FERC Form

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

NOTES TO FINANCIAL STATEMENTS

Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement, providing a subheading for each statement except where a note is applicable to more than one statement.
Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears on cumulative preferred stock.
For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant adjustments and requirements as to disposition thereof.
Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such restrictions.
If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be omitted.
For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements; status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such matters shall be provided even though a significant change since year end may not have occurred.
Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are applicable and furnish the data required by the above instructions, such notes may be included herein.

INDEX OF NOTES TO FINANCIAL STATEMENTS


			Glossary of Terms for Notes
1.			Organization and Summary of Significant Accounting Policies
2.			New Accounting Standards
3.			Comprehensive Income
4.			Rate Matters
5.			Effects of Regulation
6.			Commitments, Guarantees and Contingencies
7.			Dispositions
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.
AEP Texas						AEP Texas Inc., an AEP electric utility subsidiary.
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.
ARAM						Average Rate Assumption Method, an IRS approved method used to calculate the reversal of Excess ADIT for rate-making purposes.
ARO						Asset Retirement Obligations.
COVID-19						Coronavirus 2019, a highly infectious respiratory disease. In March 2020, the World Health Organization declared COVID-19 a worldwide pandemic.
CWIP						Construction Work in Progress.
EIS						Energy Insurance Services, Inc., a nonaffiliated captive insurance company.
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.
I&M						Indiana Michigan Power Company, an AEP electric utility subsidiary.
IRS						Internal Revenue Service.
ITC						Investment Tax Credit.
KPCo						Kentucky Power Company, an AEP electric utility subsidiary.
MTM						Mark-to-Market.
MW						Megawatt.


Term						Meaning

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.
OATT						Open Access Transmission Tariff.
OCC						Corporation Commission of the State of Oklahoma.
Oklaunion Power Station						A retired, single unit coal-fired generation plant totaling 650 MW located in Vernon, Texas. The plant was jointly-owned by AEP Texas, PSO and certain nonaffiliated entities.
OKTCo						AEP Oklahoma Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.
OPEB						Other Postretirement Benefits.
Operating Agreement						Agreement, dated January 1, 1997, as amended, by and among PSO and SWEPCo governing generating capacity allocation, energy pricing, and revenues and costs of third-party sales. AEPSC acts as the agent.
OTC						Over-the-counter.
Parent						American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
PJM						Pennsylvania – New Jersey – Maryland regional transmission organization.
PSO						Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PTC						Production Tax Credits.
Risk Management Contracts						Trading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges.
RTO						Regional Transmission Organization, responsible for moving electricity over large interstate areas.
SEC						U.S. Securities and Exchange Commission.
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.
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, PSO engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to approximately 570,000 retail customers in its service territory in eastern and southwestern Oklahoma. PSO sells electric power at wholesale to other utilities, municipalities and electric cooperatives.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Rates and Service Regulation

PSO’s rates are regulated by the FERC and the OCC. The FERC also regulates PSO’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 OCC also regulates certain intercompany transactions under various orders and affiliate statutes. Both the FERC and the OCC 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. PSO’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 PSO 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 OCC regulates all of the retail distribution operations and rates of PSO’s retail public utility subsidiaries on a cost basis. The OCC also regulates the retail generation/power supply operations and rates.

The FERC also regulates PSO’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. Bundled retail transmission rates are regulated, on a cost basis, by the OCC.

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

PSO’s accounting is subject to the requirements of the OCC 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:


·			The classification of deferred fuel as noncurrent rather than current.
·			The requirement to report deferred tax assets and liabilities separately rather than as a single amount.
·			The classification of accrued taxes as a single amount rather than as assets and liabilities.
·			The exclusion of current maturities of long-term debt from current liabilities.
·			The classification of accrued non-ARO asset removal costs as accumulated depreciation rather than regulatory liabilities.
·			The classification of finance lease payments as operating activities instead of financing activities.
·			The classification of gains/losses from disposition of allowances as utility operating expenses rather than as operating revenues.
·			The classification of 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 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 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 operation 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 deferred FICA taxes as taxes accrued rather than as a noncurrent liability.

Accounting for the Effects of Cost-Based Regulation

PSO’s financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.

Use of Estimates

The preparation of these financial statements requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.

Cash and Cash Equivalents

Cash and Cash Equivalents include Cash, Working Fund and Temporary Cash Investments on the balance sheets with original maturities of three months or less.

Supplementary Information


		2021			2020
For the Years Ended December 31,		(in millions)
Cash was Paid (Received) for:
	Interest (Net of Capitalized Amounts)	$	57.0		$	59.1
	Income Taxes (Net of Refunds)			(102.9)			(11.8)
Noncash Acquisitions Under Finance Leases				3.6			3.2
Noncash Contribution of Radial Assets from Parent				—			50.0
As of December 31,
Construction Expenditures Included in Current and Accrued Liabilities				56.8			35.5

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, PSO 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 PSO. 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 PSO. The assessment is performed by PSO, 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

PSO does not have any significant customers that comprise 10% or more of its operating revenues for the years ended December 31, 2021 and 2020.

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

Property, Plant and Equipment

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

Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in-service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed or is not probable, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.

Allowance for Funds Used During Construction

AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant.

Valuation of Nonderivative Financial Instruments

The book values of Cash, Special Deposits, Working Fund, Notes Receivable from Associated Companies, Notes Payable to Associated Companies, accounts receivable and accounts payable approximate fair value because of the short-term maturity of these instruments.

Fair Value Measurements of Assets and Liabilities

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.

For commercial activities, exchange-traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange-traded derivatives where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket-based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility.

AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan 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 fuel and related emission allowances and emission control chemicals/consumables is charged to Operation Expenses when the fuel is burned or the allowance or consumable is utilized. Fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as regulatory assets. These deferrals are amortized when refunded or when billed to customers in later months with the OCC’s review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the OCC. On a routine basis, the OCC reviews and/or audits PSO’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. PSO shares the majority of its Off-system Sales margins to customers either through an active FAC or other rate mechanisms. Where the FAC or Off-system Sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings.

Revenue Recognition

Regulatory Accounting

PSO’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

PSO recognizes revenues from customers for retail and wholesale electricity sales and electricity transmission and distribution delivery services. PSO 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 OCC’s regulatory treatment, PSO 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”, and are recognized by PSO 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. PSO 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, PSO records expenses when purchased electricity is received and when expenses are incurred. PSO defers unrealized MTM amounts as regulatory assets (for losses) and regulatory liabilities (for gains).

Energy Marketing and Risk Management Activities

PSO 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. PSO 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.

PSO recognizes revenues from marketing and risk management transactions that are not derivatives as the performance obligation of delivering the commodity is satisfied. Expenses from marketing and risk management activities that are not derivatives are also recognized upon delivery of the commodity.

PSO 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 PSO balance sheets as Derivative Instrument Assets or Liabilities, as appropriate, and on the statements of income in Operating Revenues. Realized gains and losses on marketing and risk management transactions are included in revenues or expenses based on the transaction’s facts and circumstances. However, in regulated jurisdictions subject to cost-based regulation, unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).

Certain qualifying marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge). In the event PSO 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, PSO 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

PSO expenses maintenance costs as incurred. If it becomes probable that PSO 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. PSO 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

PSO 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.

PSO applies the deferral methodology for the recognition of ITCs. Deferred ITCs are amortized to income tax expense over the life of the asset that generated the credit. Amortization of deferred ITCs begins when the asset is placed in-service, except where regulatory commissions reflect ITCs in the rate-making process, then amortization begins when the cash tax benefit is recognized. Alternatively, PTCs reduce income tax expense as they are earned. PTCs are earned when electricity is produced.

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

PSO participates in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans. Substantially all PSO employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. PSO also participates in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees. PSO 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	25	%
Fixed Income	59	%
Other Investments	15	%
Cash and Cash Equivalents	1	%

OPEB Plans Assets	Target
Equity	59	%
Fixed Income	40	%
Cash and Cash Equivalents	1	%

The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies or certain commingled funds). However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law.

For equity investments, the concentration limits are generally as follows:

•No security in excess of 5% of all equities.

•Cash equivalents must be less than 10% of an investment manager’s equity portfolio.

•No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager’s equity portfolio.

•No securities may be bought or sold on margin or other use of leverage.

For fixed income investments, each investment manager’s portfolio is compared to investment grade, diversified long and intermediate benchmark indices.

A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation. Real estate properties are illiquid, difficult to value and not actively traded. The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties. To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification. Real estate holdings include core, value-added and opportunistic classifications.

A portion of the pension assets is invested in private equity. Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance. Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded. The pension plan uses limited partnerships to invest across the private equity investment spectrum. The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise. The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investments.

AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses. AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral. All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested. The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security. The securities lending program’s objective is to provide modest incremental income with a limited increase in risk. As of December 31, 2021 and 2020, the fair value of securities on loan as part of the program was $137 million and $177 million, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned as of December 31, 2021 and 2020.

Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts. The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust. Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid. Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities. With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds. A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges. The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities.

Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal. The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities. The cash funds are valued each business day and provide daily liquidity.

Comprehensive Income (Loss)

Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners.

Subsequent Events

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

2. NEW ACCOUNTING STANDARDS

During the FASB’s standard-setting process and upon issuance of final standards, management reviews the new accounting literature to determine its relevance, if any, to PSO’s business. There are no new standards expected to have a material impact on PSO’s financial statements.

3. COMPREHENSIVE INCOME

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the years ended December 31, 2021 and 2020. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 8 - Benefit Plans for additional information.


	Cash Flow Hedge –
For the Year Ended December 31, 2021	Interest Rate
	(in millions)
Balance in AOCI as of December 31, 2020	$	0.1
Change in Fair Value Recognized in AOCI	—
Amount of (Gain) Loss Reclassified from AOCI
Interest on Long-Term Debt (a)	(0.1)
Reclassifications from AOCI, before Income Tax (Expense) Benefit	(0.1)
Income Tax (Expense) Benefit	—
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	(0.1)
Net Current Period Other Comprehensive Income (Loss)	(0.1)
Balance in AOCI as of December 31, 2021	$	—


	Cash Flow Hedge –
For the Year Ended December 31, 2020	Interest Rate
	(in millions)
Balance in AOCI as of December 31, 2019	$	1.1
Change in Fair Value Recognized in AOCI	—
Amount of (Gain) Loss Reclassified from AOCI
Interest on Long-Term Debt (a)	(1.3)
Reclassifications from AOCI, before Income Tax (Expense) Benefit	(1.3)
Income Tax (Expense) Benefit	(0.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	(1.0)
Net Current Period Other Comprehensive Income (Loss)	(1.0)
Balance in AOCI as of December 31, 2020	$	0.1

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

4. RATE MATTERS

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

2021 Oklahoma Base Rate Case

In April 2021, PSO filed a request with the OCC for a $172 million net annual increase in Oklahoma base rates based upon a 10% ROE. The proposed net annual increase includes: (a) a $57 million annual depreciation expense increase, of which $45 million is related to the accelerated depreciation recovery of the Oklaunion Power Station and Northeastern Plant, Unit 3 through 2026 and (b) $31 million related to increased SPP expenses. PSO also requested the continuation of its SPP Transmission Tariff that tracks transmission costs as well as continuation and expansion of its Distribution and Safety Reliability Rider to recover projects in its proposed grid transformation and revitalization plan, which includes $100 million annual capital spend over a 5 year period. In August 2021, PSO updated its request for a net annual revenue increase to appropriately reflect certain cost reductions and annualized rider revenues transitioning into base rates. PSO’s updated request filed with the OCC is for a $128 million net annual increase in Oklahoma base rates based upon a 10% ROE.

In September 2021, PSO, OCC staff and certain intervenors filed a contested joint stipulation and settlement agreement with the OCC that included a net annual revenue increase of $51 million based upon a 9.4% ROE. The agreement also included: (a) recovery of, with a debt return on, the Oklaunion Power Station regulatory asset through 2046 and continued recovery of Northeastern Plant, Unit 3 through 2040, (b) updated depreciation rates for plant in service, excluding coal production plant, (c) approval to defer a weighted average cost of capital carrying charge on PSO’s deferred tax asset associated with net operating loss on a stand-alone tax basis beginning in November 2021 and, contingent upon receipt of a supportive private letter ruling from the IRS, approval to collect the deferral through a rider over a 20-month period, (d) modification of the SPP transmission tariff to reduce the scope of tracked transmission expense and (e) modification of the Distribution Reliability and Safety Rider to limit recovery to previously approved projects not in service as of June 2021. PSO implemented an interim annual base rate increase of $51 million starting with the November 2021 billing cycle. In December 2021, the OCC approved the joint stipulation and settlement agreement without modifications. Effective February 2022, interim rates were terminated and updated rates and tariffs went into effect in accordance with the final order.

February 2021 Severe Winter Weather Impacts in SPP

In February 2021, severe winter weather had a significant impact in SPP, resulting in the declaration of Energy Emergency Alert Levels 2 and 3 for the first time in SPP’s history. The winter storm increased the demand for natural gas and restricted the available natural gas supply 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, PSO’s natural gas expenses and purchases of electricity still to be recovered from customers are $679 million as of December 31, 2021.

In April 2021, the OCC approved a waiver for PSO allowing the deferral of the extraordinary fuel and purchases of electricity, including a carrying charge at an interim rate of 0.75%, over a longer time period than what the FAC traditionally allows. In January 2022, PSO, OCC staff and certain intervenors filed a joint stipulation and settlement agreement with the OCC to approve PSO’s securitization of the extraordinary fuel and purchases of electricity. The agreement includes a determination that all of PSO’s extraordinary fuel and purchases of electricity were prudent and reasonable and a 0.75% carrying charge, subject to true-up based on actual financing costs. In February 2022, the OCC approved the joint stipulation and settlement agreement in its financing order.

FERC Rate Matters

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, including PSO. In March 2022, the FERC issued an order on the formal challenge which ruled in favor of the joint customers on certain issues, including an accounting issue in which the FERC determined that PSO should record public service commission fees in FERC account 928 rather than FERC account 408.1. The 2021 FERC Form 1 financial statements reflect the outcome of this order. If any refunds are ordered for previous years they will be processed as part of the annual formula rate filing true-up process.

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 are not deemed recoverable, it could materially reduce future net income and cash flows and impact financial condition.

Regulated Generating Unit that has been Retired

The Oklaunion Power Station was retired in September 2020 and sold to a nonaffiliated third-party in October 2020. As part of the 2021 Oklahoma Base Rate Case, PSO received approval from the OCC to recover the Oklaunion Power Station through 2046. See “2021 Oklahoma Base Rate Case” section of Note 4 for additional information.

Regulated Generating Unit to be Retired

In 2014, PSO received final approval from the Federal EPA to close Northeastern Plant, Unit 3, in 2026. The plant was originally scheduled to close in 2040. As a result of the early retirement date, PSO revised the useful life of Northeastern Plant, Unit 3, to the projected retirement date of 2026 and the incremental depreciation is being deferred on the balance sheets. As part of the 2021 Oklahoma Base Rate Case, PSO will continue to recover Northeastern Plant, Unit 3 through 2040. See “2021 Oklahoma Base Rate Case” section of Note 4 for additional information.

The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of December 31, 2021, of Northeastern Plant, Unit 3 that is planned for early retirement:


Net Book Value		Accelerated Depreciation		Cost of Removal			Projected Retirement Date	Current Authorized Recovery Period	Annual Depreciation (a)
(dollars in millions)
$	167.2	$	128.1	$	20.0	(b)	2026	(c)	$	14.9

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

(b)Includes Northeastern Plant, Unit 4, which was retired in 2016. Removal of Northeastern Plant, Unit 4, will be performed with Northeastern Plant, Unit 3, after retirement.

(c)Northeastern Plant, Unit 3 is currently being recovered through 2040.

Regulatory Assets and Liabilities

Regulatory assets and liabilities are comprised of the following items:


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


Regulatory assets pending final regulatory approval:

Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	$	13.90	$	15.80
COVID-19	0.30		0.30
Total Regulatory Assets Currently Not Earning a Return	14.20		16.10

Total Regulatory Assets Pending Final Regulatory Approval	14.20		16.10

Regulatory assets approved for recovery:

Regulatory Assets Currently Earning a Return
Unrecovered Winter Storm Fuel Costs	679.30		—		(a)
Under-recovered Fuel Costs	194.60		35.20		1 year
Plant Retirement Costs - Unrecovered Plant	99.50		70.40		25 years
Environmental Control Projects	25.20		26.50		19 years
Meter Replacement Costs	22.20		26.20		6 years
Storm-Related Costs	17.40		11.50		3 years
Red Rock Generating Facility	7.90		8.20		35 years
Other Regulatory Assets Approved for Recovery	1.90		0.50		various
Total Regulatory Assets Currently Earning a Return	1,048.00		178.50
Regulatory Assets Currently Not Earning a Return
Pension and OPEB Funded Status	22.90		52.30		12 years
Income Taxes Subject to Flow Through	13.50		10.40		28 years
Other Regulatory Assets Approved for Recovery	13.20		12.40		various
Total Regulatory Assets Currently Not Earning a Return	49.60		75.10

Total Regulatory Assets Approved for Recovery	1,097.60		253.60

Total FERC Account 182.3 Regulatory Assets	$	1,111.80	$	269.70

(a)In February 2022, the OCC approved PSO’s securitization of the Unrecovered Winter Storm Fuel Costs. The timing of securitization is to be determined. See ”February 2021 Severe Winter Weather Impacts in SPP” section of PSO Rate Matters in Note 4 for additional information.


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


Regulatory liabilities pending final regulatory determination:

Income Tax Related Regulatory Liabilities (a)
Excess ADIT that is Not Subject to Rate Normalization Requirements (b)	$	56.2	$	—
Total Regulatory Liabilities Pending Final Regulatory Determination	$	56.2	$	—

Regulatory liabilities approved for payment:

Regulatory Liabilities Currently Paying a Return
Over-recovered Fuel Costs	$	—	$	5.2	1 year
Total Regulatory Liabilities Currently Paying a Return	—		5.2
Regulatory Liabilities Currently Not Paying a Return
Other Regulatory Liabilities Approved for Payment	4.3		1.3		various
Total Regulatory Liabilities Currently Not Paying a Return	4.3		1.3
Income Tax Related Regulatory Liabilities (a)
Excess ADIT Associated with Certain Depreciable Property	389.3		397.0		(c)
Excess ADIT that is Not Subject to Rate Normalization Requirements	46.4		71.3		3 years
Income Taxes Subject to Flow Through	1.5		2.1		28 years
Total Income Tax Related Regulatory Liabilities	437.2		470.4

Total Regulatory Liabilities Approved for Payment	441.5		476.9

Total FERC 254 Account Regulatory Liabilities	$	497.7	$	476.9

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

(b)Amount represents regulatory liabilities for Excess ADIT as a result of a change in the state income tax rate. See the “Federal and State Tax Legislation” section of Note 12 for additional information.

(c)Refunded using ARAM.

6. COMMITMENTS, GUARANTEES AND CONTINGENCIES

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

PSO 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 PSO’s actual contractual commitments as of December 31, 2021:


Contractual Commitments	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Fuel Purchase Contracts (a)	$	48.2	$	23.0	$	—	$	—	$	71.2
Energy and Capacity Purchase Contracts	32.2		67.3		67.9		125.9		293.3
Total	$	80.4	$	90.3	$	67.9	$	125.9	$	364.5

(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

PSO enters into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of December 31, 2021, there were no material liabilities recorded for any indemnifications.

PSO is jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity.

Lease Obligations

PSO 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. PSO 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. 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.

OPERATIONAL CONTINGENCIES

Insurance and Potential Losses

PSO maintains insurance coverage normal and customary for electric utilities, subject to various deductibles. PSO 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 PSO. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers.

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cyber security incident. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition.

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

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

7. ACQUISITIONS AND DISPOSITIONS

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 at completion. PSO and SWEPCo will own undivided interests of 45.5% and 54.5% of the NCWF, respectively. In total, the three wind facilities will cost approximately $2 billion and consist of Traverse (998 MW), Maverick (287 MW) and Sundance (199 MW). Output from the NCWF will serve 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 beginning at commercial operation and until such time as amounts are reflected in base rates. The NCWF are subject to various regulatory performance requirements. If these performance requirements are not met, PSO would recognize a regulatory liability to refund retail customers. As of December 31, 2021 PSO had not incurred a material regulatory liability related to performance requirements for NCWF.

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 accordance with the guidance for “Business Combinations,” management determined that the acquisitions of Sundance and Maverick represent asset acquisitions. As of December 31, 2021, PSO had approximately $316 million of gross Utility Plant on the balance sheet related to the Sundance and Maverick NCWF projects. On an ongoing basis, management further determined that PSO and SWEPCo should apply the joint plant accounting model to account for their respective undivided interests in the assets, liabilities, revenues and expenses of Sundance and Maverick.

The Purchase and Sale Agreement (PSA) includes 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 and Maverick were built upon. These interests as lessee in each of the land contracts were transferred to Sundance and Maverick (and subsequently to PSO and SWEPCo) as a part of the closing of the PSA. As of December 31, 2021, the Noncurrent Obligations Under Operating Leases for Sundance and Maverick were $13 million and $18 million, respectively, on the balance sheet for PSO.

DISPOSITIONS

Oklaunion Power Station

In October 2020, AEP Texas, PSO and a nonaffiliated joint-owner executed an Environmental Liability and Property Transfer and Asset Purchase Agreement with a nonaffiliated third-party related to the Oklaunion Power Station site. The purchaser took ownership of the assets and assumed responsibility for environmental liabilities, including ash pond closure, asbestos abatement and decommissioning and demolition of the Oklaunion Power Station site. The sale had an immaterial impact on PSO’s financial statements in the fourth quarter of 2020.

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.

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

PSO 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. PSO 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. PSO records a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for rate-making purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.

Actuarial Assumptions for Benefit Obligations

The weighted-average assumptions used in the measurement of benefit obligations are shown in the following table:


	Pension Plans						OPEB
	December 31,
Assumption	2021			2020			2021		2020
Discount Rate	2.90	%		2.50	%		2.90	%	2.55	%
Interest Crediting Rate	4.00	%		4.00	%		NA		NA
Rate of Compensation Increase	5.10	%	(a)	5.05	%	(a)	NA		NA

(a)Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.

NA Not applicable.

A duration-based method is used to determine the discount rate for the plans. A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.

For 2021, the rate of compensation increase assumed varies with the age of the employee, ranging from 3% per year to 11.5% per year, with the average increase shown in the table above.

Actuarial Assumptions for Net Periodic Benefit Costs

The weighted-average assumptions used in the measurement of benefit costs are shown in the following table:


	Pension Plans						OPEB
	Year Ended December 31,
Assumption	2021			2020			2021		2020
Discount Rate	2.50	%		3.25	%		2.55	%	3.30	%
Interest Crediting Rate	4.00	%		4.00	%		NA		NA
Expected Return on Plan Assets	4.75	%		5.75	%		4.75	%	5.50	%
Rate of Compensation Increase	5.10	%	(a)	5.05	%	(a)	NA		NA

(a)Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.

NA Not applicable.

The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation, third-party forecasts and current prospects for economic growth.

The health care trend rate assumptions used for OPEB plans measurement purposes are shown below:


	December 31,
Health Care Trend Rates	2021		2020
Initial	6.25	%	6.50	%
Ultimate	4.50	%	4.50	%
Year Ultimate Reached	2029		2029

Significant Concentrations of Risk within Plan Assets

In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets. The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits. The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment. Management monitors the plans to control security diversification and ensure compliance with the investment policy. As of December 31, 2021, the assets were invested in compliance with all investment limits. See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details.

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

For the year ended December 31, 2021, the pension plans had an actuarial gain primarily due to an increase in the discount rate, partially offset by less favorable demographic experience than expected, resulting from the updated census information as of January 1, 2021. For the year ended December 31, 2021, the OPEB plans had an actuarial gain primarily due to an increase in the discount rate and an update of the projected reimbursements from the Employer Group Waiver Program under Medicare Part D. For the year ended December 31, 2020, the pension plans had an actuarial loss primarily due to a decrease in the discount rate, partially offset by a decrease in the assumed rate used to convert account balances to annuities. For the year ended December 31, 2020, the OPEB plans had an actuarial loss primarily due to a decrease in the discount rate and an update to the health care trend assumption, partially offset by updated projected per capita claims costs due to rate negotiations for Medicare advantage premium rates.

The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets, funded status and the presentation on the balance sheets. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively.


	Pension Plans				OPEB
	2021		2020		2021		2020
Change in Benefit Obligation	(in millions)
Benefit Obligation as of January 1,	$	279.9	$	267.5	$	64.0	$	64.7
Service Cost	8.0		7.3		0.6		0.7
Interest Cost	6.7		8.5		1.6		2.1
Actuarial (Gain) Loss	(17.2)		17.7		(6.8)		1.9
Plan Amendments	—		—		(0.3)		(0.7)
Benefit Payments	(24.8)		(21.1)		(7.0)		(6.8)
Participant Contributions	—		—		2.3		2.1
Benefit Obligation as of December 31,	$	252.6	$	279.9	$	54.4	$	64.0

Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1,	$	299.8	$	276.2	$	107.8	$	98.0
Actual Gain on Plan Assets	11.1		44.6		10.9		14.5
Company Contributions	0.1		0.1		—		—
Participant Contributions	—		—		2.3		2.1
Benefit Payments	(24.8)		(21.1)		(7.0)		(6.8)
Fair Value of Plan Assets as of December 31,	$	286.2	$	299.8	$	114.0	$	107.8

Funded Status as of December 31,	$	33.6	$	19.9	$	59.6	$	43.8


	Pension Plans				OPEB
	December 31,
	2021		2020		2021		2020
	(in millions)
Special Funds – Prepaid Benefit Costs	$	35.5	$	21.9	$	59.6	$	43.8
Miscellaneous Current and Accrued Liabilities – Short-term Benefit Liability	(0.1)		(0.1)		—		—
Accumulated Provision for Pensions and Benefits – Long-term Benefit Liability	(1.8)		(1.9)		—		—
Funded Status	$	33.6	$	19.9	$	59.6	$	43.8

Amounts Included in Regulatory Assets, Deferred Income Taxes and AOCI

The following tables show the components of the plans included in regulatory assets and the items attributable to the change in these components:


	Pension Plans				OPEB
	December 31,
	2021		2020		2021		2020
Components	(in millions)
Net Actuarial (Gain) Loss	$	35.0	$	55.9	$	(2.1)	$	10.5
Prior Service Credit	—		—		(10.0)		(14.1)

Recorded as
Regulatory Assets	$	35.0	$	55.9	$	(12.1)	$	(3.6)


	Pension Plans				OPEB
	2021		2020		2021		2020
Components	(in millions)
Actuarial Gain During the Year	$	(16.0)	$	(12.4)	$	(12.6)	$	(7.4)
Amortization of Actuarial Loss	(4.9)		(4.7)		—		(0.3)
Prior Service Credit	—		—		(0.3)		(0.7)
Amortization of Prior Service Credit	—		—		4.4		4.4
Change for the Year Ended December 31,	$	(20.9)	$	(17.1)	$	(8.5)	$	(4.0)

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 PSO using the percentages in the table below:


Pension Plan				OPEB
December 31,
2021		2020		2021		2020
5.3	%	5.4	%	5.6	%	5.5	%

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


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

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

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

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

(a)Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information.

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

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

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


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

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

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

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

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

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

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

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


Asset Class	Level 1		Level 2		Level 3		Other		Total		Year End Allocation
	(in millions)
Equities (a):
Domestic	$	542.3	$	—	$	—	$	—	$	542.3	9.7	%
International	676.3		—		—		—		676.3		12.2	%
Common Collective Trusts (c)	—		—		—		650.0		650.0		11.7	%
Subtotal – Equities	1,218.6		—		—		650.0		1,868.6		33.6	%

Fixed Income (a):
United States Government and Agency Securities	(1.4)		1,134.1		—		—		1,132.7		20.4	%
Corporate Debt	—		1,425.0		—		—		1,425.0		25.6	%
Foreign Debt	—		214.0		—		—		214.0		3.9	%
State and Local Government	—		56.0		—		—		56.0		1.0	%
Other – Asset Backed	—		0.8		—		—		0.8		—	%
Subtotal – Fixed Income	(1.4)		2,829.9		—		—		2,828.5		50.9	%

Infrastructure (c)	—		—		—		91.1		91.1		1.6	%
Real Estate (c)	—		—		—		231.6		231.6		4.2	%
Alternative Investments (c)	—		—		—		431.8		431.8		7.8	%
Cash and Cash Equivalents (c)	—		49.3		—		58.2		107.5		1.9	%
Other – Pending Transactions and Accrued Income (b)	—		—		—		(2.5)		(2.5)		—	%

Total	$	1,217.2	$	2,879.2	$	—	$	1,460.2	$	5,556.6	100.0	%

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

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

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


Asset Class	Level 1		Level 2		Level 3		Other		Total		Year End Allocation
	(in millions)
Equities:
Domestic	$	399.9	$	—	$	—	$	—	$	399.9	20.6	%
International	290.7		—		—		—		290.7		14.9	%
Common Collective Trusts (b)	—		—		—		264.7		264.7		13.6	%
Subtotal – Equities	690.6		—		—		264.7		955.3		49.1	%

Fixed Income:
Common Collective Trust – Debt (b)	—		—		—		186.4		186.4		9.6	%
United States Government and Agency Securities	(0.2)		199.7		—		—		199.5		10.2	%
Corporate Debt	—		248.7		—		—		248.7		12.8	%
Foreign Debt	—		34.9		—		—		34.9		1.8	%
State and Local Government	73.9		13.1		—		—		87.0		4.5	%
Subtotal – Fixed Income	73.7		496.4		—		186.4		756.5		38.9	%

Trust Owned Life Insurance:
International Equities	—		64.8		—		—		64.8		3.3	%
United States Bonds	—		135.9		—		—		135.9		7.0	%
Subtotal – Trust Owned Life Insurance	—		200.7		—		—		200.7		10.3	%

Cash and Cash Equivalents (b)	26.3		—		—		5.7		32.0		1.6	%
Other – Pending Transactions and Accrued Income (a)	—		—		—		2.2		2.2		0.1	%

Total	$	790.6	$	697.1	$	—	$	459.0	$	1,946.7	100.0	%

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

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

Accumulated Benefit Obligation

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


	December 31,
Accumulated Benefit Obligation	2021		2020
	(in millions)
Qualified Pension Plan	$	232.1	$	258.3
Nonqualified Pension Plans	1.5		1.6
Total	$	233.6	$	259.9

Obligations in Excess of Fair Values

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

Projected Benefit Obligation


	December 31,
	2021		2020
	(in millions)
Projected Benefit Obligation	$	1.9	$	2.0
Fair Value of Plan Assets	—		—
Underfunded Projected Benefit Obligation	$	(1.9)	$	(2.0)

Accumulated Benefit Obligation


	December 31,
	2021		2020
	(in millions)
Accumulated Benefit Obligation	$	1.5	$	1.6
Fair Value of Plan Assets	—		—
Underfunded Accumulated Benefit Obligation	$	(1.5)	$	(1.6)

Estimated Future Benefit Payments and Contributions

PSO expects contributions and payments for the pension plans of $100 thousand during 2021. 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, PSO 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 PSO’s assets. The payments include the participants’ contributions to the plan for their share of the cost. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results. The estimated payments for the pension benefits and OPEB are as follows:


	Estimated Payments
	Pension Plans		OPEB
	(in millions)
2022	$	20.3	$	7.1
2023	21.3		6.7
2024	20.5		7.0
2025	20.4		7.0
2026	20.0		6.8
Years 2027 to 2031, in Total	87.1		29.7

Components of Net Periodic Benefit Cost

The following table provides the components of net periodic benefit cost (credit) for the plans:


	Pension Plans				OPEB
	Years Ended December 31,
	2021		2020		2021		2020
	(in millions)
Service Cost	$	8.0	$	7.3	$	0.6	$	0.7
Interest Cost	6.7		8.5		1.6		2.1
Expected Return on Plan Assets	(12.3)		(14.5)		(5.0)		(5.2)
Amortization of Prior Service Credit	—		—		(4.4)		(4.4)
Amortization of Net Actuarial Loss	4.9		4.7		—		0.3
Net Periodic Benefit Cost (Credit)	7.3		6.0		(7.2)		(6.5)
Capitalized Portion	(3.4)		(2.8)		(0.3)		(0.3)
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	3.9	$	3.2	$	(7.5)	$	(6.8)

American Electric Power System Retirement Savings Plan

PSO 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, 2021 and 2020 were $5 million and $5 million, respectively.

9. BUSINESS SEGMENTS

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

10. DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

AEPSC is agent for and transacts on behalf of PSO.

PSO 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 PSO 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, PSO 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.

PSO 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. PSO 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. PSO 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 outstanding derivative contracts:

Notional Volume of Derivative Instruments

Volume

December 31,

Primary Risk Exposure

2021

2020

Unit of Measure

(in millions)

Commodity:

Power

11.9

MWhs

Natural Gas

1.3

—

MMBtus

Heating Oil and Gasoline

0.8

0.7

Gallons

Cash Flow Hedging Strategies

PSO 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. PSO does not hedge all commodity price risk.

PSO utilizes a variety of interest rate derivative transactions in order to manage interest rate risk exposure. PSO also utilizes interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. PSO 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, PSO 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,” PSO 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, PSO is required to post or receive cash collateral based on third-party contractual agreements and risk profiles. The netted cash collateral from third-parties against short-term and long-term risk management assets and netted cash collateral paid to third-parties against short-term and long-term risk management liabilities were immaterial as of December 31, 2021 and 2020.

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


	December 31, 2021
	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts -		in the Statement of		Presented in the Statement
Balance Sheet Location	Commodity (a)		Financial Position (b)		of Financial Position (c)
	(in millions)
Derivative Instrument Assets	$	12.4	$	(0.3)	$	12.1
Long-Term Portion of Derivative Instrument Assets	—		—		—

Derivative Instrument Liabilities	3.7		—		3.7
Long-Term Portion of Derivative Instrument Liabilities	—		—		—


	December 31, 2020
	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts -		in the Statement of		Presented in the Statement
Balance Sheet Location	Commodity (a)		Financial Position (b)		of Financial Position (c)
	(in millions)
Derivative Instrument Assets	$	10.5	$	(0.2)	$	10.3
Long-Term Portion of Derivative Instrument Assets	—		—		—

Derivative Instrument Liabilities	—		—		—
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)	2021		2020
	(in millions)
Operation Expenses	$	0.3	$	(0.2)
Maintenance Expenses	0.4		(0.3)
Other Regulatory Assets (a)	(3.6)		—
Other Regulatory Liabilities (a)	48.9		39.1
Total Gain on Risk Management Contracts	$	46.0	$	38.6

(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), PSO initially reports the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income on the balance sheets until the period the hedged item affects Net Income.

Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Operating Revenues or Operation Expenses on the statements of income or in Other Regulatory Assets or Other Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the years ended 2021 and 2020, PSO did not apply cash flow hedging to outstanding power derivatives.

PSO reclassifies gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income on the balance sheets into Interest on Long-term Debt on the statements of income in those periods in which hedged interest payments occur. During the years ended 2021 and 2020, PSO did not apply cash flow hedging to outstanding interest rate derivatives.

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

Cash flow hedges included in Accumulated Other Comprehensive Income on the balance sheets were immaterial for PSO for years ended 2021 and 2020.

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, surety bonds and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required.

Collateral Triggering Events

Credit Downgrade Triggers

A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. PSO has not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. PSO had no derivative contracts with collateral triggering events in a net liability position as of December 31, 2021 and 2020.

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,
2021				2020
Book Value		Fair Value		Book Value		Fair Value
(in millions)
$	1,924.1	$	2,163.7	$	1,377.5	$	1,732.1

Fair Value Measurements of Financial Assets and Liabilities

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

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


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

Derivative Instrument Assets
Risk Management Commodity Contracts (a) (b)	$	—	$	0.3	$	12.2	$	(0.4)	$	12.1

Liabilities:

Derivative Instrument Liabilities
Risk Management Commodity Contracts (a) (b)	$	—	$	3.7	$	0.1	$	(0.1)	$	3.7


	December 31, 2020
	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)

Derivative Instrument Assets
Risk Management Commodity Contracts (a) (b)	$	—	$	0.2	$	10.3	$	(0.2)	$	10.3

(a)Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.”

(b)Substantially comprised of power contracts.

The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:


	Derivative Instrument
Year Ended December 31, 2021	Assets (Liabilities)
	(in millions)
Balance as of December 31, 2020	$	10.3
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)	16.1
Settlements	(26.4)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)	12.1
Balance as of December 31, 2021	$	12.1

	Derivative Instrument
Year Ended December 31, 2020	Assets (Liabilities)
	(in millions)
Balance as of December 31, 2019	$	15.8
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)	11.9
Settlements	(27.6)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)	10.2
Balance as of December 31, 2020	$	10.3

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

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

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

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

December 31, 2021

Significant

Input/Range

Fair Value

Valuation

Unobservable

Weighted

Assets

Liabilities

Technique

Input (a)

Low

High

Average (b)

(in millions)

FTRs

12.2

0.1

Discounted Cash Flow

Forward Market Price

(18.39)

1.87

(2.57)

December 31, 2020

Significant

Input/Range

Fair Value

Valuation

Unobservable

Weighted

Assets

Liabilities

Technique

Input (a)

Low

High

Average (b)

(in millions)

FTRs

10.3

—

Discounted Cash Flow

Forward Market Price

(6.9)

0.5

(1.9)

(a)Represents market prices in dollars per MWh.

(b)The weighted-average is the product of the forward market price of the underlying commodity and volume weighted by term.

The following table provides the measurement uncertainty of fair value measurements to increases (decreases) in significant unobservable inputs related to FTRs as of December 31, 2021 and 2020:

Uncertainty of Fair Value Measurements

Significant Unobservable Input

Position

Change in Input

Impact on Fair Value

Measurement

Forward Market Price

Buy

Increase (Decrease)

Higher (Lower)

Forward Market Price

Sell

Increase (Decrease)

Lower (Higher)

12. INCOME TAXES

Income Tax Expense

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


	Years Ended December 31,
	2021			2020
	(in millions)
Charged (Credited) to Operating Expenses, Net:
Current	$	(109.1)		$	(11.1)
Deferred			114.1			15.9
Total			5.0			4.8

Charged (Credited) to Non-Operating Income, Net:
Current			(0.5)			(0.2)
Deferred			(0.4)			0.6
Total			(0.9)			0.4
Income Tax Expense	$	4.1		$	5.2

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


	Years Ended December 31,
	2021			2020
	(in millions)
Net Income	$	141.1		$	123.0
Income Tax Expense	4.1			5.2
Pretax Income	$	145.2		$	128.2

Income Taxes on Pretax Income at Statutory Rate (21%)	$	30.5		$	26.9
Increase (Decrease) in Income Taxes Resulting from the Following Items:
Depreciation	0.5			1.1
Investment Tax Credit Amortization	(1.8)			(2.1)
Production Tax Credits	(6.0)			—
Parent Company Loss Benefit	—			(0.2)
State and Local Income Taxes, Net	6.4			6.5
Tax Reform Excess ADIT Reversal	(25.4)			(25.5)
Other	(0.1)			(1.5)
Income Tax Expense	$	4.1		$	5.2

Effective Income Tax Rate	2.8		%	4.1		%

Net Deferred Tax Liability

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


	December 31,
	2021		2020
	(in thousands)
Deferred Tax Assets	$	170.0	$	239.8
Deferred Tax Liabilities	(952.3)		(928.3)
Net Deferred Tax Liabilities	$	(782.3)	$	(688.5)

Property Related Temporary Differences	$	(708.6)	$	(661.8)
Amounts Due to Customers for Future Income Taxes	111.5		118.5
Deferred State Income Taxes	(83.2)		(107.7)
Regulatory Assets	(228.0)		(39.1)
Net Operating Loss Carryforward	111.4		12.9
All Other, Net	14.6		(11.3)
Net Deferred Tax Liabilities	$	(782.3)	$	(688.5)

Tax Credit Carryforward

As of December 31, 2021, PSO has federal tax credit carryforwards in the amount of $6.3 million. If these credits are not utilized, federal general business tax credits will expire in the years 2036 through 2041. PSO anticipates future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused.

State net income tax operating losses sustained in 2017, 2011 and 2009 along with lower federal and state taxable income in 2010 resulted in unused state income tax credits. As of December 31, 2021 and December 31, 2020, PSO had state tax credit carryforwards of $39 million and $38 million, respectively. Management anticipates future taxable income will be sufficient to realize the tax benefits of the state tax credits before they expire unused.

AEP System Tax Allocation Agreement

PSO and other AEP subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax loss of the parent company (Parent Company Loss Benefit) to the AEP System subsidiaries with taxable income reducing their current tax expense proportionately. The consolidated NOL of the AEP System is allocated to each company in the consolidated group with taxable losses. With the exception of the allocation of the consolidated AEP System NOL, the loss of the Parent and tax credits, the method of allocation reflects a separate return result for each company in the consolidated group.

Net Income Tax Operating Loss Carryforward

As of December 31, 2021, PSO has Oklahoma state net income tax operating loss carryforward of $1.3 billion. As a result, PSO recognized deferred state income tax benefits. Management anticipates future taxable income will be sufficient to realize the state net income tax operating loss tax benefits before the state carryforward expires.

Federal and State Income Tax Audit Status

The statute of limitations for the IRS to examine PSO and other AEP subsidiaries originally filed federal return has expired for tax years 2016 and earlier. In the third quarter of 2019, PSO and other AEP subsidiaries elected to amend the 2014 through 2017 federal returns. In the first quarter of 2020, the IRS notified PSO and other AEP subsidiaries that it was beginning an examination of these amended returns, including the net operating loss carryback to 2015 that originated in the 2017 return. As of December 31, 2021, the IRS has not issued any proposed adjustments and the IRS is limited in their proposed adjustments to the amount PSO and other AEP subsidiaries claimed on the amended returns. PSO has agreed to extend the statute of limitations on the 2017 tax return to December 31, 2022 to allow time for the audit to be completed and the Congressional Joint Committee on Taxation to approve the associated refund claim.

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

Federal and State Tax Legislation

IRS Notice 2021-41 was issued in June 2021 by the IRS providing further extension of the continuity safe harbor for PTC and ITC-eligible projects and revising the facts and circumstances rules. For PTC and ITC-eligible projects for which construction began in calendar years 2016 through 2019, the continuity safe harbor is extended to six years. Prior guidance (IRS Notice 2020-41) had only extended the safe harbor for projects beginning in 2016 and 2017 to 5 years. Furthermore, for PTC and ITC-eligible projects for which construction began in 2020, the continuity safe harbor is extended to five years. Under a facts and circumstances analysis, the continuity requirement may be satisfied under either the continuous construction test or the continuous efforts test, regardless of whether the physical work test or the five percent safe harbor is used.

