FERC Form

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

NOTES TO FINANCIAL STATEMENTS

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

INDEX OF NOTES TO FINANCIAL STATEMENTS


			Glossary of Terms for Notes
1.			Organization and Summary of Significant Accounting Policies
2.			New Accounting Standards
3.			Comprehensive Income
4.			Rate Matters
5.			Effects of Regulation
6.			Commitments, Guarantees and Contingencies
7.			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

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 consolidated subsidiaries and consolidated affiliates.
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.
AEPEP						AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in deregulated markets.
AEPSC						American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AFUDC						Allowance for Equity Funds Used During Construction.
AOCI						Accumulated Other Comprehensive Income.
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.
ERCOT						Electric Reliability Council of Texas regional transmission organization.
ETT						Electric Transmission Texas, LLC, an equity interest joint venture between AEP Transmission Holdco and Berkshire Hathaway Energy Company formed to own and operate electric transmission facilities in ERCOT.
Excess ADIT						Excess accumulated deferred income taxes.
FASB						Financial Accounting Standards Board.
Federal EPA						United States Environmental Protection Agency.
FERC						Federal Energy Regulatory Commission.
FTR						Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP						Accounting Principles Generally Accepted in the United States of America.
IRS						Internal Revenue Service.
ITC						Investment Tax Credit.
MTM						Mark-to-Market.
MW						Megawatt.
NOL						Net operating losses.
OATT						Open Access Transmission Tariff.
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.


OPEB						Other Postretirement Benefits.
OTC						Over-the-counter.
Parent						American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
PPA						Purchase Power and Sale Agreement.
PSO						Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCT						Public Utility Commission of Texas.
REP						Texas Retail Electric Provider.
Risk Management Contracts						Trading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges.
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.
TCC						Formerly AEP Texas Central Company; now a division of AEP Texas.
Texas Restructuring Legislation						Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC						Formerly AEP Texas North Company; now a division of AEP Texas.
Utility Money Pool						Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION

Organized in Delaware in 1925, AEP Texas is engaged in the transmission and distribution of electric power to approximately 1,082,000 retail customers through REPs in west, central and southern Texas. As of December 31, 2021, AEP Texas had 1,575 employees. Among the principal industries served by AEP Texas are petroleum and coal products manufacturing, chemical manufacturing, oil and gas extraction, pipeline transportation and support activities for mining. The territory served by AEP Texas also includes several military installations. AEP Texas is a member of ERCOT.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Rates and Service Regulation

AEP Texas’ rates are regulated by the FERC and the PUCT. The FERC also regulates AEP Texas’ 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 PUCT also regulates certain intercompany transactions under various orders and affiliate statutes. Both the FERC and the PUCT 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. AEP Texas’ 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 AEP Texas 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 PUCT regulates all of the retail distribution operations and rates of AEP Texas’ retail public utility subsidiaries on a cost basis. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by REPs. AEP has one active REP in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind assets, the power from which is marketed and sold in ERCOT. Power from the Oklaunion Power Station was also marketed and sold by these nonregulated subsidiaries in ERCOT prior to its retirement in 2020.

The FERC also regulates AEP Texas’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. AEP Texas’ retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT.

Basis of Accounting

AEP Texas’s accounting is subject to the requirements of the PUCT and the FERC. The financial statements have been prepared in accordance with the Uniform System of Accounts prescribed by the FERC. The principal differences from GAAP include:


·			Accounting for subsidiaries on an equity basis.
·			The 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 an accrued provision for potential refund as other noncurrent liability rather than a current liability.
·			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 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 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 accounting for AEP Texas Central Transition Funding II LLC, AEP Texas Central Transition Funding III LLC and AEP Texas Restoration Funding LLC as nonaffiliated companies rather than consolidating the entities in accordance with the accounting guidance for "Variable Interest Entities."
·			The classification of plant impairment in utility plant adjustments rather than in property, plant and equipment - electric generation.


·			The classification of deferred equity income in other deferred credits rather than in other non-current assets as securitized transition assets.
·			The classification of amortization of deferred equity in operating revenues rather than in depreciation and amortization.
·			The classification of certain other assets and liabilities as current instead of noncurrent.
·			The classification of certain other assets and liabilities as noncurrent instead of current.
·			The classification of debt issuance costs as noncurrent assets instead of noncurrent liabilities.
·			The classification of rents receivable as rents receivable instead of customer accounts receivable.
·			The classification of Non-Service Cost Components of Net Periodic Benefit Cost as Operating Expense instead of Other Income (Expense).
·			The classification of operating lease assets as Utility Plant rather than as a noncurrent asset.
·			The presentation of obligations under finance and operating leases as a single amount in Obligations Under Capital Leases rather than as separate items.
·			The classification of certain expenses in operating income rather than operating expenses.
·			The classification of interest on regulated finance leases as operating expense instead of Other Income (Expense).
·			The classification of 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

AEP Texas’ 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)	$	156.8		$	131.8
	Income Taxes (Net of Refunds)			2.2			(40.5)
Noncash Acquisitions Under Finance Leases				4.4			5.6
As of December 31,
Construction Expenditures Included in Current and Accrued Liabilities				230.0			177.8

Special Deposits

Special Deposits include funds held by trustees primarily for margin deposits for risk management activities.

Inventory

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, AEP Texas accrues and recognizes, as Accrued Utility Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing.

Allowance for Uncollectible Accounts

For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. 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

AEP Texas had significant transactions with REPs which on a combined basis account for the following percentages of Operating Revenues for the years ended December 31 and Customer Accounts Receivable as of December 31:


Significant Customers of AEP Texas:
Reliant Energy, Direct Energy and TXU Energy (a)	2021		2020
Percentage of Operating Revenues	45	%	51	%
Percentage of Customer Accounts Receivable	41	%	41	%

(a)In January 2021, NRG Energy, parent company of Reliant Energy, completed a deal to purchase Direct Energy from Centrica.

AEP Texas monitors credit levels and the financial condition of its customers on a continuous basis to minimize credit risk. The PUCT 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.

Investment in Subsidiary Company

AEP Texas has a wholly-owned subsidiary, AEP Texas North Generation Company, LLC. AEP Texas transferred all of its mothballed generation assets and related liabilities to this subsidiary, substantially completing the business separation requirement of the Texas Restructuring Legislation.

AEP Texas also has three wholly-owned subsidiaries, AEP Texas Central Transition Funding II LLC, AEP Texas Central Transition Funding III LLC and AEP Texas Restoration Funding LLC, that are engaged in financing activities associated with AEP Texas’ securitized assets. Investments in the net assets of AEP Texas’s three wholly-owned subsidiaries are carried at cost plus equity in their undistributed earnings since creation.

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.

Revenue Recognition

Regulatory Accounting

AEP Texas’ 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

AEP Texas recognizes revenues from customers for retail and wholesale electricity sales and electricity transmission and distribution delivery services. AEP Texas 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.

Power Purchase and Sale Agreement

AEP Texas recognized revenue from an affiliate, AEPEP, for a 20-year PPA associated with the Oklaunion Power Station. AEP Texas recognized revenues for the fuel, operations and maintenance and all other taxes on a billed basis. Revenue was recognized for the capacity and depreciation billed to AEPEP on a straight-line basis over the term of the PPA as these amounts represent the minimum amount due. In September 2020, the Oklaunion Power station was retired.

Maintenance

AEP Texas expenses maintenance costs as incurred. If it becomes probable that AEP Texas 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.

Income Taxes and Investment Tax Credits

AEP Texas 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.

AEP Texas 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.

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

AEP Texas participates in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP Texas employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP Texas also participates in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees. AEP Texas 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 AEP Texas’ business. There are no new standards expected to have a material impact on AE1P Texas’ 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.



				Pension and OPEB
				Amortization		Changes in
		Cash Flow Hedge –		of Deferred		Funded
For the Year Ended December 31, 2021		Interest Rate		Costs		Status		Total
	(in millions)
Balance in AOCI as of December 31, 2020		$	(2.3)	$	5.1	$	(11.7)	$	(8.9)
Change in Fair Value Recognized in AOCI		0.1		—		1.2		1.3
Amount of (Gain) Loss Reclassified from AOCI
Interest on Long-Term Debt (a)		1.2		—		—		1.2
Amortization of Prior Service Cost (Credit)		—		(0.1)		—		(0.1)
Amortization of Actuarial (Gains) Losses		—		0.3		—		0.3
Reclassifications from AOCI, before Income Tax (Expense) Benefit		1.2		0.2		—		1.4
Income Tax (Expense) Benefit		0.3		—		—		0.3
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.9		0.2		—		1.1
Net Current Period Other Comprehensive Income (Loss)		1.0		0.2		1.2		2.4
Balance in AOCI as of December 31, 2021		$	(1.3)	$	5.3	$	(10.5)	$	(6.5)


				Pension and OPEB
				Amortization		Changes in
		Cash Flow Hedge –		of Deferred		Funded
For the Year Ended December 31, 2020		Interest Rate		Costs		Status		Total
	(in millions)
Balance in AOCI as of December 31, 2019		$	(3.4)	$	4.9	$	(14.3)	$	(12.8)
Change in Fair Value Recognized in AOCI		0.1		—		2.6		2.7
Amount of (Gain) Loss Reclassified from AOCI
Interest on Long-Term Debt (a)		1.3		—		—		1.3
Amortization of Prior Service Cost (Credit)		—		(0.1)		—		(0.1)
Amortization of Actuarial (Gains) Losses		—		0.3		—		0.3
Reclassifications from AOCI, before Income Tax (Expense) Benefit		1.3		0.2		—		1.5
Income Tax (Expense) Benefit		0.3		—		—		0.3
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		1.0		0.2		—		1.2
Net Current Period Other Comprehensive Income (Loss)		1.1		0.2		2.6		3.9
Balance in AOCI as of December 31, 2020		$	(2.3)	$	5.1	$	(11.7)	$	(8.9)

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

4. RATE MATTERS

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

AEP Texas Interim Transmission and Distribution Rates

Through December 31, 2021, AEP Texas’ cumulative revenues from interim base rate increases that are subject to review is approximately $298 million. A base rate review could result in a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. AEP Texas is required to file for a comprehensive rate review no later than April 5, 2024.

5. EFFECTS OF REGULATION

Regulatory Assets and Liabilities

Regulatory assets and liabilities are comprised of the following items:


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

Regulatory assets pending final regulatory approval:

Regulatory Assets Currently Earning a Return
Advanced Metering System	$	—	0	$	16.3
Total Regulatory Assets Currently Earning a Return	—			16.3
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	22.4			0.8
Vegetation Management Program	5.2			3.8
Texas Retail Electric Provider Bad Debt Expense	4.1			—
COVID-19	2.1			10.5
Other Regulatory Assets Pending Final Regulatory Approval	7.4			1.5
Total Regulatory Assets Currently Not Earning a Return	41.2			16.6

Total Regulatory Assets Pending Final Regulatory Approval	41.2			32.9

Regulatory assets approved for recovery:

Regulatory Assets Currently Earning a Return
Meter Replacement Costs	22.7			29.3		5 years
Advanced Metering System	10.6			—		1 year
Other Regulatory Assets Approved for Recovery	2.1			—		various
Total Regulatory Assets Currently Earning a Return	35.4			29.3
Regulatory Assets Currently Not Earning a Return
Pension and OPEB Funded Status	119.0			145.0		12 years
Income Tax Assets Subject to Flow Through	62.0			55.1		35 years
Texas Transmission Cost Recovery Factor	30.6			4.6		2 years
Vegetation Management Program	17.4			22.4		4 years
Peak Demand Reduction/Energy Efficiency	14.5			7.7		2 years
Storm-Related Costs	12.8			17.1		3 years
Other Regulatory Assets Approved for Recovery	—			2.8		various
Total Regulatory Assets Currently Not Earning a Return	256.3			254.7

Total Regulatory Assets Approved for Recovery	291.7			284.0

Total FERC Account 182.3 Regulatory Assets	$	332.9		$	316.9


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


Regulatory liabilities pending final regulatory determination:

Regulatory Liabilities Currently Paying a Return
Other Regulatory Liabilities Pending Final Regulatory Determination	$	—	$	2.5
Total Regulatory Liabilities Currently Paying a Return	—		2.5
Income Tax Related Regulatory Liabilities (a)
Excess ADIT that is Not Subject to Rate Normalization Requirements	13.0		(8.2)
Total Income Tax Related Regulatory Liabilities	13.0		(8.2)

Total Regulatory Liabilities Pending Final Regulatory Determination	13.0		(5.7)

Regulatory liabilities approved for payment:

Regulatory Liabilities Currently Paying a Return
Other Regulatory Liabilities Approved for Payment	4.8		5.3		various
Total Regulatory Liabilities Currently Paying a Return	4.8		5.3
Regulatory Liabilities Currently Not Paying a Return
Restoration Charges	3.3		3.3		8 years
Other Regulatory Liabilities Approved for Payment	1.1		1.2		various
Total Regulatory Liabilities Currently Not Paying a Return	4.4		4.5
Income Tax Related Regulatory Liabilities (a)
Excess ADIT Associated with Certain Depreciable Property	498.8		506.0		(b)
Excess ADIT that is Not Subject to Rate Normalization Requirements	—		41.7
Income Taxes Subject to Flow Through	8.4		2.3		35 years
Total Income Tax Related Regulatory Liabilities	507.2		550.0

Total Regulatory Liabilities Approved for Payment	516.4		559.8

Total FERC 254 Account Regulatory Liabilities	$	529.4	$	554.1

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

(b)Refunded using ARAM

6. COMMITMENTS, GUARANTEES AND CONTINGENCIES

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

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.

Letters of Credit

Standby letters of credit are entered into with third-parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.

AEP has $4 billion and $1 billion revolving credit facilities due in March 2026 and 2023, respectively, under which up to $1.2 billion may be issued as letters of credit on behalf of AEP Texas. As of December 31, 2021, no letters of credit were issued under the revolving credit facility.

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of AEP Texas under five uncommitted facilities totaling $375 million. Subsequently, in February 2022, the uncommitted facilities total was increased to $400 million. AEP Texas’ maximum future payments for letters of credit issued under the uncommitted facilities as of December 31, 2021 was $2.2 million with a maturity date of July 2022.

Indemnifications and Other Guarantees

Contracts

AEP Texas 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.

Lease Obligations

AEP Texas 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

The transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and non-hazardous materials. AEP Texas 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.

Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often non-hazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. As of December 31, 2021, management’s estimates do not anticipate material clean-up costs for identified Superfund sites.

OPERATIONAL CONTINGENCIES

Insurance and Potential Losses

AEP Texas maintains insurance coverage normal and customary for electric utilities, subject to various deductibles. AEP Texas 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 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 AEP Texas. 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. 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 the 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.

AEP Texas 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. AEP Texas also participates in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees.

AEP Texas 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. AEP Texas recognizes an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognizes, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. AEP Texas 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 (a)	5.10	%	5.05	%	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,	$	453.2	$	441.2	$	96.3	$	97.8
Service Cost	11.8		10.0		0.7		0.8
Interest Cost	11.2		13.9		2.4		3.2
Actuarial (Gain) Loss	(10.9)		28.1		(12.3)		2.4
Plan Amendments	—		—		(0.5)		(1.0)
Benefit Payments	(45.5)		(40.0)		(9.3)		(10.0)
Participant Contributions	—		—		3.2		3.1
Benefit Obligation as of December 31,	$	419.8	$	453.2	$	80.5	$	96.3

Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1,	$	474.0	$	435.1	$	162.3	$	148.1
Actual Gain on Plan Assets	16.0		67.2		12.5		21.1
Company Contributions	0.4		11.7		0.1		—
Participant Contributions	—		—		3.2		3.1
Benefit Payments	(45.5)		(40.0)		(9.3)		(10.0)
Fair Value of Plan Assets as of December 31,	$	444.9	$	474.0	$	168.8	$	162.3

Funded Status as of December 31,	$	25.1	$	20.8	$	88.3	$	66.0


	Pension Plans				OPEB
	December 31,
	2021		2020		2021		2020
	(in millions)
Special Funds – Prepaid Benefit Costs	$	28.7	$	24.7	$	88.3	$	66.0
Miscellaneous Current and Accrued Liabilities – Short-term Benefit Liability	(0.3)		(0.4)		—		—
Accumulated Provision for Pensions and Benefits – Long-term Benefit Liability	(3.3)		(3.5)		—		—
Funded Status	$	25.1	$	20.8	$	88.3	$	66.0

Amounts Included in Regulatory Assets, Deferred Income Taxes and AOCI

The following tables show the components of the plans included in Regulatory Assets, Accumulated Deferred Income Taxes and AOCI 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	$	144.7	$	160.5	$ (5.2)	$	12.3
Prior Service Credit	—		—		(13.7)	(19.3)

Recorded as
Regulatory Assets	$	136.7	$	151.3	$ (17.7)	$	(6.3)
Deferred Income Taxes	1.8		2.0		(0.2)	(0.1)
Net of Tax AOCI	6.2		7.2		(1.0)	(0.6)


	Pension Plans				OPEB
	2021		2020		2021	2020
Components	(in millions)
Actuarial Gain During the Year	$	(7.5)	$	(16.4)	$ (17.5)	$	(10.7)
Amortization of Actuarial Loss	(8.3)		(7.8)		—	(0.5)
Prior Service Credit	—		—		(0.4)	(1.0)
Amortization of Prior Service Credit	—		—		6.0	5.9
Change for the Year Ended December 31,	$	(15.8)	$	(24.2)	$ (11.9)	$	(6.3)

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 AEP Texas using the percentages in the table below:


Pension Plan				OPEB
December 31,
2021		2020		2021		2020
8.3	%	8.5	%	8.3	%	8.3	%

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	$	391.4	$	424.5
Nonqualified Pension Plans	3.3		3.6
Total	$	394.7	$	428.1

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	$	3.6	$	3.9
Fair Value of Plan Assets	—		—
Underfunded Projected Benefit Obligation	$	(3.6)	$	(3.9)

Accumulated Benefit Obligation


	December 31,
	2021		2020
	(in millions)
Accumulated Benefit Obligation	$	3.3	$	3.6
Fair Value of Plan Assets	—		—
Underfunded Accumulated Benefit Obligation	$	(3.3)	$	(3.6)

Estimated Future Benefit Payments and Contributions

AEP Texas expects contributions and payments for the pension plans of $6 million 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, AEP Texas 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 AEP Texas’ 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	$	36.3	$	9.6
2023	35.9		9.1
2024	35.8		9.8
2025	34.9		9.8
2026	34.7		9.8
Years 2027 to 2031, in Total	145.5		44.7

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	$	11.8	$	10.0	$	0.7	$	0.8
Interest Cost	11.2		13.9		2.4		3.2
Expected Return on Plan Assets	(19.5)		(22.7)		(7.5)		(8.0)
Amortization of Prior Service Credit	—		—		(6.0)		(5.9)
Amortization of Net Actuarial Loss	8.3		7.8		—		0.5
Net Periodic Benefit Cost (Credit)	11.8		9.0		(10.4)		(9.4)
Capitalized Portion	(6.6)		(5.5)		(0.4)		(0.4)
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	5.2	$	3.5	$	(10.8)	$	(9.8)

American Electric Power System Retirement Savings Plan

AEP Texas 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 were $6 million for the years ended December 31, 2021 and 2020.

9. BUSINESS SEGMENTS

AEP Texas has one reportable segment, an electricity transmission and distribution business. AEP Texas’ other activities are insignificant.

10. DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

AEPSC is agent for and transacts on behalf of AEP Texas.

Risk Management Strategies

AEP Texas’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEP Texas utilizes financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. AEP Texas does not hedge all fuel price risk. The gross notional volumes of AEP Texas’ outstanding derivative contracts for heating oil and gasoline as of December 31, 2021 and 2020 were 2 million gallons for both years.

Cash Flow Hedging Strategies

AEP Texas utilizes a variety of interest rate derivative transactions in order to manage interest rate risk exposure. AEP Texas also utilizes interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. AEP Texas 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, AEP Texas 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,” AEP Texas 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, AEP Texas 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 AEP Texas’ 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	$	0.6	$	(0.6)	$	—
Long-Term Portion of Derivative Instrument Assets	—		—		—

Derivative Instrument Liabilities	—		—		—
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	$	0.4	$	(0.4)	$	—
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	$	0.8	$	(0.6)
Maintenance Expenses	1.0		(0.8)
Other Regulatory Liabilities (a)	0.2		0.4
Total Gain (Loss) on Risk Management Contracts	$	2.0	$	(1.0)

(a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

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), AEP Texas 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.

AEP Texas reclassifies gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) 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 2021 and 2020, AEP Texas did not apply cash flow hedging to outstanding interest rate derivatives.

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

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

Impact of Cash Flow Hedges on the Balance Sheets

December 31, 2021

December 31, 2020

Interest Rate

Expected to be

Reclassed to

Net Income During

AOCI Gain (Loss)

the Next

AOCI Gain (Loss)

the Next

Net of Tax

Twelve Months

Net of Tax

Twelve Months

(in millions)

(1.3)

(1.1)

(2.3)

(1.1)

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

Credit Risk

Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit, 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.

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)
$	4,802.3	$	5,244.4	$	4,352.6	$	5,159.3

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, AEP Texas’ 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)

Risk Management Assets
Risk Management Commodity Contracts (a)	$	—	$	0.6	$	—	$	(0.6)	$	—


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

Risk Management Assets
Risk Management Commodity Contracts (a)	$	—	$	0.4	$	—	$	(0.4)	$	—

(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.”

12. INCOME TAXES

Income Tax Expense (Credit)

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


		Years Ended December 31,
		2021			2020
		(in millions)
Charged (Credited) to Operating Expenses, Net:
	Current	$	6.2		$	8.4
	Deferred			41.6			(14.3)
Total				47.8			(5.9)

Charged (Credited) to Nonoperating Income, Net:
	Current			(4.4)			(3.2)
	Deferred			(0.2)			(2.0)
Total				(4.6)			(5.2)
Total Income Taxes		$	43.2		$	(11.1)

The following is a reconciliation for AEP Texas between the federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported:


	Years Ended December 31,
	2021		2020

Net Income	$	289.8	$	241.0
Income Tax Expense (Credit)	43.2		(11.1)
Pretax Income	$	333.0	$	229.9

Income Taxes on Pretax Income at Statutory Rate (21%)	$	69.9	$	48.3
Increase (Decrease) in Income Taxes Resulting from the Following Items:
State and Local Income Taxes, Net	2.4		(0.8)
AFUDC	(4.5)		(4.1)
Parent Company Loss Benefit	(3.0)		(4.5)
Tax Reform Excess ADIT Reversal	(21.3)		(47.9)
Other	(0.3)		(2.1)
Income Tax Expense (Credit)	$	43.2	$	(11.1)

Effective Income Tax Rate	13.0%		(4.8)%

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


	December 31,
	2021		2020
	(in millions)
Deferred Tax Assets	$	172.5	$	182.4
Deferred Tax Liabilities	(1262.7)		(1200.4)
Net Deferred Tax Liabilities	$	(1090.2)	$	(1018)

Property Related Temporary Differences	$	(1060.3)	$	(1046.1)
Amounts Due to Customers for Future Federal Income Taxes	111.7		114.4
Deferred State Income Taxes	(32.2)		(29.1)
Regulatory Assets	(49.9)		(47.3)
Securitized Transition Assets	(84.4)		(90.2)
Operating Lease Liability	15.8		18
Deferred Revenues	6.7		2.3
All Other, Net	2.4		60
Net Deferred Tax Liabilities	$	(1090.2)	$	(1018)

AEP System Tax Allocation Agreement

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

Federal and State Income Tax Audit Status

The statute of limitations for the IRS to examine AEP Texas and other AEP subsidiaries originally filed federal return has expired for tax years 2016 and earlier. In the third quarter of 2019, AEP Texas and other AEP subsidiaries elected to amend the 2014 through 2017 federal returns. In the first quarter of 2020, the IRS notified AEP Texas 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 AEP Texas and other AEP subsidiaries claimed on the amended returns. AEP Texas 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.

AEP Texas and other AEP subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns, and AEP Texas and other AEP subsidiaries are currently under examination in several state and local jurisdictions. AEP Texas and other AEP subsidiaries 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.

13. LEASES

AEP Texas 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. AEP Texas 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 AEP Texas 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, AEP Texas 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	$	18.4	$	17.4
Finance Lease Cost:
Amortization of Right-of-Use Assets	6.7		6.3
Interest on Lease Liabilities	1.4		1.5
Total Lease Rental Costs (a)	$	26.5	$	25.2

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

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


	December 31,
	2021		2020
Weighted-Average Remaining Lease Term (years):
Operating Leases	5.91		6.51
Finance Leases	5.51		6.07
Weighted-Average Discount Rate:
Operating Leases	3.53	%	3.60	%
Finance Leases	4.31	%	4.39	%


	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	$	18.0	$	17.1
Operating Cash Flows from Finance Leases	8.1		7.8

Non-cash Acquisitions Under Operating Leases	$	4.4	$	15.8

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


	December 31,
	2021		2020
	(in millions)
Property, Plant and Equipment Under Finance Leases:
Utility Plant (a)	$	30.8	$	33.1
Net Property, Plant and Equipment Under Finance Leases	$	30.8	$	33.1

Obligations Under Finance Leases:
Noncurrent	$	24.2	$	26.8
Current	6.6		6.3
Total Obligations Under Finance Leases	$	30.8	$	33.1

(a) Includes $20 million and $17 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)	$	73.6	$	84.1
Net Property, Plant and Equipment Under Operating Leases	$	73.6	$	84.1

Obligations Under Operating Leases:
Noncurrent	$	61.3	$	71.0
Current	14.0		14.5
Total Obligations Under Operating Leases	$	75.3	$	85.5

(a) Includes $36 million and $26 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	$	7.8	$	16.7
2023	7.1		15.5
2024	5.9		14.1
2025	4.5		11.7
2026	3.5		9.5
After 2026	5.9		16.9
Total Future Minimum Lease Payments	34.7		84.4
Less: Imputed Interest	3.9		9.1
Estimated Present Value of Future Minimum Lease Payments	$	30.8	$	75.3

Master Lease Agreements

AEP Texas 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, AEP Texas 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 AEP Texas for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was $11 million.

Lessor Activity

AEP Texas’ 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
					(in millions)
Senior Unsecured Notes	2022-2051	3.67%	2.10%-6.76%	2.10%-6.76%	$	4,170.0	$	3,720.0
Pollution Control Bonds	2023-2030 (a)	3.42%	0.90%-4.55%	0.90%-4.55%	442.6		442.6
Other Long-term Debt	2022-2059	1.37%	1.35%-4.50%	1.40%-4.50%	200.9		200.9
Unamortized Discount, Net					(11.2)		(10.9)
Total Long-term Debt Outstanding					$	4,802.3	$	4,352.6

(a)Certain Pollution Control Bonds are subject to redemption earlier than the maturity date.

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


	(in millions)
2022	$	625.0
2023	185.0
2024	—
2025	300.0
2026	50.0
After 2026	3,653.5
Principal Amount	4,813.5
Unamortized Discount, Net	(11.2)
Total Long-term Debt	$	4,802.3

Dividend Restrictions

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

All of the dividends declared by AEP Texas 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.

AEP Texas 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 AEP Texas is through the credit agreements. As of December 31, 2021, the maximum amount of restricted net assets of AEP Texas that may not be distributed to the Parent in the form of a loan, advance or dividend was $2.3 billion.

The credit agreement covenant restrictions can limit the ability of AEP Texas to pay dividends out of retained earnings. As of December 31, 2021, the amount of any such restrictions was $792 million.

Corporate Borrowing Program – AEP System

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


	Maximum				Average				Net
	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	$	355.5	$	104.7	$	172.5	$	40.0	$	26.9	$	500.0
2020	320.4		313.4		132.0		139.0		67.1		500.0

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


	Maximum		Minimum		Maximum		Minimum		Average		Average
	Interest Rates		Interest Rates		Interest Rates		Interest Rates		Interest Rate		Interest Rate
	for Funds		for Funds		for Funds		for Funds		for Funds		for Funds
	Borrowed from		Borrowed from		Loaned to the		Loaned to the		Borrowed from		Loaned to the
Years ended	the Utility		the Utility		Utility Money		Utility Money		the Utility		Utility Money
December 31,	Money Pool		Money Pool		Pool		Pool		Money Pool		Pool
	(in millions)
2021	0.48	%	0.02	%	0.39	%	0.02	%	0.33	%	0.26	%
2020	2.70	%	0.27	%	2.10	%	0.27	%	1.51	%	0.81	%

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.

Credit Facilities

See “Letters of Credit” section of Note 6 for additional information.

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” section of Note 14.

Affiliated Revenues and Purchases

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


	Years Ended December 31,
Related Party Revenues	2021		2020
	(in millions)
Direct Sales to AEPEP	$	—	$	87.5
Other Revenues	3.9		3.3

ERCOT Transmission Service Charges

Pursuant to an order from the PUCT, ETT bills AEP Texas for its ERCOT wholesale transmission services. ETT billed AEP Texas $28 million and $28 million for transmission services for the years ended December 31, 2021 and 2020, respectively. The billings are recorded in Operation Expenses on AEP Texas’ statements of income.

Oklaunion PPA between AEP Texas and AEPEP

In 2007, AEP Texas entered into a PPA with an affiliate, AEPEP, whereby AEP Texas agreed to sell AEPEP 100% of AEP Texas’ capacity and associated energy from its undivided interest (54.69%) in the Oklaunion Power Station. The PPA was approved by the FERC. In September 2018, the co-owners of Oklaunion Power Station voted to close the plant in 2020. Effective October 2018, AEP Texas increased depreciation expense to ensure the plant balances are fully depreciated as of September 2020 and recovered through the PPA billings to AEPEP. Under the early termination provisions of the PPA, AEPEP paid AEP Texas the full Utility Plant balance through depreciation payments until termination of the PPA due to the plant closing in September 2020. See “Dispositions” section of Note 7 for additional information.

AEP Texas recorded revenue of $0 and $88 million from AEPEP for the years ended December 31, 2021 and 2020, respectively. These amounts are included in Operating Revenues on AEP Texas’ statements of income.

Sales and Purchases of Property

AEP Texas 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	$	0.4	$	0.9
Purchases	0.4		1.5

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

Intercompany Billings

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

AEPSC

AEPSC provides certain managerial and professional services to AEP Texas. The costs of the services are based on a direct charge or on a prorated basis and billed to AEP Texas at AEPSC’s cost. AEPSC and its billings are subject to regulation by the FERC. AEP Texas’ total billings from AEPSC were $207 million and $199 million for the years ended December 31, 2021 and 2020, respectively.

16. PROPERTY, PLANT AND EQUIPMENT

Depreciation

AEP Texas 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	Transmission		Distribution		General
	(in percentages)
2021	2.2	%	2.9	%	5.8	%
2020	2.0	%	3.1	%	6.1	%

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

AEP Texas 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. AEP Texas 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 AEP Texas plans to use its facilities indefinitely. The retirement obligation would only be recognized if and when AEP Texas abandons or ceases the use of specific easements, which is not expected.

In 2020, AEP Texas recorded a revision to decrease estimated ARO liabilities by $17 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 Settled		Revisions in Cash Flow Estimates		ARO at December 31,
	(in millions)
2021	$	4.0	$	0.2	$	(0.4)	$	—	$	3.8
2020	28.4		0.9		(8.5)		(16.8)		4.0

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::


	Years Ended December 31,
	2021		2020
	(in millions)
Retail Revenues:
Residential Revenues	$	515.0	$	480.4
Commercial Revenues	321.1		282.8
Industrial Revenues	103.4		96.2
Other Retail Revenues	30.0		27.3
Total Retail Revenues	969.5		886.7

Wholesale Revenues:
Transmission Revenues	497.5		399.9
Total Wholesale Revenues	497.5		399.9

Other Revenues from Contracts with Customers (a)	38.9		46.8

Total Revenues from Contracts with Customers	1,505.9		1,333.4

Other Revenues:
Alternative Revenues	6.1		3.4
Other Revenues (a)	8.7		96.0
Total Other Revenues	14.8		99.4

Total Operating Revenues	$	1,520.7	$	1,432.8

(a)Amounts include affiliated and nonaffiliated revenues.

Performance Obligations

AEP Texas 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. AEP Texas 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 AEP Texas are summarized as follows:

Retail Revenues

AEP Texas 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 AEP Texas 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. Payments from REPs are due to AEP Texas within 35 days.

Wholesale Revenues - Transmission

AEP Texas has performance obligations to transmit electricity to wholesale customers through assets owned and operated. The performance obligation to provide transmission services in ERCOT encompass a time frame greater than a year, where the performance obligation within ERCOT is partially fixed for a period of one year or less. Payments from ERCOT for transmission services are typically received within one week from the issuance of the invoice, which is issued monthly for ERCOT.

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 below include affiliated and nonaffiliated revenues.


