	996,053	889,558
53.3	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Notes Receivable from Associated Companies	153,842,244	153,842,244
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	1,088,493,573	921,848,603
59	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
60	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
61	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b)		1,150,000,000
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 Issuances Costs	25,000	12,359,541
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
67.1	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Proceeds on Capital Leaseback	537,238	877,789
67.2	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Notes Payable to Associated Companies - Issued	310,656,994
67.3	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Capital Contributions from Parent	350,001,429	280,000,000
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	661,170,661	1,418,518,248
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)		375,000,000
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 Associated Companies - Retired		124,613,838
78	NetDecreaseInShortTermDebt Net Decrease in Short-Term Debt (c)
80	DividendsOnPreferredStock Dividends on Preferred Stock
81	DividendsOnCommonStock Dividends on Common Stock	105,000,000
83	CashFlowsProvidedFromUsedInFinancingActivities Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)	556,170,661	918,904,410
85	NetIncreaseDecreaseInCashAndCashEquivalentsAbstract Net Increase (Decrease) in Cash and Cash Equivalents
86	NetIncreaseDecreaseInCashAndCashEquivalents Net Increase (Decrease) in Cash and Cash Equivalents (Total of line 22, 57 and 83)	2,868,184	1,770,411
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	1,293,444	3,063,854
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	4,161,628	1,293,444

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	(a) AEPSC	9,350	3,744,209
3	Economic & Business Development	AEPSC	920,923	597,994
4	Grid Solutions	AEPSC	920,923	607,565
5	Administrative and General Expenses - Operation	AEPSC	920,921,922,923,924,925,926,928,930.1,930.2,931	12,778,493
6	Corp Safety & Health	AEPSC	920,923	1,830,097
7	Information Technology	AEPSC	920,923	7,281,451
8	Audit Services	AEPSC	920,923	945,774
9	Infrastructure Ops & Support	AEPSC	920,923	1,201,939
10	Services for Jointly Owned Facility - North Central Wind	PSO	107,108,408,421,426,431,500,501,502,506,510,524,546,548,549,550,553,556,557,560,561,565,566,569,570,571,573,580,582,587,588,593,920,921,923,924,925,926,928,930,931,935,	41,232,388
11	Bus Ops & Perf Assurance	AEPSC	920,923	730,931
12	Factored Customer A/R Expense	AEP Credit	4,256	5,542,103
13	Legal GC/Administration	AEPSC	920,923	2,220,323
14	Central Machine Shop	APCo	107,108,512,513	312,588
15	Materials and Supplies	AEP Texas	107, 108, 154, 184, 566, 570, 583, 585, 592, 593, 596, 935	898,037
16	Materials and Supplies	KgPCo	107, 184, 570, 571, 592	380,023
17	Civil & Political Activities & Other Services	AEPSC	426.1,426.3,426.4,426.5	1,082,733
18	Materials and Supplies	OPCo	107, 184, 566, 570, 592	355,512
19	Operations & Performance Transformation	AEPSC	920,923	444,200
20	Construction Services	AEP Texas	107,108	617,003
21	Materials and Supplies	PSO	107, 163, 512, 513, 514, 553, 570, 571, 592, 923, 935	480,942
22	Rail Car Maintenance Facility	Cook Coal Terminal	151	7,720,942
23	Construction Services	AEPSC	107,108	74,791,834
24	Other Power Supply Expenses	AEPSC	556-557	4,203,551
25	Construction Services	PSO	107,108	593,988
26	Physical & Cyber Security	AEPSC	920,923	1,148,148
27	Corporate Accounting	AEPSC	920,923	2,477,519
28	Rail Car Lease	I&M	186	1,345,761
29	Treasury & Risk	AEPSC	920,923	1,759,574
30	Corporate Communications	AEPSC	920,923	818,900
31	Rail Car Maintenance	AEGCo	151	2,672,050
32	Corporate Human Resources	AEPSC	920,923	3,535,624
33	Non-power Goods or Services Provided for Affiliate
34	Real Estate & Workplace Svcs	AEPSC	920,923	1,785,368
35	Corporate Planning & Budgeting	AEPSC	920,923	1,546,324
36	Regulatory Services A&G	AEPSC	920,923	1,488,962
37	Customer Support
38	Regulatory Services	AEPSC	183,184,186,188	7,749,038
39	Customer Accounts Expenses - Operation	AEPSC	901,902,903,905	13,370,519
40	Steam Power Generation - Maintenance	AEPSC	510, 511, 512, 513, 514	1,921,618
41	Distribution Expenses - Operation	AEPSC	580, 581, 582, 583, 584, 586, 587, 588	3,390,600
42	Steam Power Generation - Operation	AEPSC	500, 501, 502, 505, 506	15,227,480
43	Environmental Services	AEPSC	920,923	501,462
44	Strategy & Transformation	AEPSC
45	Factored Customer A/R Bad Debts	AEP Credit, Inc.	426.5	7,138,597
46	Tax Services	AEPSC	920,923	898,498
19
20	Non-power Goods or Services Provided for Affiliated
21	Utility Operations	AEPSC
22	Non-power Goods or Services Provided for Affiliate
23	Administrative and General Expenses - Operation	DHLC	920,921,931	473,088
24	Building and Property Leases	AEPSC	454	1,048,272
25	Central Maintenance Facility	PSO	107,108,506,511,513,000	656,760
26	Construction Services	AEP Texas
27	Current and Accrued Liabilities	PSO	232	790,444
28	HVDC East Transmission Tie	AEP Texas	186, 561, 562, 570, 922, 924, 925	624,177
29	Materials and Supplies	AEP Texas	154	352,759
30	Rail Car Lease	I&M	151	650,372
31	Rail Car Lease	PSO	152	290,530
32	Fleet and Vehicle Charges	AEPSC	Various	265,795
33	Materials and Supplies	PSO	154	304,127
34	Research and Other Services	Sabine Mining Company	186	1,132,046
35	Non-power Goods or Services Provided by Affiliated
36	Factored Customer A/R Expense	AEP Credit, Inc.	426.5	5,542,103
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