In May 2021, Oklahoma enacted HB 2960. HB 2960 reduces the Oklahoma corporate income tax rate from 6% to 4%. During 2021, AEP recorded an immaterial amount of Income Tax Benefit as a result of remeasuring Oklahoma deferred taxes at the lowered statutory tax rate of 4%.

13. LEASES

PSO 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. PSO 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 PSO 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, PSO measures its lease obligation using its estimated secured incremental borrowing rate. Incremental borrowing rates are comprised of an underlying risk-free rate and a secured credit spread relative to the lessee on a matched maturity basis.

Operating and Finance lease rental costs are generally charged to Operation Expense and Maintenance Expense in accordance with rate-making treatment for regulated operations. Lease costs associated with capital projects are included in Utility Plant on the balance sheets. For regulated operations with finance leases, a finance lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. The components of rental costs were as follows:


	Years Ended December 31,
	2021		2020
	(in millions)
Operating Lease Cost	$	8.7	$	7.8
Finance Lease Cost:
Amortization of Right-of-Use Assets	3.2		3.5
Interest on Lease Liabilities	0.6		0.7
Total Lease Rental Costs (a)	$	12.5	$	12.0

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

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


	December 31,
	2021		2020
Weighted-Average Remaining Lease Term (years):
Operating Leases	20.89		7.03
Finance Leases	6.18		6.16
Weighted-Average Discount Rate:
Operating Leases	3.35	%	3.39	%
Finance Leases	4.23	%	4.35	%


	Year Ended December 31,
	2021		2020
	(in millions)
Cash paid for amounts included in the measurement of lease liabilities:
Operating Cash Flows from Operating Leases	$	8.7	$	7.7
Operating Cash Flows from Finance Leases	3.8		4.2

Non-cash Acquisitions Under Operating Leases	$	33.4	$	12.3

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


	December 31,
	2021		2020
	(in millions)
Property, Plant and Equipment Under Finance Leases
Utility Plant (a)	$	15.3	$	15.0

Obligations Under Finance Leases
Noncurrent	$	12.3	$	11.9
Current	3.0		3.1
Total Obligations Under Finance Leases	$	15.3	$	15.0

(a) Includes $9 million and $9 million of accumulated provision for depreciation and amortization for the years ended December 31, 2021 and 2020, respectively.


	December 31,
	2021		2020
	(in millions)
Property, Plant and Equipment Under Operating Leases
Utility Plant (a)	$	68.9	$	42.6

Obligations Under Operating Leases
Noncurrent	$	62.2	$	36.2
Current	6.9		6.5
Total Obligations Under Operating Leases	$	69.1	$	42.7

(a) Includes $15 million and $10 million of accumulated provision for depreciation and amortization for the years ended December 31, 2021 and 2020, respectively.

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


	Finance Leases		Operating Leases
	(in millions)
2022	$	3.6	$	9.2
2023	3.3		8.9
2024	2.8		8.1
2025	2.1		6.9
2026	1.8		6.0
After 2026	3.9		62.6
Total Future Minimum Lease Payments	17.5		101.7
Less: Imputed Interest	2.2		32.6
Estimated Present Value of Future Minimum Lease Payments	$	15.3	$	69.1

Master Lease Agreements

PSO 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, PSO is committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the amount guaranteed. As of December 31, 2021, the maximum potential loss by PSO 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

PSO’s lessor activity was immaterial as of and for the twelve months ended December 31, 2021 and December 31, 2020, 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, 2021	2021	2020	2021		2020
Senior Unsecured Notes	2021-2051	3.74%	2.20%-6.63%	3.05%-6.63%	$	1,800.0	$	1,250.0
Other Long-term Debt	2022-2027	1.50%	1.47%-3.00%	1.42%-3.00%	128.1		128.5
Unamortized Discount, Net					(3.9)		(1.0)
Total Long-term Debt Outstanding					$	1,924.2	$	1,377.5

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


	(in millions)
2022	$	125.5
2023	0.5
2024	0.6
2025	125.6
2026	50.6
After 2026	1,625.3
Principal Amount	1,928.1
Unamortized Discount, Net	(3.9)
Total Long-term Debt	$	1,924.2

Long-term Debt Subsequent Events

In February 2022, PSO issued $500 million of variable rate Other Long-term Debt due in 2022.

Dividend Restrictions

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

All of the dividends declared by PSO are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only.

PSO 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 PSO is through the credit agreements. As of December 31, 2021, the maximum amount of restricted net assets of PSO that may not be distributed to the Parent in the form of a loan, advance or dividend was $1.2 billion.

The credit agreement covenant restrictions can limit the ability of PSO to pay dividends out of retained earnings. As of December 31, 2021, there were no restrictions on PSO’s ability to pay dividends out of retained earnings.

Corporate Borrowing Program – AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of its agreement filed with the FERC. The amounts of outstanding borrowings from the Utility Money Pool as of December 31, 2021 and 2020 are included in Notes Payable to Associated Companies on the balance sheets. PSO’s money pool activity and corresponding authorized borrowing limits are described in the following table:


	Maximum				Average
	Borrowings		Maximum		Borrowings		Average		Borrowings from		Authorized
	from the		Loans to the		from the		Loans to the		the Utility Money		Short-term
Years ended	Utility		Utility		Utility		Utility		Pool as of		Borrowing
December 31,	Money Pool		Money Pool		Money Pool		Money Pool		December 31,		Limit
	(in millions)
2021	$	267.7	$	747.3	$	134.0	$	113.1	$	72.3	$	400.0
2020	155.4		57.1		72.3		28.4		155.4		300.0

The maximum, minimum and average interest rates for funds either borrowed from or loaned to the Utility Money Pool are summarized in the following table:


	Maximum		Minimum		Maximum		Minimum		Average		Average
	Interest Rates		Interest Rates		Interest Rates		Interest Rates		Interest Rate		Interest Rate
	for Funds		for Funds		for Funds		for Funds		for Funds		for Funds
	Borrowed from		Borrowed from		Loaned to the		Loaned to the		Borrowed from		Loaned to the
Years ended	the Utility		the Utility		Utility Money		Utility Money		the Utility		Utility Money
December 31,	Money Pool		Money Pool		Pool		Pool		Money Pool		Pool
	(in millions)
2021	0.48	%	0.07	%	0.48	%	0.02	%	0.34	%	0.07	%
2020	2.70	%	0.27	%	2.10	%	1.80	%	0.92	%	1.95	%

Interest expense and interest income related to the Utility Money Pool financing relationship are included in Interest on Debt to Associated Companies and Interest and Dividend Income, respectively, on the statements of income. The interest expense and interest income related to the corporate borrowing programs were immaterial for the years ended December 31, 2021 and 2020.

Securitized Accounts Receivables – AEP Credit

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

AEP Credit has a receivables securitization agreement that provides a commitment of $750 million from bank conduits to purchase receivables and was amended in September 2021 to include a $125 million and a $625 million facility, which expire in September 2023 and 2024, respectively.

The amount of accounts receivable and accrued utility revenues under the sale of receivables agreement as of December 31, 2021 and 2020 were $115 million and $85 million, respectively.

The fees paid to AEP Credit for customer accounts receivable sold were $3 million and $5 million for the years ended December 31, 2021 and 2020, respectively. In 2020, an increase in allowance for doubtful accounts was recognized in response to the anticipated impact of COVID-19 on the collectability of accounts receivable, which caused an increase in fees paid by PSO. In 2021, due to higher than expected collections of accounts receivables, allowance for doubtful accounts was adjusted resulting in the issuance of credits to offset the higher fees previously paid and to lower subsequent fees paid.

The proceeds on the sale of receivables to AEP Credit were $1.4 billion and $1.2 billion for the years ended December 31, 2021 and 2020, respectively.

15. RELATED PARTY TRANSACTIONS

For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 12 in addition to “Corporate Borrowing Program – AEP System” and “Securitized Accounts Receivables – AEP Credit” sections of Note 14.

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 PJM generally accrue to the benefit of APCo, I&M, KPCo and WPCo, while 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

The following table shows the revenues derived from other revenues for the years ended December 31, 2021 and 2020:


	Years Ended December 31,
Related Party Revenues	2021		2020
	(in millions)
Other Revenues	$	4.2	$	5.2

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. PSO’s net expenses allocated among parties to the TCA pursuant to the SPP OATT protocols were $95 million and $70 million for the years ended December 31, 2021 and 2020, respectively. The net expenses were recorded in Operation Expenses on the statements of income.

Joint License Agreement

AEPTCo entered into a 50-year joint license agreement with PSO allowing either party to occupy the granting party’s facilities or real property. After the expiration of the agreement, the term shall automatically renew for successive one-year terms unless either party provides notice. The joint license billing provides compensation to the granting party for the cost of carrying assets, including depreciation expense, property taxes, interest expense, return on equity and income taxes. For the years ended December 31, 2021 and 2020, PSO billed AEPTCo $416 thousand and $369 thousand, respectively.

Cook Coal Terminal

Cook Coal Terminal also performs railcar maintenance services at cost for PSO. AEGCo billed PSO $419 thousand and $678 thousand for the years ended December 31, 2021 and 2020, respectively, for railcar maintenance services. PSO recorded the cost of the railcar maintenance services in Fuel Stock on the balance sheets.

Central Machine Shop

APCo operates a facility which repairs and rebuilds specialized components for the generation plants across the AEP System. PSO recorded billings from APCo of $739 thousand and $900 thousand as capital or maintenance expenses depending on the nature of the services received for the years ended December 31, 2021 and 2020, respectively. These billings are recoverable from customers.

Sales and Purchases of Property

PSO had affiliated sales and purchases of electric property amounting to $100 thousand or more, sales and purchases of meters and transformers, and sales and purchases of transmission property. There were no gains or losses recorded on the transactions. The following table shows the sales and purchases, recorded at net book value:


	Years Ended December 31,
	2021		2020
	(in millions)
Sales	$	0.5	$	1.1
Purchases	0.3		0.4

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

Intercompany Billings

PSO 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 PSO. The costs of the services are based on a direct charge or on a prorated basis and billed to PSO at AEPSC’s cost. AEPSC and its billings are subject to regulation by the FERC. PSO’s total billings from AEPSC were $124 million and $113 million for the years ended December 31, 2021 and 2020, respectively.

Charitable Contributions to AEP Foundation

The American Electric Power Foundation is funded by American Electric Power and its utility operating units. The Foundation provides a permanent, ongoing resource for charitable initiatives and multi-year commitments in the communities served by AEP and initiatives outside of AEP’s 11-state service area. Charitable contributions to the AEP Foundation were recorded in Donations on the statements of income. In 2021 and 2020, there were no charitable contributions made to the AEP Foundation.

OKTCo Radial Assets Transfer

In August 2020, AEPSC filed a request with FERC, on behalf of PSO and OKTCo, to transfer OKTCo’s interests in its radial assets to PSO. OKTCo had previously constructed radial assets in the PSO service territory and after the radial assets were placed into service, management determined the radial assets were not eligible to be included as part of OKTCo’s SPP OATT formula rates. In October 2020, FERC approved the request and in December 2020, OKTCo completed the transfer of its interest in the radial assets to PSO, through Parent, at net book value. At the transfer date, the net book value of the radial assets were $60 million, before associated tax liabilities.

16. PROPERTY, PLANT AND EQUIPMENT

Depreciation

PSO 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)
2021	3.2	%	1.4	%	2.4	%	2.9	%	6.1	%
2020	3.1	%	3.3	%	2.2	%	2.9	%	5.7	%

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

PSO records ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities and wind farms. PSO 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 PSO plans to use its facilities indefinitely. The retirement obligation would only be recognized if and when PSO abandons or ceases the use of specific easements, which is not expected.

In 2020, PSO recorded a revision to decrease estimated ARO liabilities by $5 million due to the retirement of the Oklaunion Power Station in September 2020. See “Oklaunion Power Station” section of Note 7 for additional information.

The following is a reconciliation of the 2021 and 2020 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)
2021	$	47.4	$	3.3	$	7.6	$	(0.7)	$	—	$	57.6	(a)(b)
2020	52.2		3.1		—		(3.1)		(4.8)		47.4		(a)(b)

(a)Includes ARO related to ash disposal facilities.

(b)Includes ARO related to asbestos removal.

Jointly-owned Electric Facilities

PSO has an electric facility that is jointly-owned with SWEPCo. Using its own financing, PSO is obligated to pay its share of the costs of this jointly-owned facility in the same proportion as its ownership interest. PSO’s proportionate share of the operating costs associated with this facility are 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, 2021
	Fuel Type	Percent of Ownership		Utility Plant in Service		Construction Work in Progress		Accumulated Depreciation
				(in millions)
North Central Wind Energy Facilities (a)(b)	Wind	45.5	%	$	313.7	$	—	$	4.2

(a)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. See the “Acquisitions” section of Note 7 for additional information.

(b)Operated by PSO.

17. REVENUE FROM CONTRACTS WITH CUSTOMERS

Disaggregated Revenues from Contracts with Customers

The tables below represent revenues from contracts with customers, net of respective provisions for refund, by type of revenue for PSO:


	Years Ended December 31,
	2021		2020
	(in millions)
Retail Revenues:
Residential Revenues	$	651.9	$	579.5
Commercial Revenues	378.9		320.1
Industrial Revenues	274.1		221.1
Other Retail Revenues	77.7		66.0
Total Retail Revenues	1,382.6		1,186.7

Wholesale Revenues:
Generation Revenues	58.0		30.2
Transmission Revenues	37.5		27.5
Total Wholesale Revenues	95.5		57.7

Other Revenues from Contracts with Customers (a)	23.1		34.0

Total Revenues from Contracts with Customers	1,501.2		1,278.4

Other Revenues:
Alternative Revenues	0.1		2.2
Total Other Revenues	0.1		2.2

Total Operating Revenues	$	1,501.3	$	1,280.6

(a)Amounts include affiliated and nonaffiliated revenues.

Performance Obligations

PSO 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. PSO 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 PSO are summarized as follows:

Retail Revenues

PSO 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 PSO 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

PSO 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.

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

PSO has performance obligations to transmit electricity to wholesale customers through assets it owns and operates. The performance obligation to provide transmission services in SPP encompasses a time frame greater than a year, where the performance obligation within each RTO is partially fixed for a period of one year or less. Payments from the RTO for transmission services are typically received within one week from the issuance of the invoice, which is issued monthly for SPP.

PSO within the SPP region 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 table above.

Fixed Performance Obligations

The following table represents the remaining fixed performance obligations satisfied over time as of December 31, 2021. Fixed performance obligations primarily include wholesale transmission services and electricity sales for fixed amounts of energy. The amounts shown in the table below include affiliated and nonaffiliated revenues.


2022		2023-2024		2025-2026		After 2026		Total
(in millions)
$	13.1	$	—	$	—	$	—	$	13.1

Contract Assets and Liabilities

Contract assets are recognized when PSO 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. PSO did not have any material contract assets as of December 31, 2021 and 2020.

When PSO 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. PSO’s contract liabilities typically arise from services provided under joint use agreements for utility poles. PSO did not have any material contract liabilities as of December 31, 2021 and 2020.

Accounts Receivable from Contracts with Customers

Accounts receivable from contracts with customers are presented on PSO’s balance sheets within the Customer Accounts Receivable line item. PSO’s balances for receivables from contracts that are not recognized in accordance with the accounting guidance for “Revenue from Contracts with Customers” included in Customer Accounts Receivable were not material as of December 31, 2021 and 2020. See “Securitized Accounts Receivable - AEP Credit” section of Note 14 for additional information.

The amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable from Associated Companies on PSO’s balance sheets were $19 million and $8 million, as of December 31, 2021 and 2020.

Contract Costs

Contract costs to obtain or fulfill a contract for PSO 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. PSO did not have material contract costs as of December 31, 2021 and 2020.

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote. Report data on a year-to-date basis.
Line No.	Item (a)	Unrealized Gains and Losses on Available-For-Sale Securities (b)	Minimum Pension Liability Adjustment (net amount) (c)	Foreign Currency Hedges (d)	Other Adjustments (e)	Other Cash Flow Hedges Interest Rate Swaps (f)	Other Cash Flow Hedges [Specify] (g)	Totals for each category of items recorded in Account 219 (h)	Net Income (Carried Forward from Page 116, Line 78) (i)	Total Comprehensive Income (j)
1	Balance of Account 219 at Beginning of Preceding Year					1,094,731		1,094,731
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income					1,010,522		1,010,522
3	Preceding Quarter/Year to Date Changes in Fair Value
4	Total (lines 2 and 3)					1,010,522		1,010,522	122,954,783	121,944,261
5	Balance of Account 219 at End of Preceding Quarter/Year					84,209		84,209
6	Balance of Account 219 at Beginning of Current Year					84,209		84,209
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income					84,209		84,209
8	Current Quarter/Year to Date Changes in Fair Value
9	Total (lines 7 and 8)					84,209		84,209	141,082,110	140,997,901
10	Balance of Account 219 at End of Current Quarter/Year

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in column (h) common function.
Line No.	Classification (a)	Total Company For the Current Year/Quarter Ended (b)	Electric (c)	Gas (d)	Other (Specify) (e)	Other (Specify) (f)	Other (Specify) (g)	Common (h)
1	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlantInServiceAbstract In Service
3	UtilityPlantInServiceClassified Plant in Service (Classified)	5,930,027,441	5,930,027,441
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	84,244,316	84,244,316
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified	391,744,394	391,744,394
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	6,406,016,151	6,406,016,151
9	UtilityPlantLeasedToOthers Leased to Others
10	UtilityPlantHeldForFutureUse Held for Future Use	738,262	738,262
11	ConstructionWorkInProgress Construction Work in Progress	156,816,557	156,816,557
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments	3,490,722	3,490,722
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	6,567,061,692	6,567,061,692
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	1,870,450,115	1,870,450,115
15	UtilityPlantNet Net Utility Plant (13 less 14)	4,696,611,577	4,696,611,577
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	1,797,595,913.00	1,797,595,913.00
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	69,363,479.90	69,363,479.90
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	1,866,959,393	1,866,959,393
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
29	AmortizationUtilityPlantHeldForFutureUse Amortization
30	DepreciationAndAmortizationUtilityPlantHeldForFutureUse Total Held for Future Use (28 & 29)
31	AbandonmentOfLeases Abandonment of Leases (Natural Gas)
32	AmortizationOfPlantAcquisitionAdjustment Amortization of Plant Acquisition Adjustment	3,490,722	3,490,722
33	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Total Accum Prov (equals 14) (22,26,30,31,32)	1,870,450,115	1,870,450,115

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)
Report below the costs incurred for nuclear fuel materials in process of fabrication, on hand, in reactor, and in cooling; owned by the respondent. If the nuclear fuel stock is obtained under leasing arrangements, attach a statement showing the amount of nuclear fuel leased, the quantity used and quantity on hand, and the costs incurred under such leasing arrangements.
Line No.	Description of item (a)	Balance Beginning of Year (b)	Changes during Year Additions (c)	Changes during Year Amortization (d)	Changes during Year Other Reductions (Explain in a footnote) (e)	Balance End of Year (f)
1	Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1)
2	Fabrication
3	Nuclear Materials
4	Allowance for Funds Used during Construction
5	(Other Overhead Construction Costs, provide details in footnote)
6	SUBTOTAL (Total 2 thru 5)
7	Nuclear Fuel Materials and Assemblies
8	In Stock (120.2)
9	In Reactor (120.3)
10	SUBTOTAL (Total 8 & 9)
11	Spent Nuclear Fuel (120.4)
12	Nuclear Fuel Under Capital Leases (120.6)
13	(Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5)
14	TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13)
15	Estimated Net Salvage Value of Nuclear Materials in Line 9
16	Estimated Net Salvage Value of Nuclear Materials in Line 11
17	Est Net Salvage Value of Nuclear Materials in Chemical Processing
18	Nuclear Materials held for Sale (157)
19	Uranium
20	Plutonium
21	Other (Provide details in footnote)
22	TOTAL Nuclear Materials held for Sale (Total 19, 20, and 21)

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
Report below the original cost of electric plant in service according to the prescribed accounts. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and reductions in column (e) adjustments. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included in column (c) are entries for reversals of tentative distributions of the prior year reported in column (b). Likewise, if the respondent has a significant amount of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d) distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of respondent’s plant actually in service at end of year. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary account classifications. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing subaccount classification of such plant conforming to the requirement of these pages. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase, and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date.
Line No.	Account (a)	Balance Beginning of Year (b)	Additions (c)	Retirements (d)	Adjustments (e)	Transfers (f)	Balance at End of Year (g)
1	1. INTANGIBLE PLANT
2	(301) Organization
3	(302) Franchise and Consents
4	(303) Miscellaneous Intangible Plant	157,135,052	24,337,053	6,271,588			175,200,517
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)	157,135,052	24,337,053	6,271,588			175,200,517
6	2. PRODUCTION PLANT
7	A. Steam Production Plant
8	(310) Land and Land Rights	6,072,913					6,072,913
9	(311) Structures and Improvements	67,793,572	1,013,375	295,578			68,511,369
10	(312) Boiler Plant Equipment	710,191,477	3,717,243	2,227,964			711,680,756
11	(313) Engines and Engine-Driven Generators
12	(314) Turbogenerator Units	403,119,312	4,388,558	2,332,205			405,175,665
13	(315) Accessory Electric Equipment	78,666,987	1,522,955	421,588			79,768,353
14	(316) Misc. Power Plant Equipment	43,833,831	1,745,354	387,389			45,191,795
15	(317) Asset Retirement Costs for Steam Production	22,642,917					22,642,917
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)	1,332,321,008	12,387,485	5,664,724			1,339,043,769
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	62,660					62,660
38	(341) Structures and Improvements	5,771,279	40			0	5,771,319
39	(342) Fuel Holders, Products, and Accessories	11,411,270					11,411,270
40	(343) Prime Movers
41	(344) Generators	112,180,981	308,635,424	1,358,624		0	419,457,782
42	(345) Accessory Electric Equipment	15,127,828	599,852	356,789		0	15,370,891
43	(346) Misc. Power Plant Equipment	3,050,217	4,479	6,564		0	3,048,132
44	(347) Asset Retirement Costs for Other Production	16,036	7,646,242				7,662,279
44.1	(348) Energy Storage Equipment - Production
45	TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)	147,620,272	316,886,038	1,721,976			462,784,333
46	TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)	1,479,941,280	329,273,522	7,386,700			1,801,828,102
47	3. Transmission Plant
48	(350) Land and Land Rights	49,029,720	771,823				49,801,543
48.1	(351) Energy Storage Equipment - Transmission
49	(352) Structures and Improvements	17,290,782	1,283,522	33,409			18,540,896
50	(353) Station Equipment	469,303,389	17,067,172	3,084,308			483,286,253
51	(354) Towers and Fixtures	17,858,379		208,336			17,650,043
52	(355) Poles and Fixtures	318,474,098	29,410,261	10,792,053			337,092,307
53	(356) Overhead Conductors and Devices	197,879,589	7,528,065	4,233,895			201,173,759
54	(357) Underground Conduit
55	(358) Underground Conductors and Devices	71,915					71,915
56	(359) Roads and Trails
57	(359.1) Asset Retirement Costs for Transmission Plant
58	TOTAL Transmission Plant (Enter Total of lines 48 thru 57)	1,069,907,873	56,060,843	18,352,001			1,107,616,715
59	4. Distribution Plant
60	(360) Land and Land Rights	10,587,273	346,471	22,877			10,910,867
61	(361) Structures and Improvements	18,523,980	3,355,692	53,101			21,826,571
62	(362) Station Equipment	458,744,588	29,083,187	2,212,580			485,615,195
63	(363) Energy Storage Equipment – Distribution
64	(364) Poles, Towers, and Fixtures	482,354,853	30,879,169	4,768,518			508,465,504
65	(365) Overhead Conductors and Devices	477,878,778	53,233,899	12,479,027			518,633,650
66	(366) Underground Conduit	101,670,983	5,157,352	41,587			106,786,748
67	(367) Underground Conductors and Devices	393,438,559	18,184,965	1,357,503			410,266,021
68	(368) Line Transformers	391,772,570	24,138,037	11,374,013			404,536,594
69	(369) Services	291,143,953	12,584,551	1,228,971			302,499,533
70	(370) Meters	112,071,695	4,009,683	1,186,115			114,895,263
71	(371) Installations on Customer Premises	49,897,588	4,243,771	1,579,108			52,562,250
72	(372) Leased Property on Customer Premises
73	(373) Street Lighting and Signal Systems	64,435,725	3,822,829	848,318			67,410,236
74	(374) Asset Retirement Costs for Distribution Plant
75	TOTAL Distribution Plant (Enter Total of lines 60 thru 74)	2,852,520,544	189,039,606	37,151,719			3,004,408,432
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	7,363,611	95,312				7,458,923
87	(390) Structures and Improvements	71,878,352	2,414,923	845,645			73,447,629
88	(391) Office Furniture and Equipment	1,642,443	62,265	119,644			1,585,064
89	(392) Transportation Equipment	1,880,130		5,838			1,874,292
90	(393) Stores Equipment	2,650,341	39,758	303,091			2,387,007
91	(394) Tools, Shop and Garage Equipment	29,352,116	3,027,727	275,190			32,104,652
92	(395) Laboratory Equipment	1,160,776		322,800			837,976
93	(396) Power Operated Equipment	637,521					637,521
94	(397) Communication Equipment	80,201,766	24,074,101	1,145,857			103,130,011
95	(398) Miscellaneous Equipment	8,439,973	299,437	36,488			8,702,922
96	SUBTOTAL (Enter Total of lines 86 thru 95)	205,207,028	30,013,522	3,054,554			232,165,996
97	(399) Other Tangible Property						(a) 0
98	(399.1) Asset Retirement Costs for General Plant	552,361		288			552,074
99	TOTAL General Plant (Enter Total of lines 96, 97, and 98)	205,759,390	30,013,522	3,054,842			232,718,070
100	TOTAL (Accounts 101 and 106)	5,765,264,138	628,724,547	72,216,850			6,321,771,835
101	(102) Electric Plant Purchased (See Instr. 8)
102	(Less) (102) Electric Plant Sold (See Instr. 8)
103	(103) Experimental Plant Unclassified
104	TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)	5,765,264,138	628,724,547	72,216,850			6,321,771,835

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: OtherTangibleProperty

Railroad car repair facility in Alliance, Nebraska

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

ELECTRIC PLANT LEASED TO OTHERS (Account 104)
Line No.	LesseeName Name of Lessee (a)	IndicationOfAssociatedCompany * (Designation of Associated Company) (b)	LeaseDescription Description of Property Leased (c)	CommissionAuthorization Commission Authorization (d)	ExpirationDateOfLease Expiration Date of Lease (e)	ElectricPlantLeasedToOthers Balance at End of Year (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47	TOTAL

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held for future use. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.
Line No.	ElectricPlantHeldForFutureUseDescription Description and Location of Property (a)	ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate Date Originally Included in This Account (b)	ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate Date Expected to be used in Utility Service (c)	ElectricPlantHeldForFutureUse Balance at End of Year (d)
1	Land and Rights:
2	Items Under $250,000			738,261.87
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			738,262

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Report below descriptions and balances at end of year of projects in process of construction (107). Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see Account 107 of the Uniform System of Accounts). Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line No.	ConstructionWorkInProgressProjectDescription Description of Project (a)	ConstructionWorkInProgress Construction work in progress - Electric (Account 107) (b)
1	AEP-PSO CVR Distribution Line	3,149,801
2	Atoka D-Station Work	2,765,590
3	Atoka PSO CI	1,586,114
4	D - Line Technology for 2021	3,619,191
5	D/PO/Capital Blanket - PSO	1,765,220
6	Ed-Ci-Psoco-D Ast Imp	7,078,377
7	Ed-Ci-Psoco-D Cust Serv	4,239,163
8	Ed-Ci-Psoco-D Ppr	3,245,903
9	Ft Sill to LES PSO CI	1,647,090
10	Pryor Junction distribution	2,304,903
11	Pryor Junction Rehab Work 114	2,418,880
12	PSO DACR Distribution Line	1,264,896
13	PSO DACR DistributionLine 2021	2,139,333
14	PSO DACR Station	4,730,326
15	PSO DACR Station 2021	1,997,388
16	PSO Distr Pre Eng Parent	4,496,049
17	PSO Region Failure Transm	1,227,685
18	PSO Trans Pre Eng Parent	6,173,846
19	PSO/E 41st St - Upgrade Xfmrs	3,135,934
20	PSO-D Service Restoration Blkt	1,558,465
21	PSO-D Small Cap Adds Blkt	4,393,443
22	PSO-D Spare Equipment CI	8,337,831
23	PSO-D Telecom	2,020,687
24	PSO-D Third Party Work Blkt	1,776,200
25	PSO-T BlnktProj Under $3M	2,303,763
26	PSO-T Spare Equipment CI	2,254,552
27	Purchase Tulsa Hubsite	3,056,435
28	SS to Hominy PSO CI	15,523,333
29	SS-CI-PSOCo-D GEN PLT	2,990,534
30	T/PO/Capital Blanket - PSO	3,147,627
31	Traverse Wind Project PSO	6,750,512
32	WS-CI-PSOCo-G PPB	8,012,300
33	YFA Software Purchase	3,299,797
34	Other Minor Projects Which is under 5% or $1,000,000	32,405,389
43	Total	156,816,557

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
Explain in a footnote any important adjustments during year. Explain in a footnote any difference between the amount for book cost of plant retired, Line 12, column (c), and that reported for electric plant in service, page 204, column (d), excluding retirements of non-depreciable property. The provisions of Account 108 in the Uniform System of Accounts require that retirements of depreciable plant be recorded when such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional classifications. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Line No.	Item (a)	Total (c + d + e) (b)	Electric Plant in Service (c)	Electric Plant Held for Future Use (d)	Electric Plant Leased To Others (e)
Section A. Balances and Changes During Year
1	AccumulatedProvisionForDepreciationOfElectricUtilityPlant Balance Beginning of Year	1,680,876,482	1,680,876,482
2	Depreciation Provisions for Year, Charged to
3	DepreciationExpenseExcludingAdjustments (403) Depreciation Expense	173,651,934	173,651,934
4	DepreciationExpenseForAssetRetirementCosts (403.1) Depreciation Expense for Asset Retirement Costs	820,631	820,631
5	ExpensesOfElectricPlantLeasedToOthers (413) Exp. of Elec. Plt. Leas. to Others
6	TransportationExpensesClearing Transportation Expenses-Clearing
7	OtherClearingAccounts Other Clearing Accounts
8	OtherAccounts Other Accounts (Specify, details in footnote):
9.1	Other Accounts (Specify, details in footnote):	299,623	(a) 299,623
10	DepreciationProvision TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)	174,772,187	174,772,187
11	Net Charges for Plant Retired:
12	BookCostOfRetiredPlant Book Cost of Plant Retired	65,945,262	65,945,262
13	CostOfRemovalOfPlant Cost of Removal	26,161,878	(b) 26,161,878
14	SalvageValueOfRetiredPlant Salvage (Credit)	1,177,258	(c) 1,177,258
15	NetChargesForRetiredPlant TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)	90,929,882	90,929,882
16	OtherAdjustmentsToAccumulatedDepreciation Other Debit or Cr. Items (Describe, details in footnote):
17.1	Other Debit or Cr. Items (Describe, details in footnote):	32,877,126	(d) 32,877,126
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)	1,797,595,913	1,797,595,913
Section B. Balances at End of Year According to Functional Classification
20	AccumulatedDepreciationSteamProduction Steam Production	729,517,122	729,517,122
21	AccumulatedDepreciationNuclearProduction Nuclear Production
22	AccumulatedDepreciationHydraulicProductionConventional Hydraulic Production-Conventional
23	AccumulatedDepreciationHydraulicProductionPumpedStorage Hydraulic Production-Pumped Storage
24	AccumulatedDepreciationOtherProduction Other Production	59,496,527	59,496,527
25	AccumulatedDepreciationTransmission Transmission	232,884,629	232,884,629
26	AccumulatedDepreciationDistribution Distribution	728,895,288	728,895,288
27	AccumulatedDepreciationRegionalTransmissionAndMarketOperation Regional Transmission and Market Operation
28	AccumulatedDepreciationGeneral General	46,802,346	46,802,346
29	AccumulatedProvisionForDepreciationOfElectricUtilityPlant TOTAL (Enter Total of lines 20 thru 28)	1,797,595,913	1,797,595,913

FOOTNOTE DATA

(a) Concept: OtherAccounts

Depr Exp classified to acct 151 $299,623

(b) Concept: CostOfRemovalOfPlant

Includes $3,677,757 of removal cost in retirement work in progress (RWIP).

Includes ($722,414) of salvage in retirement work in progress (RWIP).

(d) Concept: OtherAdjustmentsToAccumulatedDepreciation

Ln 16 Footnote:


Transfer Oklaunion Power Station NBV as of 10/31/2021 from Accum Depr to a Reg Asset per Cause No. 202100055			32,877,126

TOTAL			32,877,126

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
Report below investments in Account 123.1, Investments in Subsidiary Companies. Provide a subheading for each company and list thereunder the information called for below. Sub-TOTAL by company and give a TOTAL in columns (e), (f), (g) and (h). (a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity, and interest rate. (b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity date, and specifying whether note is a renewal. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for Account 418.1. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee and purpose of the pledge. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission, date of authorization, and case or docket number. Report column (f) interest and dividend revenues from investments, including such revenues from securities disposed of during the year. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or the other amount at which carried in the books of account if different from cost) and the selling price thereof, not including interest adjustment includible in column (f). Report on Line 42, column (a) the TOTAL cost of Account 123.1.
Line No.	DescriptionOfInvestmentsInSubsidiaryCompanies Description of Investment (a)	DateOfAcquisitionInvestmentsInSubsidiaryCompanies Date Acquired (b)	DateOfMaturityInvestmentsInSubsidiaryCompanies Date of Maturity (c)	InvestmentInSubsidiaryCompanies Amount of Investment at Beginning of Year (d)	EquityInEarningsOfSubsidiaryCompanies Equity in Subsidiary Earnings of Year (e)	InterestAndDividendRevenueFromInvestments Revenues for Year (f)	InvestmentInSubsidiaryCompanies Amount of Investment at End of Year (g)	InvestmentGainLossOnDisplosal Gain or Loss from Investment Disposed of (h)
1
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	Total Cost of Account 123.1 $		Total

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

MATERIALS AND SUPPLIES
For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a); estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense clearing, if applicable.
Line No.	Account (a)	Balance Beginning of Year (b)	Balance End of Year (c)	Department or Departments which Use Material (d)
1	Fuel Stock (Account 151)	15,856,421	13,543,090	Electric
2	Fuel Stock Expenses Undistributed (Account 152)	2,034,802	932,968	Electric
3	Residuals and Extracted Products (Account 153)	10	10
4	Plant Materials and Operating Supplies (Account 154)
5	Assigned to - Construction (Estimated)	36,466,486	38,372,227	Electric
6	Assigned to - Operations and Maintenance
7	Production Plant (Estimated)	15,904,081	16,753,903	Electric
8	Transmission Plant (Estimated)	651,898	225,508	Electric
9	Distribution Plant (Estimated)	713,066	555,239	Electric
10	Regional Transmission and Market Operation Plant (Estimated)
11	Assigned to - Other (provide details in footnote)	216,391	(a) 312,665	Electric
12	TOTAL Account 154 (Enter Total of lines 5 thru 11)	53,951,922	56,219,542
13	Merchandise (Account 155)
14	Other Materials and Supplies (Account 156)
15	Nuclear Materials Held for Sale (Account 157) (Not applic to Gas Util)
16	Stores Expense Undistributed (Account 163)
17
18
19
20	TOTAL Materials and Supplies	71,843,155	70,695,610

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: PlantMaterialsAndOperatingSuppliesOther

Assigned to - Other Includes Customer Accounts and Administrative and General

Expenses (applies to both beginning and ending balances).

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

Allowances (Accounts 158.1 and 158.2)
Report below the particulars (details) called for concerning allowances. Report all acquisitions of allowances at cost. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k). Report on Line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40. Report on Line 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances. Report on Lines 8-14 the names of vendors/transferors of allowances acquired and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
		Current Year		Year One		Year Two		Year Three		Future Years		Totals
Line No.	SO2 Allowances Inventory (Account 158.1) (a)	No. (b)	Amt. (c)	No. (d)	Amt. (e)	No. (f)	Amt. (g)	No. (h)	Amt. (i)	No. (j)	Amt. (k)	No. (l)	Amt. (m)
1	Balance-Beginning of Year	324,602		37,382		37,382		37,382		971,932		1,408,680
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)									37,382		37,382
5	Returned by EPA
6
7
8	Purchases/Transfers:
9
10
11
12
13
14
15	Total
16
17	Relinquished During Year:
18	Charges to Account 509	4,575										4,575
19	Other:
20	Allowances Used
20.1	Allowances Used
21	Cost of Sales/Transfers:
22
23
24
25
26
27
28	Total
29	Balance-End of Year	320,027		37,382		37,382		37,382		1,009,314		1,441,487
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:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

Allowances (Accounts 158.1 and 158.2)
Report below the particulars (details) called for concerning allowances. Report all acquisitions of allowances at cost. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k). Report on Line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40. Report on Line 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances. Report on Lines 8-14 the names of vendors/transferors of allowances acquired and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
		Current Year		Year One		Year Two		Year Three		Future Years		Totals
Line No.	NOx Allowances Inventory (Account 158.1) (a)	No. (b)	Amt. (c)	No. (d)	Amt. (e)	No. (f)	Amt. (g)	No. (h)	Amt. (i)	No. (j)	Amt. (k)	No. (l)	Amt. (m)
1	Balance-Beginning of Year	4,024	7,786	2,124		2,212		2,212				10,572	7,786
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)	8		88								96
5	Returned by EPA
6
7
8	Purchases/Transfers:
9
10
11
12
13
14
15	Total
16
17	Relinquished During Year:
18	Charges to Account 509	2,344	4,411									2,344	4,411
19	Other:
20	Allowances Used
20.1	Allowances Used
21	Cost of Sales/Transfers:
22	Fathom Energy LLC	308	576									308	576
23	Consent Decree Surrenders
24	Surrenders
25	Unknown
26	Other
27
28	Total	308	576									308	576
29	Balance-End of Year	1,380	2,799	2,212		2,212		2,212				8,016	2,799
30
31	Sales:
32	Net Sales Proceeds(Assoc. Co.)
33	Net Sales Proceeds (Other)		42,544										42,544
34	Gains		42,544										42,544
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:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

EXTRAORDINARY PROPERTY LOSSES (Account 182.1)
				WRITTEN OFF DURING YEAR
Line No.	DescriptionOfExtraordinaryPropertyLoss Description of Extraordinary Loss [Include in the description the date of Commission Authorization to use Acc 182.1 and period of amortization (mo, yr to mo, yr).] (a)	ExtraordinaryPropertyLossesNotYetRecognized Total Amount of Loss (b)	ExtraordinaryPropertyLossesRecognized Losses Recognized During Year (c)	ExtraordinaryPropertyLossesWrittenOffAccountCharged Account Charged (d)	ExtraordinaryPropertyLossesWrittenOff Amount (e)	ExtraordinaryPropertyLosses Balance at End of Year (f)
1
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:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)
				WRITTEN OFF DURING YEAR
Line No.	DescriptionOfUnrecoveredPlantAndRegulatoryStudyCosts Description of Unrecovered Plant and Regulatory Study Costs [Include in the description of costs, the date of COmmission Authorization to use Acc 182.2 and period of amortization (mo, yr to mo, yr)] (a)	UnrecoveredPlantAndRegulatoryStudyCostsNotYetRecognized Total Amount of Charges (b)	UnrecoveredPlantAndRegulatoryStudyCostsRecognized Costs Recognized During Year (c)	UnrecoveredPlantAndRegulatoryStudyCostsWrittenOffAccountCharged Account Charged (d)	UnrecoveredPlantAndRegulatoryStudyCostsWrittenOff Amount (e)	UnrecoveredPlantAndRegulatoryStudyCosts Balance at End of Year (f)
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49	TOTAL

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

Transmission Service and Generation Interconnection Study Costs
Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and generator interconnection studies. List each study separately. In column (a) provide the name of the study. In column (b) report the cost incurred to perform the study at the end of period. In column (c) report the account charged with the cost of the study. In column (d) report the amounts received for reimbursement of the study costs at end of period. In column (e) report the account credited with the reimbursement received for performing the study.
Line No.	DescriptionOfStudyPerformed Description (a)	StudyCostsIncurred Costs Incurred During Period (b)	StudyCostsAccountCharged Account Charged (c)	StudyCostsReimbursements Reimbursements Received During the Period (d)	StudyCostsAccountReimbursed Account Credited With Reimbursement (e)
1	Transmission Studies
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20	Total
21	Generation Studies
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39	Total
40	Grand Total