2022		2023-2024		2025-2026		After 2026		Total
(in millions)
$	531.0	$	—	$	—	$	—	$	531.0

Contract Assets and Liabilities

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

When AEP Texas 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. AEP Texas’ contract liabilities typically arise from services provided under joint use agreements for utility poles. AEP Texas 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 AEP Texas’ balance sheets within the Customer Accounts Receivable line item. AEP Texas’ 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.

The amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable from Associated Companies on AEP Texas’ balance sheets were immaterial as of December 31, 2021 and 2020.

Contract Costs

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

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote. Report data on a year-to-date basis.
Line No.	Item (a)	Unrealized Gains and Losses on Available-For-Sale Securities (b)	Minimum Pension Liability Adjustment (net amount) (c)	Foreign Currency Hedges (d)	Other Adjustments (e)	Other Cash Flow Hedges Interest Rate Swaps (f)	Other Cash Flow Hedges [Specify] (g)	Totals for each category of items recorded in Account 219 (h)	Net Income (Carried Forward from Page 116, Line 78) (i)	Total Comprehensive Income (j)
1	Balance of Account 219 at Beginning of Preceding Year				9,429,145	3,344,048		12,773,193
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income				10,451,491	1,056,015		11,507,506
3	Preceding Quarter/Year to Date Changes in Fair Value				7,685,037			7,685,037
4	Total (lines 2 and 3)				2,766,454	1,056,015		3,822,469	240,951,099	244,773,568
5	Balance of Account 219 at End of Preceding Quarter/Year				6,662,691	2,288,033		8,950,724
6	Balance of Account 219 at Beginning of Current Year				6,662,691	2,288,033		8,950,724
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income				8,217,376	1,056,015		9,273,391
8	Current Quarter/Year to Date Changes in Fair Value				6,854,178			6,854,178
9	Total (lines 7 and 8)				1,363,198	1,056,015		2,419,213	289,824,219	292,243,432
10	Balance of Account 219 at End of Current Quarter/Year				5,299,494	1,232,017		6,531,511

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in column (h) common function.
Line No.	Classification (a)	Total Company For the Current Year/Quarter Ended (b)	Electric (c)	Gas (d)	Other (Specify) (e)	Other (Specify) (f)	Other (Specify) (g)	Common (h)
1	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlantInServiceAbstract In Service
3	UtilityPlantInServiceClassified Plant in Service (Classified)	10,277,202,595.71	10,277,202,596
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	104,477,174.30	104,477,174.30
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified	1,470,906,195.16	1,470,906,195.16
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	11,852,585,965	11,852,585,965
9	UtilityPlantLeasedToOthers Leased to Others
10	UtilityPlantHeldForFutureUse Held for Future Use	625,209	625,209
11	ConstructionWorkInProgress Construction Work in Progress	552,902,898.00	552,902,898
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments	1,845,431	1,845,431
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	12,407,959,503	12,407,959,503
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	2,368,625,863.00	2,368,625,863
15	UtilityPlantNet Net Utility Plant (13 less 14)	10,039,333,640	10,039,333,640
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	2,279,921,682.37	2,279,921,682.37
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	86,858,752	86,858,752
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	2,366,780,434	2,366,780,434
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	2.00	2.00
29	AmortizationUtilityPlantHeldForFutureUse Amortization
30	DepreciationAndAmortizationUtilityPlantHeldForFutureUse Total Held for Future Use (28 & 29)	2	2
31	AbandonmentOfLeases Abandonment of Leases (Natural Gas)
32	AmortizationOfPlantAcquisitionAdjustment Amortization of Plant Acquisition Adjustment	1,845,431	1,845,431
33	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Total Accum Prov (equals 14) (22,26,30,31,32)	2,368,625,863.00	2,368,625,863

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

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

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
Report below the original cost of electric plant in service according to the prescribed accounts. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and reductions in column (e) adjustments. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included in column (c) are entries for reversals of tentative distributions of the prior year reported in column (b). Likewise, if the respondent has a significant amount of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d) distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of respondent’s plant actually in service at end of year. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary account classifications. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing subaccount classification of such plant conforming to the requirement of these pages. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase, and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date.
Line No.	Account (a)	Balance Beginning of Year (b)	Additions (c)	Retirements (d)	Adjustments (e)	Transfers (f)	Balance at End of Year (g)
1	1. INTANGIBLE PLANT
2	(301) Organization	20,237					20,237
3	(302) Franchise and Consents
4	(303) Miscellaneous Intangible Plant	186,119,779	40,901,529	21,907,380			205,113,927
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)	186,140,016	40,901,529	21,907,380			205,134,164
6	2. PRODUCTION PLANT
7	A. Steam Production Plant
8	(310) Land and Land Rights
9	(311) Structures and Improvements
10	(312) Boiler Plant Equipment
11	(313) Engines and Engine-Driven Generators
12	(314) Turbogenerator Units
13	(315) Accessory Electric Equipment
14	(316) Misc. Power Plant Equipment
15	(317) Asset Retirement Costs for Steam Production
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)
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
38	(341) Structures and Improvements
39	(342) Fuel Holders, Products, and Accessories
40	(343) Prime Movers
41	(344) Generators
42	(345) Accessory Electric Equipment
43	(346) Misc. Power Plant Equipment
44	(347) Asset Retirement Costs for Other Production
44.1	(348) Energy Storage Equipment - Production
45	TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)
46	TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)
47	3. Transmission Plant
48	(350) Land and Land Rights	202,033,986	17,964,472	862			219,997,596
48.1	(351) Energy Storage Equipment - Transmission
49	(352) Structures and Improvements	167,272,134	33,768,445	295,203		12	200,745,388
50	(353) Station Equipment	2,198,782,419	251,240,879	7,169,489		248	2,442,853,562
51	(354) Towers and Fixtures	92,210,991	2,697,754	69,749			94,978,494
52	(355) Poles and Fixtures	1,623,831,571	211,723,462	18,654,291			1,816,900,742
53	(356) Overhead Conductors and Devices	975,572,642	67,990,186	6,150,496			1,037,412,333
54	(357) Underground Conduit	14,503,411	15,852,491				30,355,902
55	(358) Underground Conductors and Devices	25,967,014	3,505,019				29,472,033
56	(359) Roads and Trails	54,376					54,376
57	(359.1) Asset Retirement Costs for Transmission Plant
58	TOTAL Transmission Plant (Enter Total of lines 48 thru 57)	5,300,228,544	604,742,708	32,200,591		237	5,872,770,425
59	4. Distribution Plant
60	(360) Land and Land Rights	31,240,311	6,525,125				37,765,436
61	(361) Structures and Improvements	60,630,489	15,758,968	148,066			76,241,391
62	(362) Station Equipment	767,756,001	76,861,149	6,994,184			837,622,967
63	(363) Energy Storage Equipment – Distribution
64	(364) Poles, Towers, and Fixtures	937,308,770	78,879,821	7,827,772			1,008,360,819
65	(365) Overhead Conductors and Devices	831,385,124	84,221,801	8,567,224			907,039,701
66	(366) Underground Conduit	98,629,460	7,094,218	12,357			105,711,320
67	(367) Underground Conductors and Devices	402,581,237	35,384,712	1,193,372			436,772,577
68	(368) Line Transformers	768,656,930	50,152,707	15,842,763			802,966,874
69	(369) Services	340,305,994	23,047,694	1,426,964			361,926,724
70	(370) Meters	200,866,043	16,905,164	18,525,956			199,245,251
71	(371) Installations on Customer Premises	71,152,333	1,380,815	675,948			71,857,200
72	(372) Leased Property on Customer Premises	86,896					86,896
73	(373) Street Lighting and Signal Systems	114,041,552	8,427,624	2,243,985			120,225,191
74	(374) Asset Retirement Costs for Distribution Plant
75	TOTAL Distribution Plant (Enter Total of lines 60 thru 74)	4,624,641,140	404,639,797	63,458,590			4,965,822,347
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	19,922,694	2,434,278	9,779			22,347,193
87	(390) Structures and Improvements	377,133,406	4,129,070	2,864,793			378,397,683
88	(391) Office Furniture and Equipment	7,486,981	26,666	150,711			7,362,936
89	(392) Transportation Equipment	185,606					185,606
90	(393) Stores Equipment	2,228,248	40,350	144,684			2,123,914
91	(394) Tools, Shop and Garage Equipment	52,192,985	8,304,030	311,428			60,185,587
92	(395) Laboratory Equipment	440,894					440,894
93	(396) Power Operated Equipment	21,803					21,803
94	(397) Communication Equipment	164,291,712	66,366,517	4,690,453		237	225,968,013
95	(398) Miscellaneous Equipment	5,171,581	858,656	4,622			6,025,615
96	SUBTOTAL (Enter Total of lines 86 thru 95)	629,075,909	82,159,566	8,176,469		237	703,059,244
97	(399) Other Tangible Property
98	(399.1) Asset Retirement Costs for General Plant	1,460,386	11,406	126,369			1,322,611
99	TOTAL General Plant (Enter Total of lines 96, 97, and 98)	630,536,295	82,148,161	8,302,838		237	704,381,855
100	TOTAL (Accounts 101 and 106)	10,741,545,995	1,132,432,195	125,869,400			11,748,108,790
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)	10,741,545,995	1,132,432,195	125,869,400			11,748,108,790

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

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

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held for future use. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.
Line No.	ElectricPlantHeldForFutureUseDescription Description and Location of Property (a)	ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate Date Originally Included in This Account (b)	ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate Date Expected to be used in Utility Service (c)	ElectricPlantHeldForFutureUse Balance at End of Year (d)
1	Land and Rights:
2	Marina 138/12kV Substation, Nueces County, TX	12/01/2015	01/01/2022	272,882.64
3	1.962 Acres (5195)
4	Items under $250,000			352,326.62
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			625,209

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Report below descriptions and balances at end of year of projects in process of construction (107). Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see Account 107 of the Uniform System of Accounts). Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line No.	ConstructionWorkInProgressProjectDescription Description of Project (a)	ConstructionWorkInProgress Construction work in progress - Electric (Account 107) (b)
1	2021 Spare Skid &Transformers	3,802,041
2	Abilene DACR Phase 2 D Station	2,086,626
3	Abilene TNC T 2022 TTMP CI	2,448,392
4	AEP Texas - TCC Fiber Offices	2,178,868
5	AEP Texas - TNC Fiber 2020	1,969,692
6	AEPTC Trans Pre Eng Parent	4,042,771
7	AEPTC-D Telecom	2,253,804
8	AEPTN Trans Pre Eng Parent	10,307,965
9	AEPTN-D Telecom	1,484,871
10	Albany Foundry to Fort Griffin	1,246,920
11	Albany-Throckmorton 69 kV CI	15,049,023
12	Bull Moose Skid D-Line	1,146,140
13	Burma-Sterling City 69 kV CI	11,167,859
14	CIS-Common Deployment-TXC D	1,082,992
15	Concho Valley Solar CI	4,238,312
16	Corp Prgrm Billing-AEPTC Trans	2,181,973
17	Corp Prgrm Billing-AEPTN Trans	1,128,937
18	Corpus Phase 2 D Station	1,486,698
19	D/TC/Capital Blanket - TCC	3,604,786
20	Dolan Creek 138kV CI	4,352,023
21	Foxtrot CI	14,987,456
22	Friend Ranch to Sonora 69 kV L	19,408,252
23	Garza Station	3,574,861
24	Hidalgo Sub - D-Station	3,114,766
25	James Rowe Sub - D-Station	3,984,669
26	Laredo Phase 2 D Station	2,633,844
27	Laredo Service Center - Fesco	15,025,586
28	Mason to Mason Switch: CI	4,649,351
29	Munday - Throckmorton CI	11,527,213
30	Naismith-Resnik CI	2,368,790
31	Progreso Substation-D-Station	1,519,237
32	RGV Phase 3 D Line	1,071,250
33	RGV Phase 3 D Station	2,301,674
34	S & N McAllen MLSE Upgrades CI	4,712,929
35	SA Concho to Live Oak MLSEs	7,392,283
36	San Angelo T TNC TTMP 2022	1,154,819
37	Santo Nino - D Station	1,548,835
38	T/TN/Capital Blanket - TNC	1,256,266
39	T/TN/Telecom Modernization Pro	3,937,581
40	T/TNC/Abilene Telecom Moderniz	4,097,285
41	T/TNC/NERC Physical Security	3,531,597
42	TCC - Brackettville to Escondi	2,649,910
43	TCC Beeville Transmission	12,413,086
44	TCC Distr Pre Eng Parent	14,132,466
45	TCC Line Rebuild	3,027,025
46	TCC Lon Hill to Warburton	8,313,399
47	Smith - Mathis 69kV Rebuild	9,756,506
48	TCC Naval Base to North Padre	2,188,809
49	TCC Next Generation Radio Sys	12,184,479
50	TCC NGUCS Additional Radio Sit	3,721,628
51	TCC T 2022 TTMP CI	2,856,884
52	TCC Transmission Work	63,774,938
53	TCC Transmission Work HW ckt 1	6,460,986
54	TCC Transmission Work Rincon	3,621,283
55	TCC WHITEPOINT REHAB	2,836,190
56	TCC Work	3,597,607
57	Sparta Solar Interconnection	3,266,017
58	TCC work Ang-Grissom	1,280,777
59	TCC: Work	1,370,007
60	TCC-T BlnktProj Under $3M	3,338,549
61	TC-Customer Service Blkt	4,647,295
62	TC-Pole Replacement	8,515,432
63	TC-Reliability Improvement Blk	22,541,503
64	TC-Service Restoration Blkt	1,595,806
65	TC-Small Capacity Blkt	3,725,241
66	Texola MW Repeater Site	1,157,018
67	SS-CI-CPLCo-D GEN PLT	9,743,429
68	TNC Live Oak to Sonora	1,819,499
69	TNC Live Oak to Sonora (D)	1,725,588
70	TNC Major Eq/Spares-Trans	1,826,528
71	TNC Next Generation Radio Sys	3,522,651
72	TNC NGUCS Additional Radio Sit	1,691,844
73	TNC Transmission	5,519,861
74	TNC Transmission CI	13,530,611
75	TNC Transmission Work	10,634,204
76	TNC-T-BlnktProj Under $3M	12,005,018
77	SS-CI-WTUCo-D GEN PLT	2,275,947
78	TN-Reliability Improvement Blk	5,985,185
79	Trans CI-North Edinburg-relays	10,830,752
80	Trans station Renew-Refurb TCC	2,649,257
81	Transmission CI	1,090,002
82	Tres Bahias Interconnection CI	3,390,359
83	Victoria Service Center (New)	1,176,782
84	Other Minor Projects Under $1,000,000	49,852,861
85	T/TC/Capital Blanket - TCC	7,577,854
86	T/TC/Telecom Modernization Pro	3,173,227
87	T/TCC/NERC Physical Security	4,525,277
88	T/TCC/Rio Grande Telecom Moder	4,324,084
43	Total	552,902,898

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
Explain in a footnote any important adjustments during year. Explain in a footnote any difference between the amount for book cost of plant retired, Line 12, column (c), and that reported for electric plant in service, page 204, column (d), excluding retirements of non-depreciable property. The provisions of Account 108 in the Uniform System of Accounts require that retirements of depreciable plant be recorded when such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional classifications. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Line No.	Item (a)	Total (c + d + e) (b)	Electric Plant in Service (c)	Electric Plant Held for Future Use (d)	Electric Plant Leased To Others (e)
Section A. Balances and Changes During Year
1	AccumulatedProvisionForDepreciationOfElectricUtilityPlant Balance Beginning of Year	2,153,505,437	2,153,505,437
2	Depreciation Provisions for Year, Charged to
3	DepreciationExpenseExcludingAdjustments (403) Depreciation Expense	289,821,623	289,821,623
4	DepreciationExpenseForAssetRetirementCosts (403.1) Depreciation Expense for Asset Retirement Costs	58,482	58,482
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):	4,517,764	(a) 4,517,764
10	DepreciationProvision TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)	285,362,341	285,362,341
11	Net Charges for Plant Retired:
12	BookCostOfRetiredPlant Book Cost of Plant Retired	105,254,404	103,962,019	1,292,385
13	CostOfRemovalOfPlant Cost of Removal	59,730,897	(b) 61,023,280	1,292,383
14	SalvageValueOfRetiredPlant Salvage (Credit)	6,039,204	(c) 6,039,204
15	NetChargesForRetiredPlant TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)	158,946,097	158,946,095	2
16	OtherAdjustmentsToAccumulatedDepreciation Other Debit or Cr. Items (Describe, details in footnote):
17.1	Other Debit or Cr. Items (Describe, details in footnote):
18	BookCostOfAssetRetirementCosts Book Cost or Asset Retirement Costs Retired
19	AccumulatedProvisionForDepreciationOfElectricUtilityPlant Balance End of Year (Enter Totals of lines 1, 10, 15, 16, and 18)	2,279,921,680	2,279,921,682	2
Section B. Balances at End of Year According to Functional Classification
20	AccumulatedDepreciationSteamProduction Steam Production
21	AccumulatedDepreciationNuclearProduction Nuclear Production
22	AccumulatedDepreciationHydraulicProductionConventional Hydraulic Production-Conventional
23	AccumulatedDepreciationHydraulicProductionPumpedStorage Hydraulic Production-Pumped Storage
24	AccumulatedDepreciationOtherProduction Other Production
25	AccumulatedDepreciationTransmission Transmission	733,867,688	733,867,688
26	AccumulatedDepreciationDistribution Distribution	1,403,007,505	1,403,007,507	2
27	AccumulatedDepreciationRegionalTransmissionAndMarketOperation Regional Transmission and Market Operation
28	AccumulatedDepreciationGeneral General	143,046,488	143,046,488
29	AccumulatedProvisionForDepreciationOfElectricUtilityPlant TOTAL (Enter Total of lines 20 thru 28)	2,279,921,680	2,279,921,682	2

FOOTNOTE DATA

(a) Concept: OtherAccounts


Depreciation expense on meters replaced by AMI meters			($6,643,629.60)
Amortization of plant disallowance			$628,669.73
Amortization of capitalized incentives			$567,092.98
Amortization of vegetation			$920,178
Amortization of capitalized SERP			$9,925.11
			$ (4,517,763.78)

(b) Concept: CostOfRemovalOfPlant

Includes $1,396,797 of removal cost in retirement work in progress (RWIP).

Includes ($4,260,694) of salvage in retirement work in progress (RWIP).

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
Report below investments in Account 123.1, Investments in Subsidiary Companies. Provide a subheading for each company and list thereunder the information called for below. Sub-TOTAL by company and give a TOTAL in columns (e), (f), (g) and (h). (a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity, and interest rate. (b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity date, and specifying whether note is a renewal. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for Account 418.1. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee and purpose of the pledge. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission, date of authorization, and case or docket number. Report column (f) interest and dividend revenues from investments, including such revenues from securities disposed of during the year. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or the other amount at which carried in the books of account if different from cost) and the selling price thereof, not including interest adjustment includible in column (f). Report on Line 42, column (a) the TOTAL cost of Account 123.1.
Line No.	DescriptionOfInvestmentsInSubsidiaryCompanies Description of Investment (a)	DateOfAcquisitionInvestmentsInSubsidiaryCompanies Date Acquired (b)	DateOfMaturityInvestmentsInSubsidiaryCompanies Date of Maturity (c)	InvestmentInSubsidiaryCompanies Amount of Investment at Beginning of Year (d)	EquityInEarningsOfSubsidiaryCompanies Equity in Subsidiary Earnings of Year (e)	InterestAndDividendRevenueFromInvestments Revenues for Year (f)	InvestmentInSubsidiaryCompanies Amount of Investment at End of Year (g)	InvestmentGainLossOnDisplosal Gain or Loss from Investment Disposed of (h)
1	AEP Texas Central Transition Funding, LLC.	02/01/2002		4,499,680			4,499,680
2	AEP Texas Central Transition Funding II, LLC.	10/01/2006		10,040,226			10,040,226
3	AEP Texas Central Transition Funding III, LLC.	02/01/2012		4,216,178	1,025		4,217,203
4	AEP TX Restoration Funding LLC	09/01/2019		1,186,095	375		1,186,470
5	AEP Texas North Generation Company, LLC	08/01/2006		6,609,958	205,379		6,404,579
42	Total Cost of Account 123.1 $		Total	26,552,137	203,979		26,348,158

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

MATERIALS AND SUPPLIES
For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a); estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense clearing, if applicable.
Line No.	Account (a)	Balance Beginning of Year (b)	Balance End of Year (c)	Department or Departments which Use Material (d)
1	Fuel Stock (Account 151)			Electric
2	Fuel Stock Expenses Undistributed (Account 152)			Electric
3	Residuals and Extracted Products (Account 153)
4	Plant Materials and Operating Supplies (Account 154)
5	Assigned to - Construction (Estimated)	66,765,746	72,101,013	Electric
6	Assigned to - Operations and Maintenance
7	Production Plant (Estimated)	7,528	7,528	Electric
8	Transmission Plant (Estimated)	1,069,815	474,084	Electric
9	Distribution Plant (Estimated)	2,013,084	1,214,164	Electric
10	Regional Transmission and Market Operation Plant (Estimated)
11	Assigned to - Other (provide details in footnote)	190,203	(a) 70,403	Electric
12	TOTAL Account 154 (Enter Total of lines 5 thru 11)	70,046,376	73,867,192
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	70,046,376	73,867,192

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: PlantMaterialsAndOperatingSuppliesOther

This footnote applies to both current and prior year.

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

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

Allowances (Accounts 158.1 and 158.2)
Report below the particulars (details) called for concerning allowances. Report all acquisitions of allowances at cost. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k). Report on Line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40. Report on Line 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances. Report on Lines 8-14 the names of vendors/transferors of allowances acquired and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
		Current Year		Year One		Year Two		Year Three		Future Years		Totals
Line No.	SO2 Allowances Inventory (Account 158.1) (a)	No. (b)	Amt. (c)	No. (d)	Amt. (e)	No. (f)	Amt. (g)	No. (h)	Amt. (i)	No. (j)	Amt. (k)	No. (l)	Amt. (m)
1	Balance-Beginning of Year
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)
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
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
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	30.00		30.00		30.00		30.00		2,981.00		3,101.00
37	Add: Withheld by EPA									60.00		60.00
38	Deduct: Returned by EPA
39	Cost of Sales	30.00								30.00		60.00
40	Balance-End of Year			30		30.00		30.00		3,011.00		3,101.00
41
42	Sales
43	Net Sales Proceeds (Assoc. Co.)
44	Net Sales Proceeds (Other)
45	Gains
46	Losses

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

Allowances (Accounts 158.1 and 158.2)
Report below the particulars (details) called for concerning allowances. Report all acquisitions of allowances at cost. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k). Report on Line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40. Report on Line 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances. Report on Lines 8-14 the names of vendors/transferors of allowances acquired and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
		Current Year		Year One		Year Two		Year Three		Future Years		Totals
Line No.	NOx Allowances Inventory (Account 158.1) (a)	No. (b)	Amt. (c)	No. (d)	Amt. (e)	No. (f)	Amt. (g)	No. (h)	Amt. (i)	No. (j)	Amt. (k)	No. (l)	Amt. (m)
1	Balance-Beginning of Year
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)
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
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
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:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

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

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

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

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

Transmission Service and Generation Interconnection Study Costs
Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and generator interconnection studies. List each study separately. In column (a) provide the name of the study. In column (b) report the cost incurred to perform the study at the end of period. In column (c) report the account charged with the cost of the study. In column (d) report the amounts received for reimbursement of the study costs at end of period. In column (e) report the account credited with the reimbursement received for performing the study.
Line No.	DescriptionOfStudyPerformed Description (a)	StudyCostsIncurred Costs Incurred During Period (b)	StudyCostsAccountCharged Account Charged (c)	StudyCostsReimbursements Reimbursements Received During the Period (d)	StudyCostsAccountReimbursed Account Credited With Reimbursement (e)
1	Transmission Studies
2	(a) Texas (ERCOT)
3	16INR0111	107,143	186
4	17INR0031	107,960	186
5	17INR0035	43,710	186	55,950	186
6	17INR0043	9,158	186
7	17INR0045	131,232	186
8	18INR0014	57,928	186
9	18INR0058	11,330	186
10	18INR0059	27,352	186
11	18INR0060	27,825	186
12	19INR0006	39,194	186
13	19INR0022	17,698	186
14	19INR0035	305	186
15	19INR0045	3,685	186
16	19INR0057	48,256	186
17	19INR0111	64,036	186
18	19INR0122	79,524	186
19	19INR0171	6,153	186
20	19INR0177	14,131	186
21	19NIR0113	47,475	186
22	20AEPSC001	5,292	186
23	20INR0014	768	186
24	20INR0042	50,764	186
25	20INR0053	10,426	186
26	20INR0054	63,681	186
27	20INR0055	50,308	186
28	20INR0070	1,667	186
29	20INR0086	4,688	186
30	20INR0088	5,052	186
31	20INR0097	32,335	186	80,000	186
32	20INR0102	39,558	186
33	20INR0128	1,472	186
34	20INR0129	20,298	186	80,000	186
35	20INR0133	30,282	186
36	20INR0213	30,575	186
37	20INR0232	7,639	186
38	20INR0249	51,911	186	80,000	186
39	21INR0213	34,592	186
40	21INR0223	10,003	186
41	21INR0253	4,221	186
42	21INR0344	920	186
43	21INR0467	113,551	186	80,000	186
44	22INR0213	63,154	186
20	Total
21	Generation Studies
39	Total
40	Grand Total

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: DescriptionOfStudyPerformed

Respondent is unable to expand on the description due to Electric Reliability Council of Texas (ERCOT) disclosure limitations when studies are in process.

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

OTHER REGULATORY ASSETS (Account 182.3)
Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. For Regulatory Assets being amortized, show period of amortization.
				CREDITS
Line No.	DescriptionAndPurposeOfOtherRegulatoryAssets Description and Purpose of Other Regulatory Assets (a)	OtherRegulatoryAssets Balance at Beginning of Current Quarter/Year (b)	IncreaseDecreaseInOtherRegulatoryAssets Debits (c)	OtherRegulatoryAssetsWrittenOffAccountCharged Written off During Quarter/Year Account Charged (d)	OtherRegulatoryAssetsWrittenOffRecovered Written off During the Period Amount (e)	OtherRegulatoryAssets Balance at end of Current Quarter/Year (f)
1	Under-recovery of Energy Efficiency Program Expenses - as approved by PUCT Docket (updated annually)	7,698,954	12,891,322	456/907	6,077,573	14,512,703
2	Advanced Metering Systems Existing Meter Investment of "old meters retired" and replaced by "Advanced Meters" as approved in PUCT Docket #36928	29,334,864		403	6,643,630	22,691,234
3	Advanced Metering Systems O&M expenses to be recovered over 11 years beginning in 2010 as approved in PUCT Docket #36928	122,578	13,600	182/570/571/580/593/903	136,178
4	Defer incremental expense as it relates to Covid-19	10,547,103	1,042,498	143/182	9,461,965	2,127,636
5	Distribution Vegetation Estimate PUCT Docket #49494 - Rate Case	26,251,533	1,367,007	407/107/571	5,072,307	22,546,233
6	TX Line Inspection Costs		2,384,229	571/931	7,217	(a) 2,377,012
7	Over Refunded AEPTX ITR Rider		1,663,907			1,663,907
8	Power of Texas Holdings		4,092,318			4,092,318
9	Reserve for Catastrophe for storm recovery. Currently funded at an annual rate of $4.2M per year. Updated last on PUCT Docket #49494.	17,928,889	28,035,254	924/560/593	10,727,732	35,236,411
10	SFAS 106 Medicare Subsidy (Amortization period Jan 2013 - Dec 2024)	2,785,045		926	696,261	(b) 2,088,784
11	SFAS 109 Deferred FIT	25,266,009	5,092,194	282/283	498,982	29,859,221
12	SFAS 109 Deferred SIT	29,794,421	4,404,337	282	2,087,715	32,111,043
13	SFAS 158 Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans	144,989,619	157,048,194	190/219/228/242/129/165	182,947,979	(c) 119,089,834
14	Under-recovery of Advanced Metering Systems Expense as approved in PUCT Docket #36928	16,148,686	715,722	182/928/403/419/254	6,275,075	10,589,333
15	Under-recovery of Transmission Cost Recovery Factor - as approved by PUCT Dockey (updated semiannually)	4,555,985	46,784,741	254/565	20,707,028	30,633,698
16	Wholesale Distribution Substation Service - Oncor	1,452,740				1,452,740
17	Various Rate Case Expenses pending		28,271	593/146/234/928	33,318	5,047
18	Other Regulatory Assets		1,825,932			1,825,932
44	TOTAL	316,876,427	267,389,526		251,372,960	332,892,993

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: OtherRegulatoryAssets

511,580,588,593,921,923,935,450,451,454,232,234

(b) Concept: OtherRegulatoryAssets

456,907,254

129,165,242,228

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

MISCELLANEOUS DEFFERED DEBITS (Account 186)
Report below the particulars (details) called for concerning miscellaneous deferred debits. For any deferred debit being amortized, show period of amortization in column (a) Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by classes.
				CREDITS
Line No.	Description of Miscellaneous Deferred Debits (a)	Balance at Beginning of Year (b)	Debits (c)	Credits Account Charged (d)	Credits Amount (e)	Balance at End of Year (f)
1	Associated Business Development	1,249,567	25,182,861	(a) 107/108/142/146/163/184/232/582	24,953,540	1,478,888
2	Unamortized Credit Line Fees Amortization period through 6/1/2022	355,752	1,395,376	146/234/431	400,868	1,350,260
3	Deferred Lease Assets	43,155	1,790,070	143/146	1,630,456	202,769
4	Minor Items <$100,000 or 1%"	9,094	9,410	152/242/253	11,864	11,548
47	Miscellaneous Work in Progress
48	Deferred Regulatroy Comm. Expenses (See pages 350 - 351)
49	TOTAL	1,639,380				3,020,368

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: DecreaseInMiscellaneousDeferredExpenseAccountCharged

107/108/142/146/163/184/232/582

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

ACCUMULATED DEFERRED INCOME TAXES (Account 190)
Report the information called for below concerning the respondent’s accounting for deferred income taxes. At Other (Specify), include deferrals relating to other income and deductions.
Line No.	DescriptionOfAccumulatedDeferredIncomeTax Description and Location (a)	AccumulatedDeferredIncomeTaxes Balance at Beginning of Year (b)	AccumulatedDeferredIncomeTaxes Balance at End of Year (c)
1	Electric
2	Deferred Book Contract Revenue	4,778,650	4,784,754
3	Book Operating Lease - Asset	17,950,672	15,817,608
4	Disallowed Costs	13,939,647	15,143,883
5	Over/Under Recovery-Securitization Revenue	7,873,589	4,843,225
6	Securitization Defd Equity Income - Long Term	6,664,097	5,035,061
7	Other	5,586,224	5,335,411
8	TOTAL Electric (Enter Total of lines 2 thru 7)	56,792,879	50,959,942
9	Gas
15	Other
16	TOTAL Gas (Enter Total of lines 10 thru 15)
17.1	Other (Specify)	125,577,153	121,537,954
17	Other (Specify)
18	TOTAL (Acct 190) (Total of lines 8, 16 and 17)	182,370,032	172,497,896

Notes

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

CAPITAL STOCKS (Account 201 and 204)
Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year. Give details concerning shares of any class and series of stock authorized to be issued by a regulatory commission which have not yet been issued. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or noncumulative. State in a footnote if any capital stock that has been nominally issued is nominally outstanding at end of year. Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which is pledged, stating name of pledgee and purpose of pledge.
Line No.	Class and Series of Stock and Name of Stock Series (a)	Number of Shares Authorized by Charter (b)	Par or Stated Value per Share (c)	Call Price at End of Year (d)	Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Shares (e)	Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Amount (f)	Held by Respondent As Reacquired Stock (Acct 217) Shares (g)	Held by Respondent As Reacquired Stock (Acct 217) Cost (h)	Held by Respondent In Sinking and Other Funds Shares (i)	Held by Respondent In Sinking and Other Funds Amount (j)
1	Common Stock (Account 201)
2	Common Stock (Account 201)
3	Total					1
4	Preferred Stock (Account 204)
5
6
7
8	Total
1	Capital Stock (Accounts 201 and 204) - Data Conversion
2
3
4
5	Total

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

2022-05-19

Year/Period of Report

End of:

2021

Other Paid-in Capital
1. Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a subheading for each account and show a total for the account, as well as a total of all accounts for reconciliation with the balance sheet, page 112. Explain changes made in any account during the year and give the accounting entries effecting such change. Donations Received from Stockholders (Account 208) - State amount and briefly explain the origin and purpose of each donation. Reduction in Par or Stated Value of Capital Stock (Account 209) - State amount and briefly explain the capital changes that gave rise to amounts reported under this caption including identification with the class and series of stock to which related. Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210) - Report balance at beginning of year, credits, debits, and balance at end of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related. Miscellaneous Paid-In Capital (Account 211) - Classify amounts included in this account according to captions that, together with brief explanations, disclose the general nature of the transactions that gave rise to the reported amounts.
Line No.	Item (a)	Amount (b)
1	DonationsReceivedFromStockholdersAbstract Donations Received from Stockholders (Account 208)
2	DonationsReceivedFromStockholders Beginning Balance Amount	1,458,164,804
3.1	IncreasesDecreasesFromSalesOfDonationsReceivedFromStockholders Increases (Decreases) from Sales of Donations Received from Stockholders	96,000,000
4	DonationsReceivedFromStockholders Ending Balance Amount	1,554,164,804
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	217,010
11.1	IncreasesDecreasesFromGainOrResaleOrCancellationOfReacquiredCapitalStock Increases (Decreases) from Gain or Resale or Cancellation of Reacquired Capital Stock	1
12	GainOnResaleOrCancellationOfReacquiredCapitalStock Ending Balance Amount	217,011
13	MiscellaneousPaidInCapitalAbstract Miscellaneous Paid-In Capital (Account 211)
14	MiscellaneousPaidInCapital Beginning Balance Amount
15.1	IncreasesDecreasesDueToMiscellaneousPaidInCapital Increases (Decreases) Due to Miscellaneous Paid-In Capital
16	MiscellaneousPaidInCapital Ending Balance Amount
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	1,553,947,793

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

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

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

LONG-TERM DEBT (Account 221, 222, 223 and 224)
Report by Balance Sheet Account the details concerning long-term debt included in Accounts 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other Long-Term Debt. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds, and in column (b) include the related account number. For Advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate demand notes as such. Include in column (a) names of associated companies from which advances were received, and in column (b) include the related account number. For receivers' certificates, show in column (a) the name of the court and date of court order under which such certificates were issued, and in column (b) include the related account number. In a supplemental statement, give explanatory details for Accounts 223 and 224 of net changes during the year. With respect to long-term advances, show for each company: (a)principal advanced during year (b) interest added to principal amount, and (c) principal repaid during year. Give Commission authorization numbers and dates. If the respondent has pledged any of its long-term debt securities, give particulars (details) in a footnote, including name of the pledgee and purpose of the pledge. If the respondent has any long-term securities that have been nominally issued and are nominally outstanding at end of year, describe such securities in a footnote. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest expense in column (m). Explain in a footnote any difference between the total of column (m) and the total Account 427, Interest on Long-Term Debt and Account 430, Interest on Debt to Associated Companies. Give details concerning any long-term debt authorized by a regulatory commission but not yet issued.
Line No.	ClassAndSeriesOfObligationCouponRateDescription Class and Series of Obligation, Coupon Rate (For new issue, give commission Authorization numbers and dates) (a)	RelatedAccountNumber Related Account Number (b)	Principal Amount of Debt Issued (c)	LongTermDebtIssuanceExpensePremiumOrDiscount Total Expense, Premium or Discount (d)	LongTermDebtIssuanceExpenses Total Expense (e)	LongTermDebtPremium Total Premium (f)	LongTermDebtDiscount Total Discount (g)	NominalDateOfIssue Nominal Date of Issue (h)	DateOfMaturity Date of Maturity (i)	AmortizationPeriodStartDate AMORTIZATION PERIOD Date From (j)	AmortizationPeriodEndDate AMORTIZATION PERIOD Date To (k)	Outstanding (Total amount outstanding without reduction for amounts held by respondent) (l)	Interest for Year Amount (m)
1	Bonds (Account 221)
2
3
4
5	Subtotal
6	Reacquired Bonds (Account 222)
7
8
9
10	Subtotal
11	Advances from Associated Companies (Account 223)
12
13
14
15	Subtotal
16	Other Long Term Debt (Account 224)
17	Series 2001A, 6.3% - (Matagorda)		100,635,000					07/01/2009	11/01/2029	07/01/2009	11/01/2029	100,635,000	2,616,510
18	Series 2005A, 4.4% - (Matagorda)		111,700,000					12/06/2006	05/01/2030	03/16/2005	05/01/2030	111,700,000	4,914,800
19	Series 2005B, 4.55% - (Matagorda)		50,000,000					12/06/2006	05/01/2030	03/16/2005	05/01/2030	50,000,000	2,275,000
20	Series 2008 - 1&2, Matagorda Remarketing, 4.0% (Issued 6-3-2013)		120,265,000					06/03/2013	06/01/2030	06/03/2013	06/01/2030	120,265,000	4,810,600
21	Series 1996, 0.90% - Matagorda Pollution Control Bonds		60,000,000					09/01/2020	05/01/2030	09/01/2020	05/01/2030	60,000,000	540,000
22	Private Placement Notes:
23	Series B, 6.76%		1,600,000					04/01/2008	04/01/2038	04/01/2008	04/01/2038	1,600,000	108,160
24	Series B, 6.76%		12,700,000					04/01/2008	04/01/2038	04/01/2008	04/01/2038	12,700,000	858,520
25	Series B, 6.76%		13,700,000					04/01/2008	04/01/2038	04/01/2008	04/01/2038	13,700,000	926,120
26	Series B, 6.76%		35,000,000					04/01/2008	04/01/2038	04/01/2008	04/01/2038	35,000,000	2,366,000
27	Series B, 6.76%		7,000,000					04/01/2008	04/01/2038	04/01/2008	04/01/2038	7,000,000	473,200
28	Other Long-Term Debt:
29	Goodfellow Air Force Base - 4.5%		1,001,187					12/01/2009	11/01/2059	12/01/2009	11/01/2059	920,781	41,656
30	Texas Local Revolving Credit Facility		200,000,000					05/31/2019	05/31/2022	05/31/2019	05/31/2022	200,000,000	2,743,693
31	Senior Unsecured Notes:
32	Series C, 3.09%		125,000,000		597,741			02/28/2013	02/28/2023	02/28/2013	02/28/2023	125,000,000	3,862,500
33	Series C - Financial Hedges												1,336,728
34	Series D, 4.48%		75,000,000		358,644			02/27/2013	02/27/2043	02/27/2013	02/27/2043	75,000,000	3,360,000
35	Series E, 3.27%		25,000,000		126,464			09/30/2015	09/30/2022	09/30/2015	09/30/2022	25,000,000	817,500
36	Series F, 3.75%		50,000,000		252,928			09/30/2015	09/30/2025	09/30/2015	09/30/2025	50,000,000	1,875,000
37	Series G, 4.71%		50,000,000		252,928			12/15/2015	12/15/2035	12/15/2015	12/15/2035	50,000,000	2,355,000
38	Series E (formerly B) 6.65% Notes		275,000,000		2,504,241		1,342,000	02/18/2003	02/15/2033	03/01/2003	02/15/2033	275,000,000	18,287,500
39	Series B, 3.81%		50,000,000					04/30/2014	04/30/2026	04/30/2014	04/30/2026	50,000,000	1,905,000
40	Series C, 4.67%		100,000,000					04/30/2014	04/30/2044	04/30/2014	04/30/2044	100,000,000	4,670,000
41	Series D, 4.77%		100,000,000		1,454,317			10/30/2014	10/30/2044	10/30/2014	10/30/2044	100,000,000	4,770,000
42	Series G, 3.85%		250,000,000		1,864,770		2,447,500	09/18/2015	10/01/2025	09/18/2015	10/01/2025	250,000,000	9,625,000
43	Series A, 2.4% (FERC Authority ES16-47-000)		400,000,000		3,047,760		696,000	09/22/2017	10/01/2022	09/22/2017	10/01/2022	400,000,000	9,600,000
44	Series B, 3.8%		300,000,000		3,129,449		3,450,000	09/22/2017	10/01/2047	09/22/2017	10/01/2047	300,000,000	11,400,000
45	Series E, 3.95% (FERC Authority ES18-22-000)		500,000,000		3,922,721		1,650,000	05/17/2018	06/01/2028	05/17/2018	06/01/2028	500,000,000	19,750,000
46	Series G, 4.15%		300,000,000		2,625,000		3,264,120	05/01/2019	05/01/2049	05/01/2019	05/01/2049	300,000,000	12,450,000
47	Series H, 3.45%		450,000,000		3,937,500		2,106,000	12/31/2019	01/31/2050	12/31/2019	01/31/2050	450,000,000	15,525,000
48	Series I, 2.10%		600,000,000		4,860,880			07/01/2020	07/01/2030	07/01/2020	07/01/2030	600,000,000	12,600,000
49	Series J, 3.45%		450,000,000		3,946,680		1,341,000	05/06/2021	05/15/2051	05/06/2021	05/15/2051	450,000,000	10,134,375
50	Subtotal		4,813,601,187		32,882,023		16,296,620					4,813,520,781	166,997,862
33	TOTAL		4,813,601,187									4,813,520,781	166,997,862

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
Line No.	Particulars (Details) (a)	Amount (b)
1	Net Income for the Year (Page 117)	289,824,219
2	Reconciling Items for the Year
3
4	Taxable Income Not Reported on Books
5
6
7
8
9	Deductions Recorded on Books Not Deducted for Return
10
11
12
13
14	Income Recorded on Books Not Included in Return
15
16
17
18
19	Deductions on Return Not Charged Against Book Income
20
21
22
23
24
25
26
27	Federal Tax Net Income	17,450,984
28	Show Computation of Tax:
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

TAXES ACCRUED, PREPAID AND CHARGES DURING YEAR
Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual, or estimated amounts of such taxes are known, show the amounts in a footnote and designate whether estimated or actual amounts. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.) Enter the amounts in both columns (g) and (h). The balancing of this page is not affected by the inclusion of these taxes. Include in column (g) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued, (b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than accrued and prepaid tax accounts. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained. If any tax (exclude Federal and State income taxes) covers more than one year, show the required information separately for each tax year, identifying the year in column (d). Enter all adjustments of the accrued and prepaid tax accounts in column (i) and explain each adjustment in a foot- note. Designate debit adjustments by parentheses. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending transmittal of such taxes to the taxing authority. Report in columns (l) through (o) how the taxes were distributed. Report in column (o) only the amounts charged to Accounts 408.1 and 409.1 pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 409.1 pertaining to other utility departments and amounts charged to Accounts 408.2 and 409.2. Also shown in column (o) the taxes charged to utility plant or other balance sheet accounts. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
					BALANCE AT BEGINNING OF YEAR					BALANCE AT END OF YEAR		DISTRIBUTION OF TAXES CHARGED
Line No.	DescriptionOfTaxesAccruedPrepaidAndCharged Kind of Tax (See Instruction 5) (a)	TypeOfTax Type of Tax (b)	TaxJurisdiction State (c)	TaxYear Tax Year (d)	TaxesAccrued Taxes Accrued (Account 236) (e)	PrepaidTaxes Prepaid Taxes (Include in Account 165) (f)	TaxesCharged Taxes Charged During Year (g)	TaxesPaid Taxes Paid During Year (h)	TaxAdjustments Adjustments (i)	TaxesAccrued Taxes Accrued (Account 236) (j)	PrepaidTaxes Prepaid Taxes (Included in Account 165) (k)	TaxesAccruedPrepaidAndCharged Electric (Account 408.1, 409.1) (l)	IncomeTaxesExtraordinaryItems Extraordinary Items (Account 409.3) (m)	AdjustmentsToRetainedEarnings Adjustment to Ret. Earnings (Account 439) (n)	TaxesIncurredOther Other (o)
1	Federal Tax	Federal Tax			17,727,780	0	1,165,629	2,247,539		21,140,948		3,201,600			4,367,229
2	Subtotal Federal Tax				17,727,780	0	1,165,629	2,247,539		21,140,948		3,201,600			4,367,229
3	Local Tax	Local Tax		2019	1,835,151	0				1,835,151	0
4	Local Tax	Local Tax	TX	2020	3,935,202	0	56,026	3,879,176		0	0				56,026
5	Local Tax	Local Tax	TX	2021	0	0	50,796,438	46,933,914		3,862,524	0	50,740,413			56,025
6	Subtotal Local Tax				2,100,051	0	50,740,412	50,813,090		2,027,373	0	50,740,413			1
7	Property Tax	Property Tax	TX	2017	0	0	1,497	1,497		0	0	1,497
8	Property Tax	Property Tax	TX	2018	0	0	1,441	1,441		0	0	1,441
9	Property Tax	Property Tax	TX	2019	0	0	24,396	24,396		0	0	24,396
10	Property Tax	Property Tax	TX	2020	66,575,039	0	5,619	66,569,420		0	0	5,619
11	Property Tax	Property Tax	TX	2021	0	0	101,286,072	23,514,944		77,771,128	0	98,941,472			2,344,600
12	Subtotal Property Tax				66,575,039	0	101,307,787	90,111,698		77,771,128	0	98,963,187			2,344,600
13	UNEMPLOYMENT 2021	Unemployment Tax			12,074	0	75,900	72,233		15,741	0	36,380			39,520
14	STATE UNEMPLOYMENT 2021	Unemployment Tax	LA
15	STATE UNEMPLOYMENT 2021	Unemployment Tax	OK
16	STATE UNEMPLOYMENT 2021	Unemployment Tax	TX		18,660	0	129,950	124,136		24,474	0	36,926			93,024
17	Subtotal Unemployment Tax				30,734	0	205,850	196,369		40,215	0	73,306			132,544
18	Sales And Use Tax	Sales And Use Tax	TX	2020	2,553,952	0	69,558	2,484,394		0	0	222			69,336
19	Sales And Use Tax	Sales And Use Tax	TX	2021	0	0	22,686,192	19,218,324		3,467,868	0	783			22,685,409
20	Subtotal Sales And Use Tax				2,553,952	0	22,616,634	21,702,718		3,467,868	0	561			22,616,073
21	State Tax	Income Tax	MULTI	2019	1,835,151	0				1,835,151	0
22	State Tax	Income Tax	TX	2011	30,203	0				30,203	0
23	State Tax	Income Tax	TX	2017	0	0				0	0
24	State Tax	Income Tax	TX	2018	1,581,821	0				1,581,821	0
25	State Tax	Income Tax	TX	2019	3,251,272	0				3,251,272	0
26	State Tax	Income Tax	TX	2020	2,555,280	0				2,555,280	0
27	State Tax	Income Tax	TX	2021	0	0	2,997,427			2,997,427	0	2,997,427
28	Subtotal Income Tax				919,119	0	2,997,427			3,916,546	0	2,997,427
29	Other State Tax	Other State Tax	OH	2020	0	0	3	3		0	0	3
30	Other State Tax	Other State Tax	OH	2021	0	0	9	9		0	0	9
31	Subtotal Other State Tax				0	0	12	12		0	0	12
32	FICA 2021	Payroll Tax			1,672,333	0	11,794,461	14,489,269	2,299,018	1,276,543	0	5,308,762			6,485,700
33	2360104 FICA	Payroll Tax			2,635,928	0			2,635,928	0	0
34	2360105 FICA CARES ACT	Payroll Tax			2,635,928	0			336,941	2,972,869	0
35	Subtotal Payroll Tax				6,944,189	0	11,794,461	14,489,269	31	4,249,412	0	5,308,762			6,485,700
40	TOTAL				61,395,304	0	188,496,954	179,560,695	31	70,331,594	0	161,285,268			27,211,687

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g). Include in column (i) the average period over which the tax credits are amortized.
			Deferred for Year		Allocations to Current Year's Income
Line No.	Account Subdivisions (a)	Balance at Beginning of Year (b)	Account No. (c)	Amount (d)	Account No. (e)	Amount (f)	Adjustments (g)	Balance at End of Year (h)	Average Period of Allocation to Income (i)	ADJUSTMENT EXPLANATION (j)
1	Electric Utility
2	3%
3	4%
4	7%
5	10%	8,544,738	411.1		411.4	1,744,950		6,799,788	20 years
8	TOTAL Electric (Enter Total of lines 2 thru 7)	8,544,738				1,744,950		6,799,788
9	Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
10										`
47	OTHER TOTAL
48	GRAND TOTAL	8,544,738						6,799,788

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

OTHER DEFERRED CREDITS (Account 253)
Report below the particulars (details) called for concerning other deferred credits. For any deferred credit being amortized, show the period of amortization. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
			DEBITS
Line No.	Description and Other Deferred Credits (a)	Balance at Beginning of Year (b)	Contra Account (c)	Amount (d)	Credits (e)	Balance at End of Year (f)
1	Pole Attachments	2,060,747	456/454/142	5,177,828	4,812,373	1,695,292
2	Security Deposits	12,696,613	232	33,374,242	52,222,519	31,544,890
3	Deferred Equity Income relating to Supreme Court of Texas July 2011 Reversal of 2006 Capacity Auction True-up Disallowance (PUCT Docket #39722)	31,733,794	456	7,757,313		23,976,481
4	Contributions in Aid of Construction	15,439,693	107	15,439,693	12,843,878	12,843,878
5	Associated Business Development	3,536,683	186/146/234	5,068,601	13,924,811	12,392,893
6	Environmental Liabilities	220,750	242/506	45,502	76,108	251,356
7	Texas Reliability Entity - Audit Assessment	2,620,301	234/107	529,874		2,090,427
8	Minor Items < $100,000	132,659	143/186	1,307	573	131,925
9	Texas Restoration Carrying Cost	12,821,430	234/253	4,790,718	157,690	8,188,402
10	Asbestos Settlement Accrual				150,000	150,000
47	TOTAL	81,262,670		72,185,078	84,187,952	93,265,544

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)

Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to amortizable property.
For other (Specify),include deferrals relating to other income and deductions.
Use footnotes as required.

CHANGES DURING YEAR

ADJUSTMENTS

Debits

Credits

Line No.

Account

(a)

Balance at Beginning of Year

(b)

Amounts Debited to Account 410.1

(c)

Amounts Credited to Account 411.1

(d)

Amounts Debited to Account 410.2

(e)

Amounts Credited to Account 411.2

(f)

Account Credited

(g)

Amount

(h)

Account Debited

(i)

Amount

(j)

Balance at End of Year

(k)

Accelerated Amortization (Account 281)

Electric

Defense Facilities

Pollution Control Facilities

Other

5.1

Other (provide details in footnote):

TOTAL Electric (Enter Total of lines 3 thru 7)

Gas

Defense Facilities

Pollution Control Facilities

Other

12.1

Other (provide details in footnote):

TOTAL Gas (Enter Total of lines 10 thru 14)

Other

16.1

Other

16.2

Other

TOTAL (Acct 281) (Total of 8, 15 and 16)

Classification of TOTAL

Federal Income Tax

State Income Tax

Local Income Tax

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282)
Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to property not subject to accelerated amortization. For other (Specify),include deferrals relating to other income and deductions. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Account 282
2	Electric	1,417,485,827	126,414,259	108,035,697					190		1,435,864,389
3	Gas
4	Other (Specify)
5	Total (Total of lines 2 thru 4)	1,417,485,827	126,414,259	108,035,697							1,435,864,389
6	(a) Regulatory Assets - SFAS109	367,110,595					1823/254	18,194,607	1823/254	26,467,142	358,838,060
9	TOTAL Account 282 (Total of Lines 5 thru 8)	1,050,375,232	126,414,259	108,035,697				18,194,607		26,467,142	1,077,026,329
10	Classification of TOTAL
11	Federal Income Tax	1,050,375,232	126,414,259	108,035,697				18,194,607		26,467,142	1,077,026,329
12	State Income Tax
13	Local Income Tax

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: DescriptionOfNonUtilityAccountDetails


Description	Beg Bal	DR 410	CR 411	Debits	Credits	End Bal
Non-Utility	—	—	—	—	—	—
SFAS 109	(367,110,595)	—	—	18,194,607	26,467,142	(358,838,060)
Total	(367,110,595)	—	—	18,194,607	26,467,142	(358,838,060)

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283)
Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts recorded in Account 283. For other (Specify),include deferrals relating to other income and deductions. Provide in the space below explanations for Page 276. Include amounts relating to insignificant items listed under Other. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Account 283
2	Electric
3	Accrued Bk Pension Expense	34,386,529	155,953	1,443,293							33,099,189
4	Reg Asset-Defd Vegetation Mgmt	5,512,822	287,072	1,065,185							4,734,709
5	Defd Tax Gain Securitized Reg	90,208,193	12,641,010	18,456,005							84,393,198
6	Reg Asset Advanced Metering	9,577,286	99,864	2,688,232							6,988,918
7	RA-Loss on Reacquired Debt	1,038,085	82,576	219,323							901,338
8	Other	5,943,687	47,669,970	17,975,224							35,638,433
9	TOTAL Electric (Total of lines 3 thru 8)	146,666,602	60,936,445	41,847,262							165,755,785
10	Gas
11
12
13
14
15
16
17	TOTAL Gas (Total of lines 11 thru 16)
18	TOTAL Other	3,309,767			1,406,923	586,716	1823/254	3,703,706	1823/254	19,506,842	19,933,110
19	TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)	149,976,369	60,936,445	41,847,262	1,406,923	586,716		3,703,706		19,506,842	185,688,895
20	Classification of TOTAL
21	Federal Income Tax	120,881,345	60,108,328	41,847,262	1,406,923	586,716		1,336,855		14,823,369	153,449,132
22	State Income Tax	29,095,024	828,117					2,366,851		4,683,473	32,239,763
23	Local Income Tax
NOTES

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

OTHER REGULATORY LIABILITIES (Account 254)
Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. For Regulatory Liabilities being amortized, show period of amortization.
			DEBITS
Line No.	Description and Purpose of Other Regulatory Liabilities (a)	Balance at Beginning of Current Quarter/Year (b)	Account Credited (c)	Amount (d)	Credits (e)	Balance at End of Current Quarter/Year (f)
1	SFAS 109 Deferred FIT	541,842,456	190/282/283	35,318,543	13,719,877	520,243,790
2	Earnings Subject to Refund under State of Texas Restructuring Legislation Amortization @ 3.361% or approximately 30 years per Docket No. 22354	5,333,643	407	496,012		4,837,631
3	FERC System Integration Agreement (SIA) Refund to be applied as a reduction to Advanced Metering System Investment - PUCT Docket #36924 and 36928	2,479,029	1823	2,479,029
4	Transition Regulatory Liability	3,285,956				3,285,956
5	Unrealized Gain/Loss on Forward Commitments	425,022	175	9,521,465	9,685,458	589,015
6	Deferred Income Tax Adjustment - for Oncor Acquisition	780,382	407	310,042		470,340
41	TOTAL	554,146,488		48,125,091	23,405,335	529,426,732

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

Electric Operating Revenues
The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH related to unbilled revenues need not be reported separately as required in the annual version of these pages. Report below operating revenues for each prescribed account, and manufactured gas revenues in total. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added for billing purposes, one customer should be counted for each group of meters added. The average number of customers means the average of twelve figures at the close of each month. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification in a footnote.) See page 108, Important Changes During Period, for important new territory added and important rate increase or decreases. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts. Include unmetered sales. Provide details of such Sales in a footnote.
Line No.	Title of Account (a)	Operating Revenues Year to Date Quarterly/Annual (b)	Operating Revenues Previous year (no Quarterly) (c)	MEGAWATT HOURS SOLD Year to Date Quarterly/Annual (d)	MEGAWATT HOURS SOLD Amount Previous year (no Quarterly) (e)	AVG.NO. CUSTOMERS PER MONTH Current Year (no Quarterly) (f)	AVG.NO. CUSTOMERS PER MONTH Previous Year (no Quarterly) (g)
1	SalesOfElectricityHeadingAbstract Sales of Electricity
2	ResidentialSalesAbstract (440) Residential Sales
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting
7	OtherSalesToPublicAuthoritiesAbstract (445) Other Sales to Public Authorities
8	SalesToRailroadsAndRailwaysAbstract (446) Sales to Railroads and Railways
9	InterdepartmentalSalesAbstract (448) Interdepartmental Sales
10	SalesToUltimateConsumersAbstract TOTAL Sales to Ultimate Consumers
11	SalesForResaleAbstract (447) Sales for Resale		87,526,128		593,625
12	SalesOfElectricityAbstract TOTAL Sales of Electricity		87,526,128		593,625
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds		2,275,125
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds		89,801,253		593,625
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts	294,581	111,000
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	(a) 2,480,139	2,282,012
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power
19	RentFromElectricProperty (454) Rent from Electric Property	21,232,099	23,326,966
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	(b) 999,240,834	917,394,212
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	497,493,443	399,927,351
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	1,520,741,096	1,343,041,541
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	1,520,741,096	1,432,842,794
Line12, column (b) includes $ of unbilled revenues.
Line12, column (d) includes MWH relating to unbilled revenues

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: MiscellaneousServiceRevenues

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

(b) Concept: OtherElectricRevenue


Account 456.0 Other Electric Revenues:	2021		2020
Wires Revenue (Billed and Unbilled) *	$	969,542,437	$	884,434,242
Demand Side Management Programs Revenue	6,104,187		3,379,973
Electric Operations - related (Affiliated)	835,282		1,330,156
Electric Operations - related (Non Affiliated)	13,780,920		19,425,976
Third Party Plant Operations including related overhead	287,667		333,230
Amortization of Deferred Equity Income - Transition Funding III	8,690,341		8,490,571
Other Misc. Revenues - Items < $250,000	—		63

Total	999,240,834		917,394,211

* AEP Texas sells wire services through Retail Electric Providers in Texas and therefore, records both "Billed and Unbilled Revenues" in account 456 - Other Electric Revenue.

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

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

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

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

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

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

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

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

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: NameOfCompanyOrPublicAuthorityReceivingElectricityPurchasedForResale

AEP Energy Partners (AEPEP), an affiliated company, Oklaunion Power Purchase and Sales Agreement.

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line No.	Account (a)	Amount for Current Year (b)	Amount for Previous Year (c) (c)
1	PowerProductionExpensesAbstract 1. POWER PRODUCTION EXPENSES
2	SteamPowerGenerationAbstract A. Steam Power Generation
3	SteamPowerGenerationOperationAbstract Operation
4	OperationSupervisionAndEngineeringSteamPowerGeneration (500) Operation Supervision and Engineering	4,477	1,344,845
5	FuelSteamPowerGeneration (501) Fuel		13,481,036
6	SteamExpensesSteamPowerGeneration (502) Steam Expenses	3,284	784,966
7	SteamFromOtherSources (503) Steam from Other Sources
8	SteamTransferredCredit (Less) (504) Steam Transferred-Cr.
9	ElectricExpensesSteamPowerGeneration (505) Electric Expenses	25	866,755
10	MiscellaneousSteamPowerExpenses (506) Miscellaneous Steam Power Expenses	215,864	2,272,791
11	RentsSteamPowerGeneration (507) Rents
12	Allowances (509) Allowances
13	SteamPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 4 thru 12)	214,695	18,750,393
14	SteamPowerGenerationMaintenanceAbstract Maintenance
15	MaintenanceSupervisionAndEngineeringSteamPowerGeneration (510) Maintenance Supervision and Engineering		453,029
16	MaintenanceOfStructuresSteamPowerGeneration (511) Maintenance of Structures		683,344
17	MaintenanceOfBoilerPlantSteamPowerGeneration (512) Maintenance of Boiler Plant		726,958
18	MaintenanceOfElectricPlantSteamPowerGeneration (513) Maintenance of Electric Plant		152,586
19	MaintenanceOfMiscellaneousSteamPlant (514) Maintenance of Miscellaneous Steam Plant	2,135	447,320
20	SteamPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 15 thru 19)	2,135	2,463,237
21	PowerProductionExpensesSteamPower TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)	212,560	21,213,630
22	NuclearPowerGenerationAbstract B. Nuclear Power Generation
23	NuclearPowerGenerationOperationAbstract Operation
24	OperationSupervisionAndEngineeringNuclearPowerGeneration (517) Operation Supervision and Engineering
25	NuclearFuelExpense (518) Fuel
26	CoolantsAndWater (519) Coolants and Water
27	SteamExpensesNuclearPowerGeneration (520) Steam Expenses
28	SteamFromOtherSourcesNuclearPowerGeneration (521) Steam from Other Sources
29	SteamTransferredCreditNuclearPowerGeneration (Less) (522) Steam Transferred-Cr.
30	ElectricExpensesNuclearPowerGeneration (523) Electric Expenses
31	MiscellaneousNuclearPowerExpenses (524) Miscellaneous Nuclear Power Expenses
32	RentsNuclearPowerGeneration (525) Rents
33	NuclearPowerGenerationOperationsExpense TOTAL Operation (Enter Total of lines 24 thru 32)
34	NuclearPowerGenerationMaintenanceAbstract Maintenance
35	MaintenanceSupervisionAndEngineeringNuclearPowerGeneration (528) Maintenance Supervision and Engineering
36	MaintenanceOfStructuresNuclearPowerGeneration (529) Maintenance of Structures
37	MaintenanceOfReactorPlantEquipmentNuclearPowerGeneration (530) Maintenance of Reactor Plant Equipment
38	MaintenanceOfElectricPlantNuclearPowerGeneration (531) Maintenance of Electric Plant
39	MaintenanceOfMiscellaneousNuclearPlant (532) Maintenance of Miscellaneous Nuclear Plant
40	NuclearPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 35 thru 39)
41	PowerProductionExpensesNuclearPower TOTAL Power Production Expenses-Nuclear. Power (Enter Total of lines 33 & 40)
42	HydraulicPowerGenerationAbstract C. Hydraulic Power Generation
43	HydraulicPowerGenerationOperationAbstract Operation
44	OperationSupervisionAndEngineeringHydraulicPowerGeneration (535) Operation Supervision and Engineering
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
63	Fuel (547) Fuel
64	GenerationExpenses (548) Generation Expenses
64.1	OperationOfEnergyStorageEquipment (548.1) Operation of Energy Storage Equipment
65	MiscellaneousOtherPowerGenerationExpenses (549) Miscellaneous Other Power Generation Expenses
66	RentsOtherPowerGeneration (550) Rents	19
67	OtherPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 62 thru 67)	19
68	OtherPowerGenerationMaintenanceAbstract Maintenance
69	MaintenanceSupervisionAndEngineeringOtherPowerGeneration (551) Maintenance Supervision and Engineering
70	MaintenanceOfStructures (552) Maintenance of Structures
71	MaintenanceOfGeneratingAndElectricPlant (553) Maintenance of Generating and Electric Plant
71.1	MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration (553.1) Maintenance of Energy Storage Equipment
72	MaintenanceOfMiscellaneousOtherPowerGenerationPlant (554) Maintenance of Miscellaneous Other Power Generation Plant
73	OtherPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 69 thru 72)
74	PowerProductionExpensesOtherPower TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)	19
75	OtherPowerSuplyExpensesAbstract E. Other Power Supply Expenses
76	PurchasedPower (555) Purchased Power
76.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations	0
77	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching	33,133	136,113
78	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	8	65,273
79	OtherPowerSupplyExpense TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)	33,140	201,386
80	PowerProductionExpenses TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74 & 79)	179,400	21,415,016
81	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
82	TransmissionExpensesOperationAbstract Operation
83	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	20,027,641	15,888,894
85	LoadDispatchReliability (561.1) Load Dispatch-Reliability
86	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	3,862,028	3,244,567
87	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling	5,616	5,775
88	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services	99,194	72,312
89	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development	954,960	658,286
90	TransmissionServiceStudies (561.6) Transmission Service Studies
91	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies
92	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services
93	StationExpensesTransmissionExpense (562) Station Expenses	1,041,820	1,155,531
93.1	OperationOfEnergyStorageEquipmentTransmissionExpense (562.1) Operation of Energy Storage Equipment
94	OverheadLineExpense (563) Overhead Lines Expenses	226,601	352,979
95	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses	359	499
96	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	301,747,468	304,180,169
97	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	8,390,915	11,401,884
98	RentsTransmissionElectricExpense (567) Rents
99	TransmissionOperationExpense TOTAL Operation (Enter Total of Lines 83 thru 98)	336,345,369	336,949,346
100	TransmissionMaintenanceAbstract Maintenance
101	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering	152,791	98,917
102	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	83,158	29,325
103	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware	15,210	(a) 15,830
104	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software	1,015,638	1,157,501
105	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment	263,204	210,322
106	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	4,047,865	4,528,758
107.1	MaintenanceOfEnergyStorageEquipmentTransmission (570.1) Maintenance of Energy Storage Equipment
108	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	14,248,583	10,473,070
109	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines	10,777	56,168
110	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant	22,560	10,857
111	TransmissionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 101 thru 110)	19,859,786	16,580,748
112	TransmissionExpenses TOTAL Transmission Expenses (Total of Lines 99 and 111)	356,205,155	353,530,094
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
122	RentsRegionalMarketExpenses (575.8) Rents
123	RegionalMarketOperationExpense Total Operation (Lines 115 thru 122)
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)
132	DistributionExpensesAbstract 4. DISTRIBUTION EXPENSES
133	DistributionExpensesOperationAbstract Operation
134	OperationSupervisionAndEngineeringDistributionExpense (580) Operation Supervision and Engineering	6,403,119	6,098,119
135	LoadDispatching (581) Load Dispatching	3,159,234	3,150,088
136	StationExpensesDistribution (582) Station Expenses	1,455,196	1,313,649
137	OverheadLineExpenses (583) Overhead Line Expenses	3,765,342	4,031,308
138	UndergroundLineExpenses (584) Underground Line Expenses	2,303,491	2,489,228
138.1	OperationOfEnergyStorageEquipmentDistribution (584.1) Operation of Energy Storage Equipment
139	StreetLightingAndSignalSystemExpenses (585) Street Lighting and Signal System Expenses	507,903	69,513
140	MeterExpenses (586) Meter Expenses	8,255,309	9,677,560
141	CustomerInstallationsExpenses (587) Customer Installations Expenses	909,959	1,019,211
142	MiscellaneousDistributionExpenses (588) Miscellaneous Expenses	18,521,016	26,843,066
143	RentsDistributionExpense (589) Rents	1,903,971	2,693,438
144	DistributionOperationExpensesElectric TOTAL Operation (Enter Total of Lines 134 thru 143)	47,184,539	57,385,180
145	DistributionExpensesMaintenanceAbstract Maintenance
146	MaintenanceSupervisionAndEngineering (590) Maintenance Supervision and Engineering	110,765	105,580
147	MaintenanceOfStructuresDistributionExpense (591) Maintenance of Structures	10,634	59,666
148	MaintenanceOfStationEquipment (592) Maintenance of Station Equipment	2,645,016	2,491,650
148.1	MaintenanceOfEnergyStorageEquipment (592.2) Maintenance of Energy Storage Equipment
149	MaintenanceOfOverheadLines (593) Maintenance of Overhead Lines	43,616,832	39,982,075
150	MaintenanceOfUndergroundLines (594) Maintenance of Underground Lines	1,016,014	1,036,553
151	MaintenanceOfLineTransformers (595) Maintenance of Line Transformers	824,867	772,172
152	MaintenanceOfStreetLightingAndSignalSystems (596) Maintenance of Street Lighting and Signal Systems	742,703	811,403
153	MaintenanceOfMeters (597) Maintenance of Meters	240,897	239,648
154	MaintenanceOfMiscellaneousDistributionPlant (598) Maintenance of Miscellaneous Distribution Plant	209,618	208,800
155	DistributionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 146 thru 154)	49,417,347	45,707,547
156	DistributionExpenses TOTAL Distribution Expenses (Total of Lines 144 and 155)	96,601,886	103,092,727
157	CustomerAccountsExpensesAbstract 5. CUSTOMER ACCOUNTS EXPENSES
158	CustomerAccountsExpensesOperationsAbstract Operation
159	SupervisionCustomerAccountExpenses (901) Supervision	370,579	424,212
160	MeterReadingExpenses (902) Meter Reading Expenses	387,013	393,716
161	CustomerRecordsAndCollectionExpenses (903) Customer Records and Collection Expenses	11,760,191	11,190,200
162	UncollectibleAccounts (904) Uncollectible Accounts	136,777	391,073
163	MiscellaneousCustomerAccountsExpenses (905) Miscellaneous Customer Accounts Expenses	83,389	80,237
164	CustomerAccountExpenses TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)	12,464,395	11,697,292
165	CustomerServiceAndInformationalExpensesAbstract 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166	CustomerServiceAndInformationalExpensesOperationAbstract Operation
167	SupervisionCustomerServiceAndInformationExpenses (907) Supervision	17,059,549	17,183,383
168	CustomerAssistanceExpenses (908) Customer Assistance Expenses	1,369,225	1,253,217
169	InformationalAndInstructionalAdvertisingExpenses (909) Informational and Instructional Expenses
170	MiscellaneousCustomerServiceAndInformationalExpenses (910) Miscellaneous Customer Service and Informational Expenses	61,777	41,804
171	CustomerServiceAndInformationExpenses TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)	18,490,551	18,478,404
172	SalesExpenseAbstract 7. SALES EXPENSES
173	SalesExpenseOperationAbstract Operation
174	SupervisionSalesExpense (911) Supervision		663
175	DemonstratingAndSellingExpenses (912) Demonstrating and Selling Expenses	246,751	282,471
176	AdvertisingExpenses (913) Advertising Expenses
177	MiscellaneousSalesExpenses (916) Miscellaneous Sales Expenses
178	SalesExpenses TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)	246,751	283,134
179	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
180	AdministrativeAndGeneralExpensesOperationAbstract Operation
181	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	36,977,312	37,384,943
182	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	1,987,201	1,153,237
183	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit	9,071,386	9,732,458
184	OutsideServicesEmployed (923) Outside Services Employed	6,637,199	4,698,914
185	PropertyInsurance (924) Property Insurance	7,101,715	5,127,812
186	InjuriesAndDamages (925) Injuries and Damages	2,737,836	2,256,159
187	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	1,903,139	3,746,403
188	FranchiseRequirements (927) Franchise Requirements
189	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	673,655	1,065,699
190	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.
191	GeneralAdvertisingExpenses (930.1) General Advertising Expenses	501,368	616,689
192	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	1,321,121	894,862
193	RentsAdministrativeAndGeneralExpense (931) Rents	1,135,930	1,283,551
194	AdministrativeAndGeneralOperationExpense TOTAL Operation (Enter Total of Lines 181 thru 193)	51,905,089	48,495,811
195	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
196	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	16,961,208	15,788,686
197	AdministrativeAndGeneralExpenses TOTAL Administrative & General Expenses (Total of Lines 194 and 196)	68,866,297	64,284,497
198	OperationsAndMaintenanceExpensesElectric TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 156, 164, 171, 178, and 197)	552,695,636	572,781,164