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

OTHER REGULATORY ASSETS (Account 182.3)
Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. For Regulatory Assets being amortized, show period of amortization.
				CREDITS
Line No.	DescriptionAndPurposeOfOtherRegulatoryAssets Description and Purpose of Other Regulatory Assets (a)	OtherRegulatoryAssets Balance at Beginning of Current Quarter/Year (b)	IncreaseDecreaseInOtherRegulatoryAssets Debits (c)	OtherRegulatoryAssetsWrittenOffAccountCharged Written off During Quarter/Year Account Charged (d)	OtherRegulatoryAssetsWrittenOffRecovered Written off During the Period Amount (e)	OtherRegulatoryAssets Balance at end of Current Quarter/Year (f)
1	SFAS 109 Deferred FIT	9,999,013	535,982	182/283/236/409/282/190/281/254/255/411/410	489,378	10,045,618
2	SFAS 109 Deferred SIT	391,827	95,971	190/182/254/255/281/282/283/236/409/411/410	395,292	92,506
3	SFAS 106 Medicare Subsidy (Amortization period Jan 2013 - Dec 2024)	1,959,660		926	489,915	1,469,745
4	Retirement of Northeastern Power Plant Unit 4 Asbestos Asset Retirement Obligation (ARO) was granted approval in Order No. 672864, Cause No. PUD 201700151, to be amortized March 2018 through 2040 ( over 274 months).	473,764	294	506/407/506	24,805	449,253
5	SFAS 158 Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans	52,315,796	47,925,789	182/228/242/129/165	77,311,160	22,930,425
6	Deferred Debt, Unrecognized Equity Return, Depreciation Expense and Property Tax on NE Unit 3 and Comanche Environmental projects placed in service in 2016. Recovery beginning in March 2018 through 2040 in accordance with OCC Cause No. PUD 201700151, Order No. 672864	26,528,054	702,910	182/408/403/182	2,029,313	25,201,651
7	Terminated Red Rock Generating Facility Pre Construction Costs - OCC Cause No. PUD 200700465 Order No. 554328, Amortization period 48 years beginning February 2009	8,147,620		506	225,800	7,921,820
8	Under-recovery of Energy Efficiency Program Expenses - OCC Cause No. PUD 201500244 Order No. 647288	2,322,282	7,512,616	254/442/444/440/442/908	8,138,051	1,696,846
9	Monthly accrual related to PSO - Transmission and SWEPCO - Transmission - Base Plan Funding - to be amortized Jan-Dec 2019.	4	1,395,615	456/146	1,395,611
10	Under-recovery and related amortizations of Deferred Major/Minor Storm Restoration Expenses - Recovery approved per: OCC Cause No. 201300217, Order No. 639314 - 48 months beginning May 2015 OCC Cause No. 201700151, Order No. 672864 48 months beginning March 2018.	27,296,031	34,090,413	571/593/182	30,049,571	31,336,874
11	Northeastern Power Plant Unit 4 Undepreciated balance to be amortized over 274 months in accordance with OCC Cause No. PUD 201700151, beginning in March 2018 trhough 2040	70,399,839		407	3,519,992	66,879,848
12	Rate Case Expenses approved for recovery in OCC Final Order No. 672864, Cause No. PUD 201700151, to be amortized over two years, beginning March 2018.	768,510	514,360	253/928/182/253/923	639,995	642,875
13	Under-recovery and related amortizations of Deferred Major/Minor Storm Restoration Expenses - Recovery approved per: OCC Cause No. 201300217, Order No. 639314 - 48 months beginning M ay 2015 OCC Cause No. 201700151, Order No. 672864 48 months beginning March 2018.	26,199,211		407	4,034,095	22,165,116
14	The Refund for protected Excess DFIT Over/under recovery, In accordance with PUD Orders No.671981 and No.680821.	5,232,367	5,006,996	407	6,837,906	3,401,457
15	Unrecovered Fuel Cost – OK	35,248,819	874,737,363	501/182/447/142/254	715,369,851	194,616,330
16	COVID-19 Deferred Expense and Contra	270,277	844,528	182	844,528	270,277
17	PUD 201100106, Order No. 591185	2,148,566	6,380,870	254/565	8,529,436	1
18	UNREALIZED LOSS ON FORWARD COM		3,664,782			3,664,782
19	PSO WFA RIDER O/U - TRUE UP		3,415,833	403	586,957	2,828,876
20	PSO WFA RIDER O/U		270,418	254/453	270,418
21	Unrecov Fuel Cost 2021 Weather		700,284,859	182	21,010,187	679,274,672
22	NOLC Regulatory Asset		2,410,607			2,410,607
23	NOLC Reg Asset-Equity Carrying			182	2,410,607	2,410,607
24	Tax Provision Accrual		7,070,706	190/236/409/254/283/282/255/411/182/410/281	3,772,197	3,298,509
25	DRS Under Recovered Reg Asset		799,036	403	395,902	403,134
26	GRCF Regulatory Asset		599,616	407	59,962	539,654
27	Oklaunion Undepreciated Bal		32,877,126	407	217,729	32,659,397
44	TOTAL	269,701,633	1,731,136,690		889,048,658	1,111,789,665

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

MISCELLANEOUS DEFFERED DEBITS (Account 186)
Report below the particulars (details) called for concerning miscellaneous deferred debits. For any deferred debit being amortized, show period of amortization in column (a) Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by classes.
				CREDITS
Line No.	Description of Miscellaneous Deferred Debits (a)	Balance at Beginning of Year (b)	Debits (c)	Credits Account Charged (d)	Credits Amount (e)	Balance at End of Year (f)
1	Agency Fees - Factored Accounts Receivable	1,699,819	28,770,307	234/426	28,241,111	2,229,015
2	Deferred Billings on Associated Business Development	311,764	3,965,386	(a) 142/143/146/186/230/242/456/926	3,816,082	461,068
3	Unamortized Credit Line Fees Amortization period through 6/1/2022	1,231,953	2,301,959	(b) 146/181/26/234/431	2,424,576	1,109,337
4	Accrued Plant Retention and Severance Accrual related to Oklaunion.	237,210	81,541	152/183	323,598	4,847
5	Transource Missouri Formula Rate True-up Under-recovery	235,060	247,281	(c) 234/242/253/408/506/593	193,183	289,159
6	Deferred Lease Expense	169,475	474,265	143	571,919	71,821
7	Minor Items	191,454	324,924	(d) 234/242/253/408/506/593	327,959	194,489
47	Miscellaneous Work in Progress
48	Deferred Regulatroy Comm. Expenses (See pages 350 - 351)
49	TOTAL	3,693,827				3,961,063

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: DecreaseInMiscellaneousDeferredExpenseAccountCharged

142/143/146/186/230/242/456/926

(b) Concept: DecreaseInMiscellaneousDeferredExpenseAccountCharged

146/181/26/234/431

142/232/253/565

(d) Concept: DecreaseInMiscellaneousDeferredExpenseAccountCharged

234/242/253/408/506/593

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

ACCUMULATED DEFERRED INCOME TAXES (Account 190)
Report the information called for below concerning the respondent’s accounting for deferred income taxes. At Other (Specify), include deferrals relating to other income and deductions.
Line No.	DescriptionOfAccumulatedDeferredIncomeTax Description and Location (a)	AccumulatedDeferredIncomeTaxes Balance at Beginning of Year (b)	AccumulatedDeferredIncomeTaxes Balance at End of Year (c)
1	Electric
2	DSIT ENTRY - NORMALIZED	38,970,708	36,020,926
3	ACCUM DITC-STATE-A/C 2550002-MJE	21,671,729	22,030,567
4	ACCRD BOOK ARO EXPENSE - SFAS 143	9,958,426	12,097,990
5	NOL-STATE C/F-DEF STATE TAX ASSET-L/T	16,274,032	47,604,525
6	ADSITC STATE C/F-DEF STATE TAX ASSET-L/T	22,237,363	24,028,529
7	Other	9,382,164	85,819,647
8	TOTAL Electric (Enter Total of lines 2 thru 7)	118,494,422	55,962,890
9	Gas
15	Other
16	TOTAL Gas (Enter Total of lines 10 thru 15)
17.1	Other (Specify)	(a) 121,264,858	114,077,054
17	Other (Specify)
18	TOTAL (Acct 190) (Total of lines 8, 16 and 17)	239,759,280	170,039,944

Notes

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxes


	Notes
Page 234, Line 17, Columns B & C		Beginning of Year	End of Year

Acc Def Income Taxes - Federal - Hdg-CF-Int Rate		—	—
Non-Utility - 190.2		373,164	744,397
SFAS 109 - Regulatory Assets - 190.3, 190.4 & 190.6		120,891,694	113,332,658
SFAS 133		—	—
Accu Def Income Taxes Pension-OCI		—	—

Total Line 17		$121,264,858	$114,077,055

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

Balance at Beginning of Year			$239,759,280

(Less) Amounts Debited to:
	(a) Account 410.1		(393,193,592)
	(b) Account 410.2		(480,598)
	(c) 1823/254/219/129/427		(14,058,124)

(Plus) Amounts Credited to:
	(a) Account 411.1		330,662,060
	(b) Account 411.2		851,830
	(c) 1823/254/219/129/427		6,499,088

Balance at End of Year			$170,039,944

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

CAPITAL STOCKS (Account 201 and 204)
Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year. Give details concerning shares of any class and series of stock authorized to be issued by a regulatory commission which have not yet been issued. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or noncumulative. State in a footnote if any capital stock that has been nominally issued is nominally outstanding at end of year. Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which is pledged, stating name of pledgee and purpose of pledge.
Line No.	Class and Series of Stock and Name of Stock Series (a)	Number of Shares Authorized by Charter (b)	Par or Stated Value per Share (c)	Call Price at End of Year (d)	Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Shares (e)	Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Amount (f)	Held by Respondent As Reacquired Stock (Acct 217) Shares (g)	Held by Respondent As Reacquired Stock (Acct 217) Cost (h)	Held by Respondent In Sinking and Other Funds Shares (i)	Held by Respondent In Sinking and Other Funds Amount (j)
1	Common Stock (Account 201)
2	Common Stock (Account 201)	11,000,000	15.00		10,482,000	157,230,000
7	Total	11,000,000			10,482,000	157,230,000
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:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

2022-05-26

Year/Period of Report

End of:

2021

Other Paid-in Capital
1. Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a subheading for each account and show a total for the account, as well as a total of all accounts for reconciliation with the balance sheet, page 112. Explain changes made in any account during the year and give the accounting entries effecting such change. Donations Received from Stockholders (Account 208) - State amount and briefly explain the origin and purpose of each donation. Reduction in Par or Stated Value of Capital Stock (Account 209) - State amount and briefly explain the capital changes that gave rise to amounts reported under this caption including identification with the class and series of stock to which related. Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210) - Report balance at beginning of year, credits, debits, and balance at end of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related. Miscellaneous Paid-In Capital (Account 211) - Classify amounts included in this account according to captions that, together with brief explanations, disclose the general nature of the transactions that gave rise to the reported amounts.
Line No.	Item (a)	Amount (b)
1	DonationsReceivedFromStockholdersAbstract Donations Received from Stockholders (Account 208)
2	DonationsReceivedFromStockholders Beginning Balance Amount
3.1	IncreasesDecreasesFromSalesOfDonationsReceivedFromStockholders Increases (Decreases) from Sales of Donations Received from Stockholders	625,000,000
4	DonationsReceivedFromStockholders Ending Balance Amount	625,000,000
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	4,036,918
11.1	IncreasesDecreasesFromGainOrResaleOrCancellationOfReacquiredCapitalStock Increases (Decreases) from Gain or Resale or Cancellation of Reacquired Capital Stock
12	GainOnResaleOrCancellationOfReacquiredCapitalStock Ending Balance Amount	4,036,918
13	MiscellaneousPaidInCapitalAbstract Miscellaneous Paid-In Capital (Account 211)
14	MiscellaneousPaidInCapital Beginning Balance Amount	409,964,410
15.1	IncreasesDecreasesDueToMiscellaneousPaidInCapital Increases (Decreases) Due to Miscellaneous Paid-In Capital
16	MiscellaneousPaidInCapital Ending Balance Amount	409,964,410
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	1,039,001,328

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

CAPITAL STOCK EXPENSE (Account 214)
Report the balance at end of the year of discount on capital stock for each class and series of capital stock. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars (details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Line No.	NameOfClassAndSeriesOfStock Class and Series of Stock (a)	CapitalStockExpense Balance at End of Year (b)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22	TOTAL

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

LONG-TERM DEBT (Account 221, 222, 223 and 224)
Report by Balance Sheet Account the details concerning long-term debt included in Accounts 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other Long-Term Debt. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds, and in column (b) include the related account number. For Advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate demand notes as such. Include in column (a) names of associated companies from which advances were received, and in column (b) include the related account number. For receivers' certificates, show in column (a) the name of the court and date of court order under which such certificates were issued, and in column (b) include the related account number. In a supplemental statement, give explanatory details for Accounts 223 and 224 of net changes during the year. With respect to long-term advances, show for each company: (a)principal advanced during year (b) interest added to principal amount, and (c) principal repaid during year. Give Commission authorization numbers and dates. If the respondent has pledged any of its long-term debt securities, give particulars (details) in a footnote, including name of the pledgee and purpose of the pledge. If the respondent has any long-term securities that have been nominally issued and are nominally outstanding at end of year, describe such securities in a footnote. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest expense in column (m). Explain in a footnote any difference between the total of column (m) and the total Account 427, Interest on Long-Term Debt and Account 430, Interest on Debt to Associated Companies. Give details concerning any long-term debt authorized by a regulatory commission but not yet issued.
Line No.	ClassAndSeriesOfObligationCouponRateDescription Class and Series of Obligation, Coupon Rate (For new issue, give commission Authorization numbers and dates) (a)	RelatedAccountNumber Related Account Number (b)	Principal Amount of Debt Issued (c)	LongTermDebtIssuanceExpensePremiumOrDiscount Total Expense, Premium or Discount (d)	LongTermDebtIssuanceExpenses Total Expense (e)	LongTermDebtPremium Total Premium (f)	LongTermDebtDiscount Total Discount (g)	NominalDateOfIssue Nominal Date of Issue (h)	DateOfMaturity Date of Maturity (i)	AmortizationPeriodStartDate AMORTIZATION PERIOD Date From (j)	AmortizationPeriodEndDate AMORTIZATION PERIOD Date To (k)	Outstanding (Total amount outstanding without reduction for amounts held by respondent) (l)	Interest for Year Amount (m)
1	Bonds (Account 221)
2	None
3	Subtotal
4	Reacquired Bonds (Account 222)
5	None
6	Subtotal
7	Advances from Associated Companies (Account 223)
8	None
9	Subtotal
10	Other Long Term Debt (Account 224)
11	Senior Unsecured Notes, Series G - 6.625%		250,000,000		2,364,345		1,867,500	11/14/2007	11/15/2037	11/14/2007	11/15/2037	250,000,000	16,562,500
12	Senior Unsecured Notes, Series C - 3.05%		50,000,000		177,485			07/19/2016	08/01/2026	07/19/2016	08/01/2026	50,000,000	1,525,000
13	Senior Unsecured Notes, Series D - 4.11%		100,000,000		355,362			07/19/2016	08/01/2046	07/19/2016	08/01/2046	100,000,000	4,110,000
14	Senior Unsecured Notes, Series I - 4.4%		250,000,000		3,821,986			01/19/2011	02/01/2021	01/19/2011	02/01/2021		916,667
15	Senior Unsecured Notes, Series A - 3.17% (Oklahoma Corporation Commission Authority: Order No. 631653		125,000,000		607,973			01/29/2015	03/31/2025	01/29/2015	03/31/2025	125,000,000	3,962,500
16	Senior Unsecured Notes, Series B - 4.09% (Oklahoma Corporation Commission Authority: Order No. 631653		125,000,000		607,973			01/29/2015	03/31/2045	01/29/2015	03/31/2045	125,000,000	5,112,500
17	Senior Unsecured Notes, Series E - 3.91%		100,000,000		928,420			03/07/2019	03/15/2029	03/07/2019	03/15/2029	100,000,000	3,910,000
18	Senior Unsecured - Series F - 4.11%		150,000,000		2,581,779			06/01/2019	06/01/2034	06/01/2019	06/01/2034	150,000,000	6,165,000
19	Senior Unsecured - Series G - 4.50%		100,000,000		623,944		1,867,500	06/01/2019	06/01/2049	06/01/2019	06/01/2049	100,000,000	4,500,000
20	Senior Unsecured - Series K - 3.15%		400,000,000		3,763,812		1,320,000	08/13/2021	08/15/2051	08/13/2021	08/15/2051	400,000,000	4,830,000
21	Senior Unsecured - Series J -2.20%		400,000,000		3,763,812		1,696,000	08/13/2021	08/15/2031	08/13/2021	08/15/2031	400,000,000	3,373,333
22	Foreign Exchange Hedges												106,595
23	gridSMART Loan Agreement Promissory Note, 3.00% State Energy Program American Recovery and Reinvestment Act of 2009Revolving Loan Program Promissory Note - Fixed Rate 14207 SSEP 09		7,375,827					06/01/2010	06/01/2027	06/01/2012	06/01/2027	3,052,327	98,638
24	Oklahoma Local Revolving Credit Facility, Variable Rate		125,000,000					11/04/2016	11/04/2022	11/04/2016	11/04/2022	125,000,000	1,726,662
25	Revolving Credit Facility - 0.96%		400,000,000					01/19/2021	08/31/2021	01/20/2021	08/31/2021		2,552,950
26	Revolving Credit Facility - 0.960%		100,000,000					03/01/2021	08/31/2021	03/01/2021	08/31/2021
27	Subtotal		2,682,375,827		19,596,891		6,751,000					1,928,052,327	59,239,155
33	TOTAL		2,682,375,827									1,928,052,327	59,239,155

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
Line No.	Particulars (Details) (a)	Amount (b)
1	Net Income for the Year (Page 117)	141,082,110
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	Reconciling Items for the Year
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) 876,948,532
28	Show Computation of Tax:
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: FederalTaxNetIncome


		(000's)
Net Income for the year per Page 117		141,082
Federal and State Income Taxes		4,115
Pretax Book Income		145,197
Increase (Decrease) in Taxable Income resulting from:
Allowance for Funds Used During Construction and Other Differences Between Items Capitalized for Books and Expensed for Tax		(1,225)
Book/Tax Unit of Property Adj		(122,277)
Capitalized Relocation Costs		(5,029)
Deferred Fuel Costs (Net)		(838,642)
Demand Side Management Expenses		626
Deferred Storm Damages		(4,041)
Excess Tax Vs Book Depreciation		780
Pollution Control		(2,752)
Pension Expenses (Net)		(15,788)
Provision for Revenue Refunds		(936)
Regulatory Assets		(1,767)
Removal Costs		(25,381)
SFAS 106 - Post Retirement Benefit Expense Accrued/Funded (Net)		(5,049)
SFAS 112 - Post Employment Benefit Expense Accrued/Funded (Net)		(601)
Capitalized Software		410
Book/Tax Unit of Property Adj		3,514
Other (Net)		(3,969)

Less: Current Year Current State Income Tax Accrual		18

Federal Tax Net Income - Estimated Current Year Taxable Income (Separate Return Basis)		(876,948)

Computation of Tax *
Federal Income Tax on Current Year Taxable Income (Separate Return Basis) at the Statutory Rate of 21%	(a)	(184,159)
Adjustment due to System Consolidation Estimated Tax Currently Payable	(b)	—
		(184,159)

Tax Credit Carryforward		—
R & D Credit		(24)
NOL Deferred Tax Asset		74,795
		(109,388)

Adjustments of Prior Year's Accruals (Net)		(251)

Estimated Current Federal Income Taxes on Current Taxable Income(Net)		(109,639)

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

(b) The Company joins in the filing of a consolidated Federal income tax with its affiliated companies in the AEP system. The allocation of the AEP System's consolidated Federal income tax to the System companies allocates the benefit of current tax Income to the System companies giving rise to them in determining their current tax expense. The tax Income of the System parent company, American Electric Power Company, Inc., is allocated to its subsidiaries with taxable income. With the exception of the Income of the parent company, the method of allocation approximates a separate return result for each company in the consolidating group.

INSTRUCTION 2.

* The tax computation above represents an estimate of the Company's allocated portion of the System consolidated Federal income tax. The computation of actual 2021 System Federal income taxes will not be available until the consolidated Federal income tax return is completed and filed by October 2022. 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:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

TAXES ACCRUED, PREPAID AND CHARGES DURING YEAR
Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual, or estimated amounts of such taxes are known, show the amounts in a footnote and designate whether estimated or actual amounts. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.) Enter the amounts in both columns (g) and (h). The balancing of this page is not affected by the inclusion of these taxes. Include in column (g) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued, (b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than accrued and prepaid tax accounts. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained. If any tax (exclude Federal and State income taxes) covers more than one year, show the required information separately for each tax year, identifying the year in column (d). Enter all adjustments of the accrued and prepaid tax accounts in column (i) and explain each adjustment in a foot- note. Designate debit adjustments by parentheses. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending transmittal of such taxes to the taxing authority. Report in columns (l) through (o) how the taxes were distributed. Report in column (o) only the amounts charged to Accounts 408.1 and 409.1 pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 409.1 pertaining to other utility departments and amounts charged to Accounts 408.2 and 409.2. Also shown in column (o) the taxes charged to utility plant or other balance sheet accounts. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
					BALANCE AT BEGINNING OF YEAR					BALANCE AT END OF YEAR		DISTRIBUTION OF TAXES CHARGED
Line No.	DescriptionOfTaxesAccruedPrepaidAndCharged Kind of Tax (See Instruction 5) (a)	TypeOfTax Type of Tax (b)	TaxJurisdiction State (c)	TaxYear Tax Year (d)	TaxesAccrued Taxes Accrued (Account 236) (e)	PrepaidTaxes Prepaid Taxes (Include in Account 165) (f)	TaxesCharged Taxes Charged During Year (g)	TaxesPaid Taxes Paid During Year (h)	TaxAdjustments Adjustments (i)	TaxesAccrued Taxes Accrued (Account 236) (j)	PrepaidTaxes Prepaid Taxes (Included in Account 165) (k)	TaxesAccruedPrepaidAndCharged Electric (Account 408.1, 409.1) (l)	IncomeTaxesExtraordinaryItems Extraordinary Items (Account 409.3) (m)	AdjustmentsToRetainedEarnings Adjustment to Ret. Earnings (Account 439) (n)	TaxesIncurredOther Other (o)
1	Federal Taxes	Federal Tax			10,629,669	0	109,639,452	102,885,187		17,383,934	0	109,133,060			506,392
2	Subtotal Federal Tax				10,629,669	0	109,639,452	102,885,187		17,383,934	0	109,133,060			506,392
3	State Tax	Income Tax	MULTI	19	3,163	0				3,163	0
4	State Tax	Income Tax	TX	21	0	0	15,803			15,803	0	15,803
5	State Tax	Other State Tax	FIN48		0	0				0	0
6	State Tax	Income Tax	OK	17	372,740	0				372,740	0
7	State Tax	Income Tax	OK	18	213,986	0				213,986	0
8	State Tax	Income Tax	OK	19	2,935,570	0				2,935,570	0
9	State Tax	Income Tax	OK	20	2,573,053	0	4,806			2,568,247	0				4,806
10	State Tax	Income Tax	OK	21	0	0	4,808			4,808	0	4,808
11	State Tax	Income Tax	TX	18	1,041	0				1,041	0
12	State Tax	Income Tax	TX	19	849	0				849	0
13	State Tax	Income Tax	TX	20	2,401	0				2,401	0
14	Subtotal State Tax				218,837	0	15,801			203,036	0	10,995			4,806
15	Local Tax	Local Tax		19	3,163	0				3,163	0
16	Local Tax	Local Tax	OK	20	40,512	0	20,967	19,545		0	0				20,967
17	Local Tax	Local Tax	OK	21	0	0	394,695	344,150		50,545	0	373,728			20,967
18	Subtotal Local Tax				37,349	0	373,728	363,695		47,382	0	373,728
19	Property Tax	Property Tax	AR	20	0	0	1,585	1,585		0	0				1,585
20	Property Tax	Property Tax	TX	20	901,268	0		901,268		0	0
21	Property Tax	Property Tax	TX	21	0	0	564,763	2,000		562,763	0	562,961			1,802
22	Property Tax	Property Tax	WV	20	0	0	1,895	1,895		0	0				1,895
23	Property Tax	Property Tax	WY	20	0	0	1,540	1,036		504	0				1,540
24	Property Tax	Property Tax	AL	21	0	0	1	1		0	0				1
25	Property Tax	Property Tax	CO	20	0	0	2,246	2,246		0	0				2,246
26	Property Tax	Property Tax	CO	21	0	0				0	0
27	Property Tax	Property Tax	LA	21	0	0	502	502		0	0				502
28	Property Tax	Property Tax	MO	21	0	0	11,000	7,197		3,803	0				11,000
29	Property Tax	Property Tax	NE	19	0	0	94	94		0	0				94
30	Property Tax	Property Tax	OK	18	0	0				0	0	190,505			190,505
31	Property Tax	Property Tax	OK	20	22,303,449	0	4,876	22,308,325		0	0	4,876
32	Property Tax	Property Tax	OK	21	0	0	44,645,434	22,765,411		21,880,023	0	43,428,025			1,217,409
33	Subtotal Property Tax				23,204,717	0	45,233,936	45,991,560		22,447,093	0	44,186,367			1,047,569
34	(a) UNEMPLOYMENT 2021	Unemployment Tax			8,936	0	50,118	48,277		10,777	0	29,034			21,083
35	STATE UNEMPLOYMENT 2021	Unemployment Tax	OK		4,217	0	224,057	213,709		14,565	0	149,758			74,298
36	STATE UNEMPLOYMENT 2021	Unemployment Tax	TX		414	0	108	256		50	0	277			169
37	Subtotal Unemployment Tax				13,567	0	274,067	262,242		25,392	0	178,515			95,550
38	Sales & Use Tax	Sales And Use Tax	OK	20	502,809	2,274,639	11,949	1,783,779		0	0	1,284			10,665
39	Sales & Use Tax	Sales And Use Tax	OK	21	0	0	7,707,054	8,243,753		1,494,530	2,031,229	67			7,706,987
40	Sales & Use Tax	Sales And Use Tax	TX	18	0	0	403,417	403,417		0	0	239,108			164,309
41	Sales & Use Tax	Sales And Use Tax	TX	20	221	0	261	482		0	0	261
42	Sales & Use Tax	Sales And Use Tax	TX	21	0	0	575	526		49	0				575
43	Subtotal Sales And Use Tax				503,030	2,274,639	8,099,358	6,864,399		1,494,579	2,031,229	238,152			7,861,206
44	Excise Tax	Excise Tax		21	0	0	1,761	1,761		0	0	1,761
45	Subtotal Excise Tax				0	0	1,761	1,761		0	0	1,761
46	FICA 2021	Federal Insurance Tax			1,146,123	0	8,087,591	10,017,350	1,678,219	894,583	0	4,656,624			3,430,967
47	2360104 FICA	Federal Insurance Tax			1,906,299				1,906,299	0	0
48	2360105 FICA CARES ACT	Federal Insurance Tax			1,906,299	0			228,080	2,134,379	0
49	Subtotal Federal Insurance Tax				4,958,721	0	8,087,591	10,017,350		3,028,962	0	4,656,624			3,430,967
50	Franchise Tax	Franchise Tax	OK	21	0	0	20,000	20,000		0	0	20,000
51					0	0				0	0
52	Subtotal Franchise Tax				0	0	20,000	20,000		0	0	20,000
53	Other State Tax	Other State Tax	OH	20	0	0	12	12		0	0	12
54	Other State Tax	Other State Tax	OH	21	0	0	62	62		0	0	62
55	Subtotal Other State Tax				0	0	74	74		0	0	74
56	Other License and Fees Tax	Other License And Fees Tax	WY	19	51	0				51	0
57	Subtotal Other License And Fees Tax				51	0				51	0
40	TOTAL				17,868,827	2,274,639	47,533,136	39,364,106		9,456,387	2,031,229	59,466,844			11,933,706

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: DescriptionOfTaxesAccruedPrepaidAndCharged

Consists of a prepayment for sales tax only; a collect & remit tax. Beginning in 2009, included for purposes of reporting all prepaid tax activity.

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g). Include in column (i) the average period over which the tax credits are amortized.
			Deferred for Year		Allocations to Current Year's Income
Line No.	Account Subdivisions (a)	Balance at Beginning of Year (b)	Account No. (c)	Amount (d)	Account No. (e)	Amount (f)	Adjustments (g)	Balance at End of Year (h)	Average Period of Allocation to Income (i)	ADJUSTMENT EXPLANATION (j)
1	Electric Utility
2	3%
3	4%	24,282			411.4	17,053		7,229
4	7%
5	10%	8,661,616			411.4	1,806,699		6,854,917
6	State DITC	42,278,037	411.1	1,791,159	411.4	82,408		43,986,788
7	30				411.4
8	TOTAL Electric (Enter Total of lines 2 thru 7)	50,963,935		1,791,159		1,906,160		50,848,934
9	Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
10										`
47	OTHER TOTAL
48	GRAND TOTAL	50,963,935						50,848,934

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

OTHER DEFERRED CREDITS (Account 253)
Report below the particulars (details) called for concerning other deferred credits. For any deferred credit being amortized, show the period of amortization. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
			DEBITS
Line No.	Description and Other Deferred Credits (a)	Balance at Beginning of Year (b)	Contra Account (c)	Amount (d)	Credits (e)	Balance at End of Year (f)
1	Pole Attachments	881,351	454	1,771,434	1,780,167	890,084
2	Customer and Other Advance Receipts	10,799,502	142	10,799,502	5,664,471	5,664,471
3	PowerPay Prepaid Paymt Program	907,149	142	907,149	820,661	820,661
4	TRE (Texas Reliability Entity) Audit Penalty (Long Term)	808,604	234/426/242	454,706		353,898
5	Contributions in Aid of Construction	1,830,999	107/108	1,830,999	878,592	878,592
6	Deferred Revenue - Oil and Gas Lease Bonus Payment Agreement	29,156	456	29,156
7	Minor Items	138,602	186/143/234/565/456	442,668	691,180	109,910
8	Associated Business Development		456	75,000	1,000,000	925,000
9	Environmental Liabilities				150,000	150,000
47	TOTAL	15,118,159		16,310,614	10,985,071	9,792,616

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)
Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to amortizable property. For other (Specify),include deferrals relating to other income and deductions. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Accelerated Amortization (Account 281)
2	Electric
3	Defense Facilities
4	Pollution Control Facilities	22,957,410	1,134,707	785,227							23,306,890
5	Other
5.1	Other (provide details in footnote):
8	TOTAL Electric (Enter Total of lines 3 thru 7)	22,957,410	1,134,707	785,227							23,306,890
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	(a) Other - SFAS 109	8,253,041					254	110,166	254	358,409	8,004,798
17	TOTAL (Acct 281) (Total of 8, 15 and 16)	14,704,369	1,134,707	785,227				110,166		358,409	15,302,092
18	Classification of TOTAL
19	Federal Income Tax	14,704,369	1,134,707	785,227				110,166		358,409	15,302,092
20	State Income Tax
21	Local Income Tax

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: DescriptionOfAcceleratedAmortizationPropertyOtherUtilityOther


Description Page 272-273 Line 16	Balance at Beginning of The year	Amounts Debited to Account 410.2	Amounts Credits to Account 411.2	Debit Adjust.	Credit Adjust.	Balance End of Year
SFAS 109	(8,253,041)			(110,166)	358,409	(8,004,798)
Total Line 16	(8,253,041)	—	—	(110,166)	358,409	(8,004,798)

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282)
Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to property not subject to accelerated amortization. For other (Specify),include deferrals relating to other income and deductions. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Account 282
2	Electric	1,001,315,862	78,277,183	59,708,368			211		190		1,019,884,677
3	Gas
4	Other (Specify)
5	Total (Total of lines 2 thru 4)	1,001,315,862	78,277,183	59,708,368							1,019,884,677
6	(a) Other	344,210,514					1823/254	4,320,121	1823/254	31,960,595	316,570,040
9	TOTAL Account 282 (Total of Lines 5 thru 8)	657,105,348	78,277,183	59,708,368				4,320,121		31,960,595	703,314,637
10	Classification of TOTAL
11	Federal Income Tax	657,105,348	78,277,183	59,708,368				4,320,121		31,960,595	703,314,637
12	State Income Tax
13	Local Income Tax

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: DescriptionOfNonUtilityAccountDetails


Line 6 Footnote

	Beg Bal	Debits	Credits	End Bal
Non-Utility	—	—	—	—
SFAS 109	(344,210,514)	4,320,121	31,960,595	(316,570,040)
Total Other - Line 6	(344,210,514)	4,320,121	31,960,595	(316,570,040)

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283)
Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts recorded in Account 283. For other (Specify),include deferrals relating to other income and deductions. Provide in the space below explanations for Page 276. Include amounts relating to insignificant items listed under Other. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Account 283
2	Electric
3	Accrued Book Pension Expense	14,737,925	7,036	1,073,574							13,671,387
4	REG ASSET-SFAS 158 - PENSIONS	11,581,972		4,357,439							7,224,533
5	Reg Asset - NE U4 Undepr Balan	14,783,967		739,198							14,044,769
6	Reg Asset-Advanced Metering Sy	5,501,834		847,160							4,654,674
7	DSIT Normalized	185,574,799	163,040,691	134,309,648							214,305,842
8	Other	10,847,630	40,315,600	29,261,154			211				21,902,076
9	TOTAL Electric (Total of lines 3 thru 8)	243,028,127	203,363,327	170,588,173							275,803,281
10	Gas
11
12
13
14
15
16
17	TOTAL Gas (Total of lines 11 thru 16)
18	TOTAL Other	(a) 13,403,234					1823/254	79,716,531	1823/254	24,231,800	42,081,497
19	TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)	256,431,361	203,363,327	170,588,173				79,716,531		24,231,800	233,721,784
20	Classification of TOTAL
21	Federal Income Tax	70,464,735	39,092,858	44,544,051				76,351,243		19,638,823	8,301,122
22	State Income Tax	185,966,626	164,270,469	126,044,122				3,365,288		4,547,977	225,375,662
23	Local Income Tax
NOTES

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesOther


Line 18 Footnote
	Beg Bal	Debits	Credits	End Bal
SFAS 133	—	—	—	—
Hedge - Cash Flow	22,384	22,384	—	—
Non-Utility	—	—	—	—
SFAS 109	13,380,850	79,694,147	24,231,800	(42,081,497)
	13,403,234	79,716,531	24,231,800	(42,081,497)

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

OTHER REGULATORY LIABILITIES (Account 254)
Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. For Regulatory Liabilities being amortized, show period of amortization.
			DEBITS
Line No.	Description and Purpose of Other Regulatory Liabilities (a)	Balance at Beginning of Current Quarter/Year (b)	Account Credited (c)	Amount (d)	Credits (e)	Balance at End of Current Quarter/Year (f)
1	SFAS 109 Deferred Federal Income Tax	470,304,033	190/282/283	131,659,668	154,781,251	493,425,616
2	Deferred Fuel Over-Recovery	5,161,558	182/501	5,161,558
3	Unrealized Gain/Loss on Forward Commitments	694,076	175	13,877,468	14,071,122	887,730
4	PSO's OK Veg Mgmnt O/U Recovery To track the over funded balance for Oklahoma's System Reliability Rider (SRR) in accordance with PSO's Final Order No. PUD 201500208, Order No. 644241. Disposition of Balance should be determined within one year.	712,051	593	71,205		640,846
5	Over-Recovered PSO BPF				2,771,804	2,771,804
41	TOTAL	476,871,718		150,769,898	171,624,177	497,725,997

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

Electric Operating Revenues
The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH related to unbilled revenues need not be reported separately as required in the annual version of these pages. Report below operating revenues for each prescribed account, and manufactured gas revenues in total. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added for billing purposes, one customer should be counted for each group of meters added. The average number of customers means the average of twelve figures at the close of each month. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification in a footnote.) See page 108, Important Changes During Period, for important new territory added and important rate increase or decreases. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts. Include unmetered sales. Provide details of such Sales in a footnote.
Line No.	Title of Account (a)	Operating Revenues Year to Date Quarterly/Annual (b)	Operating Revenues Previous year (no Quarterly) (c)	MEGAWATT HOURS SOLD Year to Date Quarterly/Annual (d)	MEGAWATT HOURS SOLD Amount Previous year (no Quarterly) (e)	AVG.NO. CUSTOMERS PER MONTH Current Year (no Quarterly) (f)	AVG.NO. CUSTOMERS PER MONTH Previous Year (no Quarterly) (g)
1	SalesOfElectricityHeadingAbstract Sales of Electricity
2	ResidentialSalesAbstract (440) Residential Sales	651,190,620	579,751,017	6,243,064	6,116,578	487,689	483,536
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)	378,271,217	320,375,582	4,910,704	4,672,941	65,612	64,003
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)	273,884,713	221,249,527	5,829,679	5,713,383	6,562	6,796
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting	3,312,916	3,151,812	41,801	42,956	322	275
7	OtherSalesToPublicAuthoritiesAbstract (445) Other Sales to Public Authorities	74,257,030	62,936,836	1,180,529	1,156,386	8,041	8,008
8	SalesToRailroadsAndRailwaysAbstract (446) Sales to Railroads and Railways
9	InterdepartmentalSalesAbstract (448) Interdepartmental Sales
10	SalesToUltimateConsumersAbstract TOTAL Sales to Ultimate Consumers	1,380,916,495	1,187,464,773	18,205,777	17,702,244	568,226	562,618
11	SalesForResaleAbstract (447) Sales for Resale	58,031,770	30,154,370	1,144,820	1,102,760	1	1
12	SalesOfElectricityAbstract TOTAL Sales of Electricity	1,438,948,266	1,217,619,144	19,350,597	18,805,004	568,227	562,619
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds	160,457	3,026,607
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds	1,438,787,809	1,214,592,537	19,350,597	18,805,004	568,227	562,619
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts	2,092,621	2,341,608
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	(a) 173,293	137,234
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power
19	RentFromElectricProperty (454) Rent from Electric Property	7,855,192	8,370,451
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	(b) 13,008,350	18,975,952
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	39,422,463	36,134,194
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	62,551,920	65,959,439
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	1,501,339,728	1,280,551,976
Line12, column (b) includes $ 229,034 of unbilled revenues.
Line12, column (d) includes 79,833 MWH relating to unbilled revenues

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: MiscellaneousServiceRevenues

Account 451 Miscellaneous Service revenues:

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:	2021	2020
Electric Operations - Affiliated	—	665,497
Electric Operations - Nonaffiliated	25,390	125,200
Third Party Plant Operations including related overhead	3,466,649	14,082,439
Sales of Renewable Energy Credits (to non affiliates)	9,487,018	3,985,888
Other Misc Revenue - Items < $250,000	29,293	116,928
Total	13,008,350	18,975,952

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

REGIONAL TRANSMISSION SERVICE REVENUES (Account 457.1)
The respondent shall report below the revenue collected for each service (i.e., control area administration, market administration, etc.) performed pursuant to a Commission approved tariff. All amounts separately billed must be detailed below.
Line No.	Description of Service (a)	Balance at End of Quarter 1 (b)	Balance at End of Quarter 2 (c)	Balance at End of Quarter 3 (d)	Balance at End of Year (e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46	TOTAL

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	(a) RS Cogen 062	6	761	1	4,998	0.1219
2	LURS 020	9,433	1,523,134	5,712	1,651	0.1615
3	LUGS 264	53	3,360		212,048	0.0634
4	RS 015	5,938,991	612,582,462	459,365	12,929	0.1031
5	RS 038	1,764	166,682	260	6,793	0.0945
6	RS TOD2TR 028	315,574	31,973,159	21,546	14,646	0.1013
7	VPPRS 036	1,897	189,660	131	14,453	0.1000
8	RS GOGEN Distributive Generation CR 064	130	9,130	8	16,051	0.0704
9	RS Net Meter 067	9,607	729,021	666	14,425	0.0759
10	Non-Roadway Lght 151-163	9,272	2,273,701	14,464	641	0.2452
11	LED Light 170-177	517	164,102	1,667	310	0.3175
12	Deferred EE		605,583
13	Other			32,432
14	Sec Lght 093-145	10,611	2,739,199	16,301	651	0.2581
41	TOTAL Billed Residential Sales	6,297,855	651,748,788	487,689
42	TOTAL Unbilled Rev. (See Instr. 6)	54,791	558,168
43	TOTAL	6,243,064	651,190,620	487,689	12,801	0.1043

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: DescriptionOfNumberAndTitleOfRateSchedule

Revenue Accounts 440, 442, 444, and 445 have a uniform standard fuel adjustment clause applicable to the rate schedule shown and the aggregate estimated revenue billed pursuant thereto is $544,021,085

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1		7,165	498,933	904	7,924	0.0696
2	GS 254	1,581,164	132,054,364	6,183	255,710	0.0835
3	LUGS 264	855,201	81,142,053	46,055	18,569	0.0949
4	LUGS 265	368	32,848	16	23,741	0.0893
5	LUGS 266	183	24,742	102	1,788	0.1351
6	MOL 204	2,219	226,388	568	3,907	0.1020
7	MOL 214	3,484	277,647	643	5,416	0.0797
8	RS 015	135	7,637	4	30,613	0.0565
9	Sec Lght 093-145	22,301	4,567,710	8,940	2,495	0.2048
10	Non-Roadway Lght 151-163	15,577	2,506,152	5,545	2,809	0.1609
11	LED Light 170-177	1,188	349,562	801	1,483	0.2943
12	GS 255	408	36,940	3	136,121	0.0905
13	GS 252	52,206	4,095,314	50	1,038,928	0.0784
14	LPL 242	99,316	3,562,096	3	34,051,154	0.0359
15	LPL 244	248,577	10,045,124	7	34,286,434	0.0404
16	LPL 246	751,441	40,756,466	177	4,241,437	0.0542
17	LPL 248	57,910	3,968,112	21	2,746,698	0.0685
18	LPL 250	824,189	60,366,192	1,274	646,972	0.0732
19	LUGS 262	2,184	185,875	83	26,423	0.0851
20	Traffic Signal 202	91	7,136	6	14,731	0.0785
21	Traffic Signal 203	7	810	3	2,216	0.1218
22	LUGS Net Meter TOD 269	910	66,827	18	51,495	0.0735
23	LUGS TOD 269	21,125	1,552,141	384	54,989	0.0735
24	LPL PRI 296	15	19,418	1	16,364	1.2946
25	PRSV NOND	6,720	511,325	18	368,204	0.0761
26	GS PSF 304	255,495	20,771,073	730	349,994	0.0813
27	Deferred EE		541,845
28	Other			15,285
29	LUGS PSF 314	37,608	3,040,024	1,530	24,589	0.0808
30	LUGS-PSGF 315	120	8,540	4	30,089	0.0710
31	Outdoor Lght 207	413	34,568	31	13,312	0.0838
32	Standby Transmission SL1	233	33,054	0		0.1419
33	Recreational Lght 208	160	12,113	1	159,920	0.0757
34	Recreational Lght 209	39	3,726	1	39,280	0.0949
35	GS-UMSMTRD	6,174	482,309	1,010	6,114	0.0781
36	GS-Net Meter TOD 257	6,415	495,081	14	460,953	0.0772
37	GS-TOD2TR 258	179	14,862	1	178,720	0.0832
38	GS-TOD 259	64,987	5,254,968	215	302,616	0.0809
39	LUGS<100H	2,487	1,559,743	5,551	448	0.6273
41	TOTAL Billed Small or Commercial	4,927,928	377,963,920	65,612
42	TOTAL Unbilled Rev. Small or Commercial (See Instr. 6)	17,224	307,297
43	TOTAL Small or Commercial	4,910,704	378,271,217	65,612	74,844	0.0770