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: MaintenanceOfComputerHardwareTransmission

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:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

PURCHASED POWER (Account 555)
Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years. SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less. LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years. EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges. OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each adjustment. AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. Report in column (g) the megawatthours shown on bills rendered to the respondent, excluding purchases for energy storage. Report in column (h) the megawatthours shown on bills rendered to the respondent for energy storage purchases. Report in columns (i) and (j) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. Report demand charges in column (k), energy charges in column (l), and the total of any other types of charges, including out-of-period adjustments, in column (m). Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (n) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (m) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. The data in columns (g) through (n) must be totaled on the last line of the schedule. The total amount in columns (g) and (h) must be reported as Purchases on Page 401, line 10. The total amount in column (i) must be reported as Exchange Received on Page 401, line 12. The total amount in column (j) must be reported as Exchange Delivered on Page 401, line 13. Footnote entries as required and provide explanations following all required data.
					Actual Demand (MW)				POWER EXCHANGES		COST/SETTLEMENT OF POWER
Line No.	NameOfCompanyOrPublicAuthorityProvidingPurchasedPower Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	RateScheduleTariffNumber Ferc Rate Schedule or Tariff Number (c)	AverageMonthlyBillingDemand Average Monthly Billing Demand (MW) (d)	AverageMonthlyNonCoincidentPeakDemand Average Monthly NCP Demand (e)	AverageMonthlyCoincidentPeakDemand Average Monthly CP Demand (f)	MegawattHoursPurchasedOtherThanStorage MegaWatt Hours Purchased (Excluding for Energy Storage) (g)	MegawattHoursPurchasedForEnergyStorage MegaWatt Hours Purchased for Energy Storage (h)	EnergyReceivedThroughPowerExchanges MegaWatt Hours Received (i)	EnergyDeliveredThroughPowerExchanges MegaWatt Hours Delivered (j)	DemandChargesOfPurchasedPower Demand Charges ($) (k)	EnergyChargesOfPurchasedPower Energy Charges ($) (l)	OtherChargesOfPurchasedPower Other Charges ($) (m)	SettlementOfPower Total (k+l+m) of Settlement ($) (n)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15	TOTAL						0	0	0	0

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

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

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

TRANSFER OF ENERGY

REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS

Line No.

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

(m)

(n)

Floresville Electric Power System (1)

Various

SFP

N/A

Various

633,802

Pedernales Electric Cooperative, Inc (1)

ERCOT

SPP

N/A

Various

12,001,423

(a)

Austin Energy (1)

Various

SFP

N/A

Various

20,069,790

Fredericksburg, City of (1)

Various

SFP

N/A

Various

243,063

Rainbow Energy Marketing (2)

ERCOT

SPP

N/A

Various

231,917

195,909

Bandera Electric Coop (1)

Various

SFP

N/A

Various

1,146,460

Garland Power and Light (1)

Various

SFP

N/A

Various

2,457,771

Rayburn Country Electric Cooperative, Inc (1)

Various

SFP

N/A

Various

6,846,299

Bartlett, City of (1)

Various

SFP

N/A

Various

20,611

Georgetown, City of (1)

Various

SFP

N/A

Various

1,170,867

Rio Grande Electric Coop (1)

Various

SFP

N/A

Various

440,511

Bastrop, City of (1)

Various

SFP

N/A

Various

125,160

GEUS (1)

Various

SFP

N/A

Various

756,273

Robstown Utility System, City of (2)

Various

SFP

N/A

Various

249,281

Bellville, City of (1)

Various

SFP

N/A

Various

98,958

Giddings, City of (1)

Various

SFP

N/A

Various

97,610

San Antonio City Public Service (1)

Various

SFP

N/A

Various

35,471,034

Bluebonnet Electric Coop (1)

Various

SFP

N/A

Various

3,818,973

Golden Spread Electric Cooperative, Inc (1)

Various

SFP

N/A

Various

2,052,918

San Bernard Electric Coop (1)

Various

SFP

N/A

Various

1,150,494

Boerne, City of (1)

Various

SFP

N/A

Various

251,436

Goldsmith, City of (1)

Various

SFP

N/A

Various

8,587

San Marcos, City of (1)

Various

SFP

N/A

Various

946,002

Brady, City of (1)

Various

SFP

N/A

Various

109,557

Goldthwaite, City of (1)

Various

SFP

N/A

Various

40,625

San Saba, City of (1)

Various

SFP

N/A

Various

71,864

Brazos Electric Coop (1)

Various

SFP

N/A

Various

25,666,002

Gonzales, City of (1)

Various

SFP

N/A

Various

136,612

Sanger, City of (1)

Various

SFP

N/A

Various

99,077

Brenham, City of (1)

Various

SFP

N/A

Various

433,071

Granbury Municipal Utilities (1)

Various

SFP

N/A

Various

164,282

Schulenberg, City of (1)

Various

SFP

N/A

Various

102,022

Bridgeport, City of (1)

Various

SFP

N/A

Various

90,964

Guadalupe Valley Electric Coop (1)

Various

SFP

N/A

Various

3,307,443

Seguin, City of (1)

Various

SFP

N/A

Various

474,924

Brownsville Public Utilities Board (1)

Various

SFP

N/A

Various

2,055,999

Guzman Energy (1)

Various

SFP

N/A

Various

18,283

18,626

Sempra Energy Solutions, LLC (2)

Various

SFP

N/A

Various

8,920

7,481

Bryan Texas Utilities (1)

Various

SFP

N/A

Various

2,811,408

Hallettsville, City of (1)

Various

SFP

N/A

Various

70,434

Seymour, City of (1)

Various

SFP

N/A

Various

52,173

Burnet, City of (1)

Various

SFP

N/A

Various

146,140

Hamilton County Electric Coop (1)

Various

SFP

N/A

Various

312,454

Shell Energy North America (1)

Various

SFP

N/A

Various

Canadian Wood Products Energy (2)

Various

SFP

N/A

Various

14,826

Hearne, City of (1)

Various

SFP

N/A

Various

84,285

Shiner, City of (1)

Various

SFP

N/A

Various

76,144

Centerpoint Energy Houston Electric, LLC (1)

Various

SFP

N/A

Various

138,826,767

Hempstead, City of (1)

Various

SFP

N/A

Various

94,095

Smithville, City of (1)

Various

SFP

N/A

Various

75,869

Central Texas Electric Coop (1)

Various

SFP

N/A

Various

1,109,818

Kerrville Public Utility Board (1)

Various

SFP

N/A

Various

818,077

South Texas Electric Cooperative, Inc (1)

Various

SFP

N/A

Various

8,181,423

Cherokee County Electric Coop (1)

Various

SFP

N/A

Various

543,472

LaGrange Utilities (1)

Various

SFP

N/A

Various

117,063

Southwest Texas Electric Cooperative, Inc (1)

Various

SFP

N/A

Various

5,291

Coleman, City of (1)

Various

SFP

N/A

Various

67,192

Lamar County Electric Cooperative (1)

Various

SFP

N/A

Various

335,552

Taylor Electric Cooperative, Inc (1)

Various

SFP

N/A

Various

7,700

College Station, City of (1)

Various

SFP

N/A

Various

1,556,533

Lampasas, City of (1)

Various

SFP

N/A

Various

186,917

Tenaska Power Service Company (2)

ERCOT

SPP

N/A

Various

31,823

25,463

Conoco Phillips (1)

ERCOT

SPP

N/A

Various

29,008

42,915

Lexington, City of (1)

Various

SFP

N/A

Various

21,840

Texas-New Mexico Power Company (1)

Various

SFP

N/A

Various

14,607,295

Cross Texas Transmission (1)

Various

SFP

N/A

Various

40,642

Llano, City of (1)

Various

SFP

N/A

Various

79,241

Tex-La Electric Coop (1)

Various

SFP

N/A

Various

911,330

Cuero, City of (1)

Various

SFP

N/A

Various

164,322

Lockhart, City of (1)

Various

SFP

N/A

Various

200,197

TransAlta Energy Marketing (2)

Various

SFP

N/A

Various

9,176

1,216

Deep East Texas Electric Coop (1)

Various

SFP

N/A

Various

732,572

Lubbock, City of (1)

Various

SFP

N/A

Various

1,951,395

Twin Eagle Resource Mgmt (2)

Various

SFP

N/A

Various

20,596

50,396

Denton Municipal Electric (1)

Various

SFP

N/A

Various

4,253,046

Luling, City of (1)

Various

SFP

N/A

Various

98,878

Vitol, Inc (2)

Various

SFP

N/A

Various

7,541

9,649

Dynasty Power (2)

ERCOT

SPP

N/A

Various

37,692

46,291

Lyntegar Electric Coop (1)

Various

SFP

N/A

Various

3,538

Waelder, City of (1)

Various

SFP

N/A

Various

35,612

East Texas Electic Coop (1)

Various

SFP

N/A

Various

185,630

Macquarie Energy(2)

Various

SFP

N/A

Various

9,748

8,612

Weatherford, City of (1)

Various

SFP

N/A

Various

670,167

Electric Transmossion Texas (1)

Various

SFP

N/A

Various

13,547

MAG Energy Solutions (2)

Various

SFP

N/A

Various

9,762

3,831

Weimer, City of (1)

Various

SFP

N/A

Various

58,097

Endure Energy LLC (2)

ERCOT

SPP

N/A

Various

27,659

38,271

Mason, City of (1)

Various

SFP

N/A

Various

44,739

Westar Energy Inc. (2)

ERCOT

SPP

N/A

Various

69,152

85,220

Enel Trading North America, Inc (1)

Various

SFP

N/A

Various

1,310

1,099

Mercuria Energy America, Inc (1)

Various

SFP

N/A

Various

Western Farmers Electric Cooperative (1)

Various

SFP

N/A

Various

7,845

Farmersville, City of (1)

Various

SFP

N/A

Various

52,314

Moulton, City of (1)

Various

SFP

N/A

Various

17,955

Whitesboro, City of (1)

Various

SFP

N/A

Various

61,664

Fayette Electric Cooperative (1)

Various

SFP

N/A

Various

460,061

New Braunfels Utilities (1)

Various

SFP

N/A

Various

2,255,475

Yoakum, City of (1)

Various

SFP

N/A

Various

150,874

Flatonia, City of (1)

Various

SFP

N/A

Various

45,906

100

Oncor Electric Delivery (1)

Various

SFP

N/A

Various

191,563,921

TOTAL

512,611

497,493,443

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: PaymentByCompanyOrPublicAuthority

Transmission Cost of Service pursuant to Texas Substantive Rule 23.67

(2) High Voltage Direct Current Tie

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

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

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. Enter ""TOTAL"" in column (a) as the last line. Footnote entries and provide explanations following all required data.
			TRANSFER OF ENERGY		EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Line No.	NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	TransmissionOfElectricityByOthersEnergyReceived MegaWatt Hours Received (c)	TransmissionOfElectricityByOthersEnergyDelivered MegaWatt Hours Delivered (d)	DemandChargesTransmissionOfElectricityByOthers Demand Charges ($) (e)	EnergyChargesTransmissionOfElectricityByOthers Energy Charges ($) (f)	OtherChargesTransmissionOfElectricityByOthers Other Charges ($) (g)	ChargesForTransmissionOfElectricityByOthers Total Cost of Transmission ($) (h)
1	American Electric Power Service Corporation (1, 2, 3)	SFP					451,638	451,638
2	Austin Energy (2)	SFP					7,441,276	7,441,276
3	(a) Bandera Electric Cooperative (2)	SFP					488,172	488,172
4	Brazos Electric Cooperative (2)	SFP					11,610,417	11,610,417
5	Brownsville Public Utilities Board (2)	SFP					595,893	595,893
6	Bryan Texas Utilities (2)	SFP					2,251,308	2,251,308
7	Centerpoint Energy Houston Electric (2)	SFP					33,718,019	33,718,019
8	Cherokee County Electric Cooperative(2)	SFP					13,943	13,943
9	College Station City of (2)	SFP					339,453	339,453
10	Cross Texas Transmission (2, 4)	SFP					4,518,624	4,518,624
11	Deep East Texas Cooperative (2)	SFP					9,106	9,106
12	Denton Municipal Electric (2)	SFP					3,415,492	3,415,492
13	East Texas Electric Cooperative (2)	SFP					776,173	776,173
14	(b) Electric Transmission Tx, LLC (2)	SFP					20,251,286	20,251,286
15	Farmers Electric Coop (2)	SFP					47,858	47,858
16	Fayette Electric Cooperative (2)	SFP					1,659,090	1,659,090
17	Floresville Electric Power System (2)	SFP					46,144	46,144
18	Garland Power and Light (2)	SFP					5,283,972	5,283,972
19	GEUS (2)	SFP					255,418	255,418
20	Golden Spread Electric Cooperative (2)	SFP					216,549	216,549
21	Grayson-Collin Electric Cooperative (2)	SFP					107,746	107,746
22	Houston County Electric Cooperative (2)	SFP					7,877,117	7,877,117
23	Kerrville Public Utility Board (2)	SFP					15,289	15,289
24	Lamar County Electric Cooperative (2)	SFP					27,633	27,633
25	City of Lampasas (2)	SFP					844,378	844,378
26	Lone Star Transmission, LLC (2, 4)	SFP					5,926,930	5,926,930
27	Lower Colorado River Authority (LCRA) (2)	SFP					33,569,754	33,569,754
28	Lyntegar Electric Cooperative (2)	SFP					69,818	69,818
29	NRG Power Marketing, Inc (2)	SFP					15,972,092	15,972,092
30	Oncor Electric Delivery (2)	SFP					98,673,579	98,673,579
31	Pedernales Electric Cooperative, Inc (2)	SFP					395	395
32	Rayburn Country Electric Cooperative (2)	SFP					1,505,240	1,505,240
33	Rio Grande Electric Cooperative (2)	SFP					64,631	64,631
34	San Antonio City Public Service (2)	SFP					18,834,948	18,834,948
35	San Bernard Electric Cooperative (2)	SFP					350,594	350,594
36	San Miguel Electric Cooperative (2)	SFP					2,318,833	2,318,833
37	Sharyland Utilities, LP (2, 4)	SFP					1,437,662	1,437,662
38	South Texas Electric Cooperative (2)	SFP					20,581,123	20,581,123
39	Southwest Texas Electric Cooperative (2)	SFP					5,842	5,842
40	Texas Municipal Power Agency (2)	SFP					8,032,368	8,032,368
41	Texas-New Mexico Power Company (2)	SFP					8,376,950	8,376,950
42	Transmission Cost Recovery Factor (5)	SFP					26,077,714	26,077,714
43	Trinity Valley Electric Cooperative (2)	SFP					82,183	82,183
44	Wind Energy Transmission Texas(2,4)	SFP					9,714,267	9,714,267
45	Wood County Electric Cooperative (2)	SFP					45,979	45,979
	TOTAL		0	0	0	0	301,747,468	301,747,468

FOOTNOTE DATA

(a) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers

Respondent is an affiliated company of American Electric Power Service Corporation

(2) Transmission Cost of Service pursuant to Texas Substantive Rule 23.67

(3) High Voltage Direct Current (HVDC) East Tie facilities charge

(4) Transmission service surcharge

(5) Transmission Cost Recovery Factor Deferral

(b) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers

Electric Transmission Texas, LLC (ETT) is a joint venture of which American Electric Power is a 50% member.

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line No.	Description (a)	Amount (b)
1	IndustryAssociationDues Industry Association Dues	339,749
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	260,680
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	220,688
7	Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000	43,735
8	Chamber Of Commerce	419,580
9	Companies Billed to or from Respondent	36,689
46	MiscellaneousGeneralExpenses TOTAL	1,321,121

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

Depreciation and Amortization of Electric Plant (Account 403, 404, 405)
Report in section A for the year the amounts for: (b) Depreciation Expense (Account 403); (c) Depreciation Expense for Asset Retirement Costs (Account 403.1); (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric Plant (Account 405). Report in Section B the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to compute charges and whether any changes have been made in the basis or rates used from the preceding report year. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes to columns (c) through (g) from the complete report of the preceding year. Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount, account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant included in any sub-account used. In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the method of averaging used. For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification listed in column (a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type of mortality curve selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at the bottom of section C the amounts and nature of the provisions and the plant items to which related.
	A. Summary of Depreciation and Amortization Charges
Line No.	FunctionalClassificationAxis Functional Classification (a)	DepreciationExpenseExcludingAmortizationOfAcquisitionAdjustments Depreciation Expense (Account 403) (b)	DepreciationExpenseForAssetRetirementCostsExcludingAmortizationgOfAcquisitionAdjustments Depreciation Expense for Asset Retirement Costs (Account 403.1) (c)	AmortizationOfLimitedTermPlantOrProperty Amortization of Limited Term Electric Plant (Account 404) (d)	AmortizationOfOtherElectricPlant Amortization of Other Electric Plant (Acc 405) (e)	DepreciationAndAmortization Total (f)
1	Intangible Plant			33,865,744		33,865,744
2	Steam Production Plant	1,337				1,337
3	Nuclear Production Plant
4	Hydraulic Production Plant-Conventional
5	Hydraulic Production Plant-Pumped Storage
6	Other Production Plant
7	Transmission Plant	126,938,069				126,938,069
8	Distribution Plant	149,162,926				149,162,926
9	Regional Transmission and Market Operation
10	General Plant	17,626,910	58,482			17,685,393
11	Common Plant-Electric
12	TOTAL	293,726,568	58,482	33,865,744		327,650,795

B. Basis for Amortization Charges
Section A Line 1 Column D represents amortization of capitalized software development costs over a 5 year life and costs associated with the Oracle strategic partnership which are over a 10 year life.

	C. Factors Used in Estimating Depreciation Charges
Line No.	AccountNumberFactorsUsedInEstimatingDepreciationCharges Account No. (a)	DepreciablePlantBase Depreciable Plant Base (in Thousands) (b)	UtilityPlantEstimatedAverageServiceLife Estimated Avg. Service Life (c)	UtilityPlantNetSalvageValuePercentage Net Salvage (Percent) (d)	UtilityPlantAppliedDepreciationRate Applied Depr. Rates (Percent) (e)	MortalityCurveType Mortality Curve Type (f)	UtilityPlantWeightedAverageRemainingLife Average Remaining Life (g)
12	TRANSMISSION PLANT
13	TCC
14	350 (Rights)	106,715	75 years		1.2	R5
15	352	100,509	65 years	3	1.66	L1
16	353	1,587,037	51 years		2.03	L1
17	353.16	34,986	51 years		2.03	L1
18	354	46,570	70 years	10	1.62	R3
19	355	1,010,413	60 years	46	3	L0.5
20	356	573,561	65 years	30	2.18	L0
21	356.16	85,532	65 years	30	2.18	L0
22	357	21,467	65 years		1.58	R2
23	358	28,505	50 years		2.47	R3
24	358.16	419	50 years		2.47	R3
25	359	54	65 years		0.55	R4
26	TCC SUM	3,595,768
27	TNC
28	350 (Rights)	83,646	75 years		1.2	R5
29	352	88,626	65 years	3	1.66	L1
30	353-Dist & Trans	741,218	51 years		2.03	L1
31	353.16	19,189	51 years		2.03	L1
32	354	47,461	70 years	10	1.62	R3
33	355	758,466	60 years	46	3	L0.5
34	356	300,938	65 years	30	2.18	L0
35	356.16	60,866	65 years	30	2.18	L0
36	357	8,011	65 years		1.58	R2
37	358.16	522	50 years		2.47	R3
38	TNC SUM	2,108,943
39	TRANSMISSION SUM	5,704,711
40	DISTRIBUTION
41	TCC
42	360 (Rights)	2,420	60 years		1.64	R5

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

REGULATORY COMMISSION EXPENSES
Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts deferred in previous years. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization. List in columns (f), (g), and (h), expenses incurred during the year which were charged currently to income, plant, or other accounts. Minor items (less than $25,000) may be grouped.
						EXPENSES INCURRED DURING YEAR				AMORTIZED DURING YEAR
						CURRENTLY CHARGED TO
Line No.	RegulatoryCommissionDescription Description (Furnish name of regulatory commission or body the docket or case number and a description of the case) (a)	RegulatoryExpensesAssessedByRegulatoryCommission Assessed by Regulatory Commission (b)	RegulatoryExpensesOfUtility Expenses of Utility (c)	RegulatoryCommissionExpensesAmount Total Expenses for Current Year (d)	OtherRegulatoryAssetsRegulatoryCommissionExpenses Deferred in Account 182.3 at Beginning of Year (e)	NameOfDepartmentRegulatoryCommissionExpensesCharged Department (f)	AccountNumberRegulatoryCommissionExpensesCharged Account No. (g)	RegulatoryComissionExpensesIncurredAndCharged Amount (h)	RegulatoryCommissionExpensesDeferredToOtherRegulatoryAssets Deferred to Account 182.3 (i)	DeferredRegulatoryCommissionExpensesAmortizedInContraAccount Contra Account (j)	DeferredRegulatoryCommissionExpensesAmortized Amount (k)	OtherRegulatoryAssetsRegulatoryCommissionExpenses Deferred in Account 182.3 End of Year (l)
1	Expenses incurred relating to 2018 Texas Rate Case Support PUCT Docket No. 49494					Electric	928
2	Expenses incurred related to Distribution Cost Recovery Factor Filings - PUCT Docket No.s. 45787, 45788, 47015 and 48222		11,510	11,510		Electric	928	11,510
3	Expenses incurred in Interim Transmission Cost Cases and other Regulatory/Legislative actions relating to Transmission - PUCT Docket No Period 2020s 48507 and 481931		45,995	45,995		Electric	928	45,995
4	Expenses incurred related to managing Formula Rates for AEP's West Operating Companies and Transco's		131,416	131,416		Electric	928	131,416
5	Expenses incurred relating to Determination of System Restoration Costs - Hurricane Harvey - PUCT Docket No. 48577		7,703	7,703		Electric	928	7,703
6	Expenses incurred in Energy Efficiency Cost Recovery Factor filings		33,624	33,624		Electric	928	33,624
7	Minor Items (less than $25,000)		419,361	419,361		Electric	928	419,361	5,047			5,047
8	Texas AMI Final Filing		24,046	24,046		Electric	928	24,046
46	TOTAL		673,655	673,655				673,655	5,047			5,047

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D and D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(Identify recipient regardless of affiliation.) For any R, D and D work carried with others, show separately the respondent's cost for the year and cost chargeable to others (See definition of research, development, and demonstration in Uniform System of Accounts). Indicate in column (a) the applicable classification, as shown below: Classifications: Electric R, D and D Performed Internally: Generation hydroelectric Recreation fish and wildlife Other hydroelectric Fossil-fuel steam Internal combustion or gas turbine Nuclear Unconventional generation Siting and heat rejection Transmission Overhead Underground Distribution Regional Transmission and Market Operation Environment (other than equipment) Other (Classify and include items in excess of $50,000.) Total Cost Incurred Electric, R, D and D Performed Externally: Research Support to the electrical Research Council or the Electric Power Research Institute Research Support to Edison Electric Institute Research Support to Nuclear Power Groups Research Support to Others (Classify) Total Cost Incurred Include in column (c) all R, D and D items performed internally and in column (d) those items performed outside the company costing $50,000 or more, briefly describing the specific area of R, D and D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.). Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D and D activity. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year, listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e). Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research, Development, and Demonstration Expenditures, Outstanding at the end of the year. If costs have not been segregated for R, D and D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by ""Est."" Report separately research and related testing facilities operated by the respondent.
					AMOUNTS CHARGED IN CURRENT YEAR
Line No.	ResearchDevelopmentAndDemonstrationClassification Classification (a)	ResearchDevelopmentAndDemonstrationDescription Description (b)	ResearchDevelopmentAndDemonstrationCostsIncurredInternally Costs Incurred Internally Current Year (c)	ResearchDevelopmentAndDemonstrationCostsIncurredExternally Costs Incurred Externally Current Year (d)	AccountNumberForResearchDevelopmentAndDemonstrationCosts Amounts Charged In Current Year: Account (e)	ResearchDevelopmentAndDemonstrationCosts Amounts Charged In Current Year: Amount (f)	ResearchDevelopmentAndDemonstrationExpenditures Unamortized Accumulation (g)
1	A. (1)(e) Transmission and Distribution	Rolls-Royce 1MW SOFC Test & Eval
2	A. (2) Transmission	Transmission RD&D Program Mgmt	21,251		566	21,251
3		1 Items < $50,000	623		566	623
4	A. (3) Distribution	Distribution Program Management	11,952		588	11,952
5	A. (6) Other	Corporate Technology Prog Mgmt	60,382		566	60,382
6		2 Items < $50,000	46,229		588	46,229
7	A. (6)(f) Metering	Advanced Metering Equipment	2,338		588	2,338
8	A. (6)(g) Research General	DTC Walnut Test Facility	2,068		566	2,068
9			1,593		588	1,593
10		1 Items < $50,000	51		566	51
11	A. (7) Total Cost Incurred Intermally		146,487			146,487
12	B. Electric R&D External	1 Items < $50,000		43,388	566	43,388
13				69,959	588	69,959
14	B. (1) Electric Power Research Institute	1 Items < $50,000		491,433	566	491,433
15				190,912	588	190,912
16		Information Technology EPRI Annual Research Portfolio		16,444	566	16,444
17				69,496	588	69,496
18		Low Carbon Resource Initiative		92,617	566	92,617
19				71,368	588	71,368
20				367,624	566	367,624
21		2 Items < $50,000		433	588	433
22	B. (4) Research Support to Others	2 Items < $50,000		9	566	9
23	B. (5) Total Cost Incurred Externally			1,413,683		1,413,683
24		Total	146,487	1,413,683		1,560,170