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	GS 254	376,838	31,888,837	994	379,145	0.0846
2	GS 252	3,810	314,307	6	634,983	0.0825
3	MOL 204	4	385	1	3,679	0.1047
4	LPL 242	795,306	29,288,116	12	66,275,531	0.0368
5	LPL 244	3,271,059	124,896,021	41	80,107,509	0.0382
6	LPL 246	998,205	56,502,561	219	4,568,442	0.0566
7	LPL 248	28,141	2,023,045	7	4,020,143	0.0719
8	LPL 250	206,171	15,082,595	142	1,457,040	0.0732
9	LUGS 262	254	20,688	8	31,812	0.0813
10	LUGS 264	99,912	8,955,672	4,474	22,318	0.0896
11	LUGS 265	467	37,031	10	49,116	0.0794
12	MOL 214	107	7,988	4	26,101	0.0750
13	Non-Roadway Lght 151-163	2,090	308,249	486	4,301	0.1475
14	Other			1,284
15	PRSV NOND	14,508	1,122,849	21	693,631	0.0774
16	STNBY TRN 392	16,975	1,617,809	10	1,683,519	0.0953
17	LED Light 170-175	215	60,481	53	4,082	0.2809
18	Sec Lght 093-145	2,533	429,660	746	3,398	0.1696
19	GS-Net Meter TOD 257	109	10,136	1	81,975	0.0927
20	GS TOD 259	7,917	656,438	28	286,164	0.0829
21	LUGS<100H	175	146,754	540	325	0.8363
22	LUGS TOD 269	2,617	184,749	42	62,312	0.0706
23	LPL SUPPL 292	6,907	508,665	1	7,534,909	0.0736
24	Deferred EE		185,282
41	TOTAL Billed Large (or Ind.) Sales	5,834,320	273,877,754	6,562
42	TOTAL Unbilled Rev. Large (or Ind.) (See Instr. 6)	4,641	6,959
43	TOTAL Large (or Ind.)	5,829,679	273,884,713	6,562	888,355	0.0470

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41	TOTAL Billed Commercial and Industrial Sales
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	GSL 533	13	1,049	1	13,068	0.0803
2	GSL 532	330	32,559	2	164,910	0.0987
3	MSL 529	127	6,324	2	80,290	0.0497
4	MSL 531	40,386	3,203,445	190	212,653	0.0793
5	MSL 534	418	40,356	36	11,592	0.0965
6	Deferred EE		74,991
7	MSL 535	528	104,149	91	5,782	0.1974
41	TOTAL Billed Public Street and Highway Lighting	41,802	3,312,891	322
42	TOTAL Unbilled Rev. (See Instr. 6)	1	25
43	TOTAL	41,801	3,312,916	322	129,884	0.0793

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	GS 212-213	2,979	249,337	886	3,361	0.0837
2	GS 254	241,481	19,552,336	709	340,513	0.0810
3	LUGS 265	27	3,188	3	8,600	0.1202
4	MOL 204	848	74,839	114	7,426	0.0882
5	MOL 214	1,601	123,358	102	15,706	0.0771
6	MP 540	9,621	651,809	60	159,464	0.0677
7	MSL 218	8,071	627,211	21	382,802	0.0777
8	Non-Roadway Lght 151-163	1,246	201,045	366	3,402	0.1614
9	GS 252	16,235	1,310,484	7	2,319,237	0.0807
10	LPL 242	68,923	2,703,418	5	14,018,317	0.0392
11	LPL 244	289,533	11,924,940	8	36,572,589	0.0412
12	LPL 246	274,102	15,176,234	42	6,539,220	0.0554
13	LPL 248	3,316	233,005	2	1,658,160	0.0703
14	LPL 250	171,857	12,168,812	154	1,117,163	0.0708
15	LPL 251	68	9,836	12	5,525	0.1443
16	LUGS 264	86,132	7,910,393	3,012	19,344	0.0918
17	LED Light 170-176	134	40,688	68	1,972	0.3046
18	Sec Lght 093-145	2,821	628,263	1,008	2,800	0.2227
19	MSL 219	47	3,812	2	26,971	0.0808
20	GS-Net Meter TOD 257	310	27,579	2	169,135	0.0889
21	GS-TOD 259
22	LUGS<100H	306	280,167	1,046	292	0.9166
23	LUGS Net Meter TOD 269	11	856	1	11,131	0.0769
24	PRSV NOND	1,203	89,471	9	137,483	0.0744
25	LED TS 201	335	33,965	104	3,224	0.1013
26	LED TS 202	948	86,126	179	5,284	0.0909
27	LED TS 203	310	29,827	74	4,194	0.0961
28	GSMTRMSC	19	1,610	1	18,845	0.0854
29	GSMTRMSCL	502	41,388	13	38,163	0.0824
30	MOL 207	701	54,075	5	140,179	0.0772
31	MOL 210	12	3,650	25	493	0.2944
32	MOL 217	6	454	1	5,712	0.0795
41	TOTAL Billed Other Sales to Public Authorities	1,183,705	74,242,176	8,041
42	TOTAL Unbilled Rev. (See Instr. 6)	3,176	14,854
43	TOTAL	1,180,529	74,257,030	8,041	146,817	0.0629

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41	TOTAL Billed Provision For Rate Refunds
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL		160,457

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
41	TOTAL Billed - All Accounts	18,285,610	1,381,145,529	568,226
42	TOTAL Unbilled Rev. (See Instr. 6) - All Accounts	79,833	229,033
43	TOTAL - All Accounts	18,205,777	1,380,916,496	568,226

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

SALES FOR RESALE (Account 447)
Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the Purchased Power schedule (Page 326). Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the purchaser. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or setter can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less than five years. SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one year or less. LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years. OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote. AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (g) through (k). In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. Report in column (g) the megawatt hours shown on bills rendered to the purchaser. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k) the total charge shown on bills rendered to the purchaser. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,line 24. Footnote entries as required and provide explanations following all required data.
					ACTUAL DEMAND (MW)			REVENUE
Line No.	Name of Company or Public Authority (Footnote Affiliations) (a)	Statistical Classification (b)	FERC Rate Schedule or Tariff Number (c)	Average Monthly Billing Demand (MW) (d)	Average Monthly NCP Demand (e)	Average Monthly CP Demand (f)	Megawatt Hours Sold (g)	Demand Charges ($) (h)	Energy Charges ($) (i)	Other Charges ($) (j)	Total ($) (h+i+j) (k)
1	Requirement Service (RQ)
2	(a) Town of South Coffeyville (1)	RQ	234	1.3	1.6	1.4	8,399		641,096	151,793	792,889
3	Wholesale Over/Under (2)	RQ
4	Non-Requirement Service (non-RQ)
5	American Electric Power Service
6	Corporation (AEPSC) (3,4)	OS	228				0
7	AEPSC (3,5)	OS	228
8	Electric Reliability
9	Council of Texas (ERCOT) (6)	OS
10	Southwest Power Pool (7)	OS					1,136,421		44,531,366	12,707,515	57,238,881
15	Subtotal - RQ						8,399		641,096	151,793	792,889
16	Subtotal-Non-RQ						1,136,421		44,531,366	12,707,515	57,238,881
17	Total						1,144,820		45,172,462	12,859,308	58,031,770

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: NameOfCompanyOrPublicAuthorityReceivingElectricityPurchasedForResale

Includes customer charges

2 Wholesale Over/Under Recovery Calculation

3 Respondent is an affiliate company of American Electric Power Company, Inc. (AEP)

4 Bookout Margin Net

5 Realization System Integration Agreement Sharing

6 Net Trading Purchases & Sales within ERCOT

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

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line No.	Account (a)	Amount for Current Year (b)	Amount for Previous Year (c) (c)
1	PowerProductionExpensesAbstract 1. POWER PRODUCTION EXPENSES
2	SteamPowerGenerationAbstract A. Steam Power Generation
3	SteamPowerGenerationOperationAbstract Operation
4	OperationSupervisionAndEngineeringSteamPowerGeneration (500) Operation Supervision and Engineering	14,481,559	14,952,535
5	FuelSteamPowerGeneration (501) Fuel	493,515,607	104,359,008
6	SteamExpensesSteamPowerGeneration (502) Steam Expenses	8,797,082	9,933,548
7	SteamFromOtherSources (503) Steam from Other Sources
8	SteamTransferredCredit (Less) (504) Steam Transferred-Cr.
9	ElectricExpensesSteamPowerGeneration (505) Electric Expenses	4,745,397	3,334,646
10	MiscellaneousSteamPowerExpenses (506) Miscellaneous Steam Power Expenses	5,843,098	10,168,906
11	RentsSteamPowerGeneration (507) Rents	3,558	3,762
12	Allowances (509) Allowances	4,411	18,847
13	SteamPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 4 thru 12)	459,640,502	142,771,252
14	SteamPowerGenerationMaintenanceAbstract Maintenance
15	MaintenanceSupervisionAndEngineeringSteamPowerGeneration (510) Maintenance Supervision and Engineering	3,058,277	3,422,424
16	MaintenanceOfStructuresSteamPowerGeneration (511) Maintenance of Structures	4,418,779	2,681,919
17	MaintenanceOfBoilerPlantSteamPowerGeneration (512) Maintenance of Boiler Plant	10,001,006	12,669,730
18	MaintenanceOfElectricPlantSteamPowerGeneration (513) Maintenance of Electric Plant	7,431,159	9,580,981
19	MaintenanceOfMiscellaneousSteamPlant (514) Maintenance of Miscellaneous Steam Plant	2,277,953	2,616,951
20	SteamPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 15 thru 19)	27,187,175	30,972,005
21	PowerProductionExpensesSteamPower TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)	432,453,327	173,743,257
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	9
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)	9
41	PowerProductionExpensesNuclearPower TOTAL Power Production Expenses-Nuclear. Power (Enter Total of lines 33 & 40)	9
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	323,978	61,999
63	Fuel (547) Fuel	27,594,151	4,897,206
64	GenerationExpenses (548) Generation Expenses	272,477	354,394
64.1	OperationOfEnergyStorageEquipment (548.1) Operation of Energy Storage Equipment
65	MiscellaneousOtherPowerGenerationExpenses (549) Miscellaneous Other Power Generation Expenses	146,721	9,548
66	RentsOtherPowerGeneration (550) Rents	1,270,584
67	OtherPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 62 thru 67)	29,607,912	5,323,147
68	OtherPowerGenerationMaintenanceAbstract Maintenance
69	MaintenanceSupervisionAndEngineeringOtherPowerGeneration (551) Maintenance Supervision and Engineering
70	MaintenanceOfStructures (552) Maintenance of Structures	504	10,421
71	MaintenanceOfGeneratingAndElectricPlant (553) Maintenance of Generating and Electric Plant	1,317,905	968,036
71.1	MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration (553.1) Maintenance of Energy Storage Equipment
72	MaintenanceOfMiscellaneousOtherPowerGenerationPlant (554) Maintenance of Miscellaneous Other Power Generation Plant	194,216	247,037
73	OtherPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 69 thru 72)	1,512,626	1,225,494
74	PowerProductionExpensesOtherPower TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)	31,120,537	6,548,641
75	OtherPowerSuplyExpensesAbstract E. Other Power Supply Expenses
76	PurchasedPower (555) Purchased Power	1,077,323,348	442,965,335
76.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations	0
77	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching	667,153	549,922
78	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	2,724,699	91,501,410
79	OtherPowerSupplyExpense TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)	1,080,715,200	352,013,847
80	PowerProductionExpenses TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74 & 79)	679,382,419	532,305,745
81	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
82	TransmissionExpensesOperationAbstract Operation
83	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	5,640,984	4,367,863
85	LoadDispatchReliability (561.1) Load Dispatch-Reliability		25
86	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	349,655	528,992
87	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling	4,376	4,476
88	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services	4,067,542	11,824,083
89	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development	195,849	119,802
90	TransmissionServiceStudies (561.6) Transmission Service Studies
91	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies
92	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services	997,231	982,829
93	StationExpensesTransmissionExpense (562) Station Expenses	442,698	508,303
93.1	OperationOfEnergyStorageEquipmentTransmissionExpense (562.1) Operation of Energy Storage Equipment
94	OverheadLineExpense (563) Overhead Lines Expenses	73,523	276,837
95	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses	2	2
96	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	156,385,296	121,859,536
97	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	3,151,359	3,507,029
98	RentsTransmissionElectricExpense (567) Rents	2,259,670	2,169,752
99	TransmissionOperationExpense TOTAL Operation (Enter Total of Lines 83 thru 98)	173,559,430	146,140,577
100	TransmissionMaintenanceAbstract Maintenance
101	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering	48,148	21,529
102	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	9,967	9,069
103	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware	5,348	5,522
104	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software	(a) 354,609	341,933
105	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment	67,339	54,849
106	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	1,219,127	1,115,866
107.1	MaintenanceOfEnergyStorageEquipmentTransmission (570.1) Maintenance of Energy Storage Equipment
108	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	6,848,588	6,614,020
109	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines	68	858
110	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant	500,914	512,332
111	TransmissionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 101 thru 110)	9,053,972	8,675,978
112	TransmissionExpenses TOTAL Transmission Expenses (Total of Lines 99 and 111)	182,613,401	154,816,555
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	1,522,875	1,550,531
122	RentsRegionalMarketExpenses (575.8) Rents
123	RegionalMarketOperationExpense Total Operation (Lines 115 thru 122)	1,522,875	1,550,531
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)	1,522,875	1,550,531
132	DistributionExpensesAbstract 4. DISTRIBUTION EXPENSES
133	DistributionExpensesOperationAbstract Operation
134	OperationSupervisionAndEngineeringDistributionExpense (580) Operation Supervision and Engineering	2,866,371	3,106,010
135	LoadDispatching (581) Load Dispatching	2,319,769	2,576,286
136	StationExpensesDistribution (582) Station Expenses	1,076,854	1,132,966
137	OverheadLineExpenses (583) Overhead Line Expenses	1,918,585	3,425,463
138	UndergroundLineExpenses (584) Underground Line Expenses	4,592,895	4,000,790
138.1	OperationOfEnergyStorageEquipmentDistribution (584.1) Operation of Energy Storage Equipment
139	StreetLightingAndSignalSystemExpenses (585) Street Lighting and Signal System Expenses	113,094	45,201
140	MeterExpenses (586) Meter Expenses	4,708,820	4,390,189
141	CustomerInstallationsExpenses (587) Customer Installations Expenses	411,417	345,929
142	MiscellaneousDistributionExpenses (588) Miscellaneous Expenses	6,501,551	11,479,631
143	RentsDistributionExpense (589) Rents	820,601	817,824
144	DistributionOperationExpensesElectric TOTAL Operation (Enter Total of Lines 134 thru 143)	25,329,957	31,320,289
145	DistributionExpensesMaintenanceAbstract Maintenance
146	MaintenanceSupervisionAndEngineering (590) Maintenance Supervision and Engineering	98,967	55,875
147	MaintenanceOfStructuresDistributionExpense (591) Maintenance of Structures	167,710	216,609
148	MaintenanceOfStationEquipment (592) Maintenance of Station Equipment	1,591,312	1,534,402
148.1	MaintenanceOfEnergyStorageEquipment (592.2) Maintenance of Energy Storage Equipment
149	MaintenanceOfOverheadLines (593) Maintenance of Overhead Lines	48,762,887	46,449,862
150	MaintenanceOfUndergroundLines (594) Maintenance of Underground Lines	965,963	1,845,237
151	MaintenanceOfLineTransformers (595) Maintenance of Line Transformers	136,514	134,676
152	MaintenanceOfStreetLightingAndSignalSystems (596) Maintenance of Street Lighting and Signal Systems	47,401	73,533
153	MaintenanceOfMeters (597) Maintenance of Meters	358,571	329,680
154	MaintenanceOfMiscellaneousDistributionPlant (598) Maintenance of Miscellaneous Distribution Plant	143,396	197,186
155	DistributionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 146 thru 154)	52,272,720	50,837,060
156	DistributionExpenses TOTAL Distribution Expenses (Total of Lines 144 and 155)	77,602,676	82,157,349
157	CustomerAccountsExpensesAbstract 5. CUSTOMER ACCOUNTS EXPENSES
158	CustomerAccountsExpensesOperationsAbstract Operation
159	SupervisionCustomerAccountExpenses (901) Supervision	850,549	768,026
160	MeterReadingExpenses (902) Meter Reading Expenses	229,434	227,868
161	CustomerRecordsAndCollectionExpenses (903) Customer Records and Collection Expenses	13,591,706	13,598,886
162	UncollectibleAccounts (904) Uncollectible Accounts	240,501	709,796
163	MiscellaneousCustomerAccountsExpenses (905) Miscellaneous Customer Accounts Expenses	150,801	143,520
164	CustomerAccountExpenses TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)	15,062,991	15,448,096
165	CustomerServiceAndInformationalExpensesAbstract 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166	CustomerServiceAndInformationalExpensesOperationAbstract Operation
167	SupervisionCustomerServiceAndInformationExpenses (907) Supervision	1,164,640	1,095,402
168	CustomerAssistanceExpenses (908) Customer Assistance Expenses	33,550,252	31,579,320
169	InformationalAndInstructionalAdvertisingExpenses (909) Informational and Instructional Expenses	24,294	39,111
170	MiscellaneousCustomerServiceAndInformationalExpenses (910) Miscellaneous Customer Service and Informational Expenses	42,608	36,188
171	CustomerServiceAndInformationExpenses TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)	34,781,793	32,750,021
172	SalesExpenseAbstract 7. SALES EXPENSES
173	SalesExpenseOperationAbstract Operation
174	SupervisionSalesExpense (911) Supervision		362
175	DemonstratingAndSellingExpenses (912) Demonstrating and Selling Expenses	192,883	254,847
176	AdvertisingExpenses (913) Advertising Expenses
177	MiscellaneousSalesExpenses (916) Miscellaneous Sales Expenses
178	SalesExpenses TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)	192,883	255,209
179	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
180	AdministrativeAndGeneralExpensesOperationAbstract Operation
181	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	24,364,658	23,419,365
182	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	1,634,226	1,074,832
183	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit	3,854,626	3,486,443
184	OutsideServicesEmployed (923) Outside Services Employed	4,480,614	3,462,285
185	PropertyInsurance (924) Property Insurance	1,584,973	1,305,824
186	InjuriesAndDamages (925) Injuries and Damages	3,045,818	496,529
187	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	4,485,661	3,150,817
188	FranchiseRequirements (927) Franchise Requirements
189	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	5,615,424	2,092,597
190	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.
191	GeneralAdvertisingExpenses (930.1) General Advertising Expenses	230,714	188,213
192	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	3,029,094	12,282,530
193	RentsAdministrativeAndGeneralExpense (931) Rents	1,290,481	1,348,865
194	AdministrativeAndGeneralOperationExpense TOTAL Operation (Enter Total of Lines 181 thru 193)	45,907,037	44,342,356
195	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
196	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	7,168,102	6,684,078
197	AdministrativeAndGeneralExpenses TOTAL Administrative & General Expenses (Total of Lines 194 and 196)	53,075,139	51,026,434
198	OperationsAndMaintenanceExpensesElectric TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 156, 164, 171, 178, and 197)	1,044,234,178	870,309,940

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

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:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

PURCHASED POWER (Account 555)
Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years. SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less. LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years. EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges. OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each adjustment. AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. Report in column (g) the megawatthours shown on bills rendered to the respondent, excluding purchases for energy storage. Report in column (h) the megawatthours shown on bills rendered to the respondent for energy storage purchases. Report in columns (i) and (j) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. Report demand charges in column (k), energy charges in column (l), and the total of any other types of charges, including out-of-period adjustments, in column (m). Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (n) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (m) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. The data in columns (g) through (n) must be totaled on the last line of the schedule. The total amount in columns (g) and (h) must be reported as Purchases on Page 401, line 10. The total amount in column (i) must be reported as Exchange Received on Page 401, line 12. The total amount in column (j) must be reported as Exchange Delivered on Page 401, line 13. Footnote entries as required and provide explanations following all required data.
					Actual Demand (MW)				POWER EXCHANGES		COST/SETTLEMENT OF POWER
Line No.	NameOfCompanyOrPublicAuthorityProvidingPurchasedPower Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	RateScheduleTariffNumber Ferc Rate Schedule or Tariff Number (c)	AverageMonthlyBillingDemand Average Monthly Billing Demand (MW) (d)	AverageMonthlyNonCoincidentPeakDemand Average Monthly NCP Demand (e)	AverageMonthlyCoincidentPeakDemand Average Monthly CP Demand (f)	MegawattHoursPurchasedOtherThanStorage MegaWatt Hours Purchased (Excluding for Energy Storage) (g)	MegawattHoursPurchasedForEnergyStorage MegaWatt Hours Purchased for Energy Storage (h)	EnergyReceivedThroughPowerExchanges MegaWatt Hours Received (i)	EnergyDeliveredThroughPowerExchanges MegaWatt Hours Delivered (j)	DemandChargesOfPurchasedPower Demand Charges ($) (k)	EnergyChargesOfPurchasedPower Energy Charges ($) (l)	OtherChargesOfPurchasedPower Other Charges ($) (m)	SettlementOfPower Total (k+l+m) of Settlement ($) (n)
1	McAlester Army Ammunitions Plant (6,7)	OS					8,099				138,700	195,549		334,249
2	Minco (4)	OS					349,618					13,456,922		13,456,922
3	Oklahoma Gas and Electric Company(10)	EX							52,134	52,134
4	Blue Canyon Wind Power LLC (4)	OS					370,896					24,854,611		24,854,611
5	Oklahoma Municipal Power Authority(11)	EX							1,051,725	589,370
6	Covanta WBH, LLC (5)	OS					10,748					379,385		379,385
7	Sleeping Bear Wind (4)	OS					464,250					5,666,486		5,666,486
8	Cowboy Wind (4)	OS					623,772					6,458,661		6,458,661
9	Southwest Power Pool (SPP) (5, 12)	OS					7,144,825					691,730,583		691,730,583
10	Calpine (6)	SF									30,369,820			30,369,820
11	Department of Public Works -	OS					121,613					2,678,744		2,678,744
12	Evergy Kansas Central (6)	SF									2,595,183			2,595,183
13	Ft. Sill (6, 7)	OS					0				2,712,864			2,712,864
14	Elk City Wind Farm (4)	OS					369,095					18,001,409		18,001,409
15	Goodwell (4)	OS					879,368					17,398,791		17,398,791
16	Balko (4)	OS					708,241					15,169,800		15,169,800
17	Electric Reliability Council of Texas (ERCOT) (6, 8)	OS										5,243		5,243
18	Seiling (4)	OS					801,058					8,514,463		8,514,463
19	Calpine (5)	OS					683,280					26,843,848		26,843,848
20	EXELON (6)	SF									54,378,000			54,378,000
21	EXELON (5)	OS					2,144,683					134,091,645		134,091,645
22	Evergy Kasnsas Central (5) WR (5)	OS					117,696					21,659,490		21,659,490
23	Grand River Dam Authority (9)	EX					0		144,468	83,707
24	Net Metering (13)	OS					513					20,784		20,784
25	Purch Pwr-NonTrading-Nonassoc (WFEC)	OS									2,036			2,036
26	Intercompany billing	OS									331			331
15	TOTAL						14,797,755		1,248,327	725,211

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

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

Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to. Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c).
In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes.
In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (d), is provided.
Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column (g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the contract.
Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
Report in column (i) and (j) the total megawatthours received and delivered.
In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (0) in column (n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report purposes only on Page 401, Lines 16 and 17, respectively.
Footnote entries and provide explanations following all required data.

TRANSFER OF ENERGY

REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS

Line No.

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

(m)

(n)

(a)

American Electric Power Service Corporation (1, 2, 3, 8)

various

N/A

various

4,332

American Electric Power Service Corporation (1, 2, 3)

various

N/A

various

31,348

Green Country Energy LLC (2)

Cogentrix

various

N/A

Cogentrix

various

51,900

Kiowa Power Partners, LLC (2)

Kiamichi Energy Facilities

various

N/A

Kiamichi

various

43,602

Southwest Power Pool (3, 4, 5, 6, 7, 8)

various

196

various

4,638,556

Southwest Power Pool (3, 4, 6, 7)

various

196

various

34,610,567

Western Farmers Electric Cooperative (2)

Western Farmers Electric Cooperative

LFP

172

Lone Oak Substation

Bethel, Henryetta,West, Sardis, Nashob,Horntown, Allen,Hardy Sub, Webb City,Talihina, Shidler

278,417

42,158

TOTAL

278,417

39,422,463

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: PaymentByCompanyOrPublicAuthority

Respondent is an affiliated company of American Electric Power Service Corporation

(2) Facilities charge

(3) Southwest Power Pool Base Plan Funding

(4) Network Integrated Transmission Service (NITS)

(5) Direct Assignment

(6) Point to point transmission and ancillary service

(7) FERC Formula Rate Settlement

(8) Prior Year

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

TRANSMISSION OF ELECTRICITY BY ISO/RTOs
Report in Column (a) the Transmission Owner receiving revenue for the transmission of electricity by the ISO/RTO. Use a separate line of data for each distinct type of transmission service involving the entities listed in Column (a). In Column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO – Firm Network Service for Others, FNS – Firm Network Transmission Service for Self, LFP – Long-Term Firm Point-to-Point Transmission Service, OLF – Other Long-Term Firm Transmission Service, SFP – Short-Term Firm Point-to-Point Transmission Reservation, NF – Non-Firm Transmission Service, OS – Other Transmission Service and AD- Out-of-Period Adjustments. Use this code for any accounting adjustments or “true-ups” for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes. In column (c) identify the FERC Rate Schedule or tariff Number, on separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (b) was provided. In column (d) report the revenue amounts as shown on bills or vouchers. Report in column (e) the total revenues distributed to the entity listed in column (a).
Line No.	Payment Received by (Transmission Owner Name) (a)	Statistical Classification (b)	FERC Rate Schedule or Tariff Number (c)	Total Revenue by Rate Schedule or Tariff (d)	Total Revenue (e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
40	TOTAL

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. Enter ""TOTAL"" in column (a) as the last line. Footnote entries and provide explanations following all required data.
			TRANSFER OF ENERGY		EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Line No.	NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	TransmissionOfElectricityByOthersEnergyReceived MegaWatt Hours Received (c)	TransmissionOfElectricityByOthersEnergyDelivered MegaWatt Hours Delivered (d)	DemandChargesTransmissionOfElectricityByOthers Demand Charges ($) (e)	EnergyChargesTransmissionOfElectricityByOthers Energy Charges ($) (f)	OtherChargesTransmissionOfElectricityByOthers Other Charges ($) (g)	ChargesForTransmissionOfElectricityByOthers Total Cost of Transmission ($) (h)
1	American Electric Power
2	Service Corporation
3	(a) (AEPSC) (1,2,3,4,5)	OS					96,623,133	96,623,133
4	(AEPSC) (1, 6)	AD					3,562,509	3,562,509
5	Southwest Power
6	Pool (3, 7)	OS					60,043,792	60,043,792
7	Pool (3, 6)	AD					3,844,138	3,844,138
	TOTAL		0	0	0	0	156,385,296	156,385,296

FOOTNOTE DATA

(a) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers

Respondent is an affiliated company of American Electric Power Service Corporation

(2) Network Integrated Transmission Service (NITS)

(3) Southwest Power Pool Base Plan Funding

(4) Southwest Power Pool Point to Point Transmission

(5) Southwest Power Pool Ancillary Service Schedule 1

(6) Prior Year

(7) Transmission Service Charge

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line No.	Description (a)	Amount (b)
1	IndustryAssociationDues Industry Association Dues	284,150
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	136,542
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	2,019,716
7	AEP Service Corporation and Other Affiliated
8	Companies Billed to or from Respondent	495,472
9	Chamber of Commerce	68,328
10	Miscellaneous Minor Items Under $5,000	24,885
46	MiscellaneousGeneralExpenses TOTAL	3,029,094

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

Depreciation and Amortization of Electric Plant (Account 403, 404, 405)
Report in section A for the year the amounts for: (b) Depreciation Expense (Account 403); (c) Depreciation Expense for Asset Retirement Costs (Account 403.1); (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric Plant (Account 405). Report in Section B the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to compute charges and whether any changes have been made in the basis or rates used from the preceding report year. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes to columns (c) through (g) from the complete report of the preceding year. Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount, account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant included in any sub-account used. In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the method of averaging used. For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification listed in column (a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type of mortality curve selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at the bottom of section C the amounts and nature of the provisions and the plant items to which related.
	A. Summary of Depreciation and Amortization Charges
Line No.	FunctionalClassificationAxis Functional Classification (a)	DepreciationExpenseExcludingAmortizationOfAcquisitionAdjustments Depreciation Expense (Account 403) (b)	DepreciationExpenseForAssetRetirementCostsExcludingAmortizationgOfAcquisitionAdjustments Depreciation Expense for Asset Retirement Costs (Account 403.1) (c)	AmortizationOfLimitedTermPlantOrProperty Amortization of Limited Term Electric Plant (Account 404) (d)	AmortizationOfOtherElectricPlant Amortization of Other Electric Plant (Acc 405) (e)	DepreciationAndAmortization Total (f)
1	Intangible Plant			16,158,721		16,158,721
2	Steam Production Plant	42,210,412	700,796			42,911,208
3	Nuclear Production Plant
4	Hydraulic Production Plant-Conventional
5	Hydraulic Production Plant-Pumped Storage
6	Other Production Plant	6,386,840	105,219			6,492,059
7	Transmission Plant	26,836,591				26,836,591
8	Distribution Plant	86,803,793				86,803,793
9	Regional Transmission and Market Operation
10	General Plant	8,620,337	14,616			8,634,952
11	Common Plant-Electric
12	TOTAL	170,857,973	820,631	16,158,721		187,837,325

B. Basis for Amortization Charges
Section A Line 1 Column D represents amortization of capitalized software development costs 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	341 - Southwest U4&5	4,849	48 years	14	3.51
13	355	336,762	42 years	60	4.06	R0.5
14	STEAM -- COAL/LIGNITE
15	310 (Rights)	939	45 years		3.77
16	341 - Weleetka	922	47 years	8	22.15
17	356	199,138	67 years	60	2.55	R2
18	311 - Northeast U3	20,459	61 years	4	2.55
19	342 - Comanche Diesel	3	73 years	4	2.35
20	356.16	2,565	67 years	60	2.55	R2
21	312 - Northeast U3	377,389	61 years	4	3.29
22	342 - Northeast U1&2 Diesel	63	68 years	7	1.8
23	358	72	45 years		1.94	R4
24	314 - Northeast U3	46,210	61 years	4	2.13
25	342 - Riverside Diesel	24	65 years	20	3.88
26	TOTAL TRANSMISSION	1,098,520
27	315 - Northeast U3	21,242	61 years	4	1.47
28	342 - Riverside U3&4	9,798	48 years	20	2.59
29	316 - Northeast U3	18,491	61 years	4	2.61
30	342 - Southwest Diesel	59	75 years	14	2.87
31	DISTRIBUTION
32	342 - Tulsa Diesel	70	67 years	14	1.73
33	360 (Rights)	2,825	70 years		1.1	R4
34	TOTAL COAL/LIGNITE	484,730
35	342 - Weleetka Diesel	10	59 years	8	9.65
36	361	20,884	40 years	5	2.53	L0
37	342 - Weleetka	1,383	47 years	8	8.46
38	362	471,682	75 years	8	1.35	L0
39	STEAM -- GAS/OIL
40	311.3 - Comanche	6,705	62 years	4	3.48
41	344 - Comanche Diesel	820	73 years	4	1.34
42	362.16	7,781	75 years	8	1.35	L0
43	311.3 - Northeast U1&2	12,292	66 years	7	3.13
44	344 - Maverick Wind	176,634	30 years		3.21
45	364	505,462	55 years	100	3.78	L0.5
46	311.3 - Riverside	11,544	67 years	20	3.78
47	344 - Northeast U1&2 Diesel	761	68 years	7	5.05
48	365	514,744	45 years	46	3.35	R0.5
49	311.3 - Southwest	9,196	70 years	14	6.24
50	344 - Northeast U3 Diesel	438	46 years	5	2.82
51	366	106,193	78 years	60	2.07	R2.5
52	311.3 - Tulsa	8,302	71 years	14	4.83
53	344 - Riverside Diesel	470	65 years	20	1.51
54	367	408,971	70 years	29	1.86	R1.5
55	312.3 - Comanche	67,630	62 years	4	5.05
56	344 - Riverside U3&4	47,573	48 years	20	2.62
57	368	402,097	35 years	15	3.41	R1
58	312.3 - Northeast U1&2	95,536	66 years	7	3.02
59	344 - Southwest Diesel	212	75 years	14	1.39
60	369	301,667	60 years	65	2.72	R1.5
61	312.3 - Riverside	78,045	67 years	20	2.67
62	344 - Southwest U4&5	45,398	48 years	14	2.77
63	370	19,781	15 years	30	8.84	L0
64	312.3 - Southwest	37,889	70 years	14	5.79
65	344 - Sundance Wind	128,618	30 years		3.21
66	370.16	94,764	15 years	30	9.64	R2
67	312.3 - Tulsa	27,146	71 years	14	4.32
68	344 - Tulsa Diesel	608	67 years	14	1.67
69	371	52,372	34 years	18	3.22	L0
70	312.11 - Transp Eq	5,256	45 years		0.14
71	344 - Weleetka Diesel	666	59 years	8	8.9
72	373	67,191	45 years	27	2.22	L0
73	314.3 - Comanche	69,016	62 years	4	3.56
74	344 - Weleetka	16,445	47 years	8	10.27
75	TOTAL DISTRIBUTION	2,976,414
76	314.3 - Northeast U1&2	145,156	66 years	7	3.5
77	345 - Northeast U1&2 Diesel	84	68 years	7	2.69
78	314.3 - Riverside	72,856	67 years	20	3.11
79	345 - Riverside Diesel	69	65 years	20	4.39
80	GENERAL PLANT
81	314.3 - Southwest	38,040	70 years	14	5.99
82	345 - Riverside U3&4	4,946	48 years	20	3.32
83	390	73,214	56 years	10	2.02	L0
84	314.3 - Tulsa	31,926	71 years	14	3.7
85	345 - Southwest U4&5	9,669	48 years	14	2.4
86	391	1,568	20 years		5.7	SQ
87	315.3 - Comanche	8,133	62 years	4	3.06
88	345 - Weleetka Diesel	36	59 years	8	4.45
89	391.11	17	5 years		31.01	SQ
90	315.3 - Northeast U1&2	16,655	66 years	7	3.34
91	345 - Weleetka	568	47 years	8	40.32
92	392	1,874	15 years		7.18	SQ
93	315.3 - Riverside	11,375	67 years	20	2.13
94	346 - Comanche Diesel	63	73 years	4	5.68
95	393	2,383	30 years		3.86	SQ
96	315.3 - Southwest	11,679	70 years	14	6.13
97	346 - Northeast U1&2 Diesel	3	68 years	7	1.12
98	394	30,682	25 years		4.33	SQ
99	315.3 - Tulsa	10,613	71 years	14	5.97
100	346 - Riverside U3&4	183	48 years	20	2.91
101	395	838	20 years		6.32	SQ
102	316.3 - Comanche	3,338	62 years	4	3.69
103	346 - Southwest U4&5	46	48 years	14	3
104	396	638	18 years		7.93	SQ
105	316.3 - Northeast U1&2	8,714	66 years	7	2.95
106	346 - Weleetka Diesel	63	59 years	8	65.61
107	397	84,636	15 years		6.97	SQ
108	316.3 - Riverside	8,672	67 years	20	5.02
109	346 - Weleetka	2,690	47 years	8	16.95
110	397.16	17,976	15 years		7.18	SQ
111	316.3 - Southwest	1,859	70 years	14	7.2
112	398	8,636	20 years	3	5.65	SQ
113	TOTAL OTHER	454,244
114	316.3 - Tulsa	3,528	71 years	14	5.92
115	TOTAL GENERAL PLANT	222,462
116	TOTAL GAS/OIL	801,101
117	TRANSMISSION
118	350 (Rights)	45,921	75 years		1.18	R4
119	DEPRECIABLE SUM	(a) 6,037,471
120	352	17,540	60 years	3	1.77	R3
121	OTHER GENERATION

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: DepreciablePlantBase

The depreciable plant base is the November 30, 2021 total company depreciable plant.

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

REGULATORY COMMISSION EXPENSES
Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts deferred in previous years. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization. List in columns (f), (g), and (h), expenses incurred during the year which were charged currently to income, plant, or other accounts. Minor items (less than $25,000) may be grouped.
						EXPENSES INCURRED DURING YEAR				AMORTIZED DURING YEAR
						CURRENTLY CHARGED TO
Line No.	RegulatoryCommissionDescription Description (Furnish name of regulatory commission or body the docket or case number and a description of the case) (a)	RegulatoryExpensesAssessedByRegulatoryCommission Assessed by Regulatory Commission (b)	RegulatoryExpensesOfUtility Expenses of Utility (c)	RegulatoryCommissionExpensesAmount Total Expenses for Current Year (d)	OtherRegulatoryAssetsRegulatoryCommissionExpenses Deferred in Account 182.3 at Beginning of Year (e)	NameOfDepartmentRegulatoryCommissionExpensesCharged Department (f)	AccountNumberRegulatoryCommissionExpensesCharged Account No. (g)	RegulatoryComissionExpensesIncurredAndCharged Amount (h)	RegulatoryCommissionExpensesDeferredToOtherRegulatoryAssets Deferred to Account 182.3 (i)	DeferredRegulatoryCommissionExpensesAmortizedInContraAccount Contra Account (j)	DeferredRegulatoryCommissionExpensesAmortized Amount (k)	OtherRegulatoryAssetsRegulatoryCommissionExpenses Deferred in Account 182.3 End of Year (l)
1	Expenses incurred related to preparation and
2	filing of Oklahoma Tax Case - Determination
3	of Rate Adjustments necessary with 2018
4	Tax Changes
5	Oklahoma Commission Annual Assessment Fee	1,591,530		1,591,530		Electric	928	1,591,530
6	Expenses Minor in Nature < $25,000
7	Minor Expense < $25,000		43,688	43,688		Electric	928	43,688
8	Expenses incurred in rate review before the Corporation Commission of the State of Oklahoma (OCC) - Cause No. PUD 201700151 Order No. 672864. Amortization period two years beginning March 2018.		639,995	639,995	768,510	Electric	928		514,360	928	639,995	642,875
9	Regulatory/Legislative Actions - Oklahoma		54,812	54,812		Electric	928	54,812
10	Expenses incurred related to PSO's 2017 Base Rate Case		276	276		Electric	928	276
11	Expenses incurred related to PSO's 2018 Base Rate Case		21,950	21,950		Electric	928	21,950
12	Expenses incurred related to PSO's 2021 Base Rate Case		2,102,456	2,102,456		Electric	928	2,102,456
13	Expenses incurred related to managing Formula Rates for AEP's West Operating Companies and Transco		22,997	22,997		Electric	928	22,997
14	Windcatcher Cost Recovery OK Attorney General - Deferral of expenses associated with the Wind Catcher Energy Connection application pending recovery in future rates per PSO's Cause No. PUD 201700267				434,958				434,958
15	Windrenew Project - Approved on PSO's Cause No. PUD 201800138 Order No 688455				267,670				267,670
16	PSO 2021 Winter Strm Sectizatn		250,476	250,476		Electric	928	250,476
17	PSO RFP Capacity Filing		378	378		Electric	928	378
18	PSO Integrated Resource Plans		818,863	818,863		Electric	928	818,863
19	Sundance Wind Facility		68,002	68,002		Electric	928	28,796
46	TOTAL	1,591,530	4,023,893	5,615,423	1,471,138			4,936,222	188,268		639,995	642,875

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D and D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(Identify recipient regardless of affiliation.) For any R, D and D work carried with others, show separately the respondent's cost for the year and cost chargeable to others (See definition of research, development, and demonstration in Uniform System of Accounts). Indicate in column (a) the applicable classification, as shown below: Classifications: Electric R, D and D Performed Internally: Generation hydroelectric Recreation fish and wildlife Other hydroelectric Fossil-fuel steam Internal combustion or gas turbine Nuclear Unconventional generation Siting and heat rejection Transmission Overhead Underground Distribution Regional Transmission and Market Operation Environment (other than equipment) Other (Classify and include items in excess of $50,000.) Total Cost Incurred Electric, R, D and D Performed Externally: Research Support to the electrical Research Council or the Electric Power Research Institute Research Support to Edison Electric Institute Research Support to Nuclear Power Groups Research Support to Others (Classify) Total Cost Incurred Include in column (c) all R, D and D items performed internally and in column (d) those items performed outside the company costing $50,000 or more, briefly describing the specific area of R, D and D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.). Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D and D activity. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year, listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e). Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research, Development, and Demonstration Expenditures, Outstanding at the end of the year. If costs have not been segregated for R, D and D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by ""Est."" Report separately research and related testing facilities operated by the respondent.
					AMOUNTS CHARGED IN CURRENT YEAR
Line No.	ResearchDevelopmentAndDemonstrationClassification Classification (a)	ResearchDevelopmentAndDemonstrationDescription Description (b)	ResearchDevelopmentAndDemonstrationCostsIncurredInternally Costs Incurred Internally Current Year (c)	ResearchDevelopmentAndDemonstrationCostsIncurredExternally Costs Incurred Externally Current Year (d)	AccountNumberForResearchDevelopmentAndDemonstrationCosts Amounts Charged In Current Year: Account (e)	ResearchDevelopmentAndDemonstrationCosts Amounts Charged In Current Year: Amount (f)	ResearchDevelopmentAndDemonstrationExpenditures Unamortized Accumulation (g)
1	A. (5) Environmental (other than equipment)	3 Items < $50,000	8,394		506,549	8,394
2	B. (4) Research Support to Others	3 Items < $50,000		1,231	506	1,231
3		EPRI Environmental Science		152,166	506	152,166
4	A. (1) Generation
5	A. (2) Transmission	2 Items < $50,000	7,610		566	7,610
6		2 Items < $50,000	67,299		506,549	67,299
7		1 Items < $50,000	9		566	9
8	A. (6)(f) Metering	Advanced Metering Equipment (AMI) Test Bed Development	1,489		588	1,489
9	B. (1) Electric Power Research Institute	EPRI Research Protfolio		517,454	506, 566, 588	517,454
10	A. (3) Distribution	1 Item < $50,000	7,544		588	7,544
11		IT - EPRI Annual Research Port		43,114	588, 566, 506	43,114
12	A. (6)(g) Research General	DTC Walnut Test Facility	358		566	358
13	B. Electric R&D External	7 Items < $50,000		48,159	506, 566, ,588	48,159
14	A. (6) Other	2 Items < $50,000	53,135		506, 566, 588, 549	53,135
15	(e) Unconventional Generation	Center for Energy Advancement Through Technology Innovation
16	B. (5) Total Cost Incurred Externally			843,686		843,686
17		23 Items < $50,000		114,584	506, 566, 588	114,584
18			1,018		588	1,018
19	(b) Fossil Fuel Steam	Generation Asset Management - Program Management	13,587		506,549	13,587
20		Total
21		IT- EPRI Annual Research Port		48,173	506, 566, 588
22	A. (6)(a) Solar	Solar Field Panel Testing	29		506,549	29
23	B. (1) Electric Power Research Institute	EPRI Research Portfolio		484,432	566, 506, 588	484,432
24	B. Electrical R&D External	7 Items < $50,000		60,538	506,,566, 588	60,538
25	A. (7) Total Cost Incurred Internally		160,470			160,470