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

DISTRIBUTION OF SALARIES AND WAGES
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation giving substantially correct results may be used.
Line No.	Classification (a)	Direct Payroll Distribution (b)	Allocation of Payroll Charged for Clearing Accounts (c)	Total (d)
1	SalariesAndWagesElectricAbstract Electric
2	SalariesAndWagesElectricOperationAbstract Operation
3	SalariesAndWagesElectricOperationProduction Production	269,547
4	SalariesAndWagesElectricOperationTransmission Transmission	3,421,227
5	SalariesAndWagesElectricOperationRegionalMarket Regional Market
6	SalariesAndWagesElectricOperationDistribution Distribution	16,568,736
7	SalariesAndWagesElectricOperationCustomerAccounts Customer Accounts	4,674,483
8	SalariesAndWagesElectricOperationCustomerServiceAndInformational Customer Service and Informational	2,480,143
9	SalariesAndWagesElectricOperationSales Sales
10	SalariesAndWagesElectricOperationAdministrativeAndGeneral Administrative and General	1,110,277
11	SalariesAndWagesElectricOperation TOTAL Operation (Enter Total of lines 3 thru 10)	27,985,319
12	SalariesAndWagesElectricMaintenanceAbstract Maintenance
13	SalariesAndWagesElectricMaintenanceProduction Production	1,535
14	SalariesAndWagesElectricMaintenanceTransmission Transmission	3,767,046
15	SalariesAndWagesElectricMaintenanceRegionalMarket Regional Market
16	SalariesAndWagesElectricMaintenanceDistribution Distribution	24,311,044
17	SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral Administrative and General	4,257,284
18	SalariesAndWagesElectricMaintenance TOTAL Maintenance (Total of lines 13 thru 17)	32,336,909
19	SalariesAndWagesElectricOperationAndMaintenanceAbstract Total Operation and Maintenance
20	SalariesAndWagesElectricProduction Production (Enter Total of lines 3 and 13)	268,012
21	SalariesAndWagesElectricTransmission Transmission (Enter Total of lines 4 and 14)	7,188,273
22	SalariesAndWagesElectricRegionalMarket Regional Market (Enter Total of Lines 5 and 15)
23	SalariesAndWagesElectricDistribution Distribution (Enter Total of lines 6 and 16)	40,879,780
24	SalariesAndWagesElectricCustomerAccounts Customer Accounts (Transcribe from line 7)	4,674,483
25	SalariesAndWagesElectricCustomerServiceAndInformational Customer Service and Informational (Transcribe from line 8)	2,480,143
26	SalariesAndWagesElectricSales Sales (Transcribe from line 9)
27	SalariesAndWagesElectricAdministrativeAndGeneral Administrative and General (Enter Total of lines 10 and 17)	5,367,561
28	SalariesAndWagesElectricOperationAndMaintenance TOTAL Oper. and Maint. (Total of lines 20 thru 27)	60,322,228	3,952,932	64,275,160
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)	60,322,228	3,952,932	64,275,160
66	SalariesAndWagesUtilityPlantAbstract Utility Plant
67	SalariesAndWagesUtilityPlantConstructionAbstract Construction (By Utility Departments)
68	SalariesAndWagesUtilityPlantConstructionElectricPlant Electric Plant	78,021,959	5,112,800	83,134,759
69	SalariesAndWagesUtilityPlantConstructionGasPlant Gas Plant
70	SalariesAndWagesUtilityPlantConstructionOther Other (provide details in footnote):
71	SalariesAndWagesUtilityPlantConstruction TOTAL Construction (Total of lines 68 thru 70)	78,021,959	5,112,800	83,134,759
72	SalariesAndWagesPlantRemovalAbstract Plant Removal (By Utility Departments)
73	SalariesAndWagesPlantRemovalElectricPlant Electric Plant	14,021,244	918,816	14,940,060
74	SalariesAndWagesPlantRemovalGasPlant Gas Plant
75	SalariesAndWagesPlantRemovalOther Other (provide details in footnote):
76	SalariesAndWagesPlantRemoval TOTAL Plant Removal (Total of lines 73 thru 75)	14,021,244	918,816	14,940,060
77	SalariesAndWagesOtherAccountsAbstract Other Accounts (Specify, provide details in footnote):
78	SalariesAndWagesOtherAccountsDescription Other Accounts (Specify, provide details in footnote):
79	SalariesAndWagesOtherAccountsDescription 152 - Fuel Stock Undistributed
80	SalariesAndWagesOtherAccountsDescription 163 - Stores Expense Undistributed	6,471,405	6,471,405
81	SalariesAndWagesOtherAccountsDescription 183 - Prelim Survey
82	SalariesAndWagesOtherAccountsDescription 184 - Clearing Accounts	3,513,143	3,513,143
83	SalariesAndWagesOtherAccountsDescription 185 - ODD Temporary Facilities	474,849		474,849
84	SalariesAndWagesOtherAccountsDescription 186 - Misc Deferred Debits	154,451		154,451
85	SalariesAndWagesOtherAccountsDescription 188 - Research & Development	2,527		2,527
86	SalariesAndWagesOtherAccountsDescription 426 - Political Activities	189,230		189,230
87	SalariesAndWagesOtherAccountsDescription
88	SalariesAndWagesOtherAccountsDescription
89	SalariesAndWagesOtherAccountsDescription
90	SalariesAndWagesOtherAccountsDescription
91	SalariesAndWagesOtherAccountsDescription
92	SalariesAndWagesOtherAccountsDescription
93	SalariesAndWagesOtherAccountsDescription
94	SalariesAndWagesOtherAccountsDescription
95	SalariesAndWagesOtherAccounts TOTAL Other Accounts	10,800,551	9,984,548	816,003
96	SalariesAndWagesGeneralExpense TOTAL SALARIES AND WAGES	163,165,982		163,165,982

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

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

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for Resale, for items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market for purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determining whether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively.
Line No.	Description of Item(s) (a)	Balance at End of Quarter 1 (b)	Balance at End of Quarter 2 (c)	Balance at End of Quarter 3 (d)	Balance at End of Year (e)
1	Energy
2	Net Purchases (Account 555)
2.1	Net Purchases (Account 555.1)
3	Net Sales (Account 447)
4	Transmission Rights
5	Ancillary Services
6	Other Items (list separately)
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:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

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

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

MONTHLY TRANSMISSION SYSTEM PEAK LOAD
Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. Report on Column (b) by month the transmission system's peak load. Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the definition of each statistical classification.
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Firm Network Service for Self (e)	Firm Network Service for Others (f)	Long-Term Firm Point-to-point Reservations (g)	Other Long-Term Firm Service (h)	Short-Term Firm Point-to-point Reservation (i)	Other Service (j)
	NAME OF SYSTEM: 0
1	January	(a) 0
2	February
3	March
4	Total for Quarter 1				0	0	0	0	0	0
5	April
6	May
7	June
8	Total for Quarter 2				0	0	0	0	0	0
9	July	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	0

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: MonthlyPeakLoadExcludingIsoAndRto

AEP Texas' transmission service is administered through a Regional Transmission Organization (RTO) and requested information is not available on an individual company basis.

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

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

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

2022-05-19

Year/Period of Report

End of:

2021

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

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

MONTHLY PEAKS AND OUTPUT
Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required information for each non- integrated system. Report in column (b) by month the system’s output in Megawatt hours for each month. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
Line No.	MonthAxis Month (a)	EnergyActivity Total Monthly Energy (b)	NonRequiredSalesForResaleEnergy Monthly Non-Requirement Sales for Resale & Associated Losses (c)	MonthlyPeakLoad Monthly Peak - Megawatts (d)	DayOfMonthlyPeak Monthly Peak - Day of Month (e)	HourOfMonthlyPeak Monthly Peak - Hour (f)
	NAME OF SYSTEM: 0
29	January
30	February
31	March
32	April
33	May
34	June
35	July
36	August
37	September
38	October
39	November
40	December
41	Total	0	0

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

Steam Electric Generating Plant Statistics

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

Line No.	Item (a)	Plant Name: 0
1	PlantKind Kind of Plant (Internal Comb, Gas Turb, Nuclear)
2	PlantConstructionType Type of Constr (Conventional, Outdoor, Boiler, etc)
3	YearPlantOriginallyConstructed Year Originally Constructed
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed
5	InstalledCapacityOfPlant Total Installed Cap (Max Gen Name Plate Ratings-MW)
6	NetPeakDemandOnPlant Net Peak Demand on Plant - MW (60 minutes)
7	PlantHoursConnectedToLoad Plant Hours Connected to Load
8	NetContinuousPlantCapability Net Continuous Plant Capability (Megawatts)
9	NetContinuousPlantCapabilityNotLimitedByCondenserWater When Not Limited by Condenser Water
10	NetContinuousPlantCapabilityLimitedByCondenserWater When Limited by Condenser Water
11	PlantAverageNumberOfEmployees Average Number of Employees
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh
13	CostOfLandAndLandRightsSteamProduction Cost of Plant: Land and Land Rights
14	CostOfStructuresAndImprovementsSteamProduction Structures and Improvements
15	CostOfEquipmentSteamProduction Equipment Costs
16	AssetRetirementCostsSteamProduction Asset Retirement Costs
17	CostOfPlant Total cost (total 13 thru 20)
18	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 17/5) Including
19	OperationSupervisionAndEngineeringExpense Production Expenses: Oper, Supv, & Engr
20	FuelSteamPowerGeneration Fuel
21	CoolantsAndWater Coolants and Water (Nuclear Plants Only)
22	SteamExpensesSteamPowerGeneration Steam Expenses
23	SteamFromOtherSources Steam From Other Sources
24	SteamTransferredCredit Steam Transferred (Cr)
25	ElectricExpensesSteamPowerGeneration Electric Expenses
26	MiscellaneousSteamPowerExpenses Misc Steam (or Nuclear) Power Expenses
27	RentsSteamPowerGeneration Rents
28	Allowances Allowances
29	MaintenanceSupervisionAndEngineeringSteamPowerGeneration Maintenance Supervision and Engineering
30	MaintenanceOfStructuresSteamPowerGeneration Maintenance of Structures
31	MaintenanceOfBoilerPlantSteamPowerGeneration Maintenance of Boiler (or reactor) Plant
32	MaintenanceOfElectricPlantSteamPowerGeneration Maintenance of Electric Plant
33	MaintenanceOfMiscellaneousSteamPlant Maintenance of Misc Steam (or Nuclear) Plant
34	PowerProductionExpensesSteamPower Total Production Expenses
35	ExpensesPerNetKilowattHour Expenses per Net kWh

35	FuelKindAxis Plant Name
36	FuelKind Fuel Kind
37	FuelUnit Fuel Unit
38	QuantityOfFuelBurned Quantity (Units) of Fuel Burned
39	FuelBurnedAverageHeatContent Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
40	AverageCostOfFuelPerUnitAsDelivered Avg Cost of Fuel/unit, as Delvd f.o.b. during year
41	AverageCostOfFuelPerUnitBurned Average Cost of Fuel per Unit Burned
42	AverageCostOfFuelBurnedPerMillionBritishThermalUnit Average Cost of Fuel Burned per Million BTU
43	AverageCostOfFuelBurnedPerKilowattHourNetGeneration Average Cost of Fuel Burned per kWh Net Gen
44	AverageBritishThermalUnitPerKilowattHourNetGeneration Average BTU per kWh Net Generation

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

Hydroelectric Generating Plant Statistics

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

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

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

Pumped Storage Generating Plant Statistics
Large plants and pumped storage plants of 10,000 Kw or more of installed capacity (name plate ratings). If any plant is leased, operating under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. Give project number. If net peak demand for 60 minutes is not available, give that which is available, specifying period. If a group of employees attends more than one generating plant, report on Line 8 the approximate average number of employees assignable to each plant. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power System Control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses." Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes. Include on Line 36 the cost of energy used in pumping into the storage reservoir. When this item cannot be accurately computed leave Lines 36, 37 and 38 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of energy from each station or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses per net MWH as reported herein for each source described. Group together stations and other resources which individually provide less than 10 percent of total pumping energy. If contracts are made with others to purchase power for pumping, give the supplier contract number, and date of contract.
Line No.	Item (a)	FERC Licensed Project No. 0 Plant Name: 0
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)
6	PlantHoursConnectedToLoad Plant Hours Connect to Load While Generating
7	NetContinuousPlantCapability Net Plant Capability (in megawatts)
8	PlantAverageNumberOfEmployees Average Number of Employees
9	NetGenerationExcludingPlantUse Generation, Exclusive of Plant Use - kWh
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
15	CostOfReservoirsDamsAndWaterwaysPumpedStoragePlant Reservoirs, Dams, and Waterways
16	CostOfWaterWheelsTurbinesAndGeneratorsPumpedStoragePlant Water Wheels, Turbines, and Generators
17	CostOfAccessoryElectricEquipmentPumpedStoragePlant Accessory Electric Equipment
18	CostOfMiscellaneousPowerPlantEquipmentPumpedStoragePlant Miscellaneous Powerplant Equipment
19	CostOfRoadsRailroadsAndBridgesPumpedStoragePlant Roads, Railroads, and Bridges
20	AssetRetirementCostsPumpedStoragePlant Asset Retirement Costs
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
25	WaterForPower Water for Power
26	PumpedStorageExpenses Pumped Storage Expenses
27	ElectricExpensesPumpedStoragePlant Electric Expenses
28	MiscellaneousPumpedStoragePowerGenerationExpenses Misc Pumped Storage Power generation Expenses
29	RentsPumpedStoragePlant Rents
30	MaintenanceSupervisionAndEngineeringPumpedStoragePlant Maintenance Supervision and Engineering
31	MaintenanceOfStructuresPumpedStoragePlant Maintenance of Structures
32	MaintenanceOfReservoirsDamsAndWaterwaysPumpedStoragePlant Maintenance of Reservoirs, Dams, and Waterways
33	MaintenanceOfElectricPlantPumpedStoragePlant Maintenance of Electric Plant
34	MaintenanceOfMiscellaneousPumpedStoragePlant Maintenance of Misc Pumped Storage Plant
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:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

GENERATING PLANT STATISTICS (Small Plants)
Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped storage plants of less than 10,000 Kw installed capacity (name plate rating). Designate any plant leased from others, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project, give project number in footnote. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11, Page 402. If net peak demand for 60 minutes is not available, give the which is available, specifying period. If any plant is equipped with combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
									Production Expenses
Line No.	PlantName Name of Plant (a)	YearPlantOriginallyConstructed Year Orig. Const. (b)	InstalledCapacityOfPlant Installed Capacity Name Plate Rating (MW) (c)	NetPeakDemandOnPlant Net Peak Demand MW (60 min) (d)	NetGenerationExcludingPlantUse Net Generation Excluding Plant Use (e)	CostOfPlant Cost of Plant (f)	PlantCostPerMw Plant Cost (Incl Asset Retire. Costs) Per MW (g)	OperatingExpensesExcludingFuel Operation Exc'l. Fuel (h)	FuelProductionExpenses Fuel Production Expenses (i)	MaintenanceProductionExpenses Maintenance Production Expenses (j)	FuelKind Kind of Fuel (k)	FuelCostPerMmbtus Fuel Costs (in cents (per Million Btu) (l)	GenerationType Generation Type (m)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

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

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

TRANSMISSION LINE STATISTICS
Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage. If required by a State commission to report individual lines for all voltages, do so but do not group totals for each voltage under 132 kilovolts. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report substation costs and expenses on this page. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder of the line. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with respect to such structures are included in the expenses reported for the line designated. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g). Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company, give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is an associated company. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how determined. Specify whether lessee is an associated company. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
	DESIGNATION		VOLTAGE (KV) - (Indicate where other than 60 cycle, 3 phase)			LENGTH (Pole miles) - (In the case of underground lines report circuit miles)				COST OF LINE (Include in column (j) Land, Land rights, and clearing right-of-way)			EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line No.	TransmissionLineStartPoint From	TransmissionLineEndPoint To	OperatingVoltageOfTransmissionLine Operating	DesignedVoltageOfTransmissionLine Designated	SupportingStructureOfTransmissionLineType Type of Supporting Structure	LengthForStandAloneTransmissionLines On Structure of Line Designated	LengthForTransmissionLinesAggregatedWithOtherStructures On Structures of Another Line	NumberOfTransmissionCircuits Number of Circuits	SizeOfConductorAndMaterial Size of Conductor and Material	CostOfLandAndLandRightsTransmissionLines Land	ConstructionAndOtherCostsTransmissionLines Construction Costs	OverallCostOfTransmissionLine Total Costs	OperatingExpensesOfTransmissionLine Operation Expenses	MaintenanceExpensesOfTransmissionLine Maintenance Expenses	RentExpensesOfTransmissionLine Rents	OverallExpensesOfTransmissionLine Total Expenses
	(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)	(l)	(m)	(n)	(o)	(p)
1	AEP TEXAS CENTRAL	AEP TEXAS CENTRAL
2	TL1083 NORTH EDINBURG	RIO HONDO	345.00	345.00	1	15.38	0	1	2x795.0 ACSR
3	TL1083 NORTH EDINBURG	RIO HONDO			2	22.92	0
4	TL1083 NORTH EDINBURG	RIO HONDO			1	0.94	0		2x1590 ACSR
5	TL1098 LA PALMA	RIO HONDO	345.00	345.00	1	0.17	0	1	795.0 ACSR
6	TL1098 LA PALMA	RIO HONDO			2	0.13	0	1	795.0 ACSR
7	TL3113A BLESSING	STP	345.00	345.00	2	13.23	0	1	2x795.0 ACSR
8	TL3131 STP	WA PARRISH	345.00	345.00	2	14.22	0	1	2x795.0 ACSR
9	TL5109 LON C HILL	CPSB TIE (SAN ANTONIO)	345.00	345.00	1	1.81	0	1	2x795.0 ACSR
10	TL5109 LON C HILL	CPSB TIE (SAN ANTONIO)	345.00	345.00	2	55.54	0		2x795.0 ACSR
11	TL5109 LON C HILL	CPSB TIE (SAN ANTONIO)	345.00	345.00	1	0.71	0	1	2X954 ACSR
12	TL5114 LON HILL	WHITEPOINT CKT #1	345.00	345.00	1	9.78	0	2	2x795.0 ACSR
13	TL5114 LON HILL	WHITEPOINT CKT #1	345.00	345.00	2	11.00	0	1	2x795.0 ACSR
14	TL5115 WHITEPOINT	STP	345.00	345.00	1	9.75	0	1	2x795.0 ACSR
15	TL5115 WHITEPOINT	STP			2	87.11	0	1	2x795.0 ACSR
16	TL5115 WHITEPOINT	STP			2	27.00	0	1	2x1025.4 ACCC
17	TL5115 WHITEPOINT	STP			1	1.24	0	1	2x954 ACSR
18	TL5138 AJO	RIO HONDO	345.00	345.00	1	1.00	0	1	2x1590.0 ACSR
19	TL5138 AJO	RIO HONDO	345.00	345.00	1	0.26	0	1	2x954 ACSS
20	TL5138 AJO	RIO HONDO			2	65.52	0		2x1026 ACCC
21	TL3143 Lon C Hill	Coleto Creek 345KV Line	345.00	345.00	1	20.97	0	1	2x795.0 ACSR
22	TL3143 Lon C Hill	Coleto Creek 345KV Line			2	59.02	0
23	TL5138A LON HILL	NELSON SHARPE	345.00	345.00	2	20.81	0	1	2x795.0 ACSR
24	TL5138B AJO	NELSON SHARPE	345.00	345.00	1	0.84	0	1	2x1590.0 ACSR
25	TL5138B AJO	NELSON SHARPE			2	36.20	0		2x795.0 ACSR
26	TL5138E LA PALMA	RIO HONDO CKT #2	345.00	345.00	2	9.75	0	1	2x795.0 ACSR
27	TL5145 LON HILL	NORTH EDINBURG	345.00	345.00	1	0.30	0	1	2x1026 ACCC
28	TL5145 LON HILL	NORTH EDINBURG	345.00	345.00	2	111.65	0	1	2x1026 ACCC
29	TL5271 CEBOLLA	LADEKIDDE 345KV TIE LINE	345.00	345.00	1	0.04	0	1	2x954 ACSS
30	TL5282 RIO HONDO	MAJADAS 345KV LINE	345.00	345.00	1	9.42	0	1	2x957 ACSR
31	TL5293 BONILLA	EL RAYO 345KV TIE LINE	345.00	345.00	1	0.04	0	1	2x954 ACSR
32	TL5294 Grissom	Cranell	345.00	345.00	1	0.02	0	1	2-954 ACSR
33	TL5325 BONILLA	EL TRUENO 345KV TIE LINE	345.00	345.00	1	0.04	0	1	2x954 ACSR
34	TL5327 Angstrom	SDI	345.00	345.00	1	0.95	0	1	2x954 ACSR
35	TL5337 Grissom	Blackjack Creek	345.00	345.00	1	0.02	0	1	2x954 ACSR
36	TL5360 Katoen	El Algodon	345.00	345.00	1	0.10	0	1	2x795 ACSR
37	TL3131 STP	HL&P CORRIDOR	345.00	345.00	2		19	5	2x795 ACSR
38	TL1001 BATES	GARZA	138.00	138.00	1	30.42	3	1	795.0 ACSR
39	TL1002A GARZA	ROMA TAP	138.00	138.00	1	16.39	2	1	795.0 ACSR
40	TL1002B FALCON SWITCHING	ROMA TAP	138.00	138.00	1	4.87	0	1	795.0 ACSR
41	TL1002C FALCON SWITCHING	FALCON DAM (US) CKT#1	138.00	138.00	2	4.50	0	1	4/0 ACSR
42	TL1004 BATES	NORTH EDINBURG CKT#1	138.00	138.00	1	22.17	0	1	1272.0 ACSR
43	TL1005 FALFURIAS	NORTH EDINBURG	138.00	138.00	1	37.80	0	1	795.0 ACSR
44	TL1006 JL BATES	SHARYLAND	138.00	138.00	1	0.31	0	1	1272.0 ACSS
45	TL1008 LA PALMA	WESMER	138.00	138.00	1	16.15	0	1	795.0 ACSR
46	TL1019 FRONTERA	NORTH MCALLEN	138.00	138.00	1	12.80	0	1	1272.0 ACSR
47	TL1019 FRONTERA	NORTH MCALLEN			1	0.33	0	2	1272.0 ACSR
48	TL1009A HARLINGEN SS	RIO HONDO	138.00	138.00	1	1.76	0	1	795.0 ACSR/AW
49	TL1009A HARLINGEN SS	RIO HONDO	138.00	138.00	2	12.16	0	1	795.0 ACSR/AW
50	TL1009B RAYMONDVILLE #2	RIO HONDO	138.00	138.00	2	23.89	0	1	795.0 ACSR
51	TL1010 Armstrong	Raymondville #2 138KV Line	138.00	138.00	2	32.00	0	1	795 ACSR
52	TL1011 FRONTERA	RIO GRANDE CITY	138.00	138.00	1	3.54	0	1	795.0 ACSR
53	TL1029B LA PALMA	STEWART ROAD	69.00	138.00	1		2	1	4/0 ACSR
54	TL1029B LA PALMA	STEWART ROAD			2	20.64	0		795.0 ACSS
55	TL5295 LA PALMA	CAVAZOS	69.00	138.00	1	0.36	0	1	795 ACSS/AW
56	TL1054 HARLINGEN SS	ACSR	138.00	138.00	2	1.71	0	1	795.0 ACSR
57	TL1059 SOUTHEAST EDINBURG	MVEC PHARR	138.00	138.00	1	1.63	0	1	795.0 ACSS
58	TL1060 POLK	SOUTH MCALLEN	138.00	138.00	1	2.71	0	1	795.0 ACSS
59	TL1061 HEC	NORTH EDINBURG CKT #1	138.00	138.00	1	1.06	0	1	2x795.0 ACSR
60	TL1062 HEC	WESLACO SS	138.00	138.00	1	4.40	0	1	795.0 ACSR
61	TL1070 PORT ISABEL	CAUSEWAY	138.00	138.00	1	6.70	0	1	795 ACSS
62	TL1071 PORT ISABEL	PORT ISABEL	138.00	138.00	1	2.39	0	1	336.0 ACSR
63	TL1071 Causeway	South Padre Island 138KV Line	138.00	138.00	1	4.50	0	1	795ACSS
64	TL1072 NORTH EDINBURG	DUKE #2	138.00	138.00	1	7.42	0	1	795.0 ACSS
65	TL1072A HEC EXTENSION	DUKE #2	138.00	138.00	1	0.80	0	2	795.0 ACSS
66	TL1073 Las Milpas (MVEC)	Weslaco Unit 138KV Line	138.00	138.00	1	0.15	0	1	795 ACSS
67	TL1073 Las Milpas (MVEC)	Weslaco Unit 138KV Line	138.00	138.00	2	14.66	0	1	477.0 ACSR
68	TL1073C SOUTH MCALLEN	STEWART ROAD	138.00	138.00	2	10.06	0	1	795.0 ACSR
69	TL1074B LA PALMA	LAURELES	138.00	138.00	1	9.40	0	1	795.0 ACSR
70	TL1074C LAURELES	PORT ISABEL	138.00	138.00	1	7.62	0	1	795.0 ACSR
71	TL1074C LAURELES	PORT ISABEL			2	6.87	0		795.0 ACSR
72	TL1075 LA PALMA	PUB LOMA ALTA	138.00	138.00	1	12.22	0	1	795.0 AAAC
73	TL1075 LA PALMA	PUB LOMA ALTA			2	10.00	0		795.0 ACSR
74	TL1075 LA PALMA	PUB LOMA ALTA			1	0.24	0		2-795 ACSS
75	TL1076 PUB (Loma Alta)	Carbide	138.00	138.00	1	1.00	0	1	795 ACSR
76	TL1076 PUB (Loma Alta)	Carbide	138.00	138.00	1	0.24	0	1	2-795 ACSS
77	TL1077 PORT ISABEL	UNION CARBIDE BROWNSVILLE	138.00	138.00	2	12.85	0	1	477.0 ACSR
78	TL1077 PORT ISABEL	UNION CARBIDE BROWNSVILLE					0		795.0 ACSR
79	TL1079 Wesmer	Weslaco Unit 138KV Line	138.00	138.00	1	5.32	0	1	477.0 AAC
80	TL1079 Wesmer	Weslaco Unit 138KV Line	138.00	138.00	1	0.11	0	1	795 ACSS
81	TL1080 LA PALMA	MILITARY HIGHWAY	138.00	138.00	1	2.03	0	1	795.0 ACSR
82	TL1080 LA PALMA	MILITARY HIGHWAY			2	19.01	0
83	TL1081 NORTH MCALLEN	SOUTH MCALLEN	138.00	138.00	1	4.71	0	1	795.0 ACSS
84	TL1082 PHARR (MVEC)	PHARR	138.00	138.00	1	3.61	0	1	795.0 ACSS
85	TL1084 POLK	SOUTH MCALLEN	138.00	138.00	1	3.66	0	1	795.0 ACSR
86	TL1085 PALMHURST TAP	SOUTH MCALLEN	138.00	138.00	1	1.70	0	1	1270.0 ACSR
87	TL1086A NORTH EDINBURG	MVG (CALPINE) GT1	138.00	138.00	1	0.18	0	1	1590.0 ACSR
88	TL1086B NORTH EDINBURG	MVG (CALPINE) GT2	138.00	138.00	1	0.18	0	1	1590.0 ACSR
89	TL1086C NORTH EDINBURG	MVG (CALPINE) ST1	138.00	138.00	1	0.17	0	1	1590.0 ACSR
90	TL1091 MILITARY HIGHWAY	UNION CARBIDE	138.00	138.00	1	4.75	0	1	795.0 ACSR
91	TL1092 NORTH EDINBURG	NORTH MCALLEN	138.00	138.00	1	9.60	0	2	795.0 ACSS
92	TL1093 NORTH MCALLEN	SOUTH MCALLEN	138.00	138.00	1	2.63	0	1	795.0 ACSS
93	TL1093 NORTH MCALLEN	SOUTH MCALLEN			2	0.65	0
94	TL1094 SOUTH MCCALLEN	LAS MILPAS (MVEC)	138.00	138.00	1	0.35	0	1	959 ACSS
95	TL1095 MILITARY HIGHWAY	CFE TIE	138.00	138.00	1	0.14	0	1	795.0 ACSR
96	TL1096 PORT ISABEL	PORT ISABEL	138.00	138.00	4	8.56	0	1	750.0 MCM CU
97	TL1097 LA PALMA	RIO HONDO	138.00	138.00	1	10.26	0	1	2x795.0 ACSS
98	TL1099 RIO HONDO	HARLINGEN SWITCHING STATION	138.00	138.00	1	0.18	0	1	795 ACSR
99	TL1117 FRONTERA	SOUTH MCALLEN	138.00	138.00	1	14.66	0	1	1272.0 ACSR
100	TL1117A AGAVE	SLU TAYLOR	138.00	138.00	1	0.15	0	1	1272.0 ACSR
101	TL1119 RIO GRANDE CITY	ROMA TAP	138.00	138.00	1	7.61	0	1	795.0 ACSR
102	TL1121 PHARR	POLK AVENUE	138.00	138.00	1	3.92	0	1	795.0 ACSS
103	TL1122 HEC	WESLACO SS	138.00	138.00	1	11.52	0	1	795.0 ACSR
104	TL3001 VICTORIA	MEDIO CREEK	138.00	138.00	2	46.56	0	1	336.4 ACSR
105	TL3001 VICTORIA	MEDIO CREEK	138.00	138.00	2	0.34	0	1	795.0 ACSR
106	TL3001 VICTORIA	MEDIO CREEK	138.00	138.00	2	0.35	0	1	4/0 ACSR
107	TL3146 MEDIO CREEK	LON C HILL	138.00	138.00	1	0.30	0	1	959.6 ACSS
108	TL3146 MEDIO CREEK	LON C HILL	138.00	138.00	1	24.70	0	1	336.4 ACSR
109	TL3146 MEDIO CREEK	LON C HILL	138.00	138.00	1	1.20	0	1	795 ACSR
110	TL3002 COLETO	KENEDY SS	138.00	138.00	2	45.14	0	1	795.0 ACSR
111	TL3003 KENEDY SS	CPSB V.H. BRAUNIG	138.00	138.00	2	13.71	0	1	477.0 ACSR
112	TL3004 KENEDY SS	PLEASANTON	138.00	138.00	2	40.14	0	1	266.8 ACSR
113	TL3005 VICTORIA	EDNA	138.00	138.00	2	21.57	0	1	795.0 ACSR
114	TL3006 EDNA	GANADO	138.00	138.00	2	9.72	0	1	795.0 ACSR
115	TL3007 GANADO	EL CAMPO	138.00	138.00	1	2.09	0	1	795.0 AAAC
116	TL3007 GANADO	EL CAMPO	138.00	138.00	2	17.93	0		795.0 ACSR
117	TL3008 EL CAMPO	LANE CITY PUMP	138.00	138.00	1	1.91	0	1	795.0 ACSR
118	TL3008 EL CAMPO	LANE CITY PUMP			2	15.49	0		795.0 ACC
119	TL3009 EL CAMPO	LANE CITY	138.00	138.00	2	1.41	0	1	795.0 ACSR
120	TL3010 LOLITA	VICTORIA	138.00	138.00	2	23.96	0	1	795.0 ACSR
121	TL3010 LOLITA	VICTORIA			3	4.36	0	2	795.0 ACSR
122	TL3011 BLESSING	LOLITA	138.00	138.00	2	22.51	0	1	795.0 ACSR
123	TL3012 BLESSING	LANE CITY	138.00	138.00	2	25.50	0	1	477.0 ACSR
124	TL3013 DUPONT SS	VICTORIA NORTH	138.00	138.00	3	7.77	0	2	795.0 ACSR
125	TL3014 BIG THREE	DUPONT SS	138.00	138.00	2	3.39	0	1	477.0 ACSR
126	TL3014 BIG THREE	DUPONT SS	138.00	138.00	2	0.62	0		795.0 ACSR
127	TL3015 FORMOSA	LOLITA	138.00	138.00	2	11.84	0	1	795.0 ACSR
128	TL3016 JOSLIN	ALCOA (1)	138.00	138.00	1	1.00	0	1	1590.0 ACSR
129	TL3017 JOSLIN	ALCOA (2)	138.00	138.00	3	0.09	1	1	1590.0 ACSR
130	TL3018 E S JOSLIN	UNION CARBIDE	138.00	138.00	3	0.43	0	2	795 ACSR & 4/0
131	TL3018 E S JOSLIN	UNION CARBIDE			3	14.64	0	1	795 ACSR
132	TL3018 E S JOSLIN	UNION CARBIDE			1	3.48	0	2	795 ACSR & 4/0
133	TL3018 E S JOSLIN	UNION CARBIDE			1	1.95	0	1	795 ACSR
134	TL3019 AIRCO	RINCON	138.00	138.00	2	51.30	0	1	477.0 ACSR
135	TL3021 DUPONT SS	DUPONT # 1	138.00	138.00	1	2.09	0	1	795.0 AAC
136	TL3022 CELANESE	CONOCO	138.00	138.00	1	0.06	0	1	795.0 ACSR
137	TL3026 DUPONT SS	DUPONT # 2	138.00	138.00	1	2.08	0	1	795.0 AAC
138	TL3027 DUPONT SS	VICTORIA SOUTH	138.00	138.00	3	7.65	0	1	795.0 ACSR
139	TL3034 STP Tap	Celanese	138.00	138.00	2	5.66	0	1	795 ACSR
140	TL3035 BAY CITY	CONOCO	138.00	138.00	1	1.20	0	1	795 ACSR
141	TL3035 BAY CITY	CONOCO			2	18.66	0	1	795 ACSR
142	TL3036 BAY CITY	LANE CITY	138.00	138.00	1	0.14	0	1	795.0 ACSR
143	TL3036 BAY CITY	LANE CITY			2	14.90	0
144	TL3044 SIGMOR	THREE RIVERS	138.00	138.00	2	0.42	0	1	959.6 ACSS
145	TL3044 SIGMOR	THREE RIVERS			2	3.17	0	1	795 ACSR/AW
146	TL3045 SIGMOR	STEC ORANGE GROVE	138.00	138.00	2	1.83	0	1	795.0 ACSR
147	TL3046 SIGMOR	STEC SAN MIGUEL	138.00	138.00	1	2.41	0	1	1/0 ACSR
148	TL3046 SIGMOR	STEC SAN MIGUEL			2	1.83	0		795.0 ACSR
149	TL3077 GOLIAD	BERCLAIR	69.00	138.00	1	0.02	0	1	477ACSR/AW
150	TL3084 VICTORIA	LCRA CUERO	138.00	138.00	1	4.04	0	1	795.0 ACSR
151	TL3084 VICTORIA	LCRA CUERO			2	13.82	0
152	TL3085 VICTORIA	LCRA CUERO	138.00	138.00	2	10.88	0	1	795.0 ACSR
153	TL3111 DUPONT SS	JOSLIN	138.00	138.00	2	17.36	0	1	795.0 ACSR
154	TL3111 DUPONT SS	JOSLIN			3	0.95	0
155	TL3112 DUPONT SS	JOSLIN	138.00	138.00	1	0.42	0	1	795.0 ACSR
156	TL3112 DUPONT SS	JOSLIN			2	13.68	0
157	TL3112 DUPONT SS	JOSLIN			3	0.18	0
158	TL3113B BLESSING	CELANESE BAY CITY	138.00	138.00	2	5.80	0	1	795.0 ACSR
159	TL3114 STP PUMP TAP	STP CONSTRUCTION	138.00	138.00	3	6.40	0	1	795.0 ACSR
160	TL3115 STP CONSTRUCTION	STP RIVER PUMP	138.00	138.00	1	4.36	0	1	4/0 ACSR
161	TL3118 COLETO CREEK NORTH	VICTORIA	138.00	138.00	2	11.10	0	1	1590.0 ACSR
162	TL3118 COLETO CREEK NORTH	VICTORIA			3	4.81	0
163	TL3119 COLETO CREEK (S)	VICTORIA	138.00	138.00	2	6.29	0	1	1590.0 ACSR
164	TL3119 COLETO CREEK (S)	VICTORIA	138.00	138.00	3	8.53	0	1	1590 ACSR
165	TL3119 COLETO CREEK (S)	VICTORIA	138.00	138.00	1	0.82	0	1	1590 ACSR
166	TL3122 CARBIDE SEADRIFT	VISTRON	138.00	138.00	2	6.13	0	1	477.0 ACSR
167	TL3122 CARBIDE SEADRIFT	VISTRON					0		795.0 ACSR
168	TL3124 FORMOSA	JOSLIN	138.00	138.00	2	0.69	0	1	795.0 ACSR
169	TL3124 FORMOSA	JOSLIN			3	1.84	0
170	TL3125 BIG THREE	VISTRON	138.00	138.00	2	10.52	0	1	477.0 ACSR
171	TL3125 BIG THREE	VISTRON					0		795.0 ACSR
172	TL3126 CELANESE	CONOCO	138.00	138.00	2	10.37	0	1	795.0 ACSR
173	TL3127 AIRCO	CARBIDE	138.00	138.00	2	1.43	0	1	477.0 ACSR
174	TL3139 CHASEFIELD TAP#2	CHASEFIELD	69.00	138.00	1	4.58	0	1	795.0 ACSR
175	TL3150 TULETA	COLETO CREEK	138.00	138.00	1	48.95	0	1	959.6 ACSS/TW
176	TL3151 VICTORIA	(STEC) FANNIN	69.00	138.00	3	15.32	0	1	1025 ACCC
177	TL5001 KINGSVILLE	LON HILL	138.00	138.00	1	37.29	0	1	795.0 ACSR
178	TL5001 KINGSVILLE	LON HILL	138.00	138.00	1	0.50	0	1	477 ACSR
179	TL5001 KINGSVILLE	LON HILL			2	29.07	0
180	TL5001 KINGSVILLE	LON HILL			3	6.87	0
181	TL5002 KINGSVILLE	KLEBERG	138.00	138.00	1	1.37	0	1	795.0 ACSR
182	TL5002 KINGSVILLE	KLEBERG			2	4.13	0
183	TL5003 Kleberg	Armstrong 138KV Line	138.00	138.00	1	5.54	0	1	795 ACSS
184	TL5003 Kleberg	Armstrong 138KV Line	138.00	138.00	2	9.83	0	1	795 ACSR
185	TL5003A KLEBERG	LOYOLA	138.00	138.00	2	13.50	0	1	795.0 ACSR
186	TL5003B LOYOLA	RAYMONDVILLE #2	138.00	138.00	2	26.06	0	1	795.0 ACSR
187	TL5004 LON HILL	STRATTON	138.00	138.00	2	27.80	0	1	795.0 ACSR
188	TL5005A DAVIS	NELSON SHARPE	138.00	138.00	2	10.10	0	1	795.0 ACSR
189	TL5005B CELANESE	NELSON SHARPE	138.00	138.00	2	10.18	0	1	795.0 ACSR
190	TL5006A FALFURIAS	KING RANCH GAS PLANT	138.00	138.00	2	20.48	0	1	795.0 ACSR
191	TL5006B KING RANCH GAS	STRATTON	138.00	138.00	2	15.76	0	1	795.0 ACSR
192	TL5007 HIGHWAY9	JAVELINA	138.00	138.00	1		2	1	1272.0 ACSR
193	TL5008 JAVELINA	WEST OSO	138.00	138.00	1	0.11	0	1	1272.0 ACSR
194	TL5008 JAVELINA	WEST OSO	138.00	138.00	3	0.04	0	1	1272.0 ACSR
195	TL5009 LON C HILL	WHITEPOINT	138.00	138.00	3	0.72	0	2	2x795.0 ACSR & 7
196	TL5009 LON C HILL	WHITEPOINT			3	0.33	0	1	2x795.0 ACSR
197	TL5009 LON C HILL	WHITEPOINT			1	15.21	0	1	2x795.0 ACSR
198	TL5009 LON C HILL	WHITEPOINT			1	2.90	0	2	2x795.0 ACSR & 7
199	TL5009 LON C HILL	WHITEPOINT			2	0.26	0
200	TL5010 GILA	UP RIVER ROAD	138.00	138.00	1	0.08	0	1	2-795 ACSR
201	TL5011 CITGO WEST	LON HILL	138.00	138.00	2	6.12	0	1	795.0 ACSR
202	TL5013 WESTSIDE	HOLLY	138.00	138.00	1	2.68	0	1	1590.0 ACSR
203	TL5013 WESTSIDE	HOLLY			1	1.28	0	2	1590.0 ACSR
204	TL5016 B M DAVIS	RODD FIELD	138.00	138.00	1	0.06	3	1	T2 795
205	TL5016 B M DAVIS	RODD FIELD			1	0.06	0	1	1590.0 ACSR
206	TL5097 HIGHWAY 9	NUECES BAY CKT #2	138.00	138.00	1		2	1	1272.0 ACSR
207	TL5017 NUECES BAY	CABLE TERMINAL #1	138.00	138.00	4	0.41	0	1	3500kcmil XLPE
208	TL5020 S.W. REFINING	MORRIS STREET	138.00	138.00	1	1.90	0	1	795.0 AAC
209	TL5020 S.W. REFINING	MORRIS STREET	138.00	138.00	1	0.71	0	1	795.0 ACSS/AW
210	TL5022 NUECES BAY	CABLE TERMINAL #2	138.00	138.00	4	0.41	0	1	3500kcmil XLPE
211	TL5127 CABLE #2	MORRIS STREET	138.00	138.00	1	3.80	0	1	1272.0 ACSR
212	TL5127 CABLE #2	MORRIS STREET	138.00	138.00	1	1.20	0	1	795.0 AAC
213	TL5021 MORRIS STREET	WESTSIDE	138.00	138.00	1	3.74	0	1	795.0 AAAC
214	TL5021 MORRIS STREET	WESTSIDE			1	1.39	0	2	795.0 ACSR/ 1590
215	TL5021 MORRIS STREET	WESTSIDE			1	0.14	0	1	477 ACSR
216	TL5025 La Pryor	Crystal City Extension	69.00	138.00	1	0.01	0	1	795 ACSS
217	TL5027 BARNEY DAVIS	PHARAOH	138.00	138.00	1	0.06	3	1	T2 795
218	TL5027 BARNEY DAVIS	PHARAOH			1	0.07	0	1	1590.0 ACSR
219	TL5029 ALICE	KINGSVILLE	138.00	138.00	2	22.48	0	1	477.0 ACSR
220	TL5029 ALICE	KINGSVILLE			—		0		795.0 ACSR
221	TL5031 LON HILL	CITY OF ROBSTOWN	69.00	138.00	1	0.74	0	1	795.0 ACSR
222	TL5032 PHARAOH	AIRLINE	138.00	138.00	1	1.43	0	2	1590.0 ACSR
223	TL5032 PHARAOH	AIRLINE			3	0.12	0	2	1590.0 ACSR
224	TL5032 PHARAOH	AIRLINE			1	0.33	0	1	1590.0 ACSR
225	TL5058 NUECES BAY	DUPONT SS	138.00	138.00	1	1.55	0	1	795.0 ACSR
226	TL5058 NUECES BAY	DUPONT SS	138.00	138.00	2	11.25	0	1	795.0 ACSR
227	TL5078 NUECES BAY	WHITEPOINT	138.00	138.00	1	0.86	0	1	795.0 ACSR
228	TL5078 NUECES BAY	WHITEPOINT	138.00	138.00	1	2.46	0	1	795.0 ACSR
229	TL5078 NUECES BAY	WHITEPOINT	138.00	138.00	1	2.46	0	1	2x795.0 ACSR
230	TL5078 NUECES BAY	WHITEPOINT	138.00	138.00	2	7.63	0	1	795.0 ACSR
231	TL5061 MIDWAY PUMP TAP	TAFT	69.00	138.00	1	3.04	0	1	795.0 ACSR
232	TL5061 MIDWAY PUMP TAP	TAFT	69.00	138.00	2	0.13	0	1	795.0 ACSR
233	TL5061 MIDWAY PUMP TAP	TAFT	69.00	138.00	1	0.80	0	2	795.0 ACSR
234	TL5062 TAFT	SINTON	69.00	138.00	1	9.40	0	1	795.0 ACSR
235	TL5062 TAFT	SINTON	69.00	138.00	2	0.12	0	1	795.0 ACSR
236	TL5072 DUPONT SWITCHING STA	INGLESIDE	138.00	138.00	1	1.00	0	1	795.0 ACSR
237	TL5072 DUPONT SWITCHING STA	INGLESIDE	138.00	138.00	2	2.18	0	1	795.0 ACSR
238	TL5072 DUPONT SWITCHING STA	INGLESIDE	138.00	138.00	3	0.06	0	1	795.0 ACSR
239	TL5073 DUPONT SS	RINCON CKT#1	138.00	138.00	1	0.19	0	1	795.0 ACSR
240	TL5073 DUPONT SS	RINCON CKT#1			3	10.50	0
241	TL5077 ARANSAS PASS	DUPONT SS	138.00	138.00	1	0.91	0	1	795.0 ACSR
242	TL5077 ARANSAS PASS	DUPONT SS			2	3.96	0
243	TL5079 DUPONT SW.	PORTLAND	138.00	138.00	1	7.62	0	1	2x795.0 ACSR
244	TL5079 DUPONT SW.	PORTLAND	138.00	138.00	4	0.10	0	1	2X795 ACSR/AW
245	TL5082 ARANSAS PASS	ROCKPORT	69.00	138.00	1	0.15	0	1	795ACSR/AW
246	TL5086 HIGHWAY 9	NUECES BAY	69.00	138.00	1	1.33	0	1	795.0 AAC
247	TL5087 HIGHWAY 9	ARCADIA	138.00	138.00	1	3.18	0	1	1590.0 ACSR
248	TL5087 HIGHWAY 9	ARCADIA	138.00	138.00	1	3.18	0	1	1272 ACSR
249	TL5087 HIGHWAY 9	ARCADIA	138.00	138.00	1	1.20	0	1	1590.0 ACSR
250	TL5099 AIRLINE	SOUTHSIDE (WEST)	138.00	138.00	1	2.54	0	1	795.0 AAC
251	TL5099 AIRLINE	SOUTHSIDE (WEST)	138.00	138.00	1	0.04	0		795.0 ACSR/AW
252	TL5100 LGE/GPP	REYNOLDS SHERWIN	138.00	138.00	1	0.50	0	1	795.0 ACSR
253	TL5101 HOLLY	SOUTHSIDE	138.00	138.00	1	0.31	0	1	795.0 ACSR
254	TL5101 HOLLY	SOUTHSIDE			2	1.49	0
255	TL5105 DUPONT SS	ICP CKT#1	138.00	138.00	1	0.63	0	1	795.0 AAC
256	TL5106 FALFURIAS	NORTH EDINBURG	138.00	138.00	1	25.10	0	1	795.0 ACSR
257	TL5111 B M DAVIS	AIRLINE (WEST)	138.00	138.00	1	2.87	0	1	T2 795
258	TL5111 B M DAVIS	AIRLINE (WEST)			1	2.77	0	2	1590.0 ACSR
259	TL5111 B M DAVIS	AIRLINE (WEST)			3	3.05	0	2	1590.0 ACSR
260	TL5111 B M DAVIS	AIRLINE (WEST)			1	1.59	0	1	1590.0 ACSR
261	TL5112 BARNEY DAVIS	AIRLINE (EAST)	138.00	138.00	1	2.82	0	1	T2 795
262	TL5112 BARNEY DAVIS	AIRLINE (EAST)			3	1.92	0	2	1590.0 ACSR
263	TL5112 BARNEY DAVIS	AIRLINE (EAST)			1	4.78	0	2	1590.0 ACSR
264	TL5112 BARNEY DAVIS	AIRLINE (EAST)			1	0.41	0	1	1590.0 ACSR
265	TL5116 WEST OSO	WESTSIDE	138.00	138.00	1	1.59	0	1	1272.0 ACSR
266	TL5119 CELANESE	KLEBERG	138.00	138.00	1	6.09	0	1	795.0 ACSR
267	TL5120A DUPONT SS	OXY CHEM PP2	138.00	138.00	1	1.95	0	1	795.0 ACSR
268	TL5120B AIR LIQUID TAP	AIR LIQUID	138.00	138.00	1	0.01	0	1	795.0 ACSR
269	TL5123 DUPONT SS	ICP CKT#2	138.00	138.00	1	1.45	0	1	795.0 ACSR
270	TL5124 DUPONT SS	ICP CKT#1	138.00	138.00	1	0.91	0	1	795.0 AAC
271	TL5125 WEIL TRACT	WESTSIDE	138.00	138.00	1	5.11	0	1	1590.0 ACSR
272	TL5126 EQUISTAR	LON HILL	138.00	138.00	1	3.54	0	1	795.0 ACSR
273	TL5128 NUECES BAY	CITGO	138.00	138.00	1	1.06	0	1	795.0 AAC
274	TL5128 NUECES BAY	CITGO			3	0.67	0		795.0 ACSR
275	TL5135 CITGO WEST	LON HILL	138.00	138.00	1	0.66	0	1	795.0 ACSR
276	TL5135 CITGO WEST	LON HILL			2	2.19	0
277	TL5136 DAVIS	NELSON SHARPE	138.00	138.00	2	12.24	0	1	795.0 ACSR
278	TL5140 CC PETRO CHEMICAL	MCKENZIE	138.00	138.00		11.50	0		477 ACSR
279	TL5140 CC PETRO CHEMICAL	MCKENZIE	138.00	138.00			0		795 ACSR
280	TL5141 AIRLINE	HOLLY	138.00	138.00	1	1.89	0	1	1590.0 ACSR
281	TL5141 AIRLINE	HOLLY			1	0.01	0	1	1590.0 ACSS
282	TL5141 AIRLINE	HOLLY			1	0.20	0	2	1949 ACCC
283	TL5142 RODD FIELD	CABANISS	138.00	138.00	1		0	1	1590.0 ACSR
284	TL5142 RODD FIELD	CABANISS			2	1.47	0	1	1590.0 ACSR
285	TL5142 RODD FIELD	CABANISS			2	2.80	0	1	1590 ACSS
286	TL5142 RODD FIELD	CABANISS			2	1.80	0	1	1949 ACCC
287	TL5143 CABANISS	WESTSIDE	138.00	138.00	2	1.19	0	1	1590 ACSS
288	TL5143 CABANISS	WESTSIDE	138.00	138.00	1	0.46	0	1	1590 ACCC
289	TL5149 LON C HILL	ORANGE GROVE	138.00	138.00	1	2.10	0	1	795.0 ACSR
290	TL5149 LON C HILL	ORANGE GROVE	138.00	138.00	2	11.48	0		1020 ACCC
291	TL5149 LON C HILL	ORANGE GROVE	138.00	138.00	3	11.27	0	2	1026 ACCC
292	TL5150 HOMEPORT	INGLESIDE	138.00	138.00	1	3.69	0	1	795.0 AAC
293	TL5150 HOMEPORT	INGLESIDE					0		795.0 ACSR
294	TL5155 DUPONT SWITCHING STA	GPP CIRCUIT 2	138.00	138.00	1	0.04	1	1	2x795.0 ACSR
295	TL5156 DUPONT SWITCHING STA	GPP CIRCUIT 1	138.00	138.00	1	1.29	0	1	2x795.0 ACSR
296	TL5160 WHITEPOINT	DUPONT Switching Station	138.00	138.00	3	7.48	0	2	795 ACSR
297	TL5160 WHITEPOINT	DUPONT Switching Station	138.00	138.00	1	0.24	0	2	795 ACSR
298	TL5160 WHITEPOINT	DUPONT Switching Station	138.00	138.00	1	0.22	0	2	1026 ACSR
299	TL5160 WHITEPOINT	DUPONT Switching Station	138.00	138.00	1	0.03	0	1	795 ACSR
300	TL5160 WHITEPOINT	DUPONT Switching Station	138.00	138.00	4	0.11	0	1	5000 SEGMENTAL OX
301	TL5165 RINCON	WHITEPOINT CKT #2	138.00	138.00	1	3.14	0	1	795.0 ACSR
302	TL5165 RINCON	WHITEPOINT CKT #2			2	4.56	0
303	TL5166 Whitepoint	Portland	138.00	138.00	1	2.79	0	1	2x795.0 ACSR/AW
304	TL5167 WHITEPOINT	DUPONT SW BUSS #2	138.00	138.00	1		0		1026 ACSR
305	TL5167 WHITEPOINT	DUPONT SW BUSS #2	138.00	138.00	3		0		795 ACSR
306	TL5167 WHITEPOINT	DUPONT SW BUSS #2	138.00	138.00	4	0.11	0	1	5000 SEGMENTAL OX
307	TL5178 JARDIN SUBSTATION	JARDIN SUBSTATION	138.00	138.00	1	0.03	0	1	795.0 ACSR
308	TL5179 LA PALMA	PALO ALTO (PUB)	138.00	138.00			0
309	TL5187 HECKER	EXTENSION #1	138.00	138.00	1	0.52	0	2	795.0 ACSS
310	TL5188 BUNSEN	EXTENSION	138.00	138.00	2	0.73	0	2	959.6 ACSS
311	TL5194 KEPLER	EF 90	69.00	138.00	3	0.04	0	1	477ACSR/AW
312	TL5195 TORTUGA	M&G 138kV EXTENSION	138.00	138.00	1	0.40	0	1	477 ACSR
313	TL5199 PHARR 138kV LOOP	M&G 138kV EXTENSION	138.00	138.00	1	2.20	0	2	959.6 ACSS/TW SUW
314	TL5201 HECKER	EXTENSION #2	138.00	138.00	1	0.53	0	2	795.0 ACSS
315	TL5202 HECKER	ALPINE	138.00	138.00	1	0.06	0	2	795.0 ACSR
316	TL5203 HECKER	CHENIERE (CUSTOMER STATION)	138.00	138.00	1	0.09	0	2	1590 ACSR Falcon
317	TL5206 MARCONI	SAN ROMAN	138.00	138.00	1	0.70	0	1	959ACSS/TW
318	TL5207 MELON CREEK EXTENSIO	SAN ROMAN	138.00	138.00	1	0.82	0	2	795 ACSS/AW
319	TL5208 LA PRYOR	UVALDE EXTENTION	69.00	138.00	1	0.06	0	1	795ACSR
320	TL5208 LA PRYOR	UVALDE EXTENTION	138.00	138.00	1	0.50	0	1	477.0 ACSR
321	TL5221 Crystal City	Carrizo Springs (operating at 69kV)	69.00	138.00	1	12.58	0	1	795 ACSS
322	TL5222 HARLINGEN SS	RAYMONDVILLE #2	69.00	138.00	1	23.47	0	1	959.6 ACSS
323	TL5225 BEEVILLE	SINTON 138KV LINE	138.00	138.00	1	0.10	0	1	959.5 ACSS
324	TL5226 JOSLIN POI (IPP)	SINTON 138KV LINE	138.00	138.00	1	0.03	0	1	795ACSR
325	TL5227 MELON CREEK 138kV TA	SINTON 138KV LINE	138.00	138.00	1	1.82	0	1	795 ACSS/AW
326	TL5229 JOURDANTON	PLEASANTON	69.00	138.00	1	4.70	0	1	795 ACSS
327	TL5230 ROCKPORT	FULTON #1	69.00	138.00	1	7.66	0	1	795 ACSS
328	TL5231 BISHOP	STRATTON	69.00	138.00	1	4.80	0	1	795 ACSS/AW
329	TL5231 BISHOP	STRATTON			2	0.03	0	1	795 ACSS/AW
330	TL5232 Alice	North Ella 138kV Line (operating at 69kV)	69.00	138.00	1	11.21	0	1	795 ACSS
331	TL5233 PREMONT	FALFURRIAS	69.00	138.00	1	12.22	0	1	795 ACSS
332	TL5233 PREMONT	FALFURRIAS			2	0.13	0	1	795 ACSS
333	TL5234 LA PRYOR	TURTLE CREEK	69.00	138.00	1	14.48	0	1	795 ACSS
334	TL5235 LA PRYOR	UVALDE	69.00	138.00	2	17.27	0	1	795ACSS
335	TL5236 REFUGIO	TATTON	138.00	138.00	1	21.70	0	1	795 ACSS/AW
336	TL5237 BANQUETE	STADIUM	69.00	138.00	1	17.64	0	1	795 ACSS
337	TL5238 CALALLEN STEC	BANQUETE	138.00	138.00	1	12.63	0	1	795 ACSS
338	TL5239 KNIPPA	SABINAL	69.00	138.00	1	2.51	0	1	795 ACSS
339	TL5240 UVALDE	KNIPPA	69.00	138.00	1	4.59	0	1	795 ACSS
340	TL5241 PALACIOS	BLESSING	69.00	138.00	1	9.65	0	1	795 ACSS/AW
341	TL5242 CARANCAHUA	PALACIOS	69.00	138.00	2	0.08	0	1	795 ACSS/AW
342	TL5242 CARANCAHUA	PALACIOS	69.00	138.00	1	13.40	0	1	795 ACSR/AW
343	TL5243 POINT COMFORT	CARANCAHUA	69.00	138.00	1	9.12	0	1	795 ACSS/AW
344	TL5247 COY CITY TAP	PLEASANTON	69.00	138.00	1	17.27	0	1	795 ACSS
345	TL5248 COY CITY	THREE RIVERS	69.00	138.00	1	22.97	0	1	795 ACSS
346	TL5249 SEAWALL	PORT ARANSAS	69.00	138.00	1	8.02	0	1	795 ACSS/AW
347	TL5249 SEAWALL	PORT ARANSAS			2	0.10	0	1	795 ACSS/AW
348	TL5249 SEAWALL	PORT ARANSAS			4	0.50	0	1	2-5000 CU XLPE
349	TL5250 Aransas Pass	Seawall (operating at 69kV)	69.00	138.00	1	3.10	0	1	795 ACSS
350	TL5251 GOLIAD	FANNIN	69.00	138.00	1	5.10	0	1	795 ACSS/AW
351	TL5253 HEARD TAP	REFUGIO	69.00	138.00	1	3.05	0	1	795 ACSS
352	TL5254 WOODSBORO	HEARD TAP	69.00	138.00	1	3.73	0	1	795 ACSS/AW
353	TL5255 BONNIEVIEW	WOODSBORO	69.00	138.00	1	5.80	0	1	795 ACSS/AW
354	TL5256 BONNIEVIEW	RINCON	69.00	138.00	1	12.60	0	1	795 ACSS/AW
355	TL5257 NORTH ELLA	PREMONT	138.00	138.00	1	10.34	0	1	795 ACSS
356	TL5258 PHARR STATCOM BUS TI	PREMONT	138.00	138.00	1	0.11	0	1	795 ACSS
357	TL5259 PHARR STATCOM BUS TI	PREMONT	138.00	138.00	1	0.18	0	1	795 ACSS
358	TL5260 RINCON	GREGORY	69.00	138.00	1	7.47	0	1	795 ACSS/AW
359	TL5262 CAMPWOOD	UVALDE	69.00	138.00	1	19.27	0	1	795 ACSS
360	TL5263 GREENLAKE	CARBIDE	69.00	138.00	1	2.22	0	1	795 ACSS/AW
361	TL5264 LA PALMA SVC BUS TIE	CARBIDE	138.00	138.00	1	0.11	0	1	795 ACSS