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

DISTRIBUTION OF SALARIES AND WAGES
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation giving substantially correct results may be used.
Line No.	Classification (a)	Direct Payroll Distribution (b)	Allocation of Payroll Charged for Clearing Accounts (c)	Total (d)
1	SalariesAndWagesElectricAbstract Electric
2	SalariesAndWagesElectricOperationAbstract Operation
3	SalariesAndWagesElectricOperationProduction Production	17,953,554
4	SalariesAndWagesElectricOperationTransmission Transmission	2,072,485
5	SalariesAndWagesElectricOperationRegionalMarket Regional Market
6	SalariesAndWagesElectricOperationDistribution Distribution	9,181,325
7	SalariesAndWagesElectricOperationCustomerAccounts Customer Accounts	2,402,615
8	SalariesAndWagesElectricOperationCustomerServiceAndInformational Customer Service and Informational	3,615,893
9	SalariesAndWagesElectricOperationSales Sales
10	SalariesAndWagesElectricOperationAdministrativeAndGeneral Administrative and General	1,741,213
11	SalariesAndWagesElectricOperation TOTAL Operation (Enter Total of lines 3 thru 10)	36,967,085
12	SalariesAndWagesElectricMaintenanceAbstract Maintenance
13	SalariesAndWagesElectricMaintenanceProduction Production	7,508,287
14	SalariesAndWagesElectricMaintenanceTransmission Transmission	1,554,614
15	SalariesAndWagesElectricMaintenanceRegionalMarket Regional Market
16	SalariesAndWagesElectricMaintenanceDistribution Distribution	10,537,370
17	SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral Administrative and General	1,913,481
18	SalariesAndWagesElectricMaintenance TOTAL Maintenance (Total of lines 13 thru 17)	21,513,752
19	SalariesAndWagesElectricOperationAndMaintenanceAbstract Total Operation and Maintenance
20	SalariesAndWagesElectricProduction Production (Enter Total of lines 3 and 13)	25,461,841
21	SalariesAndWagesElectricTransmission Transmission (Enter Total of lines 4 and 14)	3,627,099
22	SalariesAndWagesElectricRegionalMarket Regional Market (Enter Total of Lines 5 and 15)
23	SalariesAndWagesElectricDistribution Distribution (Enter Total of lines 6 and 16)	19,718,695
24	SalariesAndWagesElectricCustomerAccounts Customer Accounts (Transcribe from line 7)	2,402,615
25	SalariesAndWagesElectricCustomerServiceAndInformational Customer Service and Informational (Transcribe from line 8)	3,615,893
26	SalariesAndWagesElectricSales Sales (Transcribe from line 9)
27	SalariesAndWagesElectricAdministrativeAndGeneral Administrative and General (Enter Total of lines 10 and 17)	3,654,694
28	SalariesAndWagesElectricOperationAndMaintenance TOTAL Oper. and Maint. (Total of lines 20 thru 27)	58,480,837	3,573,418	62,054,255
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)	58,480,837	3,573,418	62,054,255
66	SalariesAndWagesUtilityPlantAbstract Utility Plant
67	SalariesAndWagesUtilityPlantConstructionAbstract Construction (By Utility Departments)
68	SalariesAndWagesUtilityPlantConstructionElectricPlant Electric Plant	37,268,388	2,277,250	39,545,638
69	SalariesAndWagesUtilityPlantConstructionGasPlant Gas Plant
70	SalariesAndWagesUtilityPlantConstructionOther Other (provide details in footnote):
71	SalariesAndWagesUtilityPlantConstruction TOTAL Construction (Total of lines 68 thru 70)	37,268,388	2,277,250	39,545,638
72	SalariesAndWagesPlantRemovalAbstract Plant Removal (By Utility Departments)
73	SalariesAndWagesPlantRemovalElectricPlant Electric Plant	5,488,592	335,375	5,823,967
74	SalariesAndWagesPlantRemovalGasPlant Gas Plant
75	SalariesAndWagesPlantRemovalOther Other (provide details in footnote):
76	SalariesAndWagesPlantRemoval TOTAL Plant Removal (Total of lines 73 thru 75)	5,488,592	335,375	5,823,967
77	SalariesAndWagesOtherAccountsAbstract Other Accounts (Specify, provide details in footnote):
78	SalariesAndWagesOtherAccountsDescription Other Accounts (Specify, provide details in footnote):
79	SalariesAndWagesOtherAccountsDescription 152 - Fuel Stock Undistributed	1,942,583		1,942,583
80	SalariesAndWagesOtherAccountsDescription 163 - Stores Expense Undistributed	3,776,360	3,776,360
81	SalariesAndWagesOtherAccountsDescription 183 - Prelim Survey	41,795	41,795
82	SalariesAndWagesOtherAccountsDescription 184 - Clearing Accounts	2,367,888	2,367,888
83	SalariesAndWagesOtherAccountsDescription 185 - ODD Temporary Facilities	195,395		195,395
84	SalariesAndWagesOtherAccountsDescription 186 - Misc Deferred Debits	1,613,449		1,613,449
85	SalariesAndWagesOtherAccountsDescription 188 - Research & Development	10,373		10,373
86	SalariesAndWagesOtherAccountsDescription 401 - Operation Expense - Nonassociated
87	SalariesAndWagesOtherAccountsDescription 402 - Maintenance Exp
88	SalariesAndWagesOtherAccountsDescription 426 - Political Activities	39,155		39,155
89	SalariesAndWagesOtherAccountsDescription
90	SalariesAndWagesOtherAccountsDescription
91	SalariesAndWagesOtherAccountsDescription
92	SalariesAndWagesOtherAccountsDescription
93	SalariesAndWagesOtherAccountsDescription
94	SalariesAndWagesOtherAccountsDescription
95	SalariesAndWagesOtherAccounts TOTAL Other Accounts	9,986,998	6,186,043	3,800,955
96	SalariesAndWagesGeneralExpense TOTAL SALARIES AND WAGES	111,224,815		111,224,815

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

COMMON UTILITY PLANT AND EXPENSES
Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by accounts as provided by Electric Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated provisions, and amounts allocated to utility departments using the common utility plant to which such accumulated provisions relate, including explanation of basis of allocation and factors used. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such expenses are related. Explain the basis of allocation used and give the factors of allocation. Give date of approval by the Commission for use of the common utility plant classification and reference to the order of the Commission or other authorization.

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for Resale, for items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market for purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determining whether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively.
Line No.	Description of Item(s) (a)	Balance at End of Quarter 1 (b)	Balance at End of Quarter 2 (c)	Balance at End of Quarter 3 (d)	Balance at End of Year (e)
1	Energy
2	Net Purchases (Account 555)				636,650,885
2.1	Net Purchases (Account 555.1)
3	Net Sales (Account 447)				40,803,575
4	Transmission Rights
5	Ancillary Services				10,021,095
6	Other Items (list separately)
7	Congestion				90,428,557
8	Operating Reserves				9,222,770
9	Transmission Congestion Revenue				48,911,990
10	Transmission Losses				4,417,294
46	TOTAL				633,744,908

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

PURCHASES AND SALES OF ANCILLARY SERVICES
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the respondents Open Access Transmission Tariff. In columns for usage, report usage-related billing determinant and the unit of measure. On Line 1 columns (b), (c), (d), and (e) report the amount of ancillary services purchased and sold during the year. On Line 2 columns (b), (c), (d), and (e) report the amount of reactive supply and voltage control services purchased and sold during the year. On Line 3 columns (b), (c), (d), and (e) report the amount of regulation and frequency response services purchased and sold during the year. On Line 4 columns (b), (c), (d), and (e) report the amount of energy imbalance services purchased and sold during the year. On Lines 5 and 6, columns (b), (c), (d), and (e) report the amount of operating reserve spinning and supplement services purchased and sold during the period. On Line 7 columns (b), (c), (d), and (e) report the total amount of all other types ancillary services purchased or sold during the year. Include in a footnote and specify the amount for each type of other ancillary service provided.
		Amount Purchased for the Year			Amount Sold for the Year
		Usage - Related Billing Determinant			Usage - Related Billing Determinant
Line No.	Type of Ancillary Service (a)	Number of Units (b)	Unit of Measure (c)	Dollar (d)	Number of Units (e)	Unit of Measure (f)	Dollars (g)
1	Scheduling, System Control and Dispatch
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:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

MONTHLY TRANSMISSION SYSTEM PEAK LOAD
Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. Report on Column (b) by month the transmission system's peak load. Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the definition of each statistical classification.
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Firm Network Service for Self (e)	Firm Network Service for Others (f)	Long-Term Firm Point-to-point Reservations (g)	Other Long-Term Firm Service (h)	Short-Term Firm Point-to-point Reservation (i)	Other Service (j)
	NAME OF SYSTEM: 0
1	January
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	0
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	(a) 0

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: OtherService

Public Service Company of Oklahoma's transmission service is administered through a Regional Transmission Organization (RTO) and requested information is not available on an individual company basis.

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

Monthly ISO/RTO Transmission System Peak Load
Report the monthly peak load on the respondent's transmission system. If the Respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. Report on Column (b) by month the transmission system's peak load. Report on Column (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). Report on Columns (e) through (i) by month the system’s transmission usage by classification. Amounts reported as Through and Out Service in Column (g) are to be excluded from those amounts reported in Columns (e) and (f). Amounts reported in Column (j) for Total Usage is the sum of Columns (h) and (i).
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Import into ISO/RTO (e)	Exports from ISO/RTO (f)	Through and Out Service (g)	Network Service Usage (h)	Point-to-Point Service Usage (i)	Total Usage (j)
	NAME OF SYSTEM: 0
1	January
2	February
3	March
4	Total for Quarter 1				0	0	0	0	0	0
5	April
6	May
7	June
8	Total for Quarter 2				0	0	0	0	0	0
9	July
10	August
11	September
12	Total for Quarter 3				0	0	0	0	0	0
13	October
14	November
15	December
16	Total for Quarter 4				0	0	0	0	0	0
17	Total Year to Date/Year				0	0	0	0	0	0

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

2022-05-26

Year/Period of Report

End of:

2021

ELECTRIC ENERGY ACCOUNT
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
Line No.	Item (a)	MegaWatt Hours (b)	Line No.	Item (a)	MegaWatt Hours (b)
1	SOURCES OF ENERGY		21	DISPOSITION OF ENERGY
2	Generation (Excluding Station Use):		22	Sales to Ultimate Consumers (Including Interdepartmental Sales)	18,205,777
3	Steam	6,111,025	23	Requirements Sales for Resale (See instruction 4, page 311.)	8,399
4	Nuclear		24	Non-Requirements Sales for Resale (See instruction 4, page 311.)	1,136,421
5	Hydro-Conventional		25	Energy Furnished Without Charge
6	Hydro-Pumped Storage		26	Energy Used by the Company (Electric Dept Only, Excluding Station Use)	4
7	Other		27	Total Energy Losses	2,081,295
8	Less Energy for Pumping		27.1	Total Energy Stored
9	Net Generation (Enter Total of lines 3 through 8)	6,111,025	28	TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL LINE 20 UNDER SOURCES	21,431,896
10	Purchases (other than for Energy Storage)	14,797,755
10.1	Purchases for Energy Storage
11	Power Exchanges:
12	Received	1,248,327
13	Delivered	725,211
14	Net Exchanges (Line 12 minus line 13)	523,116
15	Transmission For Other (Wheeling)
16	Received	427,715
17	Delivered	427,715
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)	21,431,896

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

MONTHLY PEAKS AND OUTPUT
Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required information for each non- integrated system. Report in column (b) by month the system’s output in Megawatt hours for each month. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
Line No.	MonthAxis Month (a)	EnergyActivity Total Monthly Energy (b)	NonRequiredSalesForResaleEnergy Monthly Non-Requirement Sales for Resale & Associated Losses (c)	MonthlyPeakLoad Monthly Peak - Megawatts (d)	DayOfMonthlyPeak Monthly Peak - Day of Month (e)	HourOfMonthlyPeak Monthly Peak - Hour (f)
	NAME OF SYSTEM: 0
29	January	1,637,749	51,453	2,550	12	8
30	February	1,673,622	85,727	3,129	14	20
31	March	1,511,080	79,006	2,331	2	8
32	April	1,561,095	108,854	2,338	26	16
33	May	1,588,225	73,880	2,973	27	15
34	June	1,932,096	31,804	3,845	24	16
35	July	2,097,136	58,135	4,001	28	17
36	August	2,128,166	66,490	4,014	25	17
37	September	1,853,854	97,750	4,042	1	17
38	October	1,591,830	203,046	3,135	8	17
39	November	1,719,653	155,233	2,272	19	8
40	December	1,614,274	146,009	2,943	9	20
41	Total	20,908,780	1,157,387

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

Steam Electric Generating Plant Statistics

1. Report data for plant in Service only.
2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants.
3. Indicate by a footnote any plant leased or operated as a joint facility.
4. If net peak demand for 60 minutes is not available, give data which is available, specifying period.
5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant.
6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.
7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.
8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
9. Items under Cost of Plant are based on USofA accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses.
10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants.
11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.
12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant.

Line No.	Item (a)	Plant Name: COMANCHE	Plant Name: NORTHEASTERN 1&2	Plant Name: NORTHEASTERN 3	Plant Name: North Central Wind	Plant Name: RIVERSIDE 1 & 2	Plant Name: Riverside 3 & 4	Plant Name: SOUTHWESTERN 1 - 3	Plant Name: (a) Southwestern 4 & 5	Plant Name: TULSA	Plant Name: WELEETKA
1	PlantKind Kind of Plant (Internal Comb, Gas Turb, Nuclear)	Combined Cycle	Comb Cycle/Steam Tur	Steam	Wind	Steam	Gas Turbine	Steam	Gas Turbine	Steam	Combustion Turbine
2	PlantConstructionType Type of Constr (Conventional, Outdoor, Boiler, etc)	Conv. Outdoor Boiler	Conv. Outdoor Boiler	Conv. Outdoor Boiler	Wind Generator	Conv. Outdoor Boiler	No Boiler	Conv. Outdoor Boiler	No Boiler	Conv. Outdoor Boiler	Conventional
3	YearPlantOriginallyConstructed Year Originally Constructed	1973	1961	1979	2021	1974	2008	1952	2008	1923	1975
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed	1974	2001	1980	2021	1976	2008	1967	2008	1958	1976
5	InstalledCapacityOfPlant Total Installed Cap (Max Gen Name Plate Ratings-MW)	225.00	856.00	469.00	216.00	907.00	152.00	458.00	151.00	308.00	150.00
6	NetPeakDemandOnPlant Net Peak Demand on Plant - MW (60 minutes)	248	856	465	187	895	161	446	171	318	100
7	PlantHoursConnectedToLoad Plant Hours Connected to Load	1,255	6,862	6,304	4,340	425	321	5,010	944	3,178	27
8	NetContinuousPlantCapability Net Continuous Plant Capability (Megawatts)	0	0	0		0	0	0	0	0	0
9	NetContinuousPlantCapabilityNotLimitedByCondenserWater When Not Limited by Condenser Water	0	0	0		0	0	0	0	0	0
10	NetContinuousPlantCapabilityLimitedByCondenserWater When Limited by Condenser Water	266	918	941	216	908	151	466	170	315	200
11	PlantAverageNumberOfEmployees Average Number of Employees	19	35	85	3	30	0	32	0	26	2
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh	218,525,000	2,477,189,157	2,327,108,932	251,864,688	213,498,000	67,009,000	496,822,548	136,835,000	171,446,000	2,591,000
13	CostOfLandAndLandRightsSteamProduction Cost of Plant: Land and Land Rights	345,962	101,506	3,960,322		1,376,358		191,512	0	97,253	62,660
14	CostOfStructuresAndImprovementsSteamProduction Structures and Improvements	6,704,510	12,292,372	20,459,054		11,565,514		9,152,384	4,849,168	8,337,534	922,151
15	CostOfEquipmentSteamProduction Equipment Costs	150,108,582	266,070,194	490,947,397	306,027,613	171,145,086	62,537,033	90,213,914	55,112,856	73,331,397	21,086,067
16	AssetRetirementCostsSteamProduction Asset Retirement Costs	842,350	609,488	11,906,728	7,646,243	3,218,362		942,562	0	5,123,427	16,036
17	CostOfPlant Total cost (total 13 thru 20)	158,001,404	279,073,560	527,273,501	313,673,856	187,305,320	62,537,033	100,500,373	59,962,023	86,889,611	22,086,914
18	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 17/5) Including	702.2285	326.0205	1,124.2505		206.5108	411.4278	219.4331	397.0995	282.1091	147.2461
19	OperationSupervisionAndEngineeringExpense Production Expenses: Oper, Supv, & Engr	1,177,743	4,611,404	4,713,555	286,497	1,558,248	87,380	1,478,777	178,807	587,141	87,958
20	FuelSteamPowerGeneration Fuel	44,225,370	159,805,976	44,448,012		11,588,764	11,984,562	62,046,689	15,107,703	24,295,109	129,638
21	CoolantsAndWater Coolants and Water (Nuclear Plants Only)	0							0
22	SteamExpensesSteamPowerGeneration Steam Expenses	1,193,392	1,050,369	2,616,292		303,381		2,048,565	267,132	1,318,888
23	SteamFromOtherSources Steam From Other Sources	0							0
24	SteamTransferredCredit Steam Transferred (Cr)	0							0
25	ElectricExpensesSteamPowerGeneration Electric Expenses	29,834	955,706	786,345	146,699	1,767,239	2,162	506,097	3,101	716,472	252,173
26	MiscellaneousSteamPowerExpenses Misc Steam (or Nuclear) Power Expenses	550,283	988,968	2,148,784	34,115	842,383		605,365	1,287	945,694
27	RentsSteamPowerGeneration Rents	1,147	12,998	12,211	1,270,573	1,120		2,607	0	900
28	Allowances Allowances	0							0
29	MaintenanceSupervisionAndEngineeringSteamPowerGeneration Maintenance Supervision and Engineering	349,994	816,373	1,083,677	557	127,167		352,129	26,626	301,545	209
30	MaintenanceOfStructuresSteamPowerGeneration Maintenance of Structures	301,265	786,668	807,491		1,215,572	504	301,103	0	1,006,681
31	MaintenanceOfBoilerPlantSteamPowerGeneration Maintenance of Boiler (or reactor) Plant	1,146,042	1,285,200	4,426,607		1,235,551		1,157,396	1,547	707,679	189
32	MaintenanceOfElectricPlantSteamPowerGeneration Maintenance of Electric Plant	1,569,928	1,103,402	1,468,058		1,571,979	169,939	955,003	180,737	1,007,695	719
33	MaintenanceOfMiscellaneousSteamPlant Maintenance of Misc Steam (or Nuclear) Plant	596,877	389,280	726,420		266,673	5	82,590	26,137	187,938
34	PowerProductionExpensesSteamPower Total Production Expenses	51,141,875	171,806,344	63,237,452	1,738,441	20,478,077	12,244,552	69,536,321	15,793,077	31,075,742	469,448
35	ExpensesPerNetKilowattHour Expenses per Net kWh	0.2340	0.0694	0.0272	0.0069	0.0959	0.1827	0.1400	0.1154	0.1813	0.1812

35	FuelKindAxis Plant Name	COMANCHE	COMANCHE	NORTHEASTERN 1&2	NORTHEASTERN 1&2	NORTHEASTERN 3	NORTHEASTERN 3	NORTHEASTERN 3	North Central Wind	RIVERSIDE 1 & 2	RIVERSIDE 1 & 2	RIVERSIDE 1 & 2	Riverside 3 & 4	SOUTHWESTERN 1 - 3	Southwestern 4 & 5	TULSA	TULSA	WELEETKA	WELEETKA
36	FuelKind Fuel Kind	Diesel	GAS	Diesel	GAS	COAL	Diesel/Compo	GAS	Wind	Composite	GAS	Oil/Diesel	GAS	GAS	GAS	DIESEL	GAS	Diesel	GAS
37	FuelUnit Fuel Unit	bbl	Mcf	bbl	Mcf	t	bbl	Mcf			Mcf	bbl	Mcf	Mcf	Mcf	bbl	Mcf	bbl	Mcf
38	QuantityOfFuelBurned Quantity (Units) of Fuel Burned	93	2,024,078	24	20,448,302	1,411,564	61	46,400			2,638,361	267	755,803	6,413,047	1,475,194	233	2,429,600	63	36,159
39	FuelBurnedAverageHeatContent Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)	140,000	1,020	140,000	1,020	8,593	140,000	1,020			1,020	140,000	1,020	1,020	1,020	140,000	1,020	140,000	1,020
40	AverageCostOfFuelPerUnitAsDelivered Avg Cost of Fuel/unit, as Delvd f.o.b. during year	16.650	22.010	34.890	7.980	33.329	8.100	2.560			4.550	351.020	16.020	9.840	10.400	56.490	10.160	113.780	3.750
41	AverageCostOfFuelPerUnitBurned Average Cost of Fuel per Unit Burned	16.650	22.010	34.890	7.980	28.270	8.100	2.560			4.550	351.020	16.020	9.840	10.400	0.000	10.160	113.780	3.750
42	AverageCostOfFuelBurnedPerMillionBritishThermalUnit Average Cost of Fuel Burned per Million BTU	2.830	21.580	5.930	7.820	1.640	1.380	2.510			4.460	59.700	15.700	9.640	10.200	0.000	9.960	19.350	3.670
43	AverageCostOfFuelBurnedPerKilowattHourNetGeneration Average Cost of Fuel Burned per kWh Net Gen	0.000	0.200	0.000	0.070	0.020	0.000	0.030			0.060	0.000	0.180	0.130	0.110	0.000	0.140	0.000	0.050
44	AverageBritishThermalUnitPerKilowattHourNetGeneration Average BTU per kWh Net Generation	0.000	9,448.000	0.000	8,420.000	10,445.000	0.000	10,445.000		12,612.000	12,605.000	0.000	11,505.000	13,166.000	10,996.000	0.000	14,455.000	0.000	14,235.000

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: PlantName

In April 2021, PSO acquired a 44.5% ownership share of Sundance wind facility (199 MW total nameplate capacity) which was placed in-service in April 2021.

In September 2021, PSO acquired a 44.5% ownership share of Maverick wind facility (287 MW total nameplate capacity) which was placed in-service in September 2021.

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

Hydroelectric Generating Plant Statistics

Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings).
If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. If licensed project, give project number.
If net peak demand for 60 minutes is not available, give that which is available specifying period.
If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each plant.
The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.

Line No.	Item (a)	FERC Licensed Project No. 0 Plant Name: 0
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:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

Pumped Storage Generating Plant Statistics
Large plants and pumped storage plants of 10,000 Kw or more of installed capacity (name plate ratings). If any plant is leased, operating under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. Give project number. If net peak demand for 60 minutes is not available, give that which is available, specifying period. If a group of employees attends more than one generating plant, report on Line 8 the approximate average number of employees assignable to each plant. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power System Control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses." Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes. Include on Line 36 the cost of energy used in pumping into the storage reservoir. When this item cannot be accurately computed leave Lines 36, 37 and 38 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of energy from each station or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses per net MWH as reported herein for each source described. Group together stations and other resources which individually provide less than 10 percent of total pumping energy. If contracts are made with others to purchase power for pumping, give the supplier contract number, and date of contract.
Line No.	Item (a)	FERC Licensed Project No. 0 Plant Name: 0
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:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

GENERATING PLANT STATISTICS (Small Plants)
Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped storage plants of less than 10,000 Kw installed capacity (name plate rating). Designate any plant leased from others, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project, give project number in footnote. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11, Page 402. If net peak demand for 60 minutes is not available, give the which is available, specifying period. If any plant is equipped with combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
									Production Expenses
Line No.	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	Internal Combustion:
2	Tulsa Diesel	1967	8.25			678,776	82,276		13,161		Oil	961.00
3	Riverside Diesel	1976	2.75			563,209	204,803		11,818		Oil	5,970.00
4	Northeastern 1&2 Diesel	1968	2.75			508,092	142,228		831		Oil	593.00
5	Northeastern 3&4 Diesel	1980	1.20			437,950	364,958		498		Oil	138.00
6	Weleetka Diesel	1963	4.00			776,384	194,096		7,148		Oil	1,935.00
7	Comanche Diesel	1962	4.00			775,321	193,830		1,543		Oil	283.00
8	Southwestern Diesel	1962	2.00			271,295	135,648				Oil
9	Note: Operation and Maintenance expenses
10	are immaterial in nature and are no longer
11	available for specific diesel unit.

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

ENERGY STORAGE OPERATIONS (Large Plants)
Large Plants are plants of 10,000 Kw or more. In columns (a) (b) and (c) report the name of the energy storage project, functional classification (Production, Transmission, Distribution), and location. In column (d), report Megawatt hours (MWH) purchased, generated, or received in exchange transactions for storage. In columns (e), (f) and (g) report MWHs delivered to the grid to support production, transmission and distribution. The amount reported in column (d) should include MWHs delivered/provided to a generator’s own load requirements or used for the provision of ancillary services. In columns (h), (i), and (j) report MWHs lost during conversion, storage and discharge of energy. In column (k) report the MWHs sold. In column (l), report revenues from energy storage operations. In a footnote, disclose the revenue accounts and revenue amounts related to the income generating activity. In column (m), report the cost of power purchased for storage operations and reported in Account 555.1, Power Purchased for Storage Operations. If power was purchased from an affiliated seller specify how the cost of the power was determined. In columns (n) and (o), report fuel costs for storage operations associated with self-generated power included in Account 501 and other costs associated with self-generated power. In columns (q), (r) and (s) report the total project plant costs including but not exclusive of land and land rights, structures and improvements, energy storage equipment, turbines, compressors, generators, switching and conversion equipment, lines and equipment whose primary purpose is to integrate or tie energy storage assets into the power grid, and any other costs associated with the energy storage project included in the property accounts listed.
Line No.	Name of the Energy Storage Project (a)	Functional Classification (b)	Location of the Project (c)	MWHs (d)	MWHs delivered to the grid to support Production (e)	MWHs delivered to the grid to support Transmission (f)	MWHs delivered to the grid to support Distribution (g)	MWHs Lost During Conversion, Storage and Discharge of Energy Production (h)	MWHs Lost During Conversion, Storage and Discharge of Energy Transmission (i)	MWHs Lost During Conversion, Storage and Discharge of Energy Distribution (j)	MWHs Sold (k)	Revenues from Energy Storage Operations (l)	Power Purchased for Storage Operations (555.1) (Dollars) (m)	Fuel Costs from associated fuel accounts for Storage Operations Associated with Self- Generated Power (Dollars) (n)	Other Costs Associated with Self-Generated Power (Dollars) (o)	Project Costs included in (p)	Production (Dollars) (q)	Transmission (Dollars) (r)	Distribution (Dollars) (s)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