362	TL5265 LA PALMA SVC BUS TIE	CARBIDE	138.00	138.00	1	0.12	0	1	795 ACSS
363	TL5266 AIRLINE	NAVAL BASE TIE LINE	138.00	138.00	1	0.10	0	1	1590 ACSS
364	TL5267 Airline	Lunana	138.00	138.00	1	0.03	0	1	1590 ACSS
365	TL5268 Nelson Sharpe 345kV	Lunana	345.00	345.00	1	0.06	0	1	2X954 ACSR
366	TL5272 BUNSEN	TEXSTAR 138KV LINE	138.00	138.00	1	0.82	0	1	795 ACSS
367	TL5276 GIBBS SUBSTATION	GCGV #1 TIE LINE	138.00	138.00	2	0.04	0	1	795 AAC
368	TL5277 GIBBS SUBSTATION	GCGV #2 TIE LINE	138.00	138.00	2	0.04	0	1	795 AAC
369	TL5278 GIBBS SUBSTATION	GCGV #3 TIE LINE	138.00	138.00	2	0.02	0	1	795 AAC
370	TL5279 GIBBS SUBSTATION	GCGV #4 TIE LINE	138.00	138.00	2	0.02	0	1	795 AAC
371	TL5280 GODDARD	JARVIK (KARANKAWA I) TIE LI	345.00	345.00	1	0.02	0	1	2X954 ACSR/AW
372	TL5285 GIBBS EXTENSION	JARVIK (KARANKAWA I) TIE LI	138.00	138.00	1	0.92	0	2	2X795ACSS/AW
373	TL5286 PAVLOV EXTENSION	JARVIK (KARANKAWA I) TIE LI	138.00	138.00	1	0.65	0	2	795 ACSS
374	TL5287 Dupont SS	RUPLEY	138.00	138.00	1	0.04	0	1	795 ACSS
375	TL5289 VICTORIA	LEOPOLD	138.00	138.00	1	0.04	0	1	795 ACSS
376	TL5290 GODDARD	WELDER (KARANKAWA II) TIE L	345.00	345.00	1	0.02	0	1	2X954 ACSR/AW
377	TL5292 KELVIN	CHALUPA 138KV TIE LINE	138.00	138.00	1	0.04	0	1	795 ACSS
378	TL5304 GARZA	CONTINENTAL	69.00	138.00	1	0.06	0	1	795 ACSS
379	TL5305 Luna	Rayos Del Sol	138.00	138.00	1	0.10	0	1	795 ACSS
380	TL5306 Luna Extension	Rayos Del Sol	138.00	138.00	1	0.46	0	2	795 ACSS
381	TL5307 Esperanza Extension	Rayos Del Sol	138.00	138.00	1	0.60	0	2	795 ACSS
382	TL5313 Stewart Road 345kV	138kV Auto Trans Bus Tie No. 1	138.00	138.00	1	0.15	0	1	2-795 ACSS
383	TL5314 Stewart Road 345kV	138kV Auto Trans Bus Tie No. 2	138.00	138.00	1	0.15	0	1	2-795 ACSS
384	TL5316 Raymondsville #2	La Sara (STEC)	138.00	138.00	—	0.05	0	1	795 ACSR
385	TL5342 Blessing	Clemville Sw. (STEC)	69.00	138.00	1	10.78	0	1	795 ACSS
386	TL5344 WEAVER ROAD	GREEN LAKE 138KV LINE	69.00	138.00	1	0.30	0	1	4/0 ACSR
387	TL5346 ODEM	SINTON 138KV LINE	69.00	138.00	1	0.05	0	1	ACSS/AW
388	TL5364 Luna	Vancourt 138kV Tie Line	138.00	138.00	1	0.10	0	1	795 ACSS
389	TL7001 LAREDO	MILO ROAD	138.00	138.00	1	2.83	0	1	795.0 ACSR
390	TL7001 LAREDO	MILO ROAD	138.00	138.00	1	0.43	0	1	2x795.0 ACSR
391	TL7003 CONOCO TAP	CONOCO	138.00	138.00	2	4.80	0	1	4/0 ACSR
392	TL7005 GANSO	EAGLE PASS	138.00	138.00	1	0.41	0	1	795 ACSS
393	TL7005A EAGLE PASS	ESCONDIDO CKT#2	138.00	138.00	2	1.14	0	1	336.0 ACSR
394	TL7005B ESCONDIDO	HAMILTON ROAD	138.00	138.00	2	10.13	0	1	336.0 ACSR
395	TL7006 EAGLE PASS HYDRO	GANSO	138.00	138.00	1	0.64	0	1	795 ACSS
396	TL7006 EAGLE PASS HYDRO	GANSO	138.00	138.00	2	0.04	0	1	336.0 ACSR
397	TL7007 Maverick	Ganso	138.00	138.00	2	1.87	0	1	336.0 ACSR
398	TL7007 Maverick	GANSO	138.00	138.00	1	0.46	0	1	795 ACSS
399	TL7008 HAMILTON ROAD PST	SONORA	138.00	138.00	2	66.85	0	1	477.0 ACSR
400	TL7008 HAMILTON ROAD PST	SONORA	138.00	138.00	1	0.30	0	1	959.6 ACSS/TW
401	TL7009 ASHERTON	WEST BATESVILLE	138.00	138.00	2	36.09	0	1	336.0 ACSR
402	TL7010 PLEASANTON	CPSB LEON CREEK	138.00	138.00	2	15.40	0	1	1020.0 ACCC/TW
403	TL7011 PLEASANTON	BIGFOOT	138.00	138.00	2	29.83	0	1	336.4 ACSR
404	TL 7012 MOORE	UVALDE	138.00	138.00	1	0.04	0	1	795 ACSS
405	TL 7012 MOORE	UVALDE	138.00	138.00	1	0.15	0	1	336 ACSR
406	TL7012A MOORE	MEC DOWNIE	138.00	138.00	2	41.03	0	1	336.4 ACSR
407	TL7012B UVALDE	MEC DOWNIE	138.00	138.00	2	9.34	0	1	336.4 ACSR
408	TL7016 FALFURRIAS	LOBO	138.00	138.00	1	26.96	0	1	2x795.0 ACSS
409	TL7016 FALFURRIAS	LOBO					0		795.0 ACSR
410	TL7017 BRUNI	CRESTONIO	138.00	138.00	1	14.80	0	1	795.0 ACSR
411	TL7018 LAREDO PLANT	DEL MAR	138.00	138.00	1	2.67	0	1	795.0 ACSR/AW
412	TL7019 ZAPATA	RANDADO	138.00	138.00	2	22.20	0	1	4/0 ACSR
413	TL7020A FALCON SWITCHING	FALCON DAM (US) CKT#2	138.00	138.00	2	4.50	0	1	4/0 ACSR
414	TL7020B FALCON SWITCHING	ZAPATA	138.00	138.00	1	25.86	4	1	795.0 ACSR
415	TL7021C LAREDO POWER PLANT	LAREDO VFT SOUTH	138.00	138.00	2	0.24	0	1	795.0 ACSR
416	TL7025 HEIGHTS	LAREDO CKT #1	138.00	138.00	1	4.40	0	1	795.0 AAAC
417	TL7025B HEIGHTS	LAREDO CKT #2	138.00	138.00	1	5.19	0	1	795.0 AAAC
418	TL7026 FREER	LOBO	69.00	138.00	1	1.09	0	1	2x795.0 ACSS
419	TL7026 FREER	LOBO			2	48.38	0		4/0 ACSR
420	TL7030 ENCINAL	COTULLA	138.00	138.00	1	29.05	0	1	795.0 ACSR
421	TL7030 ENCINAL	COTULLA			1	0.05	0	1	795 ACSS
422	TL7046 ASHERTON	DILLEY SS	138.00	138.00	2	15.98	0	1	795.0 ACSR
423	TL7047 ASHERTON	DILLEY SS	138.00	138.00	2	21.80	0	1	795.0 ACSR
424	TL7048 COTULLA	DILLEY SS	138.00	138.00	1	16.15	1	1	795.0 ACSR
425	TL7065 HAMILTON ROAD	PICACHO CKT#1 138KV LINE	138.00	138.00	1	8.81	0	1	795 ACSS
426	TL7066 PICACHO	AMISTAD HYDRO	138.00	138.00	2	6.40	0	1	4/0 ACSR
427	TL7067 HAMILTON ROAD	PICACHO CKT#2	138.00	138.00	1	1.45	0	1	4/0 ACSR
428	TL7067 HAMILTON ROAD	PICACHO CKT#2			2	1.07	0
429	TL7068 HAMILTON ROAD	PICACHO CKT#2	138.00	138.00	1	1.29	0	1	4/0 ACSR
430	TL7068 HAMILTON ROAD	PICACHO CKT#2			2	1.53	0
431	TL7069 HAMILTON ROAD	PICACHO CKT#2	138.00	138.00	1	0.44	0	1	4/0 ACSR
432	TL7069 HAMILTON ROAD	PICACHO CKT#2			2	2.65	0
433	TL7079 BIGFOOT	MOORE	138.00	138.00	2	6.06	0	1	336.4 ACSR
434	TL7081 EAGLE PASS	CFE PIEDRAS NEGRAS	138.00	138.00	1	1.33	0	1	477.0 ACSR
435	TL7082 ESCONDIDO	HAMILTON ROAD	138.00	138.00	2	41.21	0	1	336.0 ACSR
436	TL7086 UVALDE	WEST BATESVILLE	138.00	138.00	2	20.61	0	1	336.0 ACSR
437	TL7087 WEST BATESVILLE	MEC BATESVILLE	138.00	138.00	2	9.36	0	1	795.0 ACSR
438	TL7088 DILLEY SS	STEC SAN MIGUEL	138.00	138.00	1	47.54	0	1	795.0 ACSR
439	TL7088 DILLEY SS	STEC SAN MIGUEL			2		0
440	TL7091 PICACHO	AMISTAD HYDRO	138.00	138.00	1	1.91	0	1	336.0 ACSR
441	TL7092B EAGLE PASS	ESCONDIDO CKT#1	138.00	138.00	1	0.32	0	1	4/0 ACSR
442	TL7092B EAGLE PASS	ESCONDIDO CKT#1			2	1.13	0		795.0 ACSR
443	TL7102 RIO BRAVO	ZAPATA	138.00	138.00	1	27.48	3	1	795 ACSR
444	TL7102 RIO BRAVO	ZAPATA			1	0.23	0	1	4/0 ACSR
445	TL7105 WORMSER	RIO BRAVO	138.00	138.00	1	0.46	0	1	795.0 ACSR
446	TL7111 UNIVERSITY	WORMSER	138.00	138.00	1	1.74	0	1	795 ACSR
447	TL7111 UNIVERSITY	WORMSER			1	2.68	0	2	795 ACSR
448	TL7114 ENCINAL	WORMSER	138.00	138.00	1	40.77	0	1	795 ACSR
449	TL7114 ENCINAL	WORMSER			1	8.43	0	2	795 ACSR
450	TL7114 ENCINAL	WORMSER			1	0.27	0	1	795 ACSR/AW
451	TL7115B UNIVERSITY	WORMSER	138.00	138.00	1	9.99	0	1	795.0 ACSR
452	TL7117 ASHERTON	NORTH LAREDO	138.00	138.00	1	6.95	0	1	366.4 ACSR
453	TL7117 ASHERTON	NORTH LAREDO			2	56.69	0		795.0 ACSR
454	TL7123 SIERRA VISTA	WORMSER	138.00	138.00	1	1.11	0	1	795.0 ACSR
455	TL7123 SIERRA VISTA	WORMSER	138.00	138.00	1	1.76	0	2	795.0 ACSR
456	TL7124 EL GATO	GOOLIE/SOUIX RD	138.00	138.00	1	5.30	0	1	795.0 ACSS
457	TL7125 SOUTH MCALLEN	STEWART ROAD	138.00	138.00	1	3.70	0	1	1590 ACSS
458	TL7125 SOUTH MCALLEN	STEWART ROAD			1	2.14	0	2	795.0 ACSS
459	TL7125 SOUTH MCALLEN	STEWART ROAD	138.00	138.00	1	5.96	0	1	795.0 ACSS
460	TL7138 PILONCILLO	PRANCH #1	138.00	138.00	1	0.06	0	1	795 ACSR
461	TL7141 BRACKETVILLE	BUS TIE #1	138.00	138.00	1	0.11	0	1	795 ACSS
462	TL7144 ASHERTON	CARRIZO SPRINGS	69.00	138.00	1	8.36	0	1	959.6ACSS/TW
463	TL5224 BRACKETVILLE	BUS TIE #2	138.00	138.00	1	0.13	0	1	795 ACSS
464	TL5185 KENEDY SWITCHING STA	TULETA	138.00	138.00	1	19.33	0	2	959 ACSR/TW
465	TL5180 KENEDY SWITCHING STA	PETTUS	138.00	138.00	1	19.33	0	2	959 ACSR/TW
466	TL5261 BRACKETTVILLE	ESCONDIDO	138.00	138.00			0
467	TL5209 BONILLA	LADEKIDDE	345.00	345.00			0
468	TL5264 LA PALMA SVC	138KV BUS TIE #1	138.00	138.00			0
469	TL5265 LA PALMA SVC	138KV BUS TIE #2	138.00	138.00			0
470	69 KV for AEPTC	69 KV for AEPTC	69.00	69.00	1,2&4	843.70	47
471	AEP TEXAS NORTH	AEP TEXAS NORTH
472	TL125A ABILENE MULBERRY	BLUFF CREEK SS	345.00	345.00	2	26.50	0	1	2x795.0 ACSR
473	TL125B BLUFF CREEK SS	SAN ANGELO RED CREEK	345.00	345.00	2	49.56	0	1	2x795.0 ACSR
474	TL126 Mulberry Creek	Oklaunion	345.00	345.00	1	0.22	0	1	2-795 ACSR
475	TL126 Mulberry Creek	Oklaunion	345.00	345.00	2	115.65	0	1	2x795 ACSR
476	TL131 OKLAUNION	TU FISHER ROAD	345.00	345.00	2	28.81	0	1	2x795.0 ACSR
477	TL131 OKLAUNION	TU FISHER ROAD	345.00	345.00	1	1.60	0	1	2x795.0 ACSR
478	TL324 OKLAUNION DC TIE	DC TERMINAL NORTH (SPP)	345.00	345.00	1	0.02	0	1	1926.9KCM ACSR
479	TL325 OKLAUNION DC TIE	DC TERMINAL SOUTH (ERC)	345.00	345.00	1	0.02	0	1	1926.9KCM ACSR
480	TL407 SOLSTICE	BAKERSFIELD	345.00	345.00	3	35.50	0	1	2-1590 ACSS
481	TL423 SOLSTICE	SAND LAKE (ONCOR)	345.00	345.00	3	22.60	0	2	2-1590 ACSS
482	TL467 Perigee	Apogee	345.00	345.00	1	0.04	0	1	2-795 ACSR
483	TL001 ABILENE SOUTH	PUTNAM	138.00	138.00	1	3.13	0	1	4/0 ACSR
484	TL001 ABILENE SOUTH	PUTNAM			2	32.16	0		477.0 ACSR
485	TL028 ABILENE NORTHWEST	ANSON	69.00	138.00	1	1.63	0	1	795 ACSS/AW
486	TL031 SANTA ANNA	BROWNWOOD	138.00	138.00	1	7.29	0	1	795.0 ACSR
487	TL033 EDEN	YELLOWJACKET	69.00	138.00	1	0.11	0	1	795 ACSS
488	TL038 San Angelo	Sterling City (Interconnect TESCo) - Tmgren 69KV Line	69.00	138.00	1	0.15	0	1	795 ACSS
489	TL048 MCCAMEY - MCELROY	CRANE GULF 1&2	69.00	138.00	1	0.32	0	1	795 ACSS
490	TL050 RIO PECOS	FORT STOCKTON	138.00	138.00	2	35.39	0	1	477.0 ACSR
491	TL050 RIO PECOS	FORT STOCKTON	138.00	138.00	1	0.13	0	1	795.0 ACSS
492	TL051 EAST MUNDAY	PADUCAH CLARE STREET	138.00	138.00	1	3.20	0	1	477.0 ACSR
493	TL051 EAST MUNDAY	PADUCAH CLARE STREET			2	59.08	0
494	TL051 EAST MUNDAY	PADUCAH CLARE STREET	138.00	138.00	1	0.40	0	1	T2-795.0 ACSR
495	TL064A EAST MUNDAY	LAKE PAULINE	138.00	138.00	2	56.97	0	1	2x4/0 ACSR
496	TL064B EAST MUNDAY	PAINT CREEK WEST#1	138.00	138.00	2	25.96	0	1	397.0 ACSR
497	TL066A FORT PHANTOM	PAINT CREEK	138.00	138.00	2	38.73	0	1	1272.0 AAC
498	TL066A FORT PHANTOM	PAINT CREEK			3	0.48	0		477.0 ACSR
499	TL066B CALIFORNIA CREEK TAP	CALIFORNIA CREEK	138.00	138.00	2	0.02	0	1	4/0 ACSR
500	TL070 ABILENE NORTHWEST	OAK CREEK 138KV LINE	138.00	138.00	2	47.01	0	1	397.0 ACSR
501	TL070 ABILENE NORTHWEST	OAK CREEK 138KV LINE			2	5.21	0	1	795.0 ACSR
502	TL072 ABILENE NORTHWEST	PAINT CREEK	138.00	138.00	2	43.94	0	1	477.0 ACSR
503	TL072 ABILENE NORTHWEST	PAINT CREEK	138.00	138.00	1	0.28	0	1	477.0 ACSR
504	TL077 BALLINGER	OAK CREEK	138.00	138.00	2	30.85	0	1	397.0 ACSR
505	TL077 BALLINGER	OAK CREEK			—		0		477.0 ACSR
506	TL079A NICOLE	SAN ANGELO RED CREEK	138.00	138.00	1	3.21	0	2	2x795.0 ACSS
507	TL079A NICOLE	SAN ANGELO RED CREEK			2	33.77	0		397.0 ACSR
508	TL079A NICOLE	SAN ANGELO RED CREEK			—		0		477.0 ACSR
509	TL079B NORTH SAN ANGELO	SAN ANGELO RED CREEK	138.00	138.00	1	0.64	0	1	795.0 ACSR
510	TL079B NORTH SAN ANGELO	SAN ANGELO RED CREEK			2	8.96	0
511	TL079C SAN ANGELO CONCHO	SAN ANGELO RED CREEK	138.00	138.00	1	2.07	0	1	795.0 ACSR
512	TL079C SAN ANGELO CONCHO	SAN ANGELO RED CREEK			2	7.66	0
513	TL080 ALPINE	FORT STOCKTON	69.00	138.00	1	0.15	0	1	477ACSR
514	TL082 ABILENE SOUTH	BLUFF CREEK	138.00	138.00	2	17.60	0	1	1020.0 ACCC/TW
515	TL082 ABILENE SOUTH	BLUFF CREEK	138.00	138.00	1	2.20	0	2	2x795.0 ACSS
516	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	1	4.67	0	1	795.0 ACSR
517	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	2	4.70	0	1	795 ACSR
518	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	1	0.55	0	1	795.0 ACSR
519	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	2	2.44	0	1	795 ACSR
520	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	1	0.14	0	1	795 ACSS
521	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	3	0.50	0	1	1272.0 AAC
522	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	3	0.50	0	1	1272.0 ACSR
523	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	1	0.10	0	1	1272.0 AAC
524	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	2	5.50	0	1	1272 AAC
525	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	2	8.50	0	1	2x795 ACSR
526	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	3	0.53	0	1	1272 AAC
527	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	3	0.53	0	1	1272 ACSR
528	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	2	0.54	0	1	1272 ACSS
529	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	2	8.65	0	1	2x477 ACSR
530	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	1	2.10	0	1	795 ACSR
531	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	3	0.21	0	1	2x477 ACSR
532	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	2	2.78	0	1	795 ACSR
533	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	2	3.81	0	2	795 ACSR
534	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	2	5.67	0	1	1272 ACSR
535	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	1	0.16	0	1	1272.0 ACSR
536	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	2	3.30	0	1	(2) 795.0 ACSR
537	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	2	3.30	0	1	477 ACSR
538	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	1	0.11	0		795 ACSS
539	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	1	3.60	0	1	795.0 ACSR
540	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	2	1.00	0	1	795 ACSR
541	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	2	4.80	0	1	795 ACSR
542	TL083 ABILENE 138KV LOOP	TAYLOR	138.00	138.00	1	0.95	0		795.0 ACSR
543	TL084A SAN ANGELO CONCHO	SAN ANGELO POWER STATION	138.00	138.00	2	5.93	0	1	477.0 ACSR
544	TL084A SAN ANGELO CONCHO	SAN ANGELO POWER STATION			3	0.16	0
545	TL084A SAN ANGELO CONCHO	SAN ANGELO POWER STATION			1	0.12	0		1590 ACSR
546	TL084B SOUTH ANGELO TAP	SOUTH ANGELO	138.00	138.00	3	1.00	0	1	4/0 ACSR
547	TL085 SAN ANGELO	BIG LAKE	138.00	138.00	2	54.90	0	1	477.0 ACSR
548	TL085 SAN ANGELO	BIG LAKE	138.00	138.00	1	0.02	0	1	795.0 ACSR
549	TL086 BIG LAKE	N MCCAMEY	138.00	138.00	2	36.23	0	1	477.0 ACSR
550	TL086 BIG LAKE	N MCCAMEY	138.00	138.00	2	10.30	0	1	956.6 ACSS
551	TL086 BIG LAKE	N MCCAMEY	138.00	138.00	1	0.39	0	1	795 ACSS
552	TL086 BIG LAKE	N MCCAMEY	138.00	138.00	2	0.09	0	1	795.0 ACSS
553	TL087 LAKE PAULINE	VERNON CKT #2	138.00	138.00	2	23.44	0	1	477.0 ACSR
554	TL088A SAN ANGELO POWER	SAN ANGELO RED CREEK	138.00	138.00	1	1.29	0	1	477.0 ACSR
555	TL088A SAN ANGELO POWER	SAN ANGELO RED CREEK			2	17.33	0
556	TL088B BALLINGER	SAN ANGELO RED CREEK	138.00	138.00	1	3.07	0	1	477.0 ACSR
557	TL088B BALLINGER	SAN ANGELO RED CREEK			2	29.48	0
558	TL088 San Angelo Power	Red Creek	138.00	138.00	2	18.35	0	1	477 ACSR
559	TL089 SAN ANGELO	VAL VERDE	138.00	138.00	2	21.44	0	1	477.0 ACSR
560	TL089 SAN ANGELO	VAL VERDE	138.00	138.00	1	0.55	0	1	477.0 ACSR
561	TL089A ELDORADO LIVE OAK	SAN ANGELO POWER STATION	138.00	138.00	2	38.23	0	1	477.0 ACSR
562	TL089B ELDORADO LIVE OAK	SONORA CKT#2	138.00	138.00	2	22.07	0	1	477.0 ACSR
563	TL090 ASPERMONT	PAINT CREEK	138.00	138.00	2	39.74	0	1	477.0 ACSR
564	TL092 RIO PECOS	CRANE	138.00	138.00	2	22.29	0	1	636.0 ACSR
565	TL092 RIO PECOS	CRANE	138.00	138.00	1	0.81	0	1	2x795.0 ACSR
566	TL092 RIO PECOS	CRANE			1	0.21	0		636 ACSR
567	TL092B TEXAS NEW MEXICO TAP	CRANE TAP #2	69.00	138.00	1	0.10	0	1	4/0 ACSR
568	TL093 SAN ANGELO	MENARD	138.00	138.00	3	0.36	0	2	477 ACSR
569	TL093 SAN ANGELO	MENARD	138.00	138.00	2	54.90	0	1	477 ACSR
570	TL093 SAN ANGELO	MENARD	138.00	138.00	3	0.15	0	1	336 ACSR
571	TL093 SAN ANGELO	MENARD	138.00	138.00	1	0.17	0	1	795.0 ACSS
572	TL094 PUTNAM	LEON CKT #2	138.00	138.00	2	21.93	0	1	4/0 ACSR
573	TL094 PUTNAM	LEON CKT #2			—		0		477.0 ACSR
574	TL095 SAN ANGELO COLLEGE	SAN ANGELO POWER STATION	138.00	138.00	2	2.75	0	1	795.0 ACSR
575	HILLS	SAN ANGELO POWER STATION			—		0		0
576	TL097 EAST MUNDAY	PAINT CREEK EAST#2	138.00	138.00	2	26.67	0	1	477.0 ACSR
577	TL100 BARRILLA JUNCTION	FORT STOCKTON PLANT	138.00	138.00	1	25.56	0	1	477.0 ACSR
578	TL111 ASPERMONT	SPUR	138.00	138.00	1	10.19	0	1	477.0 ACSR
579	TL111 ASPERMONT	SPUR			2	35.36	0
580	TL113 ALAMITO CREEK	BARRILLA JUNCTION	138.00	138.00	1	0.32	0	1	477.0 ACSR
581	TL113 ALAMITO CREEK	BARRILLA JUNCTION			2	66.89	0		477 ACSR
582	TL113 ALAMITO CREEK	BARRILLA JUNCTION			1	0.10	0		795 ACSS
583	TL117 NORTH SAN ANGELO	SAN ANGELO COLLEGE HILLS	138.00	138.00	1	2.10	0	1	795.0 ACSR
584	TL117 NORTH SAN ANGELO	SAN ANGELO COLLEGE HILLS			2	6.48	0
585	TL120A CEDAR HILL	OAK CREEK	138.00	138.00	2	26.26	0	1	4/0 ACSR
586	TL120A CEDAR HILL	OAK CREEK	138.00	138.00	1	0.09	0	1	959.6 ACSS
587	TL120B FORT CHADBOURNE TAP	FORT CHADBOURNE	138.00	138.00	2	0.02	0	1	4/0 ACSR
588	TL122 ABILENE MULBERRY	ABILENE NORTHWEST	138.00	138.00	2	2.59	0	1	1272.0 AAC
589	TL122 ABILENE MULBERRY	ABILENE NORTHWEST			—		0		1272.0 ACSR
590	TL123 MENARD	FORT MASON (LCRA)	138.00	138.00	1	1.05	0	1	477.0 ACSR
591	TL123 MENARD	FORT MASON (LCRA)			2	37.27	0		795 ACSS
592	TL124 FORT MASON (LCRA)	GILLESPIE COUNTY LINE	138.00	138.00	2	22.87	0	1	477.0 ACSR
593	TL124 FORT MASON (LCRA)	GILLESPIE COUNTY LINE			1	0.05	0	1	795 ACSS
594	TL127A BALLINGER	SANTA ANNA CKT #1	138.00	138.00	1	0.56	0	1	477.0 ACSR
595	TL127A BALLINGER	SANTA ANNA CKT #1			2	37.82	0
596	TL127B EAST COLEMAN TAP	EAST COLEMAN	138.00	138.00	2	2.98	0	1	477.0 ACSR
597	TL128 OKLAUNION	VERNON	138.00	138.00	1	2.59	0	1	795.0 ACSR
598	TL128 OKLAUNION	VERNON			2	6.72	0
599	TL129 ABILENE ELM CREEK	ABILENE MULBERRY CREEK	138.00	138.00	1	0.52	0	1	1272.0 AAC
600	TL129 ABILENE ELM CREEK	ABILENE MULBERRY CREEK			2	5.19	0
601	TL133 OKLAUNION	SOUTHWEST VERNON	138.00	138.00	2	6.98	0	1	795.0 ACSR
602	TL133 OKLAUNION	SOUTHWEST VERNON			1	0.48	0	1	795.0 ACSR
603	TL136 SPUR	SUN	138.00	138.00	1	0.31	0	1	795.0 ACSR
604	TL136 SPUR	SUN			2	17.48	0
605	TL138 PADUCAH CLARE STREET	WEST CHILDRESS	138.00	138.00	1	1.87	0	1	477.0 ACSR
606	TL138 PADUCAH CLARE STREET	WEST CHILDRESS			2	29.55	0
607	TL140 SOLSTICE	YUCCA DRIVE (ONCOR)	138.00	138.00	2	1.70	0	1	477.0 ACSR
608	TL140 SOLSTICE	YUCCA DRIVE (ONCOR)	138.00	138.00	1	0.49	0	1	477 ACSR
609	TL140 SOLSTICE	YUCCA DRIVE (ONCOR)	138.00	138.00	1	0.57	0	1	2-795 ACSR
610	TL140 SOLSTICE	YUCCA DRIVE (ONCOR)	138.00	138.00	1	35.57	0	1	2x795 ACSS
611	TL141 FRIEND RANCH	CARVER	138.00	138.00	1	32.85	0	1	477.0 ACSR
612	TL204 STERLING-SUN JAMESON	ROBERT LEE - STERLING	69.00	138.00	1	0.08	0	1	959.6ACSS/TW
613	TL242 BIG LAKE	FRIEND RANCH	138.00	138.00	1	39.63	0	1	477.0 ACSR
614	TL242 BIG LAKE	FRIEND RANCH	138.00	138.00	1	0.40	0	2	959 ACSR/TW
615	TL243 LCRA NORTH MCCAMEY	NORTH MCCAMEY	138.00	138.00	1	0.19	0	1	795.0 ACSR
616	TL310 BLUFF CREEK	BUFFALO GAP	138.00	138.00	1	2.04	0	1	2x795.0 ACSS
617	TL311 BLUFF CREEK	EXTENSION	345.00	345.00	1	0.45	0	2	2x795.0 ACSR
618	TL319 GONZALES	ACACIA	69.00	138.00	1	2.40	0	1	795.0 ACSR
619	TL321 ESMERALDA	YUCCA	138.00	138.00	3	14.80	0	1	4/0ACSR
620	TL322 SAN ANGELO	RUSTHILL #1	69.00	138.00	1	0.02	0	1	1590 ACSR
621	TL323 SAN ANGELO CONCHO	RUSTHILL #2	138.00	138.00	1	0.17	0	1	1590 ACSR
622	TL327 SANTA RITA	EXTENSION	69.00	138.00	1	0.17	0	1	2/0 ACSR
623	TL353 DINNY	WEST YATES	69.00	138.00	1	3.19	0	1	959 ACSS/TW
624	TL329 BARRILLA JUNCTION	SOLSTICE	138.00	138.00	1	0.20	0	1	2x956.6 ACSS
625	TL330 SOLSTICE	CLOVIS	138.00	138.00	1	4.50	0	1	795.0 ACSS
626	TL331 N BRADY	BRADY CITY	69.00	138.00	1	0.90	0	2	795
627	TL332 HEARTLAND 138KV EXTEN	BRADY CITY	69.00	138.00	1	0.73	0	1	ACSR/TW
628	TL333 ABILENE NORTHWEST	ELY	69.00	138.00	1	8.25	0	1	477ACSR
629	TL334 ALAMITO CREEK	MARFA	69.00	138.00	1	0.58	0	1	959 ACSS/TW
630	TL335 MUNDAY	POINTER	69.00	138.00	1	5.75	0	1	959 ACSR/TW
631	TL336 HEARTLAND	YELLOWJACKET 138KV LINE	69.00	138.00	1	18.80	0	1	959 ACSR
632	TL337 CASSAVA	YUCCA	138.00	138.00	1	11.90	0	1	397ACSR/T2
633	TL338 SOLSTICE	HOVEY	138.00	138.00	1	0.14	0	1	477 ACSR
634	TL338 SOLSTICE	HOVEY	138.00	138.00	1	0.10	0	1	477 ACSR
635	TL339 HENDRICK 138KV	HAIRPIN	138.00	138.00	1	0.68	0	2	795ACSS
636	TL340 ALBANY FOUNDRY	HULLTOWN	69.00	138.00	1	9.50	0	1	795 ACSS/AW
637	TL341 HULLTOWN	PUTNAM	69.00	138.00	1	13.30	0	1	795 ACSS
638	TL342 LOTEBUSH	ENSTOR HACBERRY DRAW	138.00	138.00	1	0.04	0	1	477 ACSR
639	TL343 BISON	POWELL FIELD 138KV TAP	69.00	138.00	1	6.80	0	1	4/0ACSR
640	TL344 BISON	OZONA	69.00	138.00	1	0.06	0	1	795.0 ACSS
641	TL345 ALBANY	FORT GRIFFIN	69.00	138.00	1	0.86	0	1	795 ACSS/AW
642	TL346 BIG LAKE	SAN ANGELO MATHIS FIELD	69.00	138.00	1	16.50	0	1	795 ACSS
643	TL348 CROWELL	MUNDAY	69.00	138.00	1	3.80	0	1	4/0 ACSR
644	TL348 CROWELL	MUNDAY	69.00	138.00	1	25.50	0	1	2x477 ACSR
645	TL349 JAYTAN	ROTAN	69.00	138.00	1	20.82	0	1	795 ACSS/TW
646	TL349 JAYTAN	ROTAN	69.00	138.00	1	20.99	0	1	477.0 ACSR
647	TL350 ALPINE	BARRILLA JUNCTION	69.00	138.00	1	49.34	0	1	795 ACSS
648	TL351 ABILENE SOUTH	SAWGRASS	69.00	138.00	1	1.95	0	1	795 ACSS
649	TL352 CACTUS	FORT LANCASTER	69.00	138.00	1	9.20	0	1	956.6 ACSS
650	TL354 QUAINT 138kV	EXTENSION	69.00	138.00	1	0.27	0	2	795 ACSS/AW
651	TL356 BRONCO 138KV	EXTENSION	69.00	138.00	1	0.29	0	1	795 ACSS
652	TL358 FORT GRIFFIN	RAINEY CREEK	69.00	138.00	1	0.37	0	1	795 ACSS/AW
653	TL359 ALBANY FOUNDRY	FORT GRIFFIN	69.00	138.00	1	0.14	0	1	795 ACSS
654	TL360 SAGE	OLLIN	69.00	138.00	1	2.80	0	1	795.0 ACSS
655	TL361 KINNISON	CRANE	69.00	138.00	1	1.10	0	1	795.0 ACSS
656	TL362 CRANE	MCELROY	69.00	138.00	1	2.30	0	1	795.0 ACSS
657	TL363 ABILENE NORTHWEST	ANSON 138KV LINE	69.00	138.00	1	19.39	0	1	795 ACSS
658	TL363 ABILENE NORTHWEST	ANSON	69.00	138.00	1	1.74	0	1	795 ACSS/AW
659	TL363 ABILENE NORTHWEST	ANSON	69.00	138.00	1	0.10	0	1	4/0 ACSR
660	TL364 MASON	FORT MASON	138.00	138.00	1	0.15	0	1	795.0 ACSS
661	TL365 ABILENE NORTHWEST	ELM CREEK (EAST)	69.00	138.00	1	3.10	0	1	795 ACSS
662	TL366 HENDRICK POI (OCI)	ELM CREEK (EAST)	138.00	138.00	1	0.03	0	1	477ACSR
663	TL367 BENJAMIN	TARDIS	138.00	138.00	1	7.69	0	1	T2-795 ACSR
664	TL368 Benjamin	Gyp	138.00	138.00	1	9.53	0	1	795 ACSR
665	TL369 Sonora	Carver	69.00	138.00	1	0.40	0	1	795 ACSS
666	TL370 LYNX	RIO PECOS	138.00	138.00	1	2.05	0	1	2x795 ACSS
667	TL371 Woodward #2 Tap	RIO PECOS	138.00	138.00	1	0.05	0	1	795 ACSS
668	TL372 WOODWARD #1 138KV TAP	RIO PECOS	138.00	138.00	1	0.33	0	1	795.0 ACSS
669	TL373 DERRICK	OWLS	69.00	138.00	1	4.24	0	1	795 ACSS
670	TL374 ELY TAP	ESKOTA 138KV LINE	69.00	138.00	1	42.35	0	1	T2-477 ACSR
671	TL375 BISON	POWELL FIELD 138KV TAP	69.00	138.00	1	7.26	0	1	795.0 ACSS
672	TL377 BIG LAKE	BISON	69.00	138.00	1	10.43	0	1	795.0 ACSS
673	TL378 HASKELL TAP	PAINT CREEK	69.00	138.00	1	0.11	1	1	477.0 ACSR
674	TL379 ANSON	PAINT CREEK	69.00	138.00	1	39.40	0	1	T2-477 ACSR
675	TL380 COLLEGE HILLS WEST	BURMA	69.00	138.00	1	10.38	0	1	795.0 ACSS
676	TL382 ONYX TAP	BELKNAP 138KV LINE	69.00	138.00	1	8.01	0	1	T2-477 ACSR
677	TL383 RAINEY CREEK	BELKNAP 138KV LINE	69.00	138.00	1	8.66	0	1	T2-477 ACSR
678	TL385 Pecos Valley	FORT STOCKTON SW	69.00	138.00	1	19.35	0	1	795.0 ACSS
679	TL386 BALLINGER	CONCHO 138KV LINE	69.00	138.00	1	16.04	0	1	795 ACSS
680	TL387 PECOS VALLEY	RIO PECOS	69.00	138.00	1	25.58	0	1	795 ACSS
681	TL388 MILES	BRONTE ATLANTIC	69.00	138.00	1	17.70	0	1	795 ACSS
682	TL389 BRONTE	BRONTE ATLANTIC	69.00	138.00	1	3.70	0	1	795.0 ACSS
683	TL390 ROBERT LEE	BRONTE	69.00	138.00	1	8.60	0	1	795.0 ACSS
684	TL392 KIRKLAND	CHILRESS 138KV LINE	69.00	138.00	1	5.61	0	1	T2-477 ACSR
685	TL393 QUANAH	KIRKLAND GODDLETT 138KV LIN	69.00	138.00	1	17.35	0	1	477.0 ACSR
686	TL394 SANTA ANNA	CROSS PLAINS	69.00	138.00	1	28.31	0	1	795.0 ACSS
687	TL395 SAN ANGELO CONCHO	ELDORADO LIVE OAK	69.00	138.00	1	33.12	0	1	795.0 ACSS
688	TL395 SAN ANGELO CONCHO	ELDORADO LIVE OAK	69.00	138.00	1	6.63	0	2	795.0 ACSS
689	TL396 LAKE PAULINE	CHILLICOTHE	69.00	138.00	1	8.97	0	1	477.0 ACSR
690	TL397 CHILLICOTHE	VERNON	69.00	138.00	1	14.17	0	1	477.0 ACSR
691	TL398 Yellowjacket	Junction	69.00	138.00	1	27.58	0	1	795 ACSS
692	TL399 BALLINGER	EDEN 138KV LINE	69.00	138.00	1	34.87	0	1	795 ACSS
693	TL400 CEDAR HILL ROBERT LEE	ROBERT LEE CEDAR HILL	69.00	138.00	1	21.58	0	1	795 ACSS
694	TL401 FRIEND RANCH	SONORA #2	69.00	138.00	1	13.21	0	1	795.0 ACSS
695	TL402 BRONCO	LASSO	69.00	138.00	1	0.10	0	1	795 ACSS
696	TL403 Wolfgang	Mozart Wind Farm	69.00	138.00	1	0.07	0	1	795.0 ACSS
697	TL404 TREADWELL	CACTUS FLATS	138.00	138.00	1	0.14	0	1	795.0 ACSR
698	TL406 Rio Pecos	Horse Crossing (LCRA)	138.00	138.00	1	0.11	0	1	795 ACSR
699	TL410 CHERRY CREEK 138KV EX	Horse Crossing (LCRA)	69.00	138.00	1	0.87	0	1	795.0 ACSS
700	TL410 CHERRY CREEK 138KV EX	Horse Crossing (LCRA)	69.00	138.00	1	0.17	0	1	2/0 ACSR
701	TL411 SARAGOSA	SOLSTICE (SOUTH)	138.00	138.00	1	18.70	0	1	795.0 ACSS
702	TL412 LOTEBUSH	BROZOS MIDSTREAM	138.00	138.00	1	0.04	0	1	959.6 ACSS/TW
703	TL413 LOTEBUSH	ARROWHEAD	138.00	138.00	1	0.04	0	1	1926.9 ACSR/TW
704	TL414 LOTEBUSH	NW COYANOSA	138.00	138.00	1	0.06	0	2	959.6 ACSS/TW
705	TL416 CRYO	SARGOSA	138.00	138.00	1	4.70	0	1	795 ACSS
706	TL417 Solstice	Ft Stockton SW 138kV Line	138.00	138.00	1	16.50	0	1	795 ACSS
707	TL418 CRYO	DIAMOND (APACHE) EXTENSION	138.00	138.00	1	0.08	0	1	795 ACSS
708	TL419 BIG LAKE	CASSAVA 138KV LINE	69.00	138.00	1	17.70	0	1	795 ACSS
709	TL420 MERTZON	MATHIS FIELD	69.00	138.00	1	23.60	0	1	795 ACSS
710	TL422 CROSSOVER 138KV TAP	MATHIS FIELD	138.00	138.00	1	0.09	0	1	795.0 ACSS
711	TL424 PIG CREEK	Tarbush (TNMP)	138.00	138.00	1	0.04	0	1	795 ACSS
712	TL428 PIG CREEK	TAYGETE 138KV TIE LINE	138.00	138.00	1	0.04	0	1	795 ACSS
713	TL430 LYNX	SOAPTREE (TNMP) 138KV TIE L	138.00	138.00	1	0.04	0	1	2-795 ACSS
714	TL431 LYNX	16TH STREET (TNMP) 138KV TI	138.00	138.00	1	0.04	0	1	2-795 ACSS
715	TL436 HEARTLAND 138KV EXTEN	16TH STREET (TNMP) 138KV TI	69.00	138.00	1	0.70	0	1	959 ACSR/TW
716	TL441 Pig Creek	Flat Top (TNMP)	138.00	138.00	1	0.05	0	1	795 ACSS
717	TL442 Bond Road Extension (operating at 69kV)	Flat Top (TNMP)	69.00	138.00	1	0.05	0	1	959.6 ACSS
718	TL447 BELKNAP 138KV EXTENSI	Flat Top (TNMP)	69.00	138.00	1	0.12	0	1	T2-477 ACSR
719	TL450 Pig Creek	Taygete II 138V Tie Line	138.00	138.00	1	0.05	0	1	795 ACSS
720	TL454 ESKOTA	ROBY 138KV LINE	69.00	138.00	1	2.85	0	1	T2-477 ACSR
721	TL460 SARAGOSA	SOLSTICE (NORTH)	138.00	138.00	1	0.05	0	1	795 ACSS
722	TL470 RULE	ASPERMONT	69.00	138.00	1	0.12	0	1	336.0 ACSR
723	TL473 Rio Pecos	Soaptree (TNMP)	138.00	138.00	1	0.04	0	1	2-795 ACSS
724	TL474 Cross Plains	Putnam 138kV Line (operating at 69kV)	69.00	138.00	1	0.10	0	1	795 ACSS
725	TL479 ANSON	RADIUM 138KV LINE	69.00	138.00	1	0.60	0	1	T2-477 ACSR
726	TL482 Aspermont	Hamlin 138kV Line (operating at 69kV)	69.00	138.00	1	0.17	0	1	2/0 ACSR
727	TL483 Jayton	Aspermont 138kV Line (operating at 69kV)	69.00	138.00	1	0.16	0	1	336.4 ACSR
728	TL484 Aspermont	Aspermont (BEPC) 138kV Line (operating at 69kV)	69.00	138.00	1	0.04	0	1	477 ACSR
729	TL490 Avenger	Atwell (TEC) 69kV Extension	69.00	138.00	1	0.02	0	1	795 ACSS
730	TL5311 REVILLA	VENADO TIE LINE	138.00	138.00	1	0.13	0	1	795 ACSS
731	69kV for AEPTN	VENADO TIE LINE	69.00	69.00	1,2,3	1,518.55	45		VARIOUS
732	Line costs and expense are	not available by individual
733	transmission line.	Totals shown in col j-p								190,883,027	2,815,722,796	3,006,605,823	226,959	14,259,360		14,486,319
734					TOTAL	8,398	141	699		190,883,027	2,815,722,796	3,006,605,823	226,959	14,259,360	0	14,486,319
36	TOTAL