TRANSMISSION LINE STATISTICS
Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage. If required by a State commission to report individual lines for all voltages, do so but do not group totals for each voltage under 132 kilovolts. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report substation costs and expenses on this page. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder of the line. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with respect to such structures are included in the expenses reported for the line designated. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g). Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company, give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is an associated company. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how determined. Specify whether lessee is an associated company. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
	DESIGNATION		VOLTAGE (KV) - (Indicate where other than 60 cycle, 3 phase)			LENGTH (Pole miles) - (In the case of underground lines report circuit miles)				COST OF LINE (Include in column (j) Land, Land rights, and clearing right-of-way)			EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line No.	TransmissionLineStartPoint From	TransmissionLineEndPoint To	OperatingVoltageOfTransmissionLine Operating	DesignedVoltageOfTransmissionLine Designated	SupportingStructureOfTransmissionLineType Type of Supporting Structure	LengthForStandAloneTransmissionLines On Structure of Line Designated	LengthForTransmissionLinesAggregatedWithOtherStructures On Structures of Another Line	NumberOfTransmissionCircuits Number of Circuits	SizeOfConductorAndMaterial Size of Conductor and Material	CostOfLandAndLandRightsTransmissionLines Land	ConstructionAndOtherCostsTransmissionLines Construction Costs	OverallCostOfTransmissionLine Total Costs	OperatingExpensesOfTransmissionLine Operation Expenses	MaintenanceExpensesOfTransmissionLine Maintenance Expenses	RentExpensesOfTransmissionLine Rents	OverallExpensesOfTransmissionLine Total Expenses
	(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)	(l)	(m)	(n)	(o)	(p)
1	TL90-901 ONETA SUB	OG&E INTERCONNECT CLARKSVILLE	345.00	345.00	3	16.21	0.00	1	2267.0 ACAR
2	TL90-902 ONETA SUB	RIVERSIDE PLANT	345.00	345.00	3	1.23	0.00	1	2156.0 ACSR
3	TL90-902 ONETA SUB	RIVERSIDE PLANT	345.00	345.00	3	13.32	0.00	1	2168.0 ACAR
4	TL90-902 ONETA SUB	RIVERSIDE PLANT	345.00	345.00	3	2.23	0.00	1	2267.0 ACAR
5	TL90-902 ONETA SUB	RIVERSIDE PLANT	345.00	345.00	3	1.45	0.00	2	2267.0 ACAR
6	TL90-903 NORTHEASTERN POWER STATION	ONETA	345.00	345.00	2	30.73	0.00	1	2267.0 ACAR
7	TL90-903 NORTHEASTERN POWER STATION	ONETA	345.00	345.00	3	1.69	0.00	1	2267.0 ACAR
8	TL90-904 VALLIANT	PITTSBURG	345.00	345.00	2	70.20	0.00	1	2x795.0 ACSR
9	TL90-905 VALLIANT SUB	SWEPCO INTERCONNECT OKLAHOMA-TEXAS STATE LINE	345.00	345.00	1	0.22	0.00	1	2x795.0 ACSR
10	TL90-905 VALLIANT SUB	SWEPCO INTERCONNECT OKLAHOMA-TEXAS STATE LINE	345.00	345.00	2	20.40	0.00	1	2x795.0 ACSR
11	TL90-906 RIVERSIDE PLANT	WEKIWA SUB	345.00	345.00	1	0.76	0.00	1	2156.0 ACSR
12	TL90-906 RIVERSIDE PLANT	WEKIWA SUB	345.00	345.00	3	0.80	0.00	2	2267.0 ACAR AND 1272 ACSR
13	TL90-906 RIVERSIDE PLANT	WEKIWA SUB	345.00	345.00	2	18.80	0.00	1	2267.0 ACAR
14	TL90-906 RIVERSIDE PLANT	WEKIWA SUB	345.00	345.00	3	1.30	0.00	1	2267.0 ACAR
15	TL90-907 RIVERSIDE PLANT	OG&E INTERCONNECT KENDRICK	345.00	345.00	3	47.20	0.00	1	2267.0 ACAR
16	TL90-907 RIVERSIDE PLANT	OG&E INTERCONNECT KENDRICK	345.00	345.00	3	3.80	0.00	2	2267.0 ACAR and 2x 795 ACSR
17	TL90-907 RIVERSIDE PLANT	OG&E INTERCONNECT KENDRICK	345.00	345.00	2	1.80	0.00	1	2267 ACAR
18	TL90-908 DELAWARE PLANT	KG&E INTERCONNECT KANSAS STATE LINE	345.00	345.00	2	28.22	0.00	1	2x795.0 ACSR
19	TL90-908 DELAWARE PLANT	KG&E INTERCONNECT KANSAS STATE LINE	345.00	345.00	3	1.65	0.00	2	2x795 ACSR
20	TL90-909 NORTHEASTERN POWER STATION	TULSA NORTH	345.00	345.00	3	19.35	0.00	2	2267.0 ACAR and 795 ACSR
21	TL90-909 NORTHEASTERN POWER STATION	TULSA NORTH	345.00	345.00	3	1.40	0.00	1	2267 ACAR
22	TL90-909 NORTHEASTERN POWER STATION	TULSA NORTH	345.00	345.00	2	1.95	0.00	2	2267.0 ACAR and 795 ACSR
23	TL90-914 TULSA NORTH SUB	WEKIWA SUB	345.00	345.00	2	17.50	0.00	1	2267.0 ACAR
24	TL90-915 PITTSBURG SUB	OG&E INTERCONNECT ARDMORE	345.00	345.00	2	85.60	0.00	1	2x954.0 ACSR
25	TL90-915 PITTSBURG SUB	OG&E INTERCONNECT ARDMORE	345.00	345.00	3	1.80	0.00	2	2x 795 ACSR
26	TL90-916 LAWTON EASTSIDE SUB	OG&E INTERCONNECT ARDMORE	345.00	345.00	2	0.00	1.77	1	2x954 ACSR
27	TL90-916 LAWTON EASTSIDE SUB	OG&E INTERCONNECT ARDMORE	345.00	345.00	2	69.32	0.00	1	2x954.0 ACSR
28	TL90-916 LAWTON EASTSIDE SUB	OG&E INTERCONNECT ARDMORE	345.00	345.00	3	0.41	0.00	2	2x954.0 ACSR
29	TL90-917 PITTSBURG SUB	OG&E INTERCONNECT ASHLAND	345.00	345.00	2	10.96	0.00	1	2x795.0 ACSR
30	TL90-918 LAWTON EASTSIDE SUB	OKLAUNION SUB	345.00	345.00	2	66.60	0.00	1	2x795.0 ACSR
31	TL90-919 LAWTON EASTSIDE SUB	OG&E INTERCONNECT APACHE	345.00	345.00	2	21.30	0.00	1	2x795.0 ACSR
32	TL90-919 LAWTON EASTSIDE SUB	OG&E INTERCONNECT APACHE	345.00	345.00	1	0.15	0.00	1	2x795.0 ACSR
33	TL90-921 CLARKSVILLE	OG&E INTERCONNECT	345.00	345.00	3	0.85	0.00	1	2156.0 ACSR
34	TL90-921 CLARKSVILLE	OG&E INTERCONNECT	345.00	345.00	3	1.43	0.00	1	2168.0 ACAR
35	TL90-922 DELAWARE SUB	KG&E INTERCONNECT	345.00	345.00	2	24.48	0.00	1	2x795.0 ACSR
36	TL90-923 RIVERSIDE SWITCHYARD	Co-GENTRIX SWITCHYARD	345.00	345.00	1	1.00	0.00	1	2-1272.0 ACSR
37	TL90-924 ONETA	ONETA ENERGY CENTER (CAL	345.00	345.00	2	0.14	0.00	1	2 -1272.0 ACSR
38	TL90-925 ONETA	ONETA ENERGY CENTER (CAL	345.00	345.00	2	0.15	0.00	1	2 -1272.0 ACSR
39	TL81-609 OKLAUNION DC TIE	DC TERMINAL NORTH	345.00	345.00	1	0.01	0.00	1	1926.9 ACSR
40	TL90-920 OKLAUNION SUB	SPS INTERCONNECT	345.00	345.00	2	0.88	0.00	1	2x795.0 ACSR
41	TL90-910 CATOOSA SUB	GRADA INTERCONNECT	345.00	345.00	3	13.07	0.00	1	2267.0 ACAR
42	TL90-910 CATOOSA SUB	GRADA INTERCONNECT	345.00	345.00	2	1.15	0.00	2	2267 ACAR and 795 ACSR
43	TL90-910 CATOOSA SUB	GRADA INTERCONNECT	345.00	345.00	2	0.30	0.00	1	2267 ACAR
44	TL85-100 ELK CITY SUB	SPS INTERCONNECT TEXAS STATE	230.00	230.00	2	34.12	0.00	1	795.0 ACSR
45	TL83-555 GROVE	EMPIRE ELECTRIC	161.00	161.00	2	7.61	0.80	1	(T2) 397 ACSR
46	TL81-501 (RADIAL) SOUTHEAST SUB	KENOSHA SUB	138.00	138.00	1	4.40	0.00	1	477.0 ACSR
47	TL81-501A (RADIAL) SOUTHEAST SUB	KENOSHA SUB	138.00	138.00
48	TL81-501B (RADIAL) SOUTHEAST SUB	KENOSHA SUB	138.00	138.00
49	TL81-501C (RADIAL) SOUTHEAST SUB	KENOSHA SUB	138.00	138.00
50	TL81-502 FORD GLASS PLANT SUB	SOUTHEAST SUB	138.00	138.00	1	2.38	0.00	2	795 AND 1272 ACSR
51	TL81-502 FORD GLASS PLANT SUB	SOUTHEAST SUB	138.00	138.00	2	0.74	0.00	1	795 ACSR
52	TL81-502 FORD GLASS PLANT SUB	SOUTHEAST SUB	138.00	138.00	1	1.83	0.00	1	795.0 ACSR
53	TL81-502A (RADIAL) 53RD & GARNETT TAP		138.00	138.00
54	TL81-503 SOUTH HUDSON SUB	SOUTHEAST SUB	138.00	138.00	1	1.22	0.00	1	556.5 ACSR
55	TL81-503 SOUTH HUDSON SUB	SOUTHEAST SUB	138.00	138.00	2	0.75	0.00	1	556.5 ACSR
56	TL81-506 CLINTON JCT	WEATHERFORD WINDFARM	138.00	138.00	1	0.56	0.00	1	(T2) 636 ACSR
57	TL81-506A (RADIAL)	WEATHERFORD CITY	138.00	138.00	1	3.35	0.00	1	(T2) 636 ACSR
58	TL81-506B CLINTON NATURAL GAS TAP	TLN114:0506A	138.00	138.00	1	3.01	0.00	1	(T2) 636 ACSR
59	TL81-506B CLINTON NATURAL GAS TAP	TLN114:0506B	138.00	138.00	1	0.59	0.00	1	T2 636 ACSR
60	TL81-507 (RADIAL) VALLIANT SUB	WEYCO VALLIANT SUB	138.00	138.00	1	2.72	0.00	1	477.0 ACSR
61	TL81-507 (RADIAL) VALLIANT SUB	WEYCO VALLIANT SUB	138.00	138.00	2	1.65	0.00	1	795.0 ACSR
62	TL81-509 CORNVILLE SUB	NORGE ROAD SUB	138.00	138.00	2	0.27	0.00	1	397.0 ACSR
63	TL81-509 CORNVILLE SUB	NORGE ROAD SUB	138.00	138.00	1	0.07	0.00	1	1272 ACSR
64	TL81-509 CORNVILLE SUB	NORGE ROAD SUB	138.00	138.00	2	4.55		2	397.5 ACSR
65	TL81-510A (RADIAL) CLINTON SHERMAN AFB TAP		138.00	138.00	1	4.48	0.00	1	1272 ACSR
66	TL81-511 ELK CITY SUB	CLINTON JCT SUB	138.00	138.00	2	23.17	0.00	1	477.0 ACSR
67	TL81-511 ELK CITY SUB	CLINTON JCT SUB	138.00	138.00	2	0.93	0.00	2	477.0 ACSR
68	TL81-512 ONETA SUB	BROKEN ARROW 81ST STREET SUB	138.00	138.00	1	2.08	0.00	1	1590 ACSR
69	TL81-512 ONETA SUB	BROKEN ARROW 81ST STREET SUB	138.00	138.00	1	0.21	0.00	2	1272.0 ACSR AND T2 795 ACSR
70	TL81-512 ONETA SUB	BROKEN ARROW 81ST STREET SUB	138.00	138.00	1	5.85	0.00	2	1590.0 ACSR AND 1272 ACSR
71	TL81-512 ONETA SUB	BROKEN ARROW 81ST STREET SUB	138.00	138.00	1	0.10	0.00	1	477.0 ACSR
72	TL81-513 RIVERSIDE PLANT SUB	EAST 61ST ST	138.00	138.00	1	0.44	0.00	1	2X 795 ACSR
73	TL81-513 RIVERSIDE PLANT SUB	EAST 61ST ST	138.00	138.00	2	1.00	0.00	1	2X 795 ACSR
74	TL81-513 RIVERSIDE PLANT SUB	EAST 61ST ST	138.00	138.00	3	0.55	0.00	1	2X 795 ACSR
75	TL81-513 RIVERSIDE PLANT SUB	EAST 61ST ST	138.00	138.00	1	0.41	1.87	1	1272.0 ACSR
76	TL81-513A (RADIAL) WARREN MEDICAL CENTER TAP		138.00	138.00	2	1.39	0.00	1	266.8 ACSR
77	TL81-513A (RADIAL) WARREN MEDICAL CENTER TAP		138.00	138.00	1	1.63	0.00	1	477.0 ACSR
78	TL81-513B (RADIAL) ORAL ROBERTS TAP		138.00	138.00	1	1.19	0.00	1	477 ASCR
79	TL81-514 BIXBY 111TH ST SUB	ONETA SUB	138.00	138.00	1	5.72		1	1272.0 ACSR
80	TL81-514 BIXBY 111TH ST SUB	ONETA SUB	138.00	138.00	1	0.20	0.00	2	1272 ACSR AND 1590 ASCR
81	TL81-515 COMANCHE PLANT	LAWTON EASTSIDE SUB	138.00	138.00	3	5.08	0.00	3	795.0 ACSR, 795 ACSR, AND 266.8
82	TL81-515 COMANCHE PLANT	LAWTON EASTSIDE SUB	138.00	138.00	3	0.17	0.00	2	795 ACSR AND 266.8 ACSR
83	TL81-515 COMANCHE PLANT	LAWTON EASTSIDE SUB	69.00	138.00	1	0.35	0.00	1	795 ACSR
84	TL81-516 VALLIANT SUB	CRAIG JCT SUB	138.00	138.00	2	0.50	0.00	2	795 ACSR AND 795 ACSR
85	TL81-516 VALLIANT SUB	CRAIG JCT SUB	138.00	138.00	2	11.90	0.00	1	795.0 ACSR/SD 42/7 (MACAW)
86	TL81-516 VALLIANT SUB	CRAIG JCT SUB	138.00	138.00	2	5.85	0.00	1	795.0 ACSR
87	TL81-517 SWPA W/TAP	EXPLORER PUMP SUB	138.00	138.00	1	0.42	0.00	1	477 ACSR
88	TL81-517 SWPA W/TAP	EXPLORER PUMP SUB	138.00	138.00	1	0.03	0.00	1	397.5 ACSR
89	TL81-518 (RADIAL) TULSA NORTH	WEST EDISON SUB	138.00	138.00	1	8.20	0.00	1	477.0 ACSR
90	TL81-518 (RADIAL) TULSA NORTH	WEST EDISON SUB	138.00	138.00	2	1.12	0.00	1	477 ACSR
91	TL81-518 (RADIAL) TULSA NORTH	WEST EDISON SUB	138.00	138.00	1	0.76	0.00	2	477 26/7 ACSR and 477 18/1 ACSR
92	TL81-518 (RADIAL) TULSA NORTH	WEST EDISON SUB	138.00	138.00	1	2.10	0.00	1	795 ACSR
93	TL81-519 TULSA PLANT	36TH & LEWIS SUB	138.00	138.00	1	1.41	0.00	1	2156.0 ACSR
94	TL81-519 TULSA PLANT	36TH & LEWIS SUB	138.00	138.00	3	0.47	0.00	1	2x795.0 ACSR
95	TL81-519 TULSA PLANT	36TH & LEWIS SUB	138.00	138.00	3	0.11	0.00	1	2156 ACSR
96	TL81-519 TULSA PLANT	36TH & LEWIS SUB	138.00	138.00	3	0.02	0.00	2	2156 ACSR AND 2156 ACSR
97	TL81-520 TULSA SOUTHEAST SUB	36TH & LEWIS SUB	138.00	138.00	1	3.10	0.00	1	1272.0 ACSR
98	TL81-520A (RADIAL) ZUNIS TAP		138.00	138.00	1	3.60	0.00	1	477.0 ACSR
99	TL81-520B (RADIAL) 52ND & DELAWARE EAST TAP		138.00	138.00	1	1.96	0.00	1	477.0 ACSR
100	TL81-520B (RADIAL) 52ND & DELAWARE EAST TAP		138.00	138.00	1	0.10	0.00	2	477.0 ACSR and 477 ACSR
101	TL81-521 RIVERSIDE PLANT	TULSA PLANT	138.00	138.00	1	3.27	0.00	1	795 ASCR
102	TL81-521 RIVERSIDE PLANT	TULSA PLANT	138.00	138.00	2	3.37	0.00	1	795 ACSR
103	TL81-521 RIVERSIDE PLANT	TULSA PLANT	138.00	138.00	3	0.07	0.00	2	795 ACSR
104	TL81-521A (RADIAL) 52ND & DELAWARE WEST TAP		138.00	138.00	1	3.20	0.00	2	795.0 ACSR and 1272 ACSR
105	TL81-521 B (RADIAL) JENKS TAP		138.00	138.00	2	1.59	0.00	0	477.0 ACSR
106	TL81-521 C (RADIAL) SOUTHERN HILLS TAP		138.00	138.00	3	0.65	0.00	0	559.6 AAAC
107	TL81-522 RIVERSIDE PLANT	TULSA PLANT W/TAP	138.00	138.00	3	0.31	0.00	2	556.5 ACSR and 795 ACSR
108	TL81-522 RIVERSIDE PLANT	TULSA PLANT W/TAP	138.00	138.00	2	5.39	0.00	1	556.5 ACSR
109	TL81-522 RIVERSIDE PLANT	TULSA PLANT W/TAP	138.00	138.00	1	0.10	0.00	1	795 ACSR
110	TL81-522 RIVERSIDE PLANT	TULSA PLANT W/TAP	138.00	138.00	1	0.07	0.00	3	795 ACSR, 795 ACSR and 1272 ACSR
111	TL81-522 RIVERSIDE PLANT	TULSA PLANT W/TAP	138.00	138.00	1	0.05	0.00	2	2x 795 ACSR and 1272 ACSR
112	TL81-523 RIVERSIDE PLANT	OG&E INTERCONNECT	138.00	138.00	2	1.90	1.90	3	1020 ACSR, 795 ACSR AND 1272 KCM
113	TL81-524 (RADIAL) SAND SPRINGS SUB	DENVER SUB	138.00	138.00	1	0.26	0.00	2	1272 ACSR
114	TL81-524 (RADIAL) SAND SPRINGS SUB	DENVER SUB	138.00	138.00	1	0.30	0.00	2	556.5 ACSR and 636 ACSR
115	TL81-524 (RADIAL) SAND SPRINGS SUB	DENVER SUB	138.00	138.00	1	0.22	0.00	1	636 ACSR
116	TL81-524 (RADIAL) SAND SPRINGS SUB	DENVER SUB	138.00	138.00	1	4.07	0.00	1	397 ACSR
117	TL81-524 (RADIAL) SAND SPRINGS SUB	DENVER SUB	138.00	138.00	1	0.18	0.00	1	795 ACSR
118	TL81-524 (RADIAL) SAND SPRINGS SUB	DENVER SUB	138.00	138.00	1	2.40	0.00	1	556.5 ACSR
119	TL81-525 TULSA PLANT	DENVER	138.00	138.00	1	0.06	0.00	1	477.0 ACSR
120	TL81-525 TULSA PLANT	DENVER	138.00	138.00	1	5.87	0.00	1	795.0 AAC
121	TL81-526 CATOOSA	MAID SUB w/TAP	138.00	138.00	3	0.20	0.00	1	795 ACSR
122	TL81-526 CATOOSA	MAID SUB w/TAP	138.00	138.00	2	11.30	0.00	1	1272 ACSR
123	TL81-526 CATOOSA	MAID SUB w/TAP	138.00	138.00	1	4.80	0.00	1	1272 ACSR
124	TL81-526 CATOOSA	MAID SUB w/TAP	138.00	138.00	1	3.75	0.00	1	1272 ACSR
125	TL81-526 CATOOSA	MAID SUB w/TAP	138.00	138.00	2	3.63	0.00	2	1272 ACSR and 2/0 ACSR
126	TL81-526 CATOOSA	MAID SUB w/TAP	138.00	138.00	1	0.70	0.00	2	1272 ACSR and 1272 ACSR
127	TL81526A : (RADIAL) INOLA TAP		138.00	138.00	1	2.00	0.00	1	795 ACSR
128	TL81526B : (RADIAL) CHOUTEAU 138kV TAP		138.00	138.00	1	5.63	0.00	1	T2 4/0 6/1 PENGUIN
129	TL81-527 LAWTON EASTSIDE	112TH & W. GORE	138.00	138.00	1	15.64	0.00	1	795.0 ACSR
130	TL81-527A (RADIAL) LAWTON WESTSIDE SOUTH TAP		138.00	138.00	1	0.45	0.00	1	795.0 ACSR
131	TL81-528 WEKIWA SUB	TULSA NORTH SUB	138.00	138.00	2	9.00	0.00	2	1272 ACSR and 1272 ACSR/AW
132	TL81-528 WEKIWA SUB	TULSA NORTH SUB	138.00	138.00	3	10.84	0.00	1	636 ACSR
133	TL81-528 WEKIWA SUB	TULSA NORTH SUB	138.00	138.00	3	0.10	0.00	2	1272 ACSR and 477 HAWK
134	TL81-528 WEKIWA SUB	TULSA NORTH SUB	138.00	138.00	3	0.22	0.00	1	795.0 ACSR
135	TL81-528A (RADIAL) PINE & PEORIA TAP		138.00	138.00	1	3.18	0.00	1	266.8 ACSR
136	TL81-528A (RADIAL) PINE & PEORIA TAP		138.00	138.00	1	1.17	0.00	1	477 ACSR
137	TL81-528A (RADIAL) PINE & PEORIA TAP		138.00	138.00	1	1.47	0.00	1	795 ACSR
138	TL81-529 WEKIWA SUB	KEYSTONE (SWPA) SUB	138.00	138.00	1	0.20	0.00	1	2 - 1272 ACSR
139	TL81-530 RIVERSIDE 345kV SUB	RIVERSIDE 138kV LINE SUB	138.00	138.00	1	1.13	0.00	1	2 -2156.0 ACSR
140	TL81-530 RIVERSIDE 345kV SUB	RIVERSIDE 138kV LINE SUB	138.00	138.00	1	0.38	0.00	2	2- 2156 ACSR
141	TL81-531 (RADIAL) HOLLIS TAP	HOLLIS 138kV LINE (INTERCONNECT-TX PORTION)	138.00	138.00	1	16.00	0.00	1	477.0 ACSR
142	TL81-531 (RADIAL) HOLLIS TAP	HOLLIS 138kV LINE (INTERCONNECT-TX PORTION)	138.00	138.00	2	1.00	0.00	1	477.0 ACSR
143	TL81-534 WEKIWA SUB	ARMCO SUB	138.00	138.00	1	5.58	0.00	1	1272.0 ACSR
144	TL81-534 WEKIWA SUB	ARMCO SUB	138.00	138.00	3	0.12	0.57	2	1272 ACSR AND 2267 ACSR
145	TL81-534 WEKIWA SUB	ARMCO SUB	138.00	138.00	2	0.07	0.00	1	795 ACSR
146	TL81-534 WEKIWA SUB	ARMCO SUB	138.00	138.00	2	0.11	0.00	1	1272 ACSR
147	TL81-536 SHIDLER SUB	OG&E INTERCONNECT (OSAGE)	138.00	138.00	2	5.34	0.00	1	477.0 ACSR
148	TL81-537 ELK CITY SUB	ELK CITY FALCON ROAD SUB	138.00	138.00	1	4.40	0.00	1	477.0 ACSR
149	TL81-537 ELK CITY SUB	ELK CITY FALCON ROAD SUB	138.00	138.00	1	14.60		1	(T2) 423.0 KCM (2-4/0 KC ACSR) 6/1 PENGUIN
150	TL81-539 MCALESTER SOUTH SUB	LONE OAK SUB	138.00	138.00	1	0.17	0.00	1	795 ACSR
151	TL81-539 MCALESTER SOUTH SUB	LONE OAK SUB	138.00	138.00	1	13.30	0.00	1	556.50 ACSR
152	TL81-539 MCALESTER SOUTH SUB	LONE OAK SUB	138.00	138.00	1	0.16		1	795 ACSR
153	TL81-539A MCALESTER SOUTH TAP	-	138.00	138.00	1	5.73	0.00	1	795 ACSR
154	TL81-540 LAWTON EASTSIDE	SHERIDAN ROAD	138.00	138.00	1	7.17		1	1272.0 ACSR
155	TL81-540 LAWTON EASTSIDE	SHERIDAN ROAD	138.00	138.00	1	0.35		2	1272.0 ACSR & 477 ACSR
156	TL81-541 LAWTON SHERIDAN ROAD	LAWTON 112TH & W GORE	138.00	138.00	1	7.06	0.00	1	477.0 ACSR
157	TL81-541A (RADIAL) LAWTON WESTSIDE NORTH TAP		138.00	138.00	1	1.50		1	477.0 ACSR
158	TL81-542 LAWTON 112TH W GORE	SNYDER	138.00	138.00	1	8.11		1	795 ACSR
159	TL81-542 LAWTON 112TH W GORE	SNYDER	138.00	138.00	2	19.00		1	795 ACSR
160	TL81-542A (RADIAL) CACHE TAP		138.00	138.00	1	0.04		1	795 ACSR
161	TL81-542B (RADIAL) LAWTON AIR PRODUCTS TAP		138.00	138.00	1	0.60		1	477.0 ACSR
162	TL81-543 (RADIAL) LAWTON 112TH & W. GORE	GOODYEAR 138KV LINE	138.00	138.00	1	0.59	0.00	0	477.0 ACSR
163	TL81-544 RIVERSIDE PLANT SUB	KIMBERLY CLARK SUB 138kV LINE	138.00	138.00	1	0.74	0.00	2	1272.0 ACSR
164	TL81-544 RIVERSIDE PLANT SUB	KIMBERLY CLARK SUB 138kV LINE	138.00	138.00	1	1.57	0.00	1	1272 ACSR
165	TL81-544 RIVERSIDE PLANT SUB	KIMBERLY CLARK SUB 138kV LINE	138.00	138.00	3	0.31	0.00	2	1272 ACSR
166	TL81-545 NORTHEASTERN POWER STATION	VINITA JUNCTION 138kV LINE	138.00	138.00	1	0.09	0.00	1	1272 ACSR
167	TL81-545 NORTHEASTERN POWER STATION	VINITA JUNCTION 138kV LINE	138.00	138.00	1	1.91	0.00	1	477.0 ACSR
168	TL81-545 NORTHEASTERN POWER STATION	VINITA JUNCTION 138kV LINE	138.00	138.00	2	30.00	0.00	1	1272.0 ACSR
169	TL81-545 NORTHEASTERN POWER STATION	VINITA JUNCTION 138kV LINE	138.00	138.00	1	4.36	0.00	1	1272.0 ACSR
170	TL81-545 NORTHEASTERN POWER STATION	VINITA JUNCTION 138kV LINE	138.00	138.00	1	5.54	0.00	1	(T2) 636 ACSR
171	TL81-545 NORTHEASTERN POWER STATION	VINITA JUNCTION 138kV LINE	138.00	138.00	1	0.13	0.00	2	(T2) 636 ACSR AND 397.5 ACSR
172	TL81-545 NORTHEASTERN POWER STATION	VINITA JUNCTION 138kV LINE	138.00	138.00	1	1.08	0.00	2	1272 ACSR AND 397.5 ACSR
173	TL81-545 NORTHEASTERN POWER STATION	VINITA JUNCTION 138kV LINE	138.00	138.00	1	2.70	0.00	2	1272 ACSR AND 477 ACSR
174	TL81-545A (RADIAL) HAWTHORNE TAP		138.00	138.00	1	0.18	0.00	1	477 ACSR
175	TL81-545B (RADIAL) ALLUWE SHELL TAP		138.00	138.00	2	0.30	0.00	1	1272 ACSR
176	TL81-545B (RADIAL) ALLUWE SHELL TAP		138.00	138.00	2	1.67	0.00	1	477 ACSR
177	TL81-546 PRYOR JCT SUB	MAID SUB	138.00	138.00	1	0.63	0.00	1	1272.0 ACSR
178	TL81-546 PRYOR JCT SUB	MAID SUB	138.00	138.00	2	5.67	0.00	1	1272.0 ACSR
179	TL 81-546A (RADIAL) ELKEM MIDWEST CABIDE TAP		138.00	138.00	2	0.06	0.00	1	1272.0 ACSR
180	TL81-547 CATOOSA SUB	AMERICAN AIRLINES SUB	138.00	138.00	1	3.39	0.00	1	1272.0 ACSR
181	TL81-547 CATOOSA SUB	AMERICAN AIRLINES SUB	138.00	138.00	2	5.44	0.00	1	(T2) 636 ACSR
182	TL81-547 CATOOSA SUB	AMERICAN AIRLINES SUB	138.00	138.00	1	0.07	0.00	1	636 ACSR
183	TL81-548 TULSA NORTH	AMERICAN AIRLINES 138kV	138.00	138.00	1	0.33	0.00	2	1272.0 ACSR and 636 ACSR
184	TL81-548 TULSA NORTH	AMERICAN AIRLINES 138kV	138.00	138.00	2	3.16	0.00	1	1272 ACSR
185	TL81-548 TULSA NORTH	AMERICAN AIRLINES 138kV	138.00	138.00	1	7.25	0.00	1	1272 ACSR
186	TL81-548A (RADIAL) CHEROKEE DATA CENTER WEST TAP		138.00	138.00	1	1.00	0.00	1	(T2) 397 ACSR
187	TL81-549 NOWATA SUB	BARTLESVILLE SOUTHEAST	138.00	138.00	1	14.36	0.00	1	(T2) 397 ACSR
188	TL81-550 TULSA PLANT	RIVERSIDE PLANT 138kV	138.00	138.00	1	0.17	0.00	2	1272 ACSR and 795 ACSR
189	TL81-550 TULSA PLANT	RIVERSIDE PLANT 138kV	138.00	138.00	2	1.14	0.00	1	T2 636 ACSR
190	TL81-550 TULSA PLANT	RIVERSIDE PLANT 138kV	138.00	138.00	1	1.11	0.00	1	T2 636 ACSR
191	TL81-550 TULSA PLANT	RIVERSIDE PLANT 138kV	138.00	138.00	1	4.67	0.00	1	1272 ACSR
192	TL81-550A (RADIAL) OAKS 138kV		138.00	138.00	1	3.04	0.00	1	4/0 ACSR (PENGUIN)
193	TL81-551 KIMBERLY CLARK	BIXBY 111TH 138kV	138.00	138.00	1	4.69	0.00	1	1272.0 ACSR
194	TL81-551 KIMBERLY CLARK	BIXBY 111TH 138kV	138.00	138.00	3	0.71	0.00	1	1272 ACSR
195	TL81-551 KIMBERLY CLARK	BIXBY 111TH 138kV	138.00	138.00	1	1.40	0.00	2	1272 ACSR
196	TL81-553 TULSA SOUTHEAST	ONETA	138.00	138.00	1	2.26	0.00	1	1272.0 ACSR
197	TL81-553A (RADIAL) 77TH MEMORIAL TAP		138.00	138.00	1	1.30	0.00	1	477 ACSR
198	TL81-553B (RADIAL) 53RD & GARNETT TAP		138.00	138.00	1	0.70	0.00	2	(T2) 4/0, 6/1 and 477 ACSR
199	TL81-554 PRYOR JCT SUB	GROVE	138.00	138.00	1	2.22	0.00	1	795 ACSR
200	TL81-554 PRYOR JCT SUB	GROVE	138.00	138.00	2	14.06	0.00	1	795 ACSR
201	TL81-554 PRYOR JCT SUB	GROVE	138.00	138.00	2	32.00	0.00	1	(T2) 397.0 ACSR
202	TL81-554 PRYOR JCT SUB	GROVE	138.00	138.00	1	0.52	0.00	2	795 ACSR
203	TL81-554 PRYOR JCT SUB	GROVE	138.00	138.00	1	0.30	0.00	2	(T2) 397 ACSR
204	TL81-554A JAY TAP		138.00	138.00	1	0.16	0.00	2	795 ACSR
205	TL81-556 TULSA SOUTHEAST SUB	EAST 61ST SUB	138.00	138.00	1	0.14	0.00	1	1272.0 ACSR
206	TL81-556 TULSA SOUTHEAST SUB	EAST 61ST SUB	138.00	138.00	1	1.69	0.00	2	1272.0 ACSR
207	TL81-556 TULSA SOUTHEAST SUB	EAST 61ST SUB	138.00	138.00	1	1.80	0.00	1	1272.0 ACSR (54/19)
208	TL81-557 VINITA JCT SUB	HOCKERVILLE SUB (EDE)	138.00	138.00	1	3.51	0.00	1	795 ACSR
209	TL81-557 VINITA JCT SUB	HOCKERVILLE SUB (EDE)	138.00	138.00	1	1.19	0.00	1	(T2) 397 ACSR
210	TL81-557 VINITA JCT SUB	HOCKERVILLE SUB (EDE)	138.00	138.00	2	12.30	0.00	1	(T2) 397 ACSR
211	TL81-557 VINITA JCT SUB	HOCKERVILLE SUB (EDE)	138.00	138.00	2	17.52	0.00	1	795 ACSR
212	TL81-558 MOUND ROAD SUB	SHIDLER/PAWHUSKA	138.00	138.00	1	2.54	0.00	1	795.0 ACSR
213	TL81-558 MOUND ROAD SUB	SHIDLER/PAWHUSKA	138.00	138.00	1	0.87	0.00	2	795.0 ACSR
214	TL81-558 MOUND ROAD SUB	SHIDLER/PAWHUSKA	138.00	138.00	2	3.60	0.00	1	477 HAWK
215	TL81-559 BARTLESVILLE SOUTHEAST SUB	BARTLESVILLE COMANCHE SUB	138.00	138.00	1	0.08	0.00	1	795 ACSR
216	TL81-559 BARTLESVILLE SOUTHEAST SUB	BARTLESVILLE COMANCHE SUB	138.00	138.00	1	3.28	0.00	1	636.0 ACSR
217	TL81-559 BARTLESVILLE SOUTHEAST SUB	BARTLESVILLE COMANCHE SUB	138.00	138.00	2	1.42	0.00	1	636.0 ACSR
218	TL81-559 BARTLESVILLE SOUTHEAST SUB	BARTLESVILLE COMANCHE SUB	138.00	138.00	1	0.04	0.00	2	477 ACSR and 477 ACSR
219	TL81-559 BARTLESVILLE SOUTHEAST SUB	BARTLESVILLE COMANCHE SUB	138.00	138.00	1	0.03	0.00	2	477 ACSR and 4/0 ACSR 6/1
220	TL81-560 ONETA SUB	81ST & GARNETT SUB	138.00	138.00	1	8.19	0.00	1	(T2) 636 ACSR
221	TL81-560 ONETA SUB	81ST & GARNETT SUB	138.00	138.00	1	9.33	0.00	1	1272 ACSR
222	TL81-560A (RADIAL) 121ST & LYNN LANE TAP		138.00	138.00	1	0.02	0.00	1	1272 ACSR
223	TL81-561 CRAIG JCT.	IDABEL	138.00	138.00	1	0.15	0.00	1	1272 ACSR
224	TL81-561 CRAIG JCT.	IDABEL	138.00	138.00	2	11.58	0.00	1	795 ACSR/SD
225	TL81-561 CRAIG JCT.	IDABEL	138.00	138.00	1	2.00	0.00	1	795 ACSR
226	TL81-561 CRAIG JCT.	IDABEL	138.00	138.00	2	3.63	0.00	1	795 ACSR
227	TL81-561 CRAIG JCT.	IDABEL	138.00	138.00	2	0.50	0.00	2	795 ACSR AND 795 ACSR
228	TL81-561A (RADIAL) BROKEN BOW TAP		138.00	138.00	1	2.30	0.00	1	477 ACSR
229	TL81-562 MOHAWK	AMERICAN AIRLINES	138.00	138.00	1	4.49	0.00	1	1272.0 ACSR
230	TL81-562 MOHAWK	AMERICAN AIRLINES	138.00	138.00	2	1.55	0.00	1	1272 ACSR
231	TL81-563 96TH AND YALE SUB	EAST 61ST ST SUB 138kV	138.00	138.00	2	2.87	0.00	1	1272.0 ACSR/AW
232	TL81-563 96TH AND YALE SUB	EAST 61ST ST SUB 138kV	138.00	138.00	1	2.32	0.00	1	1272 ACSR/AW
233	TL81-563 96TH AND YALE SUB	EAST 61ST ST SUB 138kV	138.00	138.00	1	0.40	0.00	2	1272 ACSR/AW 477 ACSR
234	TL81-564 DELAWARE SUB	KANSAS STATE LINE 138KV	138.00	138.00	1	15.54	0.00	1	1272.0 ACSR
235	TL81-565 COMANCHE	112TH & W. GORE	138.00	138.00	1	19.69	0.00	1	(T2) 636 ACSR
236	TL81-566 BROKEN ARROW 81ST STREET SUB	FORD GLASS PLANT SUB 138KV	138.00	138.00	1	3.06	0.00	1	795.0 ACSR
237	TL81-579 HENRYETTA	WELEETKA (TLN114:00567)	138.00	138.00	1	13.33	0.00	1	1272.0 ACSR
238	TL81-568 AMERICAN AIRLINES	MINGO ROAD AIRPORT	138.00	138.00	1	0.93	0.38	0	1272.0 ACSR
239	TL81-616 Craig Junction	Hugo (WFEC)	138.00	138.00	1	0.24	0.00	1	1272 ACSR
240	TL81-802 WELEETKA PLANT	RIVERSIDE PLANT (TLN114:0802A)	138.00	138.00	3	2.62	0.00	1	795.0 ACSR
241	TL81-600 CARSON TAP NORTH		138.00	138.00	1	0.10	0.00	1	1233.6 ACSR/TW
242	TL81-612 MCALESTER CITY BUS TIE		69.00	138.00	1	0.04	0.00	0	795 ACSR
243	TL81-802 WELEETKA PLANT	RIVERSIDE PLANT (TLN114:0802)	138.00	138.00	1	28.31	1.90	0	1272.0 ACSR
244	TL81-803 SOUTHWESTERN POWER STATION	ANADARKO (WFEC)	138.00	138.00	2	7.37	0.00	1	795.0 ACSR
245	TL81-804 SOUTHWESTERN PLANT	NORGE ROAD	138.00	138.00	2	21.90	0.00	1	397.0 ACSR
246	TL81-805 WELEETKA PLANT	OKMULGEE	138.00	138.00	1	0.16	0.00	1	477.0 ACSR
247	TL81-805 WELEETKA PLANT	OKMULGEE	138.00	138.00	2	23.27	0.00	1	477.0 ACSR
248	TL81-806 SAND SPRINGS SUB	WILDHORSE SUB 138kV	138.00	138.00	2	1.11	0.00	2	266.8 ACSR AND 1272 ACSR
249	TL81-806 SAND SPRINGS SUB	WILDHORSE SUB 138kV	138.00	138.00	2	14.44	0.00	1	266.8 ACSR
250	TL81-806 SAND SPRINGS SUB	WILDHORSE SUB 138kV	138.00	138.00	2	3.16	0.00	1	795 ACSR
251	TL81-806 SAND SPRINGS SUB	WILDHORSE SUB 138kV	138.00	138.00	2	2.73	0.00	1	3/0 ACSR
252	TL81-806A HIGHWAY 20 TAP		138.00	138.00	2	6.16	0.00	1	4/0 ACSR
253	TL81-806B (RADIAL) HOMINY TAP		138.00	138.00	1	6.56	0.00	1	477 ACSR
254	TL81-806C (RADIAL) 81-806 TAP (11/2) 81-843 EMERGENCY CON		138.00	138.00	1	1.21	0.00	1	266.8 ACSR
255	TL81-807 ONETA	TULSA SOUTHEAST	138.00	138.00	3	9.18	0.00	2	1026 ACCC AND T2 795 ACSR
256	TL81-807 ONETA	TULSA SOUTHEAST	138.00	138.00	3	5.64	0.00	2	795 ACSR AND T2 397.5 ACSR
257	TL81-807 ONETA	TULSA SOUTHEAST	138.00	138.00	2	0.83	0.00	2	T2 397.5 ACSR
258	TL81-807 ONETA	TULSA SOUTHEAST	138.00	138.00	1	0.47	0.00	1	477 ACSR
259	TL81-807 ONETA	TULSA SOUTHEAST	138.00	138.00	1	2.32	0.00	2	(T2) 795 ACSR T2 397.5 ACSR
260	TL81-807A (RADIAL) BROKEN ARROW NORTH TAP		138.00	138.00	1	0.29	0.00	1	477 ACSR
261	TL81-807A (RADIAL) BROKEN ARROW NORTH TAP		138.00	138.00	2	2.95	0.00	1	477 ACSR
262	TL81-808 TULSA PLANT SUB	SAND SPRINGS SUB	138.00	138.00	3	2.44	0.00	2	T2 636 ACSR
263	TL81-808 TULSA PLANT SUB	SAND SPRINGS SUB	138.00	138.00	3	1.20	0.00	2	T2 636 ACSR AND 556.5 ACSR
264	TL81-808 TULSA PLANT SUB	SAND SPRINGS SUB	138.00	138.00	3	4.15	0.00	2	556.5 ACSR
265	TL81-808 TULSA PLANT SUB	SAND SPRINGS SUB	138.00	138.00	1	0.32	0.00	2	T2 636 ACSR AND 556.5 ACSR
266	TL81-808 TULSA PLANT SUB	SAND SPRINGS SUB	138.00	138.00	1	0.07	0.00	2	1272 ACSR
267	TL81-808A (RADIAL) 12TH & CARSON SOUTH TAP		138.00	138.00	1	6.82	0.00	0	2x795.0 ACSR
268	TL81-808B (RADIAL) UNION AVENUE REFINERY
269	TL81-809 RIVERSIDE POWER	SOUTH HUDSON 138kV	138.00	138.00	2	1.57	0.00	3	T2 795 ACSR
270	TL81-809 RIVERSIDE POWER	SOUTH HUDSON 138kV	138.00	138.00	1	0.31	0.00	3	T2 795 ACSR
271	TL81-809 RIVERSIDE POWER	SOUTH HUDSON 138kV	138.00	138.00	1	1.08	0.00	2	T2 795 ACSR
272	TL81-809 RIVERSIDE POWER	SOUTH HUDSON 138kV	138.00	138.00	2	0.65	0.00	1	T2 397.5 ACSR
273	TL81-809 RIVERSIDE POWER	SOUTH HUDSON 138kV	138.00	138.00	1	1.18	0.00	1	1272 ACSR
274	TL81-809 RIVERSIDE POWER	SOUTH HUDSON 138kV	138.00	138.00	1	1.40	0.00	1	T2 795 ACSR
275	TL81-809 RIVERSIDE POWER	SOUTH HUDSON 138kV	138.00	138.00	2	4.02	0.00	1	1272 ACSR
276	TL81-809A (RADIAL) 81ST & YALE TAP		138.00	138.00	2	0.45	0.00	1	266.8 ACSR
277	TL81-809B (RADIAL) SOUTHERN HILLS TAP		138.00	138.00	1	1.10	0.00	1	477.0 ACSR
278	TL81-809D (RADIAL) WARREN MEDICAL TAP		138.00	138.00	1	0.25	0.00	1	477 ACSR
279	TL81-809D (RADIAL) WARREN MEDICAL TAP		138.00	138.00	1	0.23	0.00	1	400 MCM_UNDERGROUND
280	TL81-809E (RADIAL) ORAL ROBERTS TAP		138.00	138.00	1	0.68	0.00	1	477 ACSR
281	TL81-810 TULSA SOUTHEAST SUB	CATOOSA SUB	138.00	138.00	3		1.48	2	1026 ACCC
282	TL81-810 TULSA SOUTHEAST SUB	CATOOSA SUB	138.00	138.00	3		4.16	2	T2 397.5 ACSR
283	TL81-810 TULSA SOUTHEAST SUB	CATOOSA SUB	138.00	138.00	3		2.51	2	1026 ACCC and 954 ACSR
284	TL81-810 TULSA SOUTHEAST SUB	CATOOSA SUB	138.00	138.00	4		1.83	2	556.5 ACSR and 954 ACSR
285	TL81-810 TULSA SOUTHEAST SUB	CATOOSA SUB	138.00	138.00	2		0.83	2	T2 397.5 ACSR
286	TL81-810 TULSA SOUTHEAST SUB	CATOOSA SUB	138.00	138.00	1		0.47	2	T2 397.5 ACSR
287	TL81-810B (RADIAL) 21ST STREET TAP		138.00	138.00	1	1.34	0.00	1	556.5 ACSR
288	TL81-810B (RADIAL) 21ST STREET TAP		138.00	138.00	1	0.50	0.00	1	795 ACSR
289	TL81-810C (RADIAL) 15TH & FULTON TAP		138.00	138.00	1	0.50	0.00	1	556.5 ACSR
290	TL81-810C (RADIAL) 15TH & FULTON TAP		138.00	138.00	1	2.35			477 ACSR
291	TL81-810D (RADIAL) LYNN LANE TAP		138.00	138.00	1	1.00	0.00	1	477 ACSR
292	TL81-811 WEKIWA	SAND SPRINGS SUB 138	138.00	138.00	3	0.67	0.00	1	636 ACSR
293	TL81-811 WEKIWA	SAND SPRINGS SUB 138	138.00	138.00	1	0.10	0.00	1	1272 ACSR
294	TL81-811 WEKIWA	SAND SPRINGS SUB 138	138.00	138.00	3	0.14	0.00	2	636 ACSR
295	TL81-811 WEKIWA	SAND SPRINGS SUB 138	138.00	138.00	3	2.12	0.00	1	636 ACSR
296	TL81-812A OAKS TAP		138.00	138.00	1	2.44	0.00	1	477.0 ACSR
297	TL81-813 SAND SPRINGS SUB	ARMCO STEEL	138.00	138.00	3	0.86	0.00	2	1272.0 ACSR
298	TL81-814 NORTHEASTERN POWER STATION	TULSA NORTH 138	138.00	138.00	3	12.36	0.00	2	636 ACSR
299	TL81-814 NORTHEASTERN POWER STATION	TULSA NORTH 138	138.00	138.00	2	0.21	0.00	2	1272 ACSR
300	TL81-814 NORTHEASTERN POWER STATION	TULSA NORTH 138	138.00	138.00	1	0.81	0.00	2	636 ACSR
301	TL81-814A (RADIAL) OWASSO 86TH STREET TAP		138.00	138.00	1	0.51	0.00	0	477 ACSR
302	TL81-814B (RADIAL) OWASSO 109TH STREET TAP		138.00	138.00	1	0.24	0.00	1	795 ACSR
303	TL81-815 NORTHEASTERN POWER STATION	NOWATA	138.00	138.00	1	0.11	0.00	1	1272 ACSR
304	TL81-815 NORTHEASTERN POWER	NOWATA	138.00	138.00	2	0.31	0.00	2	795.0 ACSR AND 477 ACSR
305	TL81-815 NORTHEASTERN POWER	NOWATA	138.00	138.00	2	19.80	0.00	1	795 ACSR
306	TL81-816 NORTHEASTER POWER STATION	BARTLESVILLE SOUTHEAST	138.00	138.00	3	0.14	0.00	2	1272.0 ACSR
307	TL81-816 NORTHEASTER POWER STATION	BARTLESVILLE SOUTHEAST	138.00	138.00	3	0.07	0.00	2	1272.0 ACSR 556.5 ACSR
308	TL81-816 NORTHEASTER POWER STATION	BARTLESVILLE SOUTHEAST	138.00	138.00	3	0.71	0.00	2	1272.0 ACSR and 795 ACSR
309	TL81-816 NORTHEASTER POWER STATION	BARTLESVILLE SOUTHEAST	138.00	138.00	1	23.38	0.00	1	1272.0 ACSR
310	TL81-817 CATOOSA	NORTHEASTERN POWER STATION	138.00	138.00	1	3.35	0.00	1	477.0 ACSR
311	TL81-817B CATOOSA	NORTHEASTERN POWER STATION	138.00	138.00	1	0.03	0.00	1	477 ACSR
312	TL81-818 SAND SPRINGS SUB	OG&E INTERCONNECT	138.00	138.00	2	1.76	0.00	1	795 ACSR
313	TL81-818 SAND SPRINGS SUB	OG&E INTERCONNECT	138.00	138.00	3	0.83	0.00	1	795 ACSR
314	TL81-818 SAND SPRINGS SUB	OG&E INTERCONNECT	138.00	138.00	1	0.15	0.00	1	795 ACSR
315	TL81-818A (RADIAL) PRATTVILLE TAP		138.00	138.00	1	0.10	0.00	1	1926 ACSR TYPE 13
316	TL81-818A (RADIAL) PRATTVILLE TAP		138.00	138.00	1	0.10	0.00	2	1927 ACSR TYPE 13
317	TL81-819 SOUTHWESTERN PLANT	HOBART JCT SUB	138.00	138.00	1	0.10	0.00	2	T2 477 ACSR and 795 ACSR
318	TL81-819 SOUTHWESTERN PLANT	HOBART JCT SUB	138.00	138.00	1	16.17	0.00	1	T2 477 ACSR
319	TL81-819 SOUTHWESTERN PLANT	HOBART JCT SUB	138.00	138.00	1	0.22	0.00	1	397 ACSR
320	TL81-819 SOUTHWESTERN PLANT	HOBART JCT SUB	138.00	138.00	2	27.78	0.00	1	397 ACSR
321	TL81-819A (RADIAL) CARNEGIE TAP		138.00	138.00	1	0.03	0.00	1	477 ACSR
322	TL81-820 ALTUS JCT	RUSSELL (WFEC) ( TLN114:0820)	138.00	138.00	2	32.90	0.00	1	477.0 ACSR
323	TL81-820 ALTUS JCT	RUSSELL (WFEC) ( TLN114:0820)	138.00	138.00	1	7.10	0.00	2	795 ACSR
324	TL81-820 ALTUS JCT	RUSSELL (WFEC) ( TLN114:0820A)	138.00	138.00	2	3.85	0.00	1	477.0 ACSR
325	TL81-821 CORNVILLE SUB	DUNCAN SUB W/TAP	138.00	138.00	1	0.06	0.00	1	1272 ACSR
326	TL81-821 CORNVILLE SUB	DUNCAN SUB W/TAP	138.00	138.00	1	16.70	0.00	1	795 ACSR
327	TL81-821 CORNVILLE SUB	DUNCAN SUB W/TAP	138.00	138.00	1	0.41	0.00	1	1533.3 ACSR TYPE 13
328	TL81-821 CORNVILLE SUB	DUNCAN SUB W/TAP	138.00	138.00	2	24.00	0.00	1	266.8 ACSR
329	TL81-821 CORNVILLE SUB	DUNCAN SUB W/TAP	138.00	138.00	2	0.86	0.00	1	477 ACSR
330	TL81-821A (RADIAL) RUSH SPRINGS CHESTNUT STREET TAP		138.00	138.00	1	2.04	0.00	1	477 ACSR
331	TL81-821B RUSH SPRINGS NATURAL GAS TAP		138.00	138.00	1	0.25	0.00	1	1533.3 ACSR TYPE 13
332	TL81-821B RUSH SPRINGS NATURAL GAS TAP		138.00	138.00	1	6.74	0.00	1	T2 397.5 ACSR
333	TL81-823 SWPA INTERCONNECT TUPELO SUB	ATOKA SUB	138.00	138.00	2	24.70	0.00	1	477.0 ACSR
334	TL81-823A (RADIAL) COALGATE PUMP TAP		138.00	138.00	2	0.60	0.00	1	477.0 ACSR
335	TL81-823C (RADIAL) ALLEN TRANSOK TAP		138.00	138.00	2	8.30	0.00	1	477.0 ACSR
336	TL81-823CA EXPLORER COALGATE PUMP STATION TAP		138.00	138.00	2	0.18	0.00	1	477.0 ACSR
337	TL81-824 MARKHAM FERRY SUB	PRYOR SUB W/TAP LONE STAR	138.00	138.00	3	0.47	0.00	1	556.5 ACSR
338	TL81-824 MARKHAM FERRY SUB	PRYOR SUB W/TAP LONE STAR	138.00	138.00	2	7.66	0.00	1	556.5 ACSR
339	TL81-824 MARKHAM FERRY SUB	PRYOR SUB W/TAP LONE STAR	138.00	138.00	1	2.10	0.00	1	795 ACSR
340	TL81-824A (RADIAL) LONE STAR		138.00	138.00	2	0.16	0.00	1	556.5 ACSR
341	TL81-825 SOUTHWESTERN PLANT SUB	LAWTON EASTSIDE SUB	138.00	138.00	1	0.12	0.00	1	795 ACSR
342	TL81-825 SOUTHWESTERN PLANT SUB	LAWTON EASTSIDE SUB	138.00	138.00	2	35.90	0.00	1	795 ACSR
343	TL81-825 SOUTHWESTERN PLANT SUB	LAWTON EASTSIDE SUB	138.00	138.00	1	0.10	0.00	2	795 ACSR
344	TL81-826 BARTLESVILLE SOUTHEAST SUB	KG&E INTERCONNECT	138.00	138.00	1	0.03	0.00	1	T2 795 ACSR
345	TL81-826 BARTLESVILLE SOUTHEAST SUB	KG&E INTERCONNECT	138.00	138.00	1	1.35	0.00	2	795 ACSR and T2 795 ACSR
346	TL81-826 BARTLESVILLE SOUTHEAST SUB	KG&E INTERCONNECT	138.00	138.00	1	5.87	0.00	2	796 ACSR and 1590 ACSR
347	TL81-826 BARTLESVILLE SOUTHEAST SUB	KG&E INTERCONNECT	138.00	138.00	1	15.00	0.00	1	1590 ACSR
348	TL81-826 (RADIAL) SOUTH COFFEYVILLE TAP		138.00	138.00	1	6.00	0.00	1	1590 ACSR
349	TL81-827 BARTLESVILLE SOUTHEAST SUB	SHIDLER SUB W/TAP COMMERCE	138.00	138.00	1	0.14	0.00	1	795 ACSR
350	TL81-827(RADIAL) 81-827 TAP - 81-558 EMERGENCY CONNECTION		138.00	138.00	2	4.31	0.00	1	477 ACSR
351	TL81-828 CATOOSA	NORTHEASTERN POWER STATION	138.00	138.00	2	8.17	0.00	1	795 ACSR
352	TL81-828 CATOOSA	NORTHEASTERN POWER STATION	138.00	138.00	3	0.73	0.00	1	795.0 ACSR
353	TL81-828 CATOOSA	NORTHEASTERN POWER STATION	138.00	138.00	1	12.60	0.00	1	795.0 ACSR
354	TL81-828 CATOOSA	NORTHEASTERN POWER STATION	138.00	138.00	1	0.64	0.00	2	795.0 ACSR
355	TL81-828 CATOOSA	NORTHEASTERN POWER STATION	138.00	138.00	3	0.34	0.00	2	795.0 ACSR
356	TL81-828 CATOOSA	NORTHEASTERN POWER STATION	138.00	138.00	3	0.06	0.00	2	795.0 ACSR and 636 ACSR
357	TL81-828A (RADIAL) TERRA NITROGEN TAP		138.00	138.00	1	1.30	0.00	1	477 ACSR
358	TL81-828B (RADIAL) PORT OF CATOOSA		138.00	138.00	1	1.97	0.00	1	477 ACSR
359	TL81-828C (RADIAL) TRANSCO CLAREMORE		138.00	138.00	1	0.81	0.00	1	T2 4/0 6/1 PENGUIN
360	TL81-829 CATOOSA SUB	TULSA NORTH SUB W/TAP CHEROKEE INDUSTRIAL PARK	138.00	138.00	1	0.36	0.00	1	636.0 ACSR
361	TL81-829 CATOOSA SUB	TULSA NORTH SUB W/TAP CHEROKEE INDUSTRIAL PARK	138.00	138.00	3	16.60	0.00	2	556.5 ACSR and 636 ACSR
362	TL81-829 CATOOSA SUB	TULSA NORTH SUB W/TAP CHEROKEE INDUSTRIAL PARK	138.00	138.00	1	0.37	0.00	1	556.5 ACSR
363	TL81-829B (RADIAL) CHEROKEE INDUSTRIAL PARK TAP		138.00	138.00	1	2.20	0.00	1	795 ACSR
364	TL81-833 CORNVILLE SUB	OG&E INTERCONNECT (CIMMARON SUBSTATION)	138.00	138.00	1	0.25	0.00	1	1272.0 ACSR
365	TL81-833 CORNVILLE SUB	OG&E INTERCONNECT (CIMMARON SUBSTATION)	138.00	138.00	1	0.34	0.00	1	1590 ACSR
366	TL81-833 CORNVILLE SUB	OG&E INTERCONNECT (CIMMARON SUBSTATION)	138.00	138.00	1	0.15	0.00	1	795 ACSR
367	TL81-833 CORNVILLE SUB	OG&E INTERCONNECT (CIMMARON SUBSTATION)	138.00	138.00	2	16.52	0.00	1	795 ACSR
368	TL81-833A (RADIAL) TUTTLE CONOCO TAP		138.00	138.00	1	4.78	0.00	1	266.8 ACSR
369	TL81-836 RED OAK	EUFAULA (SWPA)	138.00	138.00	1	16.53	0.00	0	4/0 ACSR
370	TL81-836 RED OAK	EUFAULA (SWPA)	0.00	0.00	2	26.59	0.00	0	477.0 ACSR
371	TL81-836 RED OAK	EUFAULA (SWPA)	0.00	0.00	3	0.84	0.00	0	556.5 ACSR
372	TL81-836 RED OAK	EUFAULA (SWPA)	0.00	0.00	0	0.00	0.00	0	795.0 ACSR
373	TL81-837 OKMULGEE SUB	RIVERSIDE PLANT	138.00	138.00	2	26.00	1.90	1	795.0 ACSR
374	TL81-838 CATOOSA	ONETA SUB w/TAP BROKEN ARROW SUB	138.00	138.00	3	1.48	0.00	2	954 ACSR and 556.5 ACSR
375	TL81-838 CATOOSA	ONETA SUB w/TAP BROKEN ARROW SUB	138.00	138.00	3	0.95	0.00	2	954 ACSR
376	TL81-838 CATOOSA	ONETA SUB w/TAP BROKEN ARROW SUB	138.00	138.00	3	2.50	0.00	2	954 ACSR and 1026 ACCC
377	TL81-838A (RADIAL) BROKEN ARROW NORTH TAP		138.00	138.00	1	0.53	0.00	1	477 ACSR
378	TL81-838A (RADIAL) BROKEN ARROW NORTH TAP		138.00	138.00	1	3.45	0.00	1	477 ACSR
379	TL81-838B (RADIAL) 21ST & EAST AVENUE TAP		138.00	138.00	1	8.00	0.00	1	556.5 ACSR
380	TL81-838D LYNN LANE TAP		138.00	138.00	1	1.01	0.00	1	795 ACSR
381	TL81-840 LAWTON EASTSIDE	DUNCAN W/TAP COMANCHE	138.00	138.00	2	21.70	0.00	1	266.8 ACSR
382	TL81-841 SOUTHWESTERN PLANT	CORNVILLE	138.00	138.00	1	0.49	0.00	0	1272.0 ACSR
383	TL81-841 SOUTHWESTERN PLANT	CORNVILLE	138.00	138.00	2	2.00	0.00	0	795.0 ACSR
384	TL81-841C Verden Natural Gas Tap		138.00	138.00	1	0.35	0.00	1	T2 477 ACSR
385	TL81-843 TULSA NORTH SUB	BARTLESVILLE SUB	138.00	138.00	2	19.90	0.00	1	795.0 ACSR
386	TL81-843 TULSA NORTH SUB	BARTLESVILLE SUB	138.00	138.00	1	5.37	0.00	1	795 ACSR
387	TL81-844 BARTLESVILLE MOUNDS ROAD SUB	BARTLESVILLE COMANCHE	138.00	138.00	2	2.90	0.00	1	795.0 ACSR
388	TL81-844 BARTLESVILLE MOUNDS ROAD SUB	BARTLESVILLE COMANCHE	138.00	138.00	2	0.00	0.97	2	795.0 ACSR
389	TL81-845 (WFEC) INTERCONNECT RUSSELL SUB	WTU INTERCONNECT TREXAS STATE LINE	138.00	138.00	1	7.13	0.00	2	795 ASCSR
390	TL81-845 (WFEC) INTERCONNECT RUSSELL SUB	WTU INTERCONNECT TREXAS STATE LINE	138.00	138.00	2	15.83	0.00	1	477.0 ACSR
391	TL81-845 (WFEC) INTERCONNECT RUSSELL SUB	WTU INTERCONNECT TREXAS STATE LINE	138.00	138.00	3	0.97	0.00	1	477.0 ACSR
392	TL81-846 MOHAWK	TULSA NORTH 138	138.00	138.00	1	7.00	0.00	1	477.0 ACSR
393	TL81-846A (RADIAL) PINE & PEORIA TAP		138.00	138.00	1	3.46	0.00	1	477.0 ACSR
394	TL81-846B (RADIAL) 46TH STREET NORTH (EAST) TAP		138.00	138.00	1	0.83	0.00	1	477.0 ACSR
395	TL81-846B (RADIAL) YALE & ARCHER TAP		138.00	138.00	1	3.71	0.00	1	477.0 ACSR
396	TL81-847 CRAIG JCT SUB	(SWEPCO) INTERCONNECT ARKANSAS	138.00	138.00	1	2.25	0.00	2	1590.0 ACSR
397	TL81-847 CRAIG JCT SUB	(SWEPCO) INTERCONNECT ARKANSAS	138.00	138.00	1	9.30	0.00	1	1272 ACSR
398	TL81-848 SOUTHWESTERN PLANT	LAWTON EASTSIDE SUB	138.00	138.00	1	0.71	0.00	1	795 ACSR
399	TL81-848 SOUTHWESTERN PLANT	LAWTON EASTSIDE SUB	138.00	138.00	2	36.80	0.00	1	795 ACSR
400	TL81-848 SOUTHWESTERN PLANT	LAWTON EASTSIDE SUB	138.00	138.00	1	2.00	0.00	1	2x397.5 ACSR
401	TL81-848A (RADIAL) FLETCHER TEMPLE EASTEX TAP		138.00	138.00	1	1.12	0.00	1	477 ACSR
402	TL81-849 OKMULGEE	HENRYETTA	138.00	138.00	1	13.64	0.16	0	1272.0 ACSR
403	TL81-851 SAPULPA ROAD 138kV EAST LOOP		138.00	138.00	1	5.03	0.00	2	T2 636 ACSR
404	TL81-852 SAPULPA ROAD 138kV NORTH LOOP		138.00	138.00	1	5.20	0.00	2	1272 ACSR
405	TL81-853 ALTUS JUNCTION	SNYDER	138.00	138.00	1	25.20	0.00	1	T2 397
406	TL81-853 ALTUS JUNCTION	SNYDER	138.00	138.00	1	0.50	0.00	2	T2 397 AND 795 ACSR
407	TL81-531 (RADIAL) HOLLIS TAP (WTU)	HOLLIS ( INTERCONNECT-OK PORTION)	138.00	138.00	1	5.33	0.00	1	477.0 ACSR
408	TL81-504 CRAIG JCT SUB	SWPA INTERCONNECT-BROKEN BOW	138.00	138.00	1	7.88	0.00	1	795.0 ACSR
409	TL81-504 CRAIG JCT SUB	SWPA INTERCONNECT-BROKEN BOW	138.00	138.00	2	1.37	0.00	1	795.0 ACSR
410	TL81-504 CRAIG JCT SUB	SWPA INTERCONNECT-BROKEN BOW	138.00	138.00	1	0.00	2.14	2	1590 ACSR
411	TL81-504 CRAIG JCT SUB	SWPA INTERCONNECT-BROKEN BOW	138.00	138.00	1	0.15	0.00	1	1590 ACSR
412	TL81-552 BARNSDALL SUB	MOUNDS ROAD SUB	138.00	138.00	2	14.86	0.00	1	795.0 ACSR
413	TL81-552 BARNSDALL SUB	MOUNDS ROAD SUB	138.00	138.00	1	0.40	0.00	1	795.0 ACSR
414	TL81-552 BARNSDALL SUB	MOUNDS ROAD SUB	138.00	138.00	1	2.40	0.00	2	1272.0 ACSR
415	TL81-598 BROKEN ARROW	WATER PLANT TAP	69.00	138.00	1	3.11	0.00	1	1272 ACSR
416	TL81-599 COWETA JUNCTION	TAP	69.00	138.00	1	5.47	0.00	1	1272 ACSR
417	TL81-621 GRADY	CHOCTAW	138.00	138.00	1	4.10	0.15	1	1533 ACSR
418	TL81-608 GRADY 138kV	EXTENSION	138.00	138.00	1	4.10	0.00	2	1272 ACSR
419	TL81-613 PERNELL OGE	PRAIRIE POINT	138.00	138.00	1	5.20	0.00	1	1533 ACSR
420	TL81-606 TALAWANDA	MCALESTER INDUSTRIAL	138.00	138.00	1	8.80	0.00	1	1533 ACSR
421	TL81-675 TEXAS COMANCHE	PUMP 138KV TAP	69.00	138.00	1	5.56	0.00	1	1272 ACSR
422	TL66-622B THOMAS CITY	138KV TAP	69.00	138.00	1	18.11	0.00	1	477 ACSR
423	TL81-589 TIPTON TAP		69.00	138.00	1	9.44	0.00	1	1272 ACSR
424	TL66-610A TOSCO REFINERY	138KV TAP	69.00	138.00	1	1.25	0.00	1	1272 ACSR
425	TL81-824 MARKHAM FERRY SUB	PRYOR SUB W/TAP LONE STAR	115.00	138.00	1	2.15	0.00	0	795.0 ACSR
426	TL81-824 MARKHAM FERRY SUB	PRYOR SUB W/TAP LONE STAR	115.00	138.00	2	7.68	0.00	1	556.5 ACSR
427	TL81-824 MARKHAM FERRY SUB	PRYOR SUB W/TAP LONE STAR	115.00	138.00	3	0.48	0.00	1	556.5 ACSR
428	TL81-824A(RADIAL) LONE STAR TAP		115.00	138.00	2	0.16	0.00	1	556.5 ACSR
429	TL66-103 WELEETKA PLANT	OG&E INTERCONNECT (SEMINOL)	69.00	69.00	3	0.11	0.00	0	266.8 ACSR
430	TL66-106 CHOUTEAU	TULSA SOUTHEAST	69.00	69.00	2	3.15	0.00	0	266.8 ACSR
431	TL66-106 CHOUTEAU	TULSA SOUTHEAST	0.00	0.00	0	0.00	0.00	0	2/0 CU Hard Drawn
432	TL66-106 CHOUTEAU	TULSA SOUTHEAST	0.00	0.00	0	0.00	0.00	0	4/0 ACSR
433	TL66-106 CHOUTEAU	TULSA SOUTHEAST	0.00	0.00	0	0.00	0.00	0	477.0 ACSR
434	TL66-106 CHOUTEAU	TULSA SOUTHEAST	0.00	0.00	0	0.00	0.00	0	556.5 ACSR
435	TL66-109 CATOOSA	DAWSON	69.00	69.00	1	5.99	0.00	0	477.0 ACSR
436	TL66-109 CATOOSA	DAWSON	69.00	69.00	2	1.26	0.00	0	477.0 ACSR
437	TL66-111 LONE OAK - RED OAK	WILBURTON	69.00	69.00	1	7.50	0.00	1	477 ACSR
438	TL66-112 SAND SPRINGS	SUNRAY DX	69.00	69.00	1	0.51	0.00	1	556.5 ACSR
439	TL66-112 SAND SPRINGS	SUNRAY DX	69.00	69.00	1	2.44	0.00	1	266.8 ACSR
440	TL66-112 SAND SPRINGS	SUNRAY DX	69.00	69.00	1	0.60	0.00	1	795 ACSR
441	TL66-112 SAND SPRINGS	SUNRAY DX	69.00	69.00	2	0.37	0.00	1	477 ACSR
442	TL66-112 SAND SPRINGS	SUNRAY DX	69.00	69.00	3	0.79	0.00	2	636.0 ACSR
443	TL66-112 SAND SPRINGS	SUNRAY DX	69.00	69.00	1	0.22	0.00	1	636.0 ACSR
444	TL66-112 SAND SPRINGS	SUNRAY DX	69.00	69.00	1	0.00	0.26	2	1272 ACSR
445	TL66-113 BARTLESVILLE COMAN	BLAKE STATION	69.00	69.00	2	12.00	4.71	0	4/0 ACSR
446	TL66-118 RED OAK SUB - MCCURTAIN	TALHINA	69.00	69.00	1	14.50	0.00	1	4/0 ACSR
447	TL66-118 RED OAK SUB - MCCURTAIN	TALHINA	69.00	138.00	1	0.02	0.00	1	795 ACSR
448	TL66-119 HUGO	VALLIANT 345 KV	69.00	69.00	2	5.37	0.00	2	477.0 ACSR and 795 ACSR
449	TL66-119 HUGO	VALLIANT 345 KV	69.00	69.00	2	2.33	0.00	1	477.0 ACSR
450	TL66-119 HUGO	VALLIANT 345 KV	69.00	69.00	1	1.06	0.00	1	477.0 ACSR
451	TL66-119 HUGO	VALLIANT 345 KV	69.00	69.00	2	1.51	0.00	2	477.0 ACSR
452	TL66-121 RED OAK (PSO)	HOWE (OG&E)	69.00	69.00	2	0.16	0.00	0	4/0 ACSR
453	TL81-624B Antlers 138kV Extension		138.00	138.00	1	0.65	0.00	1	795 ACSR
454	TL66-130 ATOKA - HUGO	ANTLERS	69.00	69.00	2	1.50	0.00	1	4/0 ACSR
455	TL81-624A McGee Creek 138kV Extension		138.00	138.00	1	3.83	0.00	1	1272 ACSR
456	TL81-624C Valley Timbers 138kV Extension		138.00	138.00	1	0.34	0.00	1	1272 ACSR
457	TL66-131 TULSA POWER	SUNRAY DX	69.00	69.00		0.09	0.00	0	477.0 ACSR
458	TL66-131 TULSA POWER	SUNRAY DX	0.00	0.00		4.75	0.00	0	556.5 ACSR
459	TL66-131 TULSA POWER	SUNRAY DX	0.00	0.00		0.63	0.00	0	636.0 ACSR
460	TL66-138 WELEETKA STATION	OKEMAH	69.00	69.00	2	11.83	0.11	0	4/0 ACSR
461	TL66-138 WELEETKA STATION	OKEMAH	0.00	0.00	3	0.11	0.00	0	4/0 CU
462	TL66-140 PRYOR JCT	PRYOR CITY(GRDA)	69.00	69.00	1	4.65	0.00	0	397.0 ACSR
463	TL66-141 CHOUTEAU	PRYOR CITY(GRDA)	69.00	69.00	1	1.92	0.00	0	2/0 ACSR
464	TL66-141 CHOUTEAU	PRYOR CITY(GRDA)	0.00	0.00	2	11.39	0.00	0	4/0 ACSR
465	TL66-142 PRYOR JCT	VINITA	69.00	69.00	1	25.64	1.08	0	3/0 CU Hard Drawn
466	TL66-142 PRYOR JCT	VINITA	0.00	0.00	0	0.00	0.00	0	397.0 ACSR
467	TL66-142 PRYOR JCT	VINITA	0.00	0.00	0	0.00	0.00	0	477.0 ACSR
468	TL66-145 VALLIANT 345	GEORGIA PACIFIC	69.00	69.00	1	12.19	1.50	0	4/0 ACSR
469	TL66-145 VALLIANT 345	GEORGIA PACIFIC	0.00	0.00	2	5.97	0.00	0	477.0 ACSR
470	TL66-146 GRDA TAP (AFTON)	EXPLORER PIPELINE PUMP	69.00	69.00	1	4.32	0.00	0	4/0 ACSR
471	TL66-147 GRDA TAP (RAMONA)	RAMONA	69.00	69.00	2	0.11	0.00	0	4/0 ACSR
472	TL66-148 GRDA TAP (AFTON)	AFTON	69.00	69.00	1	0.61	0.00	0	4/0 ACSR
473	TL66-149 VINITA	VINITA JUNCTION	69.00	69.00	1	0.04	2.81	0	397.0 ACSR
474	TL66-149 VINITA	VINITA JUNCTION	0.00	0.00	0	0.00	0.00	0	477.0 ACSR
475	TL66-150 DAWSON	COLLINSVILLE (GRDA)	69.00	69.00	1	6.46	0.00	0	4/0 ACSR
476	TL66-150 DAWSON	COLLINSVILLE (GRDA)	0.00	0.00		0.00	0.00	0	2/0 CU
477	TL66-601 FREDERICK JCT	SNYDER	69.00	69.00	1	0.06	0.00	0	1/0 ACSR
478	TL66-601 FREDERICK JCT	SNYDER	0.00	0.00	0	0.00	0.00	0	4/0 ACSR
479	TL66-606 HOBART CITY	SNYDER	69.00	69.00	1	5.38	0.00	0	3/0 ACSR
480	TL66-606 HOBART CITY	SNYDER	0.00	0.00	2	23.91	0.00	0	397.0 ACSR
481	TL66-606A ROOSEVELT AMOCO TAP		69.00	69.00	1	0.66	0.00	0	3/0 ACSR
482	TL66-607 FORT SILL	LAWTON EASTSIDE	69.00	69.00	1	4.32	5.74	1	477.0 ACSR
483	TL81-637A Headrick Tap	TIPTON	69.00	138.00	1	7.00	0.00	1	477.0 ACSR
484	TL66-609 CORNVILLE	LINDSAY WATER FLOOD	69.00	69.00	1	0.76	0.29	0	# 2A CW
485	TL66-610 DUNCAN	COMANCHE(WFEC)	69.00	69.00	1	10.94	0.00	0	4/0 ACSR
486	TL66-611 HOBART CITY	HOBART JCT.	69.00	69.00	2	1.93	0.00	0	397.5 ACSR
487	TL66-612 SOUTHWESTERN	BINGER	69.00	69.00	2	15.19	0.00	0	266.8 ACSR
488	STATION		0.00	0.00		0.00	0.00	0	397.0 ACSR
489	STATION		0.00	0.00		0.00	0.00	0	4/0 ACSR
490	TL66-613 CORNVILLE	CYRIL	69.00	69.00	2	9.27	0.00	1	4/0 ACSR
491	TL66-613 CORNVILLE	CYRIL	69.00	69.00	2	7.92	0.00	1	477.0 ACSR
492	TL66-613 CORNVILLE	CYRIL	69.00	69.00	1	0.40	0.00	1	477.0 ACSR
493	TL66-617 FORT SILL	PORTER HILL	69.00	69.00	1	10.08	0.00	0	477.0 ACSR
494	TL66-618 ELGIN JCT	PORTER HILL	69.00	69.00	1	6.70	0.00	0	477.0 ACSR
495	TL66-619 LAWTON EASTSIDE	LAWTON WOLF CREEK	69.00	69.00	1	5.18	0.00	0	477.0 ACSR
496	TL66-619 LAWTON EASTSIDE	LAWTON WOLF CREEK	0.00	0.00	2	3.50	0.00	0
497	TL66-619 LAWTON EASTSIDE	LAWTON WOLF CREEK	0.00	0.00	3	0.19	0.00	0
498	TL66-622 WEATHERFORD	CLINTON	69.00	69.00	1	0.23	0.00	1	477.0 ACSR
499	TL66-624A Davidson Tap		69.00	69.00	1	4.10	0.00	1	477 ACSR
500	TL66-624 FREDERICK JCT	WTU Interconnect	69.00	69.00	3	0.62	0.00	1	4/0 ACSR
501	TL66-625 CYRIL	ELGIN JCT.	69.00	69.00	2	9.01	0.00	0	477.0 ACSR
502	TL66-626 CLINTON CITY	CLINTON JCT	69.00	69.00	1	5.40	0.00	1	477.0 ACSR
503	TL66-626 CLINTON CITY	CLINTON JCT	69.00	69.00	1	0.16	0.00	1	556.5 ACSR
504	TL66-626 CLINTON CITY	CLINTON JCT	69.00	69.00	1	0.08	0.00	1	477.0 ACSR
505	TL66-626A Foss Water Treatment Plant Tap		69.00	69.00	1	12.70	0.00	1	4/0 ACSR
506	TL66-627 DUKE	RUSSELL (WFEC)	69.00	69.00	1	2.50	0.00	0	4/0 ACSR
507	TL66-628 COMANCHE STATION	LAWTON EASTSIDE	69.00	69.00	1	0.45	4.92	0	477.0 ACSR
508	TL66-628 COMANCHE STATION	LAWTON EASTSIDE	0.00	0.00	0	0.00	0.00	0	795.0 ACSR
509	TL66-629 COMANCHE POWER STA	WALTERS JCT	69.00	69.00	1	13.02	0.00	0	477 ACSR
510	TL66-629 COMANCHE POWER STA	WALTERS JCT	0.00	0.00	1	4.84	0.00	0	4/0 ACSR
511	TL66-629 COMANCHE POWER STA	WALTERS JCT	0.00	0.00	1	1.46	0.00	0	397 ACSR
512	TL66-630 WAURIKA	COMANCHE (WFEC)	69.00	69.00	1	20.07	0.70	0	266.8 ACSR
513	TL66-630 WAURIKA	COMANCHE (WFEC)	0.00	0.00		0.00	0.00	0	397.0 ACSR
514	TL66-630 WAURIKA	COMANCHE (WFEC)	0.00	0.00		0.00	0.00	0	4/0 ACSR
515	TL66-630 WAURIKA	COMANCHE (WFEC)	0.00	0.00		0.00	0.00	0	477.0 ACSR
516	TL66-631 ELK CITY	HAMMON JCT	69.00	69.00	1	17.25	0.00	0	4/0 ACSR
517	TL66-631 ELK CITY	HAMMON JCT	0.00	0.00	2	0.95	0.00	0	477.0 ACSR
518	TL66-632 WEATHERFORD	WEATHERFORD SE	69.00	69.00	1	2.20	0.00	0	477.0 ACSR
519	Line cost and expense are transmission lines	not available by individual Total shown in Column j-p								46,584,352	551,229,601	597,813,952	73,522	6,848,521		6,922,042
36	TOTAL					2,623.61	47.91	549		46,584,351.65	551,229,600.76	597,813,952.41	73,521.74	6,848,520.72	0.00	6,922,042.46

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

TRANSMISSION LINES ADDED DURING YEAR

Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report minor revisions of lines.
Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m).
If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase, indicate such other characteristic.

LINE DESIGNATION

SUPPORTING STRUCTURE

CIRCUITS PER STRUCTURE

CONDUCTORS

LINE COST

Line No.

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

(m)

(n)

(o)

(p)

(q)

(a)

TL81616 Craig Junction

Hugo (WFEC)

0.24

1272

ACSR

138

938,753

91,370

1,030,123

(b)

TL81-851 SAPULPA ROAD 138kV EAST LOOP

5.03

T2 636

ACSR

138

12,032

TOTAL

950,785

91,370

1,042,155

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: TransmissionLineStartPoint

Radial line investment was transferred from AEP Oklahoma Transmission Company, Inc. to Public Service Company of Oklahoma per FERC Docket No. EC20-91-000.

(b) Concept: TransmissionLineStartPoint

Radial line investment was transferred from AEP Oklahoma Transmission Company, Inc. to Public Service Company of Oklahoma per FERC Docket No. EC20-91-000.

Name of Respondent:

Public Service Company of Oklahoma

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/26/2022

Year/Period of Report

End of:

2021

SUBSTATIONS
Report below the information called for concerning substations of the respondent as of the end of the year. Substations which serve only one industrial or street railway customer should not be listed below. Substations with capacities of Less than 10 MVA except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f). Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
		Character of Substation		VOLTAGE (In MVa)						Conversion Apparatus and Special Equipment
Line No.	SubstationNameAndLocation Name and Location of Substation (a)	SubstationCharacterDescription Transmission or Distribution (b)	SubstationCharacterAttendedOrUnattended Attended or Unattended (b-1)	PrimaryVoltageLevel Primary Voltage (In MVa) (c)	SecondaryVoltageLevel Secondary Voltage (In MVa) (d)	TertiaryVoltageLevel Tertiary Voltage (In MVa) (e)	SubstationInServiceCapacity Capacity of Substation (In Service) (In MVa) (f)	NumberOfTransformersInService Number of Transformers In Service (g)	Number of Spare Transformers (h)	ConversionApparatusAndSpecialEquipmentType Type of Equipment (i)	NumberOfConversionApparatusAndSpecialEquipmentUnits Number of Units (j)	CapacityOfConversionApparatusAndSpecialEquipment Total Capacity (In MVa) (k)
1	116TH & PEORIA - OK	Distribution		138.00	13.09		25.00	1			0	0.00
2	116TH & PEORIA - OK	Distribution		138.00	13.80		20.00	1			0	0.00
3	136TH & YALE - OK	Distribution		138.00	13.09		14.00	1			0	0.00
4	141ST & PINE - OK	Distribution		13.80	0.00	0.00	0.00			STATCAP	1	6.30
5	141ST & PINE - OK	Distribution		138.00	13.80		25.00	1			0	0.00
6	15TH & FULTON - OK	Distribution		138.00	13.80		77.30	2			0	0.00
7	15TH & PEORIA - OK	Distribution		13.20	4.36		4.68	1			0	0.00
8	15TH & PEORIA - OK	Distribution		13.20	4.16		3.00	1			0	0.00
9	1ST & PEORIA - OK	Distribution		13.20	4.36		9.36	2			0	0.00
10	36TH & LEWIS - OK	Distribution		13.20	4.16		5.00	1			0	0.00
11	36TH & LEWIS - OK	Distribution		138.00	13.80		74.60	2			0	0.00
12	36TH & OLYMPIA - OK	Transmission		138.00	13.80		80.00	2			0	0.00
13	36TH AND PITTSBURG - OK	Distribution		13.20	4.36		16.86	4			0	0.00
14	46TH STREET NORTH - OK	Distribution		138.00	13.80		37.30	1			0	0.00
15	48TH AND VANCOUVER - OK	Distribution		13.20	4.36		5.60	1			0	0.00
16	52ND AND DELAWARE - OK	Distribution		138.00	13.80		74.60	2			0	0.00
17	53RD & GARNETT - OK	Distribution		138.00	13.80		74.60	2			0	0.00
18	5TH STREET - OK	Distribution		13.80	2.40		6.25	1			0	0.00
19	72ND AND ELWOOD - OK	Distribution		13.80	0.00	0.00	0.00			STATCAP	1	7.20
20	72ND AND ELWOOD - OK	Distribution		138.00	13.80		25.00	1			0	0.00
21	77TH & MEMORIAL - OK	Distribution		138.00	13.80		74.60	2			0	0.00
22	77TH & MEMORIAL - OK	Distribution		13.80	0.00	0.00	0.00			STATCAP	2	15.60
23	81ST & GARNETT - OK	Distribution		138.00	13.80		114.60	3			0	0.00
24	81ST & GARNETT - OK	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	28.80
25	81ST AND YALE - OK	Distribution		138.00	13.20		74.60	2			0	0.00
26	96TH & YALE - OK	Distribution		138.00	13.80		37.30	1			0	0.00
27	ADAIR - OK	Distribution		69.00	13.80		10.50	1			0	0.00
28	AFTON - OK	Distribution		69.00	13.20		9.36	3			0	0.00
29	AFTON CONTL PIPE(CHEROKE - OK	Distribution		69.00	2.40		3.75	3			0	0.00
30	AFTON CONTL PIPE(CHEROKE - OK	Distribution		2.40	0.00	0.00	0.00			STATCAP	1	1.20
31	AFTON EXPLORER PUMP - OK	Distribution		69.00	2.40		9.39	3			0	0.00
32	AGRICO-TERRA NITROGEN - OK	Distribution		138.00	4.36		28.00	2			0	0.00
33	ALEX BRADLEY - OK	Distribution		138.00	13.80		9.38	1			0	0.00
34	ALLEN 138KV - OK	Transmission		138.00	13.80		20.00	1			0	0.00
35	ALLEN TRANSOK - OK	Distribution		138.00	4.16		22.40	1			0	0.00
36	ALLUWE SHELL - OK	Distribution		138.00	4.30		7.00	1			0	0.00
37	ALTUS JUNCTION - OK	Transmission		138.00	69.00	13.80	93.30	1			0	0.00
38	ALTUS JUNCTION - OK	Transmission		69.00	34.50		14.00	1			0	0.00
39	ALTUS JUNCTION - OK	Transmission		34.50	13.80		5.00	1			0	0.00
40	ALTUS JUNCTION - OK	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	9.60
41	AMERICAN AIRLINE CO. - OK	Transmission		13.80	0.00	0.00	0.00			STATCAP	2	19.20
42	AMERICAN AIRLINE CO. - OK	Transmission		138.00	13.80		74.60	2			0	0.00
43	ANTLERS - OK	Distribution		69.00	13.80		14.00	1			0	0.00
44	ATOKA 138 - OK	Transmission		138.00	23.90		22.40	1			0	0.00
45	ATOKA 138 - OK	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	9.60
46	ATOKA 138 - OK	Transmission		69.00	0.00	0.00	0.00			AIR CORE REACTOR	1	0.00
47	ATOKA 138 - OK	Transmission		13.80	0.00	0.00	0.00			STATCAP	1	6.00
48	ATOKA 138 - OK	Transmission		69.00	0.00	0.00	0.00			STATCAP	4	38.40
49	ATOKA PUMP - OK	Distribution		69.00	4.16		9.38	1			0	0.00
50	BARNSDALL TAP - OK	Transmission		34.50	0.00	0.00	0.00			STATCAP	1	6.00
51	BARNSDALL TAP - OK	Transmission		138.00	13.80		22.40	1			0	0.00
52	BARNSDALL TAP - OK	Transmission		138.00	34.50	13.80	33.60	1			0	0.00
53	BARTLESVILLE COMANCHE - OK	Distribution		13.80	0.00	0.00	0.00			STATCAP	1	6.00
54	BARTLESVILLE COMANCHE - OK	Distribution		138.00	13.20		37.30	1			0	0.00
55	BARTLESVILLE COMANCHE - OK	Distribution		138.00	13.80		37.30	1			0	0.00
56	BARTLESVILLE COMANCHE - OK	Distribution		138.00	70.50	36.20	30.00	1			0	0.00
57	BARTLESVILLE SOUTHEAST - OK	Transmission		138.00	13.80		74.60	2			0	0.00
58	BARTLESVILLE SOUTHEAST - OK	Transmission		13.80	0.00	0.00	0.00			STATCAP	1	6.00
59	BELLAIRE - OK	Distribution		13.20	4.36		9.36	2			0	0.00
60	BENTON OIL - OK	Distribution		34.50	13.80		4.20	1			0	0.00
61	BINGER 69 - OK	Distribution		69.00	13.80		7.50	1			0	0.00
62	BIRD CREEK PUMP - OK	Distribution		138.00	0.00	0.00	0.00			AIR CORE REACTOR	1
63	BIRD CREEK PUMP - OK	Distribution		138.00	4.16		5.60	1			0	0.00
64	BIRD HOLLOW - OK	Distribution		138.00	13.80		20.00	1			0	0.00
65	BIXBY 111TH STREET - OK	Distribution		138.00	13.09		20.00	1			0	0.00
66	BIXBY 111TH STREET - OK	Distribution		138.00	13.80		74.60	2			0	0.00
67	BIXBY 111TH STREET - OK	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	28.80
68	BLAKE - OK	Distribution		13.80	2.40		2.00	1			0	0.00
69	BLAKE - OK	Distribution		69.00	2.40		9.39	3			0	0.00
70	BLANCHARD SOUTH - OK	Distribution		138.00	13.80		20.00	1			0	0.00
71	BLOOMFIELD - OK	Distribution		13.20	4.36		9.36	2			0	0.00
72	BLUESTEM - OK	Distribution		138.00	13.80		22.40	1			0	0.00
73	BROKEN ARROW 101ST SOUTH - OK	Distribution		138.00	13.80		77.30	2			0	0.00
74	BROKEN ARROW 71ST - OK	Distribution		138.00	13.80		40.00	1			0	0.00
75	BROKEN ARROW 81ST - OK	Distribution		138.00	13.80		74.60	2			0	0.00
76	BROKEN ARROW 81ST - OK	Distribution		13.80	0.00	0.00	0.00			STATCAP	1	9.60
77	BROKEN ARROW NORTH - OK	Distribution		138.00	13.80		74.60	2			0	0.00
78	BROKEN ARROW WATER PLANT - OK	Distribution		69.00	13.80		9.38	1			0	0.00
79	BROKEN BOW - OK	Distribution		138.00	13.80		26.50	2			0	0.00
80	BROOKSIDE (PO) - OK	Distribution		13.20	4.33		22.50	3			0	0.00
81	BUTLER (PO) - OK	Distribution		34.50	4.40		1.68	1			0	0.00
82	CACHE - OK	Distribution		138.00	13.80		7.84	1			0	0.00
83	CANADIAN COUNTY NATURAL GAS - OK	Distribution		138.00	4.10		10.50	1			0	0.00
84	CANUTE - OK	Distribution		34.50	13.80		5.60	1			0	0.00
85	CARNES - OK	Distribution		34.50	13.80		5.25	1			0	0.00
86	CARSON - OK	Distribution		138.00	14.15		89.60	4			0	0.00
87	CARTER - OK	Distribution		34.50	4.16		3.00	3			0	0.00
88	CATOOSA - OK	Transmission		138.00	69.00	13.80	54.00	1			0	0.00
89	CATOOSA - OK	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	57.60
90	CATOOSA - OK	Transmission		138.00	13.80		37.30	1			0	0.00
91	CATOOSA - OK	Transmission		138.00	13.20		10.50	1			0	0.00
92	CHELSEA - OK	Distribution		138.00	13.80		10.50	1			0	0.00
93	CHEROKEE INDUSTRIAL PARK - OK	Distribution		138.00	13.80		36.40	2			0	0.00
94	CHEYENNE - OK	Distribution		34.50	4.36		5.25	1			0	0.00
95	CHICKASHA NORTH 29TH - OK	Distribution		138.00	13.80		37.30	1			0	0.00
96	CHOUTEAU - OK	Transmission		138.00	13.80		14.00	1			0	0.00
97	CHOUTEAU - OK	Transmission		69.00	13.20		10.50	1			0	0.00
98	CLAYTON - OK	Distribution		138.00	13.80		5.60	1			0	0.00
99	CLINTON CITY - OK	Transmission		69.00	13.80		44.80	2			0	0.00
100	CLINTON CITY - OK	Transmission		13.80	0.00	0.00	0.00			STATCAP	3	14.40
101	CLINTON CITY - OK	Transmission		69.00	34.50	14.40	12.50	1			0	0.00
102	CLINTON JUNCTION - OK	Transmission		138.00	69.00	13.80	84.00	1			0	0.00
103	CLINTON JUNCTION - OK	Transmission		138.00	13.80		37.30	1			0	0.00
104	CLINTON JUNCTION - OK	Transmission		13.80	0.00	0.00	0.00			STATCAP	1	6.00
105	CLINTON NAT. GAS - OK	Distribution		138.00	4.36		22.40	2			0	0.00
106	CLINTON SHERMAN I A P - OK	Distribution		138.00	13.80		8.40	1			0	0.00
107	COALGATE PUMP - OK	Distribution		138.00	4.36		4.20	1			0	0.00
108	COLLEGE - OK	Distribution		13.20	4.36		4.68	1			0	0.00
109	COMANCHE TEXAS PUMP - OK	Distribution		69.00	2.40		6.90	3			0	0.00
110	COPAN SOUTH - OK	Transmission		69.00	13.20		5.01	3			0	0.00
111	CORN COLONY - OK	Distribution		34.50	13.80		4.68	1			0	0.00
112	CORNVILLE - OK	Transmission		138.00	70.50	34.50	50.00	1			0	0.00
113	CORNVILLE - OK	Transmission		138.00	13.80		37.30	1			0	0.00
114	COWETA JUNCTION - OK	Distribution		69.00	13.80		10.00	1			0	0.00
115	CRAIG JUNCTION - OK	Transmission		138.00	13.80		4.20	1			0	0.00
116	CROWDER STEP DOWN - OK	Distribution		26.00	13.80		3.75	3			0	0.00
117	CYRIL - OK	Distribution		69.00	4.16		5.84	3			0	0.00
118	CYRIL - OK	Distribution		69.00	13.80		8.40	1			0	0.00
119	DARBY - OK	Distribution		34.50	13.20		3.12	3			0	0.00
120	DARLINGTON ROAD - OK	Distribution		138.00	13.80		50.00	2			0	0.00
121	DAVIDSON (PO) - OK	Distribution		69.00	13.09	4.16	6.25	1			0	0.00
122	DAWSON - OK	Transmission		69.00	13.20		66.00	2			0	0.00
123	DAWSON - OK	Transmission		138.00	69.00	13.80	84.00	1			0	0.00
124	DAWSON - OK	Transmission		138.00	13.80		33.30	1			0	0.00
125	DELAWARE 345 - OK	Transmission		345.00	137.50	13.80	450.00	1			0	0.00
126	DENVER SUB - OK	Distribution		138.00	14.15		111.90	3			0	0.00
127	DILL CITY - OK	Distribution		34.50	4.16		2.50	0	1		0	0.00
128	DUKE - OK	Transmission		34.50	13.20		2.50	1			0	0.00
129	DUKE - OK	Transmission		69.00	34.50		14.00	1			0	0.00
130	DUNCAN 138 - OK	Transmission		69.00	13.09		25.00	1			0	0.00
131	DUNCAN 138 - OK	Transmission		138.00	69.00	13.80	90.00	1			0	0.00
132	DUNCAN 138 - OK	Transmission		13.80	0.00	0.00	0.00			STATCAP	3	18.00
133	DUNCAN 6TH STREET - OK	Distribution		13.80	2.40		4.20	1			0	0.00
134	DUNCAN EASTSIDE - OK	Distribution		138.00	13.80		37.30	1			0	0.00
135	DUNCAN SUNRAY (TOSCO) - OK	Distribution		69.00	13.80	2.40	12.50	1			0	0.00
136	DUSTIN - OK	Distribution		138.00	13.80		7.00	1			0	0.00
137	EARLSBORO - OK	Distribution		138.00	4.36		40.00	2			0	0.00
138	EAST 121ST STREET - OK	Distribution		138.00	13.80		40.00	1			0	0.00
139	EAST 121ST STREET - OK	Distribution		13.80	0.00	0.00	0.00			STATCAP	1	6.30
140	EAST 21ST STREET - OK	Distribution		138.00	13.80		74.60	2			0	0.00
141	EAST 41ST STREET - OK	Distribution		138.00	13.80		50.00	2			0	0.00
142	EAST 61ST STREET - OK	Distribution		138.00	13.80		74.60	2			0	0.00
143	ELGIN JUNCTION - OK	Transmission		138.00	69.00	13.80	50.40	1			0	0.00
144	ELK CITY - OK	Transmission		138.00	69.00	13.80	93.30	1			0	0.00
145	ELK CITY - OK	Transmission		69.00	34.50	14.40	27.56	1			0	0.00
146	ELK CITY - OK	Transmission		14.40	0.00	0.00	0.00			STATCAP	1
147	ELK CITY - OK	Transmission		138.00	13.80		22.40	1			0	0.00
148	ELK CITY - OK	Transmission		13.80	0.00	0.00	0.00			STATCAP	1	4.80
149	ELK CITY - OK	Transmission		230.00	141.45	13.80	450.00	1			0	0.00
150	ELK CITY FALCON ROAD - OK	Distribution		138.00	13.80		37.30	1			0	0.00
151	ELLIS 4KV SUB - OK	Distribution		138.00	4.36		50.00	2			0	0.00
152	ERICK - OK	Distribution		34.50	13.80		9.38	1			0	0.00
153	FLETCHER-TEMPLE EASTEX - OK	Distribution		138.00	13.80		7.00	1			0	0.00
154	FORD GLASS - OK	Distribution		13.80	0.00	0.00	0.00			STATCAP	1	6.00
155	FORD GLASS - OK	Distribution		138.00	13.80		74.60	2			0	0.00
156	FORT SILL - OK	Transmission		69.00	13.80		53.00	2			0	0.00
157	FORT SILL - OK	Transmission		13.80	0.00	0.00	0.00			STATCAP	1	8.40
158	FORT SILL MOW-WAY - OK	Transmission		138.00	13.80		48.00	2			0	0.00
159	FORT TOWSON - OK	Distribution		69.00	13.20		5.25	3			0	0.00
160	FOSS CITY - OK	Distribution		34.50	13.20		1.68	1			0	0.00
161	FOSS WATER TREATMENT PLAN - OK	Distribution		69.00	13.80		3.50	1			0	0.00
162	FREDERICK JUNCTION - OK	Transmission		69.00	13.20	2.40	1.50	3			0	0.00
163	GLENHAVEN - OK	Distribution		13.20	4.36		9.36	2			0	0.00
164	GOULD - OK	Distribution		34.50	4.16		1.50	1			0	0.00
165	GRADY COUNTY POD - OK	Transmission		138.00	4.36		75.00	3			0	0.00
166	GRANDFIELD - OK	Distribution		34.50	13.20		3.75	1			0	0.00
167	GRANITE - OK	Distribution		34.50	13.80		4.20	1			0	0.00
168	GROVE - OK	Transmission		161.00	138.00	13.80	112.00	1			0	0.00
169	GROVE - OK	Transmission		138.00	13.80		44.80	2			0	0.00
170	HALLIBURTON NO. 2 - OK	Distribution		13.20	2.40		4.68	3			0	0.00
171	HAMMON JUNCTION - OK	Distribution		34.50	13.20		2.50	1			0	0.00
172	HAMMON JUNCTION - OK	Distribution		69.00	34.50		25.00	1			0	0.00
173	HASKELL AND ZUNIS - OK	Distribution		13.20	4.36		9.36	2			0	0.00
174	HAWTHORNE PUMP - OK	Distribution		138.00	4.16		10.50	1			0	0.00
175	HEADRICK - OK	Distribution		69.00	12.40		3.00	3			0	0.00
176	HENRYETTA - OK	Distribution		138.00	13.80		74.60	2			0	0.00
177	HIGHWAY 20 - OK	Transmission		138.00	34.50	13.80	8.40	1			0	0.00
178	HINTON (PO) - OK	Distribution		138.00	13.80		5.00	1			0	0.00
179	HOBART CITY - OK	Transmission		69.00	34.50	14.40	27.56	1			0	0.00
180	HOBART CITY - OK	Transmission		69.00	13.80		19.88	2			0	0.00
181	HOBART CITY - OK	Transmission		13.80	0.00	0.00	0.00			STATCAP	2	9.60
182	HOBART JUNCTION - OK	Transmission		13.80	0.00	0.00	0.00			STATCAP	3	18.00
183	HOBART JUNCTION - OK	Transmission		138.00	66.00	13.80	75.00	1			0	0.00
184	HOLDENVILLE EXPLORER - OK	Distribution		138.00	4.16		22.40	1			0	0.00
185	HOLLIS - OK	Distribution		138.00	34.50		14.00	1			0	0.00
186	HOLLIS - OK	Distribution		34.50	4.16		9.38	1			0	0.00
187	HOLLIS - OK	Distribution		34.50	4.16		5.25	0	1		0	0.00
188	HOMINY PRISON - OK	Distribution		34.50	13.20		7.00	1			0	0.00
189	HUGO - OK	Transmission		138.00	70.50	13.09	90.00	1			0	0.00
190	HUGO - OK	Transmission		138.00	13.80		22.40	1			0	0.00
191	HUGO - OK	Transmission		69.00	13.80		21.00	2			0	0.00
192	IDABEL - OK	Distribution		138.00	13.80		44.80	2			0	0.00
193	IDABEL-GEORGIA PACIFIC - OK	Distribution		69.00	13.80		10.50	1			0	0.00
194	INOLA (TS4) - OK	Distribution		138.00	13.80		22.40	1			0	0.00
195	JAMESTOWN - OK	Distribution		13.20	4.36		14.04	3			0	0.00
196	JAY (PO) - OK	Distribution		138.00	13.80		14.00	1			0	0.00
197	JENKS - OK	Distribution		138.00	13.80		20.00	1			0	0.00
198	KELCO-OKMULGEE - OK	Distribution		138.00	13.80		37.30	1			0	0.00
199	KENOSHA - OK	Distribution		138.00	13.80		74.60	2			0	0.00
200	KIAMICHI PUMPING - OK	Distribution		69.00	2.40		4.00	6			0	0.00
201	LAWTON 112TH AND W GORE - OK	Transmission		138.00	13.80		22.40	1			0	0.00
202	LAWTON 53RD & CACHE ROAD - OK	Distribution		138.00	13.80		37.33	1			0	0.00
203	LAWTON AIR GAS - OK	Distribution		138.00	4.10		37.30	1			0	0.00
204	LAWTON DISP PLANT - OK	Distribution		69.00	13.80		7.00	1			0	0.00
205	LAWTON EASTSIDE - OK	Transmission		138.00	69.00	13.80	168.00	2			0	0.00
206	LAWTON EASTSIDE - OK	Transmission		345.00	138.00	13.80	300.00	0	1		0	0.00
207	LAWTON EASTSIDE - OK	Transmission		345.00	138.00	13.80	450.00	1			0	0.00
208	LAWTON EASTSIDE - OK	Transmission		138.00	13.80		37.30	1			0	0.00
209	LAWTON EASTSIDE - OK	Transmission		13.80	0.00	0.00	0.00			AIR CORE REACTOR	3	28.70
210	LAWTON EASTSIDE - OK	Transmission		345.00	137.50	13.80	450.00	1			0	0.00
211	LAWTON GOODYEAR - OK	Distribution		138.00	4.36		84.00	6			0	0.00
212	LAWTON GORE - OK	Distribution		69.00	13.20		70.60	2			0	0.00
213	LAWTON PAPERBOARD - OK	Transmission		138.00	13.80		37.30	1			0	0.00
214	LAWTON PAPERBOARD - OK	Transmission		13.80	0.00	0.00	0.00			STATCAP	2	7.20
215	LAWTON SHERIDAN ROAD - OK	Distribution		138.00	13.80		74.60	2			0	0.00
216	LAWTON WEST SIDE - OK	Distribution		13.80	0.00	0.00	0.00			STATCAP	1	6.00
217	LAWTON WEST SIDE - OK	Distribution		138.00	13.80		74.60	2			0	0.00
218	LAWTON WOLF CREEK - OK	Distribution		69.00	13.80		37.30	1			0	0.00
219	LEHIGH CITY - OK	Distribution		138.00	23.90		30.50	2			0	0.00
220	LEQUIRE - OK	Distribution		138.00	13.80		10.50	1			0	0.00
221	LINDSAY TEXAS PIPELINE CO - OK	Distribution		138.00	4.16		12.50	1			0	0.00
222	LINDSAY WATER FLOOD - OK	Distribution		138.00	13.80		25.00	1			0	0.00
223	LOCUST GROVE - OK	Distribution		115.00	13.09		25.00	1			0	0.00
224	LONE OAK - OK	Transmission		13.80	0.00	0.00	0.00			STATCAP	1	9.60
225	LONE OAK - OK	Transmission		138.00	70.50	13.80	108.00	2			0	0.00
226	LONE WOLF - OK	Distribution		34.50	13.80		5.25	1			0	0.00
227	LYNN LANE - OK	Distribution		138.00	13.80		57.30	2			0	0.00
228	LYNN LANE & 121ST - OK	Distribution		138.00	13.09		40.00	1			0	0.00
229	MAPLEWOOD - OK	Distribution		13.20	4.36		4.68	1			0	0.00
230	MAPLEWOOD - OK	Distribution		13.20	4.10		7.20	2			0	0.00
231	MARTHA SUB - OK	Distribution		138.00	13.80		9.38	1			0	0.00
232	MARY FRANCIS - OK	Distribution		13.20	4.36		9.36	2			0	0.00
233	MAYO ROAD - OK	Distribution		138.00	13.80		74.60	2			0	0.00
234	MAYO ROAD - OK	Distribution		13.80	0.00	0.00	0.00			STATCAP	1	7.20
235	MCALESTER CHEROKEE - OK	Distribution		23.00	4.36		9.37	2			0	0.00
236	MCALESTER CITY - OK	Transmission		138.00	69.00	13.80	56.00	1			0	0.00
237	MCALESTER CITY - OK	Transmission		69.00	4.40		8.63	3			0	0.00
238	MCALESTER CITY - OK	Transmission		138.00	23.90		74.60	2			0	0.00
239	MCALESTER CITY - OK	Transmission		23.00	0.00	0.00	0.00			STATCAP	2	15.60
240	MCALESTER INDUSTRIAL - OK	Distribution		138.00	23.90		50.00	2			0	0.00
241	MCALESTER OIL WELL - OK	Distribution		26.00	2.40		4.00	3			0	0.00
242	MCALESTER SOUTH - OK	Distribution		138.00	23.90		37.30	1			0	0.00
243	MCGEE CREEK - OK	Distribution		69.00	4.36		7.00	1			0	0.00
244	MIDLAND (PS) - OK	Distribution		13.20	4.36		9.36	2			0	0.00
245	MINGO - OK	Distribution		13.80	0.00	0.00	0.00			STATCAP	2	12.00
246	MINGO - OK	Distribution		138.00	13.80		40.00	2			0	0.00
247	MOHAWK PUMP - OK	Distribution		138.00	13.80	7.97	38.40	2			0	0.00
248	MOUND ROAD - OK	Distribution		138.00	13.20		37.30	1			0	0.00
249	MOUND ROAD - OK	Distribution		138.00	13.80		37.30	1			0	0.00
250	MOUND ROAD - OK	Distribution		13.80	0.00	0.00	0.00			STATCAP	1	6.00
251	MOUNTAIN VIEW - OK	Distribution		34.50	4.40		5.25	1			0	0.00
252	NORGE ROAD - OK	Distribution		138.00	13.80		44.80	2			0	0.00
253	NORGE ROAD - OK	Distribution		13.80	0.00	0.00	0.00			STATCAP	1	6.00
254	NORTH HARVARD - OK	Distribution		13.20	4.10		3.75	0	1		0	0.00
255	NORTH MINGO - OK	Distribution		138.00	13.80		40.00	1			0	0.00
256	NORTHEASTERN 138 - OK	Transmission		138.00	13.80		10.50	1			0	0.00
257	NORTHEASTERN 345 - OK	Transmission		345.00	138.00	34.50	405.00	0	1		0	0.00
258	NOWATA - OK	Distribution		138.00	13.80		22.40	1			0	0.00
259	OAKS - OK	Distribution		13.20	4.33		7.50	1			0	0.00
260	OAKS 138 - OK	Distribution		138.00	13.80		40.00	1			0	0.00
261	OAKS 138 - OK	Distribution		138.00	13.80	7.96	22.40	1			0	0.00
262	OKEMAH - OK	Distribution		69.00	13.09		20.00	1			0	0.00
263	OKLAUNION 345-PSO - TX	Transmission		345.00						REACTOR	1	50.00
264	OKMULGEE CITY - OK	Distribution		138.00	13.80		37.30	1			0	0.00
265	OKMULGEE CITY - OK	Distribution		138.00	4.16		9.38	1			0	0.00
266	OKMULGEE CITY - OK	Distribution		13.80	0.00	0.00	0.00			STATCAP	2	14.40
267	ONETA - OK	Transmission		345.00	141.45	13.80	560.00	1			0	0.00
268	ONETA - OK	Transmission		345.00	138.00	34.50	1350.00	2			0	0.00
269	ONETA - OK	Transmission		138.00	13.80	79.00	22.40	1			0	0.00
270	ONETA - OK	Transmission		138.00	13.80	7.90	22.40	1			0	0.00
271	ORAL ROBERTS UNIVERSITY - OK	Distribution		13.80	0.00	0.00	0.00			AIR CORE REACTOR	6
272	ORAL ROBERTS UNIVERSITY - OK	Distribution		138.00	13.80		40.00	2			0	0.00
273	ORAL ROBERTS UNIVERSITY - OK	Distribution		13.80	0.00	0.00	0.00			STATCAP	2
274	OWASSO 109TH STREET - OK	Distribution		13.80	0.00	0.00	0.00			STATCAP	1
275	OWASSO 109TH STREET - OK	Distribution		138.00	13.80		45.00	2			0	0.00
276	OWASSO 86TH STREET - OK	Distribution		138.00	13.80	7.96	44.80	2			0	0.00
277	OWASSO 88TH & MINGO - OK	Distribution		138.00	13.80		40.00	1			0	0.00
278	PERNELL - OK	Distribution		138.00	4.36	2.52	15.00	1			0	0.00
279	PHILLIPS GAS CO. - OK	Distribution		138.00	13.80		9.38	1			0	0.00
280	PINE AND OSAGE - OK	Distribution		13.20	4.36		7.50	2			0	0.00
281	PINE AND PEORIA - OK	Distribution		138.00	13.80	7.96	44.80	2			0	0.00
282	PITTSBURG (PO) - OK	Distribution		69.00	13.20		4.50	3			0	0.00
283	PORT OF CATOOSA - OK	Distribution		138.00	13.80		61.30	2			0	0.00
284	PORT OF CATOOSA - OK	Distribution		13.80	0.00	0.00	0.00			STATCAP	1	6.00
285	PORTER HILL - OK	Distribution		69.00	13.20		5.25	1			0	0.00
286	PORTER HILL - OK	Distribution		69.00	13.09		8.40	1			0	0.00
287	PRATTVILLE - OK	Distribution		138.00	13.80		22.40	1			0	0.00
288	PRUE - OK	Distribution		34.50	13.20		1.68	1			0	0.00
289	PRYOR CEMENT - OK	Distribution		115.00	4.36		26.50	3			0	0.00
290	PRYOR CONTINENTAL PIPE - OK	Distribution		69.00	2.40		2.25	3			0	0.00
291	PRYOR CREEK - OK	Transmission		138.00	13.80		50.40	4			0	0.00
292	PRYOR CREEK - OK	Transmission		13.80	0.00	0.00	0.00			STATCAP	2	15.17
293	PRYOR JUNCTION - OK	Transmission		138.00	69.00	13.80	130.00	1			0	0.00
294	PRYOR JUNCTION - OK	Transmission		115.00	69.00	13.80	75.00	1			0	0.00
295	RAMONA - OK	Distribution		69.00	13.09		9.38	1			0	0.00
296	RED FORK - OK	Distribution		13.20	4.36		5.00	1			0	0.00
297	RED OAK (PO) - OK	Transmission		69.00	13.09		9.38	1			0	0.00
298	RED OAK PUMP - OK	Distribution		138.00	4.16		20.00	1			0	0.00
299	RED OAK PUMP - OK	Distribution		4.16	0.00	0.00	0.00			STATCAP	2	7.20
300	RIVERSIDE 138KV - OK	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	115.20
301	RIVERSIDE 345KV - OK	Transmission		345.00	138.00	34.50	1350.00	2			0	0.00
302	RIVERVIEW (PO) - OK	Distribution		13.20	4.36		3.75	1			0	0.00
303	ROOSEVELT AMOCO - OK	Distribution		69.00	4.36		6.25	1			0	0.00
304	ROOSEVELT AMOCO - OK	Distribution		69.00	14.00		0.50	1			0	0.00
305	ROOSEVELT AMOCO - OK	Distribution		69.00	12.47		2.00	2			0	0.00
306	RUSH SPRINGS CHESTNUT - OK	Distribution		138.00	13.80		7.00	1			0	0.00
307	RUSH SPRINGS NAT GAS - OK	Distribution		138.00	4.16		22.40	1			0	0.00
308	SAILBOAT BRIDGE - OK	Distribution		69.00	13.80		10.50	1			0	0.00
309	SAND SPRINGS 138KV - OK	Transmission		138.00	13.80		74.60	2			0	0.00
310	SAPULPA ROAD - OK	Transmission		345.00	141.45	13.80	560.00	1			0	0.00
311	SAVANNA - OK	Distribution		69.00	13.80		9.38	1			0	0.00
312	SAWYER HUGO WTR. PLANT - OK	Distribution		69.00	13.20		2.00	3			0	0.00
313	SAYRE - OK	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	14.40
314	SAYRE - OK	Distribution		138.00	13.80		14.00	1			0	0.00
315	SAYRE - OK	Distribution		34.50	13.20		9.38	1			0	0.00
316	SENTINEL CITY - OK	Distribution		34.50	4.36		5.25	1			0	0.00
317	SHEFFIELD STEEL (PO) - OK	Distribution		138.00	13.80		22.40	0	1		0	0.00
318	SHEFFIELD STEEL (PO) - OK	Distribution		138.00	13.80		50.00	0	1		0	0.00
319	SHIDLER - OK	Distribution		138.00	13.80	7.90	22.40	1			0	0.00
320	SHIDLER - OK	Distribution		138.00	13.80		14.00	1			0	0.00
321	SKIATOOK WATER PUMP - OK	Distribution		138.00	0.00	0.00	0.00			AIR CORE REACTOR	3
322	SKIATOOK WATER PUMP - OK	Distribution		138.00	2.50		7.00	1			0	0.00
323	SNYDER - OK	Transmission		69.00	13.80		3.75	3			0	0.00
324	SNYDER - OK	Transmission		138.00	66.00	13.20	75.00	1			0	0.00
325	SNYDER - OK	Transmission		69.00	4.16		4.20	1			0	0.00
326	SNYDER - OK	Transmission		13.80	0.00	0.00	0.00			STATCAP	1	6.00
327	SOUTH COFFEYVILLE - OK	Distribution		138.00	13.80		47.80	2			0	0.00
328	SOUTH HUDSON - OK	Distribution		138.00	13.80		40.00	2			0	0.00
329	SOUTH HUDSON - OK	Distribution		13.80	0.00	0.00	0.00			STATCAP	2	12.00
330	SOUTHERN HILLS - OK	Distribution		138.00	13.80		93.30	2			0	0.00
331	SOUTHWESTERN STATION - OK	Transmission		138.00	69.00	13.80	54.00	0	1		0	0.00
332	SOUTHWESTERN STATION - OK	Transmission		69.00	13.80		5.25	1			0	0.00
333	SOUTHWESTERN STATION - OK	Transmission		138.00	69.00	13.80	50.00	1			0	0.00
334	STIGLER - OK	Distribution		138.00	13.80		25.63	2			0	0.00
335	STUART LINE - OK	Distribution		23.00	13.20		5.00	1			0	0.00
336	TALIHINA WEST - OK	Distribution		69.00	13.80		14.00	1			0	0.00
337	TEMPLE - OK	Distribution		34.50	4.10		3.75	3			0	0.00
338	TERRAL - OK	Distribution		34.50	13.80		4.20	1			0	0.00
339	THOMAS (PO) - OK	Distribution		69.00	13.80		5.20	1			0	0.00
340	THOMAS OK REFINING CO. - OK	Distribution		69.00	13.80		10.50	1			0	0.00
341	TIPTON CITY - OK	Distribution		69.00	4.40		4.20	1			0	0.00
342	TRANSOK CLAREMORE - OK	Distribution		138.00	4.16		22.40	1			0	0.00
343	TRANSOK CLAREMORE - OK	Distribution		4.16	0.00	0.00	0.00			STATCAP	1	9.60
344	TULSA APACHE - OK	Distribution		13.20	4.36		4.68	1			0	0.00
345	TULSA FAIRGROUNDS - OK	Distribution		13.20	4.30		5.00	1			0	0.00
346	TULSA FAIRGROUNDS - OK	Distribution		13.20	4.16		5.00	1			0	0.00
347	TULSA INT AIRPORT - OK	Distribution		13.20	4.36		7.50	2			0	0.00
348	TULSA NORTH 138 - OK	Transmission		13.80	0.00	0.00	0.00			STATCAP	1	5.00
349	TULSA NORTH 138 - OK	Transmission		138.00	13.80		37.30	1			0	0.00
350	TULSA NORTH 345 - OK	Transmission		345.00	141.45	13.80	560.00	0	1		0	0.00
351	TULSA POWER - OK	Transmission		138.00	0.00	0.00	0.00			AIR CORE REACTOR	3
352	TULSA POWER - OK	Transmission		69.00	13.09		25.00	1			0	0.00
353	TULSA POWER - OK	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	115.20
354	TULSA POWER - OK	Transmission		138.00	13.80		70.63	2			0	0.00
355	TULSA POWER - OK	Transmission		138.00	69.00	13.80	140.00	1			0	0.00
356	TULSA SOUTHEAST - OK	Transmission		138.00	65.92	13.20	50.00	1			0	0.00
357	TULSA SOUTHEAST - OK	Transmission		138.00	69.00	13.20	33.00	1			0	0.00
358	TULSA SOUTHEAST - OK	Transmission		13.80	0.00	0.00	0.00			STATCAP	3	18.00
359	TULSA SOUTHEAST - OK	Transmission		138.00	13.80		70.64	2			0	0.00
360	TULSA SOUTHEAST - OK	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	48.00
361	TULSA SUNRAY REF. - OK	Distribution		69.00	13.20		66.60	2			0	0.00
362	TULSA SUNRAY REF. - OK	Distribution		13.80	0.00	0.00	0.00			STATCAP	2	12.00
363	TULSA TRANS RESERVE - OK	Transmission		138.00	70.50	13.09	78.00	0	1		0	0.00
364	TULSA WILLIAMS PIPELINE C - OK	Distribution		69.00	4.16	2.40	6.25	1			0	0.00
365	TUTTLE - OK	Distribution		138.00	13.09		25.00	1			0	0.00
366	UNION AVENUE REFINERY - OK	Distribution		138.00	13.80		33.00	1			0	0.00
367	UTICA SQUARE - OK	Distribution		13.80	4.36		5.00	1			0	0.00
368	UTICA SQUARE - OK	Distribution		13.20	4.10		3.60	1			0	0.00
369	VALLIANT 345 - OK	Transmission		345.00	138.00	13.80	322.56	2			0	0.00
370	VALLIANT 345 - OK	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	19.20
371	VALLIANT 345 - OK	Transmission		138.00	70.50	36.20	90.00	1			0	0.00
372	VALLIANT 345 - OK	Transmission		69.00	13.80		14.00	1			0	0.00
373	VALLIANT WEYCO - OK	Distribution		13.80	0.00	0.00	0.00			STATCAP	1	6.00
374	VALLIANT WEYCO - OK	Distribution		138.00	13.80		112.00	2			0	0.00
375	VALLIANT WEYCO #2 - OK	Distribution		138.00	13.80		106.00	2			0	0.00
376	VERDEN NATURAL GAS - OK	Distribution		138.00	4.10		22.40	1			0	0.00
377	VILLA GROVE - OK	Distribution		13.20	4.36		4.68	1			0	0.00
378	VINITA - OK	Transmission		69.00	13.80		28.00	2			0	0.00
379	VINITA - OK	Transmission		13.80	0.00	0.00	0.00			STATCAP	1	6.00
380	VINITA JUNCTION - OK	Transmission		138.00	69.00	13.80	50.00	1			0	0.00
381	VINITA JUNCTION - OK	Transmission		138.00	13.80		20.00	1			0	0.00
382	WAGONER - OK	Distribution		69.00	13.80		2.50	1			0	0.00
383	WALTERS JUNCTION - OK	Transmission		69.00	36.20		8.40	1			0	0.00
384	WAPANUCKA - OK	Distribution		138.00	4.36		40.00	2			0	0.00
385	WARREN MEDICAL CENTER - OK	Distribution		13.80	0.00	0.00	0.00			STATCAP	1	6.00
386	WARREN MEDICAL CENTER - OK	Distribution		138.00	13.80		74.60	2			0	0.00
387	WAURIKA - OK	Distribution		69.00	4.36		7.00	1			0	0.00
388	WEATHERFORD - OK	Distribution		69.00	13.80		22.40	1			0	0.00
389	WEATHERFORD - OK	Distribution		138.00	13.80		22.40	1			0	0.00
390	WEATHERFORD - OK	Distribution		13.80	0.00	0.00	0.00			STATCAP	1	6.00
391	WEATHERFORD JUNCTION - OK	Transmission		138.00	13.80		41.67	1			0	0.00
392	WEATHERFORD SE - OK	Transmission		138.00	66.00	13.80	50.00	1			0	0.00
393	WEKIWA - OK	Transmission		345.00	138.00	34.00	675.00	1			0	0.00
394	WEKIWA - OK	Transmission		138.00	13.80		22.40	1			0	0.00
395	WELEETKA POWER - OK	Transmission		138.00	66.00	13.80	100.00	2			0	0.00
396	WEST EDISON - OK	Distribution		138.00	13.80		74.60	2			0	0.00
397	WHIRLPOOL (PO) - OK	Distribution		138.00	13.80		14.00	1			0	0.00
398	WHITE CITY - OK	Distribution		13.20	4.30		9.36	2			0	0.00
399	WILBURTON - OK	Distribution		69.00	13.80		20.00	1			0	0.00
400	WILBURTON TRANSOK - OK	Distribution		138.00	4.16		7.50	1			0	0.00
401	WILDHORSE SHELL - OK	Distribution		138.00	4.16		3.34	2			0	0.00
402	WILLOW BRINKMAN - OK	Distribution		34.50	4.16		2.50	1			0	0.00
403	WISTER - OK	Distribution		69.00	13.20		4.69	1			0	0.00
404	WOODLAND (PO) - OK	Distribution		13.20	4.30		4.68	1			0	0.00
405	WOODLAND (PO) - OK	Distribution		13.20	4.16		5.00	1			0	0.00
406	WRIGHT CITY - OK	Distribution		69.00	13.80		10.50	1			0	0.00
407	YALE AND ARCHER - OK	Distribution		13.20	4.36		6.25	1			0	0.00
408	YALE AND ARCHER - OK	Distribution		138.00	13.80		74.60	2			0	0.00
409	YALE AND ARCHER - OK	Distribution		13.80	0.00	0.00	0.00			STATCAP	2	12.00
410	ZUNIS - OK	Distribution		138.00	13.80		74.60	2			0	0.00
411	ZUNIS - OK	Distribution		13.20	4.16		9.38	1			0	0.00
412	ZUNIS - OK	Distribution		13.80	0.00	0.00	0.00			STATCAP	2	12.00
413	TotalDistributionSubstationMember											270.60
414	TotalTransmissionSubstationMember											690.47
415	Total											961.07

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 6th 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: OK Date of Incorporation: 1913-05-29 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. The generation, transmission and sale of electric energy.All operations within the State of 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

OFFICERS
Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function (such as sales, administration or finance), and any other person who performs similar policy making functions. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous incumbent, and the date the change in incumbency was made.
Line No.	OfficerTitle Title (a)	OfficerName Name of Officer (b)	OfficerSalary Salary for Year (c)	DateOfficerIncumbencyStarted Date Started in Period (d)	DateOfficerIncumbencyEnded Date Ended in Period (e)
1	(a) Footnote

DIRECTORS
Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), name and abbreviated titles of the directors who are officers of the respondent. Provide the principle place of business in column (b), designate members of the Executive Committee in column (c), and the Chairman of the Executive Committee in column (d).
Line No.	NameAndTitleOfDirector Name (and Title) of Director (a)	PrincipalBusinessAddress Principal Business Address (b)	MemberOfTheExecutiveCommittee Member of the Executive Committee (c)	ChairmanOfTheExecutiveCommittee Chairman of the Executive Committee (d)
1	Nicholas K. Akins , Chairman of the Board and Chief Executive Officer	Columbus, Ohio
2	Lisa M. Barton , Vice President	Columbus, Ohio
3	Paul Chodak , Vice President	Columbus, Ohio
4	David M. Feinberg , Secretary	Columbus, Ohio
5	Therace M Risch , Vice President	Columbus, Ohio
6	Peggy I Simmons , President and Chief Operating Officer	Columbus, Ohio
7	Julia A Sloat , Chief Financial Officer and Vice President	Columbus, Ohio
8	Toby L Thomas , Vice President	Columbus, Ohio
9	Charles R. Patton, Director	Columbus, Ohio
10	The Respondent does not have an Executive Committee.

INFORMATION ON FORMULA RATES
Does the respondent have formula rates?		☐ Yes ☑ No
Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No) accepting the rate(s) or changes in the accepted rate.
Line No.	RateScheduleTariffNumber FERC Rate Schedule or Tariff Number (a)	ProceedingDocketNumber FERC Proceeding (b)
1	SPP FERC Electric Tariff 6th Revision Vol. No. 1	ER07-1069
2	Addendum 4 to Attachment H, Parts 1 and 2
3	SPP FERC Electric Tariff Vol. No. 1	ER18-195
4	Attachment H, Parts 1 and 2
5	Rate Schedule 233	ER89-476
6		ER92-191

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.

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)
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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 2020 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

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)
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4
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12
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21
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23
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25
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28
29
30
31
32
33
34
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38
39
40
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42
43
44

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	6,410,245,134	5,826,847,063
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	156,816,557	128,944,504
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		6,567,061,692	5,955,791,567
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	1,870,450,115	1,743,843,550
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		4,696,611,577	4,211,948,017
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)		4,696,611,577	4,211,948,017
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)
17	OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS
18	NonutilityProperty Nonutility Property (121)		3,474,744	5,232,764
19	AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Prov. for Depr. and Amort. (122)		1,819,032	1,712,762
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances	228
24	OtherInvestments Other Investments (124)		53	2,300
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)		95,203,725	65,765,274
30	DerivativeInstrumentAssetsLongTerm Long-Term Portion of Derivative Assets (175)
31	DerivativeInstrumentAssetsHedgesLongTerm Long-Term Portion of Derivative Assets - Hedges (176)
32	OtherPropertyAndInvestments TOTAL Other Property and Investments (Lines 18-21 and 23-31)		100,497,554	72,713,099
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)		1,264,638	2,594,792
36	SpecialDeposits Special Deposits (132-134)		6,900,046	330,119
37	WorkingFunds Working Fund (135)		200
38	TemporaryCashInvestments Temporary Cash Investments (136)
39	NotesReceivable Notes Receivable (141)
40	CustomerAccountsReceivable Customer Accounts Receivable (142)		40,458,885	29,846,144
41	OtherAccountsReceivable Other Accounts Receivable (143)		623,043	2,030,771
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		282	4,972
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)		32,804,603	13,878,588
45	FuelStock Fuel Stock (151)	227	13,543,090	15,856,421
46	FuelStockExpensesUndistributed Fuel Stock Expenses Undistributed (152)	227	932,968	2,034,802
47	Residuals Residuals (Elec) and Extracted Products (153)	227	10	10
48	PlantMaterialsAndOperatingSupplies Plant Materials and Operating Supplies (154)	227	56,219,542	53,951,922
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	2,799	7,786
53	NoncurrentPortionOfAllowances (Less) Noncurrent Portion of Allowances	228
54	StoresExpenseUndistributed Stores Expense Undistributed (163)	227
55	GasStoredCurrent Gas Stored Underground - Current (164.1)
56	LiquefiedNaturalGasStoredAndHeldForProcessing Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)
57	Prepayments Prepayments (165)		5,905,991	6,153,083
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)
60	RentsReceivable Rents Receivable (172)		1,062,687	1,000,763
61	AccruedUtilityRevenues Accrued Utility Revenues (173)		25,423,530	25,652,564
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)
63	DerivativeInstrumentAssets Derivative Instrument Assets (175)		12,127,522	10,289,154
64	DerivativeInstrumentAssetsLongTerm (Less) Long-Term Portion of Derivative Instrument Assets (175)
65	DerivativeInstrumentAssetsHedges Derivative Instrument Assets - Hedges (176)
66	DerivativeInstrumentAssetsHedgesLongTerm (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176)
67	CurrentAndAccruedAssets Total Current and Accrued Assets (Lines 34 through 66)		197,269,272	163,621,948
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		10,613,686	2,828,905
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	1,111,789,665	269,701,633
73	PreliminarySurveyAndInvestigationCharges Prelim. Survey and Investigation Charges (Electric) (183)		4,322,315	4,273,268
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)		4,491	4,218
77	TemporaryFacilities Temporary Facilities (185)
78	MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186)	233	3,961,063	3,693,827
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)		5,657,048	6,093,175
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	170,039,944	239,759,280
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		1,306,388,213	526,354,306
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		6,300,766,616	4,974,637,370

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	157,230,000	157,230,000
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	1,039,001,328	414,001,328
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	1,095,372,043	974,289,933
12	UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1)	118
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)		84,210
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		2,291,603,370	1,545,605,471
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	1,928,052,327	1,378,563,643
22	UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225)
23	UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Debit (226)		3,928,257	1,068,771
24	LongTermDebt Total Long-Term Debt (lines 18 through 23)		1,924,124,070	1,377,494,872
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		74,510,005	48,087,436
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		72,814	23,668
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		5,169,458	5,682,806
30	AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4)
31	AccumulatedProvisionForRateRefunds Accumulated Provision for Rate Refunds (229)			545,516
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)		57,609,475	47,421,077
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		137,361,752	101,760,503
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)
38	AccountsPayable Accounts Payable (232)		157,446,804	106,979,590
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)		72,271,991	155,371,007
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		76,434,057	69,015,728
41	CustomerDeposits Customer Deposits (235)		56,155,550	54,806,022
42	TaxesAccrued Taxes Accrued (236)	262	9,456,387	17,868,827
43	InterestAccrued Interest Accrued (237)		17,452,764	14,535,116
44	DividendsDeclared Dividends Declared (238)
45	MaturedLongTermDebt Matured Long-Term Debt (239)
46	MaturedInterest Matured Interest (240)
47	TaxCollectionsPayable Tax Collections Payable (241)		7,294,548	5,459,004
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		26,833,179	45,006,204
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		9,961,302	9,540,137
50	DerivativesInstrumentLiabilities Derivative Instrument Liabilities (244)		3,664,782
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)		436,971,364	478,581,635
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)
57	AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255)	266	50,848,934	50,963,935
58	DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256)
59	OtherDeferredCredits Other Deferred Credits (253)	269	9,792,616	15,118,159
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	497,725,997	476,871,718
61	UnamortizedGainOnReacquiredDebt Unamortized Gain on Reaquired Debt (257)
62	AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty Accum. Deferred Income Taxes-Accel. Amort.(281)	272	15,302,092	14,704,369
63	AccumulatedDeferredIncomeTaxesOtherProperty Accum. Deferred Income Taxes-Other Property (282)		703,314,637	657,105,348
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		233,721,784	256,431,361
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		1,510,706,059	1,471,194,890
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		6,300,766,616	4,974,637,371

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	1,501,339,728	1,280,551,976			1,501,339,728	1,280,551,976
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	947,039,575	771,915,325			947,039,575	771,915,325
5	MaintenanceExpense Maintenance Expenses (402)	320	97,194,603	98,394,615			97,194,603	98,394,615
6	DepreciationExpense Depreciation Expense (403)	336	170,857,973	158,071,770			170,857,973	158,071,770
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336	820,631	741,441			820,631	741,441
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	16,158,721	13,685,383			16,158,721	13,685,383
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)		8,408,145	7,577,727			8,408,145	7,577,726
13	RegulatoryCredits (Less) Regulatory Credits (407.4)		678,567	6,430,469			678,567	6,430,469
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	49,655,221	47,608,488			49,655,221	47,608,488
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	109,133,060	10,763,088			109,133,060	10,763,088
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	10,995	323,366			10,995	323,366
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	646,832,758	118,804,954			646,832,758	118,804,954
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	532,607,777	102,443,265			532,607,777	102,443,265
19	InvestmentTaxCreditAdjustments Investment Tax Credit Adj. - Net (411.4)	266	115,002	454,907			115,002	454,907
20	GainsFromDispositionOfPlant (Less) Gains from Disp. of Utility Plant (411.6)		82,885				82,885
21	LossesFromDispositionOfServiceCompanyPlant Losses from Disp. of Utility Plant (411.7)
22	GainsFromDispositionOfAllowances (Less) Gains from Disposition of Allowances (411.8)		42,556	2			42,556	2
23	LossesFromDispositionOfAllowances Losses from Disposition of Allowances (411.9)
24	AccretionExpense Accretion Expense (411.10)		3,257,104	3,174,018			3,257,104	3,174,018
25	UtilityOperatingExpenses TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)		1,299,098,783	1,099,558,623			1,299,098,783	1,099,558,623
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		202,240,945	180,993,353			202,240,945	180,993,353
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)		517,219	362,560
34	ExpensesOfNonutilityOperations (Less) Expenses of Nonutility Operations (417.1)		35,723	35,723
35	NonoperatingRentalIncome Nonoperating Rental Income (418)		29,230	1,843
36	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1)	119
37	InterestAndDividendIncome Interest and Dividend Income (419)		4,269,557	95,356
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		2,359,466	4,034,050
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		902,626	694,648
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)		7,176	172,973
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		8,035,200	5,325,707
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)		1,651,767
44	MiscellaneousAmortization Miscellaneous Amortization (425)
45	Donations Donations (426.1)		537,071	268,352
46	LifeInsurance Life Insurance (426.2)
47	Penalties Penalties (426.3)		168,148	675
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		651,471	1,468,635
49	OtherDeductions Other Deductions (426.5)		4,809,424	1,238,234
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		7,481,586	2,975,895
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262	91	91
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262	506,392	677,983
54	IncomeTaxesOther Income Taxes-Other (409.2)	262	4,806	431,002
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272	480,598	851,829
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272	851,830	255,647
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)		872,727	349,293
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		1,426,340	2,000,520
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		59,239,155	57,775,096
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		717,288	743,338
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)		436,127	405,565
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)		314,499	566,982
68	OtherInterestExpense Other Interest Expense (431)		2,597,680	2,536,750
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		719,574	1,988,641
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		62,585,175	60,039,089
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		141,082,110	122,954,783
72	ExtraordinaryItemsAbstract Extraordinary Items
73	ExtraordinaryIncome Extraordinary Income (434)
74	ExtraordinaryDeductions (Less) Extraordinary Deductions (435)
75	NetExtraordinaryItems Net Extraordinary Items (Total of line 73 less line 74)
76	IncomeTaxesExtraordinaryItems Income Taxes-Federal and Other (409.3)	262
77	ExtraordinaryItemsAfterTaxes Extraordinary Items After Taxes (line 75 less line 76)
78	NetIncomeLoss Net Income (Total of line 71 and 77)		141,082,110	122,954,783

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		974,289,933	851,045,425
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			289,725
15	AdjustmentsToRetainedEarningsDebit TOTAL Debits to Retained Earnings (Acct. 439)			289,725
16	BalanceTransferredFromIncome Balance Transferred from Income (Account 433 less Account 418.1)		141,082,110	122,954,783
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 $15 par value 9,013,000 shares outstanding
30.2	DividendsDeclaredCommonStock Total Dividends Decl - Common Stk (438)		20,000,000
36	DividendsDeclaredCommonStock TOTAL Dividends Declared-Common Stock (Acct. 438)		20,000,000
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)		1,095,372,043	974,289,933
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)		1,095,372,043	974,289,933
	UnappropriatedUndistributedSubsidiaryEarningsAbstract UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49	UnappropriatedUndistributedSubsidiaryEarnings Balance-Beginning of Year (Debit or Credit)
50	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings for Year (Credit) (Account 418.1)
51	DividendsReceived (Less) Dividends Received (Debit)
52	ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits TOTAL other Changes in unappropriated undistributed subsidiary earnings for the year
53	UnappropriatedUndistributedSubsidiaryEarnings Balance-End of Year (Total lines 49 thru 52)

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)	141,082,110	122,954,783
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	187,837,325	172,498,594
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of	9,086,712	1,147,257
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	113,853,749	16,957,871
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)	115,002	454,907
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	28,154,521	1,049,042
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	1,394,548	14,154,044
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory	4,987	18,847
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	28,454,606	23,002,851
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	878,960,423	34,872,728
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	1,667,688	60,918,062
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	2,359,466	4,034,050
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription (a) Other (provide details in footnote):	7,018,509	18,047,181
18.2	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Customer Deposits	1,349,529	4,119,399
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	435,212,044	155,023,171
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)	335,758,238	343,229,941
27	GrossAdditionsToNuclearFuelInvestingActivities Gross Additions to Nuclear Fuel
28	GrossAdditionsToCommonUtilityPlantInvestingActivities Gross Additions to Common Utility Plant
29	GrossAdditionsToNonutilityPlantInvestingActivities Gross Additions to Nonutility Plant		309,345
30	AllowanceForOtherFundsUsedDuringConstructionInvestingActivities (Less) Allowance for Other Funds Used During Construction	2,359,466	4,034,050
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
31.1	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Acquired Assets	297,423,379	509,382
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	630,822,150	340,014,617
36	AcquisitionOfOtherNoncurrentAssets Acquisition of Other Noncurrent Assets (d)
37	ProceedsFromDisposalOfNoncurrentAssets Proceeds from Disposal of Noncurrent Assets (d)	523,351	1,087,307
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 Proceeds from Disposal of Noncurrent Assets-Fixed Assets
53.2	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription (b) CIAC Proceeds	2,291,655	3,373,817
53.3	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription (Increase) Decrease in Other Special Deposits	200	38,783
53.4	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Notes Receivable from Associated Companies		38,848,097
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	628,006,945	296,666,614
59	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
60	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
61	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b)	1,300,000,000
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	9,962,221
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
67.1	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Proceeds on Capital Leaseback	461,588	484,887
67.2	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Notes Payable to Associated Companies - Issued	625,000,000	155,371,007
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	1,915,499,367	155,855,894
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)	750,511,316	13,156,223
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	83,099,017
78	NetDecreaseInShortTermDebt Net Decrease in Short-Term Debt (c)
80	DividendsOnPreferredStock Dividends on Preferred Stock
81	DividendsOnCommonStock Dividends on Common Stock	20,000,000
83	CashFlowsProvidedFromUsedInFinancingActivities Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)	1,061,889,034	142,699,671
85	NetIncreaseDecreaseInCashAndCashEquivalentsAbstract Net Increase (Decrease) in Cash and Cash Equivalents
86	NetIncreaseDecreaseInCashAndCashEquivalents Net Increase (Decrease) in Cash and Cash Equivalents (Total of line 22, 57 and 83)	1,329,956	1,056,228
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	2,594,792	1,538,563
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	1,264,837	2,594,792

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	935	3,446,301
3	Administrative and General Expenses - Operation	AEPSC	920, 921, 922, 923, 925, 926, 928, 930.1, 930.2, 930.10	4,386,750
4	Fuel & Storeroom Services	AEPSC	152,163	5,018,613
5	Audit Services	AEPSC	920,923	752,784
6	Grid Solutions	AEPSC	920	577,794
7	Building and Property Leases	OKTCo	507,589	2,422,906
8	HVDC North Transmission Tie	AEP Texas	566,573,925,926	884,075
9	Bus Ops & Perf Assurance	AEPSC	920	570,394
10	Information Technology	AEPSC	920,923	5,727,869
11	Central Machine Shop	APCo	107,108, 500,512,513,531	738,638
12	Infrastructure Ops & Support	AEPSC	920,923	741,087
13	Central Maintenance Facility	SWEPCo	107,108, 512, 513	593,192
14	Legal GC/Administration	AEPSC	920,923	1,487,234
15	Civil & Political Activities & Other Services	AEPSC	426	504,569
16	Corp Safety & Health	AEPSC	920,923	1,911,636
17	Construction Services	AEPSC	107,108	49,008,730
18	Material and Supplies	OPCo	107,108, 562, 581, 592,593, 930, 935	331,063
19	Corporate Accounting	AEPSC	920,923	1,519,796
20	Other Power Supply Expenses	AEPSC	556-557	3,513,243
21	Corporate Communications	AEPSC	920,923	589,561
22	Physical & Cyber Security	AEPSC	920,923	896,559
23	Corporate Human Resources	AEPSC	920,923	2,387,199
24	Physical & Cyber Security	SWEPCo	186	254,503
25	Corporate Planning & Budgeting	AEPSC	920,923	1,174,848
26	Rail Car Maintenance	AEGCo	151	418,893
27	Current and Accrued Liabilities	SWEPCO	232	2,134,075
28	Real Estate & Workplace Svcs	AEPSC	920,923	1,756,584
29	Customer Accounts Expenses	AEPSC	901,902,903,904,905	10,419,048
30	Regulatory Services	AEPSC	920,923	789,474
31	Customer Service and Informational Expenses	AEPSC	907,908,910	255,785
32	Research and Other Services	AEPSC	183,186,188	2,099,081
33	Customer Support	AEPSC	920,923	1,411,301
34	Steam Power Generation - Maintenance	AEPSC	510, 511, 512, 513, 514	1,544,171
35	Distribution Expenses - Operation	AEPSC	580,581,582,583,584,586,588	2,608,912
36	Steam Power Generation - Operation	AEPSC	500,501,502,506	8,995,230
19
20	Non-power Goods or Services Provided for Affiliated
21	Factored Customer A/R Bad Debts	AEP Credit, Inc	426.5	1,765,108
22	Tax Services	AEPSC	920,923	609,700
23	Non-power Goods or Services Provided for Affiliate
24	Transmission Expenses - Maintenance	AEPSC	568, 569, 569.1, 569.2, 570, 571, 572, 573	308,516
25	Building and Property Leases	AEPSC	454	3,696,526
26	Construction Services	OKTCo	107,108	1,951,683
27	Construction Services	SWEPCo	107-108	517,580
28	Fleet and Vehicle Charges	AEPSC	Various	369,799
29	Materials and Supplies	AEP Texas	154	911,087
30	Materials and Supplies	OKTCo	154	1,843,843
31	Materials and Supplies	SWEPCo	154	1,008,589
32	Transmission Expenses - Maintenance	OKTCo	568, 569, 570, 571, 573	1,138,230
33	Transmission Expenses - Operation	OKTCo	560,562, 563, 566	1,907,470
34	Use of Jointly Owned Facility	OKTCo	454	415,531
35	Distribution Expenses - Maintenance	AEP Texas	592,593,594,595,596	256,927
36	Distribution Expenses - Maintenance	I&M	592,593,594,595	432,710
37	Distribution Expenses - Maintenance	SWEPCo	592,593,597	564,254
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