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

TRANSMISSION LINES ADDED DURING YEAR
Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report minor revisions of lines. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m). If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase, indicate such other characteristic.
	LINE DESIGNATION			SUPPORTING STRUCTURE		CIRCUITS PER STRUCTURE		CONDUCTORS				LINE COST
Line No.	TransmissionLineStartPoint From	TransmissionLineEndPoint To	LengthOfTransmissionLineAdded Line Length in Miles	SupportingStructureOfTransmissionLineType Type	AverageNumberOfSupportingStructuresOfTransmissionLinePerMiles Average Number per Miles	NumberOfTransmissionCircuitsPerStructurePresent Present	NumberOfTransmissionCircuitsPerStructureUltimate Ultimate	ConductorSize Size	ConductorSpecification Specification	ConductorConfigurationAndSpacing Configuration and Spacing	OperatingVoltageOfTransmissionLine Voltage KV (Operating)	CostOfLandAndLandRightsTransmissionLinesAdded Land and Land Rights	CostOfPolesTowersAndFixturesTransmissionLinesAdded Poles, Towers and Fixtures	CostOfConductorsAndDevicesTransmissionLinesAdded Conductors and Devices	Asset Retire. Costs	CostOfTransmissionLinesAdded Total	SupportingStructureConstructionType Construction
	(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)	(l)	(m)	(n)	(o)	(p)	(q)
1	TL5327 Angstrom	SDI 345kV Line	0.95	1	1.00	1	1	2-954	ACSR/AW		345.00		1,250,518	178,389		1,428,907
2	TL5337 Grissom	Blackjack Creek 345kV Tie Line	0.02	1	1.00	1	1	2-954	ACSR		345.00		537,301			537,301
3	TL5360 Katoen	El Algodon 345kV Tie Line	0.10	1	1.00	1	1	2-795	ACSR/AW		345.00		380,889	166,331		547,220
4	TL5305 Luna	Rayos Del Sol	0.10	1	1.00	1	1	795	ACSS/TW		138.00		485,924	43,170		529,094
5	TL5306 Luna 138kV Extension		0.46	1	1.00	2	2	795	ACSS/AW		138.00	70,048	811,200	245,365		1,126,613
6	TL5307 Esperanza 138kV Extension		0.60	1	1.00	2	2	795	ACSS/AW		138.00	31,620	957,493	135,711		1,124,824
7	TL5313 Stewart Road 345kV	138kV Auto Trans Bus Tie No. 1	0.15	1	1.00	1	1	2-795	ACSS/AW		138.00		527,947	75,188		603,135
8	TL5316 Raymondsville #2	La Sara (STEC) 138kV Line	0.05	1	1.00	1	1	795	ACSR		138.00		57,362	25,801		83,163
9	TL5364 Luna	Vancourt 138kV Tie Line	0.10	1	1.00	1	1	795	ACSS/AW		138.00		554,736	161,631		716,367
10	TL467 Perigee	Apogee 345kV Tie Line	0.04	1	1.00	1	1	2-795	ACSR		345.00		260,263	63,471		323,735
11	TL368 Benjamin	Gyp 138kV Line (BEC)	9.53	1	1.00	1	1	T2-795	ACSR		138.00	528,297	1,694,455	1,651,574		3,874,327
12	TL369 Sonora	Carver 138kV Tie Line	0.40	1	1.00	1	1	795	ACSS		138.00	19,826	963,116	72,025		1,054,966
13	TL406 Rio Pecos	Horse Crossing (LCRA) 138kV Line	0.11	1	1.00	1	1	795	ACSR		138.00	61	323,302	209,098		532,461
14	TL450 Pig Creek	Taygete II 138V Tie Line	0.05	1	1.00	1	1	795	ACSS		138.00		182,160	119,029		301,189
15	TL473 Rio Pecos	Soaptree (TNMP) 138kV Tie Line	0.04	1	1.00	1	1	2-795	ACSS		138.00	384	386,356	180,263		567,003
16	TL424 Pig Creek	Tarbush (TNMP)	0.04	1	1.00	1	1	795	ACSS		138.00		437,012	36,094		473,106
17	TL5314 Stewart Road 345kV	138kV Auto Trans Bus Tie No. 2	0	1	1	1	1	2-795	ACSS		138.00		635,157	90,457		725,614
44	TOTAL		13		17	19	19					650,237	10,445,192	3,453,596		14,549,025

Name of Respondent:

AEP Texas

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

SUBSTATIONS
Report below the information called for concerning substations of the respondent as of the end of the year. Substations which serve only one industrial or street railway customer should not be listed below. Substations with capacities of Less than 10 MVA except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f). Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
		Character of Substation		VOLTAGE (In MVa)						Conversion Apparatus and Special Equipment
Line No.	SubstationNameAndLocation Name and Location of Substation (a)	SubstationCharacterDescription Transmission or Distribution (b)	SubstationCharacterAttendedOrUnattended Attended or Unattended (b-1)	PrimaryVoltageLevel Primary Voltage (In MVa) (c)	SecondaryVoltageLevel Secondary Voltage (In MVa) (d)	TertiaryVoltageLevel Tertiary Voltage (In MVa) (e)	SubstationInServiceCapacity Capacity of Substation (In Service) (In MVa) (f)	NumberOfTransformersInService Number of Transformers In Service (g)	Number of Spare Transformers (h)	ConversionApparatusAndSpecialEquipmentType Type of Equipment (i)	NumberOfConversionApparatusAndSpecialEquipmentUnits Number of Units (j)	CapacityOfConversionApparatusAndSpecialEquipment Total Capacity (In MVa) (k)
1	ABILENE AILEEN - TX	Distribution		138.00	13.09	0.50	28.00	1			0	0.00
2	ABILENE COUNTRY CLUB - TX	Distribution		138.00	13.09		20.00	1			0	0.00
3	ABILENE EAST - TX	Transmission		138.00	13.09		28.00	1			0	0.00
4	ABILENE EAST - TX	Transmission		138.00	69.00	7.67	75.00	1			0	0.00
5	ABILENE EAST - TX	Transmission		138.00	69.30	13.20	62.50	1			0	0.00
6	ABILENE INDUSTRIAL PARK - TX	Distribution		138.00	13.09		56.00	2			0	0.00
7	ABILENE NORTHWEST - TX	Transmission		138.00	69.00	11.20	91.60	1			0	0.00
8	ABILENE NORTHWEST - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	28.80
9	ABILENE NORTHWEST - TX	Transmission		138.00	69.50	36.20	90.00	1			0	0.00
10	ABILENE OIL MILL - TX	Distribution		69.00	13.00		25.00	1			0	0.00
11	ABILENE ONYX REA - TX	Distribution		69.00	13.00		12.00	3			0	0.00
12	ABILENE POWER PLANT - TX	Transmission		69.00	7.56	2.40	6.67	1			0	0.00
13	ABILENE POWER PLANT - TX	Transmission		69.00	7.56		13.34	2			0	0.00
14	ABILENE POWER PLANT - TX	Transmission		69.00	13.09			1			0	0.00
15	ABILENE SOUTH - TX	Transmission		138.00	70.50	13.09	180.00	2			0	0.00
16	ABILENE SOUTH - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	57.60
17	ACME BESTWALL - TX	Distribution		69.00	13.00		5.00	1			0	0.00
18	AFTON (WT) - TX	Distribution		69.00	7.20		3.00	3			0	0.00
19	AIRLINE(CP) - TX	Transmission		69.00	0.00	0.00	0.00			STATCAP	3	26.30
20	AIRLINE(CP) - TX	Transmission		138.00	69.00	12.00	224.00	1			0	0.00
21	AIRLINE(CP) - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	57.60
22	AIRLINE(CP) - TX	Transmission		69.00	0.00	0.00	0.00			AIR CORE REACTOR	6
23	ALAZAN - TX	Distribution		138.00	24.90		10.50	1			0	0.00
24	ALAZAN - TX	Distribution		26.00	12.47		9.25	1			0	0.00
25	ALBANY (WT) - TX	Distribution		69.00	13.00		10.00	1			0	0.00
26	ALBANY FOUNDRY - TX	Distribution		69.00	13.00		25.00	1			0	0.00
27	ALBANY HUBBARD BOOSTER #1 WCT - TX	Distribution		2.40				3			0	0.00
28	ALBANY HUBBARD BOOSTER #1 WCT - TX	Distribution		69.00	2.52		3.75	3			0	0.00
29	ALBANY HUBBARD BOOSTER #2 WCT - TX	Distribution		69.00	2.52		3.75	3			0	0.00
30	ALBANY HUBBARD BOOSTER #2 WCT - TX	Distribution		2.40	0.48		0.18	3			0	0.00
31	ALICE - TX	Transmission		138.00	69.00	12.00	93.00	1			0	0.00
32	ALICE - TX	Transmission		69.00	12.47		28.00	1			0	0.00
33	ALPINE - TX	Distribution		69.00	13.00		40.00	4			0	0.00
34	AMISTAD - TX	Distribution		138.00	12.47		5.60	1			0	0.00
35	ANNA STREET - TX	Distribution		138.00	12.47		80.00	2			0	0.00
36	ANSON - TX	Distribution		69.00	13.09		9.38	1			0	0.00
37	ANSON REA - TX	Distribution		69.00	13.00		5.00	1			0	0.00
38	ARANSAS PASS - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	1
39	ARANSAS PASS - TX	Transmission		138.00	69.00	12.00	224.00	1			0	0.00
40	ARCADIA - TX	Distribution		138.00	12.47		89.60	2			0	0.00
41	ARCADIA - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	2	4.80
42	ARMSTRONG - TX	Distribution		138.00	12.47		5.60	1			0	0.00
43	ARROTT - TX	Distribution		69.00	12.50		2.50	3			0	0.00
44	ASHERTON - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	14.40
45	ASHERTON - TX	Transmission		138.00	69.00	13.09	130.00	1			0	0.00
46	ASHERTON - TX	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.40
47	ASPERMONT - TX	Transmission		69.00	13.00		9.40	1			0	0.00
48	ASPERMONT - TX	Transmission		138.00	69.00	14.40	62.50	1			0	0.00
49	ASPERMONT - TX	Transmission		138.00	70.50	36.20	78.00	1			0	0.00
50	ASPERMONT CONTINENTAL OIL CO. - TX	Distribution		69.00	13.00		3.75	1			0	0.00
51	ATKINSON RANCH - TX	Distribution		69.00	2.40		0.25	2			0	0.00
52	B&B GRAVEL - TX	Distribution		69.00	12.47		4.80	3			0	0.00
53	BAIRD CITY - TX	Distribution		69.00	13.00		5.00	1			0	0.00
54	BALLINGER - TX	Transmission		138.00	66.00	13.80	62.50	1			0	0.00
55	BALLINGER - TX	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	7.20
56	BALLINGER - TX	Transmission		138.00	13.09		25.00	1			0	0.00
57	BANQUETE - TX	Distribution		69.00	12.47		9.40	1			0	0.00
58	BARNHART - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	3.60
59	BARNHART - TX	Distribution		69.00	13.09		9.38	1			0	0.00
60	BARRILLA JUNCTION - TX	Transmission		69.00	12.40		0.33	1			0	0.00
61	BARRILLA JUNCTION - TX	Transmission		138.00	69.00	6.57	62.50	1			0	0.00
62	BAY CITY - TX	Distribution		138.00	12.47		89.60	2			0	0.00
63	BAY CITY - TX	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	14.40
64	BAY CITY PUMP NO. 1 - TX	Distribution		69.00	2.30		0.99	3			0	0.00
65	BAY CITY PUMP NO. 3 - TX	Distribution		69.00	2.30		3.00	3			0	0.00
66	BEEVILLE - TX	Distribution		69.00	12.47		28.00	1			0	0.00
67	BEEVILLE - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	3	45.60
68	BERCLAIR - TX	Distribution		69.00	7.50		3.00	3			0	0.00
69	BESSEL - TX	Distribution		138.00	0.00	0.00	0.00			STATCAP	1
70	BIG FOOT SW - TX	Transmission		138.00	69.00	12.47	37.00	1			0	0.00
71	BIG FOOT SW - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	14.40
72	BIG FOOT SW - TX	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	7.20
73	BIG LAKE - TX	Transmission		138.00	69.00	2.40	50.00	1			0	0.00
74	BIG LAKE - TX	Transmission		12.00	4.10		2.50	3			0	0.00
75	BIG LAKE - TX	Transmission		69.00	13.00		10.00	3			0	0.00
76	BIG LAKE - TX	Transmission		138.00	69.00	5.39	50.00	1			0	0.00
77	BIG LAKE - PHILLIPS PUMP - TX	Distribution		69.00	12.50		2.00	3			0	0.00
78	BIG OAK - TX	Distribution		69.00	13.09		25.00	1			0	0.00
79	BIG OAK - TX	Distribution		23.00	12.00		1.00	1			0	0.00
80	BIG WELLS - TX	Distribution		138.00	12.47		10.50	1			0	0.00
81	BISHOP - TX	Distribution		69.00	12.47		9.40	1			0	0.00
82	BLACK BAYOU - TX	Distribution		138.00	12.47		10.50	1			0	0.00
83	BLESSING - TX	Transmission		69.00	12.00		4.50	3			0	0.00
84	BLESSING - TX	Transmission		345.00	138.00	12.47	600.00	1			0	0.00
85	BLESSING - TX	Transmission		138.00	69.00	12.47	83.00	1			0	0.00
86	BLUFF CREEK - TX	Transmission		138.00	0.00	0.00	0.00			AIR CORE REACTOR	12	0.00
87	BLUFF CREEK - TX	Transmission		345.00	138.00	34.50	1350.00	2			0	0.00
88	BLUFF CREEK - TX	Transmission		34.50	0.00	0.00	0.00			AIR CORE REACTOR	5	0.00
89	BLUFF CREEK - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	57.60
90	BLUFFS - TX	Distribution		138.00	12.47		25.00	1			0	0.00
91	BOBCAT HILLS - TX	Distribution		69.00	12.47		5.00	1			0	0.00
92	BOND ROAD - TX	Distribution		7.62	13.09		9.38	1			0	0.00
93	BOND ROAD - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	2	14.40
94	BONNIE VIEW - TX	Distribution		69.00	13.09		9.38	1			0	0.00
95	BRACKETTVILLE - TX	Distribution		138.00	12.47		6.25	1			0	0.00
96	BRADSHAW - TX	Distribution		69.00	12.40		0.75	3			0	0.00
97	BRADY CITY (MUNICIPAL INTERCON - TX	Distribution		69.00	13.00	7.62	10.50	1			0	0.00
98	BRADY CITY (MUNICIPAL INTERCON - TX	Distribution		0.00	0.00	0.00	0.00			STATCAP	1	6.00
99	BRONTE - TX	Distribution		69.00	12.47		6.25	1			0	0.00
100	BRONTE - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	2
101	BRONTE (AMBASSADOR) - TX	Distribution		69.00	13.00		1.50	3			0	0.00
102	BRONTE ATLANTIC - TX	Transmission		69.00	12.50		1.50	1			0	0.00
103	BROOKHOLLOW - TX	Distribution		69.00	13.09		25.00	1			0	0.00
104	BROOKHOLLOW - TX	Distribution		69.00	12.47		10.50	1			0	0.00
105	BROWNSVILLE (CP) - TX	Distribution		69.00	12.47		19.90	2			0	0.00
106	BROWNSVILLE (CP) - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	2	4.80
107	BRUNI - TX	Distribution		138.00	13.09		12.50	1			0	0.00
108	BRYANT RANCH - TX	Distribution		69.00	12.47		1.00	3			0	0.00
109	BUENA VISTA - TX	Distribution		138.00	12.47		28.00	1			0	0.00
110	BUSH KNOB (THROCKMORTON) - TX	Distribution		69.00	7.56		7.50	3			0	0.00
111	CAMPWOOD - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	2	7.20
112	CAMPWOOD - TX	Distribution		26.00	12.47	7.20	3.00	1			0	0.00
113	CAMPWOOD - TX	Distribution		69.00	7.20		5.01	3			0	0.00
114	CAMPWOOD - TX	Distribution		26.00	12.47		3.00	1			0	0.00
115	CANYON ROCK - TX	Distribution		138.00	13.09		15.00	1			0	0.00
116	CARBIDE - TX	Transmission		138.00	69.00	12.47	280.00	2			0	0.00
117	CARVER - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	28.80
118	CARVER - TX	Transmission		138.00	13.09	13.09	180.00	2			0	0.00
119	CARVER - TX	Transmission		138.00	13.09	70.50	180.00	2			0	0.00
120	CARVER - TX	Transmission		138.00	70.50	13.09	180.00	2			0	0.00
121	CARVER - TX	Transmission		138.00	70.50	70.50	180.00	2			0	0.00
122	CASA BLANCA - TX	Distribution		69.00	13.09		9.40	1			0	0.00
123	CASA BLANCA - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	2.40
124	CASSAVA - TX	Transmission		138.00	70.50	13.09	720.00	8			0	0.00
125	CATARINA - TX	Transmission		138.00	12.00		25.00	1			0	0.00
126	CEDAR GAP - TX	Distribution		69.00	13.09	2.40	15.00	1			0	0.00
127	CEDAR HILL - TX	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	12.00
128	CEDAR HILL - TX	Transmission		138.00	70.50	13.09	90.00	1			0	0.00
129	CHARLOTTE - TX	Distribution		69.00	13.09		9.38	1			0	0.00
130	CHASE FIELD - TX	Distribution		69.00	12.47		9.40	1			0	0.00
131	CHERRY CREEK (WT) - TX	Distribution		69.00	13.09	69.00	15.00	1			0	0.00
132	CHILDRESS (69) - TX	Transmission		69.00	12.47		12.00	1			0	0.00
133	CHILDRESS 20TH ST SUB CHILDRES - TX	Distribution		69.00	13.00		16.00	1			0	0.00
134	CHILDRESS WEST - TX	Transmission		138.00	69.00	2.40	50.00	1			0	0.00
135	CHILLICOTHE - TX	Distribution		69.00	13.09		11.19	3			0	0.00
136	CHINATI - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	0.45
137	CHOKE CANYON - TX	Distribution		138.00	13.09		15.00	1			0	0.00
138	CHRISTOVAL - TX	Distribution		69.00	13.00		6.00	1			0	0.00
139	CISCO - TX	Distribution		138.00	13.09		24.00	2			0	0.00
140	CITRUS CITY - TX	Transmission		138.00	13.09		50.00	2			0	0.00
141	CLAIRMONT SUN OIL CO. - TX	Distribution		69.00	7.20		1.98	3			0	0.00
142	CLARKWOOD - TX	Distribution		138.00	12.47		56.00	2			0	0.00
143	CLARKWOOD - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	2.40
144	CLEMVILLE - TX	Distribution		69.00	12.47		9.40	1			0	0.00
145	CLYDE - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	12.00
146	CLYDE - TX	Distribution		69.00	13.00		25.00	1			0	0.00
147	CLYDE MAGNOLIA PUMP PIPELINE - TX	Distribution		69.00	2.50		6.25	1			0	0.00
148	COFFEE PORT - TX	Distribution		138.00	12.47		10.50	1			0	0.00
149	COFFEE PORT - TX	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	28.80
150	COLEMAN EAST - TX	Distribution		138.00	13.09		25.00	1			0	0.00
151	COLETO CREEK - TX	Transmission		13.80	0.00	0.00	0.00			AIR CORE REACTOR	12	127.36
152	COLETO CREEK - TX	Transmission		345.00	138.00	13.80	600.00	1			0	0.00
153	COLETO CREEK - TX	Transmission		345.00	138.00	12.47	600.00	1			0	0.00
154	COMSTOCK - TX	Distribution		138.00	13.00		7.50	1			0	0.00
155	CONOCO - TX	Distribution		138.00	12.47		6.25	1			0	0.00
156	CONTINENTAL(CP) - TX	Distribution		69.00	69.00	13.00	25.00	1			0	0.00
157	COTULLA - TX	Distribution		138.00	12.00		50.00	2			0	0.00
158	CRANE (TESCO INTER) - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	56.70
159	CRANE (TESCO INTER) - TX	Transmission		138.00	70.50	13.09	130.00	1			0	0.00
160	CRANE COUNTY AIRPORT - TX	Distribution		69.00	4.10		10.50	1			0	0.00
161	CRESTONIO - TX	Distribution		138.00	12.47		18.80	2			0	0.00
162	CROCKETT HEIGHTS (OZONA) - TX	Distribution		69.00	12.00		2.00	3			0	0.00
163	CROSS PLAINS - TX	Distribution		69.00	13.09		7.50	1			0	0.00
164	CROWELL - TX	Transmission		69.00	13.00		6.20	1			0	0.00
165	CRYO - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	28.80
166	DEL RIO - TX	Distribution		138.00	12.47		53.00	2			0	0.00
167	DEVINE - TX	Distribution		69.00	12.47		18.75	3			0	0.00
168	DILLEY - TX	Distribution		69.00	13.09		18.75	2			0	0.00
169	DILLEY - TX	Distribution		69.00	12.47		10.50	1			0	0.00
170	DILLEY SW - TX	Transmission		138.00	69.00	12.47	37.00	1			0	0.00
171	DILLEY SW - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	113.40
172	DILLEY SW - TX	Transmission		69.00	0.00	0.00	0.00			STATCAP	3	26.30
173	DILLEY SW - TX	Transmission		69.00	0.00	0.00	0.00			AIR CORE REACTOR	6
174	DIMMIT - TX	Distribution		138.00	13.09		25.00	1			0	0.00
175	DISCOVERY CANYON - TX	Distribution		69.00	12.50		5.00	3			0	0.00
176	DUNE FIELD - TX	Distribution		69.00	13.00		10.00	3			0	0.00
177	DUSTDEVIL - TX	Distribution		138.00	35.40	13.80	30.00	1			0	0.00
178	DYESS AFB #1 - TX	Distribution		69.00	13.00	2.40	3.13	1			0	0.00
179	DYESS AFB #1 - TX	Distribution		69.00	7.56	2.40	5.63	2			0	0.00
180	DYESS AFB #2 - TX	Distribution		69.00	13.00		16.00	1			0	0.00
181	DYESS AFB #3 - TX	Distribution		69.00	7.56	2.40	18.75	3			0	0.00
182	EAGLE LAKE - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	2	4.80
183	EAGLE LAKE - TX	Distribution		69.00	12.47		19.90	2			0	0.00
184	EAGLE PASS - TX	Distribution		138.00	12.47		28.00	1			0	0.00
185	EAGLE PASS - TX	Distribution		138.00	0.00	0.00	0.00			STATCAP	2	31.20
186	EAGLE PASS - TX	Distribution		138.00	0.00	0.00	0.00			AIR CORE REACTOR	3
187	EAGLE PASS HVDC - TX	Transmission		138.00	17.90		94.80	2			0	0.00
188	EAGLE PASS HVDC - TX	Transmission		13.20	0.00	0.00	0.00			REACTIVE SPECIAL	1
189	EAGLE PASS HVDC - TX	Transmission		18.00	0.00	0.00	0.00			STATCAP	4	25.08
190	EAGLE PASS HVDC - TX	Transmission		138.00	0.00	0.00	0.00			AIR CORE REACTOR	2
191	EAST HARRISON - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	5	24.00
192	EAST HARRISON - TX	Distribution		69.00	12.47		100.80	3			0	0.00
193	EDEN - TX	Transmission		69.00	13.00		5.00	3			0	0.00
194	EDITH HUMBLE - TX	Distribution		69.00	13.09		3.13	1			0	0.00
195	EDNA - TX	Distribution		138.00	12.47		18.80	2			0	0.00
196	EDROY - TX	Distribution		69.00	0.00	0.00	0.00			AIR CORE REACTOR	3
197	EL CAMPO - TX	Transmission		138.00	12.47		28.00	1			0	0.00
198	EL CAMPO - TX	Transmission		138.00	69.00	12.47	93.00	1			0	0.00
199	EL CAMPO - TX	Transmission		69.00	12.47		28.00	1			0	0.00
200	EL CAMPO - TX	Transmission		12.00	0.00	0.00	0.00			STATCAP	2	4.80
201	EL GATO - TX	Distribution		138.00	13.09		40.00	1			0	0.00
202	ELDORADO - TX	Distribution		69.00	13.00		7.50	3			0	0.00
203	ELDORADO CITIES SERVICE CO. - TX	Distribution		69.00	12.50		0.67	1			0	0.00
204	ELDORADO CITIES SERVICE CO. - TX	Distribution		69.00	12.00		1.33	2			0	0.00
205	ELDORADO LIVE OAK SUB. - TX	Transmission		0.00	0.00	0.00	0.00			STATCAP	1	12.00
206	ELDORADO LIVE OAK SUB. - TX	Transmission		138.00	69.00	7.00	50.00	1			0	0.00
207	ELDORADO LIVE OAK SUB. - TX	Transmission		138.00	69.00	6.60	62.50	1			0	0.00
208	ELDORADO SHELL BAILEY - TX	Distribution		69.00	4.36		7.50	1			0	0.00
209	ELM CREEK - TX	Transmission		138.00	69.00	8.55	91.70	1			0	0.00
210	ELM CREEK - TX	Transmission		138.00	13.09		48.00	2			0	0.00
211	ELMDALE - TX	Distribution		69.00	13.00		9.40	1			0	0.00
212	ELSA - TX	Distribution		138.00	12.47		56.00	2			0	0.00
213	ELSA - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	2	4.80
214	ENCINAL - TX	Distribution		138.00	12.47		5.00	1			0	0.00
215	EOLA - TX	Distribution		69.00	13.00		3.75	3			0	0.00
216	ESCONDIDO - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	14.40
217	ESCONDIDO - TX	Transmission		138.00	12.47		25.00	1			0	0.00
218	ESPERANZA - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	2
219	ESPERANZA - TX	Transmission		138.00	0.00	0.00	0.00			REACTIVE SPECIAL	6
220	ESPY WELLS - TX	Distribution		69.00	7.20		0.20	1			0	0.00
221	FALCON SW - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	14.40
222	FALFURRIAS - TX	Transmission		138.00	69.00	13.09	54.00	1			0	0.00
223	FLOMOT - TX	Distribution		69.00	13.00		2.49	3			0	0.00
224	FORT DAVIS - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	3.60
225	FORT DAVIS - TX	Distribution		69.00	12.40		7.50	3			0	0.00
226	FORT GRIFFIN - TX	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	7.20
227	FORT LANCASTER - TX	Transmission		138.00	69.00	12.47	50.00	1			0	0.00
228	FORT MCKAVITT - TX	Distribution		69.00	2.40		1.50	3			0	0.00
229	FORT STOCKTON PLANT - TX	Transmission		138.00	69.00	8.88	62.50	1			0	0.00
230	FORT STOCKTON SW STATION - TX	Transmission		69.00	7.20		0.15	1			0	0.00
231	FOSTER FIELD - TX	Distribution		69.00	12.47		9.40	1			0	0.00
232	FREDERICKSBURG PHILLIPS - TX	Distribution		69.00	2.40		1.00	3			0	0.00
233	FREER - TX	Distribution		69.00	12.47		9.40	1			0	0.00
234	FREER - TX	Distribution		69.00	13.09		9.38	1			0	0.00
235	FRIEND RANCH - TX	Transmission		138.00	69.00	13.20	62.50	1			0	0.00
236	FRIEND RANCH - TX	Transmission		2.40	0.00	0.00	0.00			DRCS	1	10.00
237	FRIESS RANCH - TX	Distribution		69.00	12.50		2.50	3			0	0.00
238	FRONTERA SWITCH - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	115.20
239	FT CHADBOURNE - TX	Distribution		138.00	13.09		10.50	1			0	0.00
240	FT PHANTOM CLEAR FORK PUM - TX	Distribution		69.00	2.40		12.60	3			0	0.00
241	FT PHANTOM EAST PUMP STA - TX	Distribution		69.00	4.30		2.50	3			0	0.00
242	FT PHANTOM PLANT - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	28.80
243	FULTON (CP) - TX	Distribution		69.00	12.47		28.00	1			0	0.00
244	GANADO - TX	Distribution		138.00	12.47		9.40	1			0	0.00
245	GARCENO - TX	Distribution		138.00	12.47		25.00	1			0	0.00
246	GARWOOD CITY - TX	Distribution		69.00	12.47		4.50	3			0	0.00
247	GARWOOD IDEAL - TX	Distribution		69.00	4.16		3.00	3			0	0.00
248	GARWOOD PUMP - TX	Distribution		69.00	2.30		2.49	3			0	0.00
249	GARWOOD RELIFT - TX	Distribution		69.00	2.30		90.00	3			0	0.00
250	GARZA - TX	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	10.80
251	GARZA - TX	Transmission		138.00	69.00	12.50	83.00	1			0	0.00
252	GATEWAY (CP) - TX	Distribution		138.00	12.47		68.00	2			0	0.00
253	GEORGE WEST - TX	Distribution		138.00	12.47		9.40	1			0	0.00
254	GEORGE WEST - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	2	4.80
255	GILLESPIE (KNOX CITY REA - TX	Distribution		69.00	12.47		3.00	3			0	0.00
256	GIRARD - TX	Distribution		69.00	2.40		1.00	3			0	0.00
257	GOHLKE - TX	Distribution		138.00	12.47		6.25	1			0	0.00
258	GOLIAD - TX	Distribution		69.00	12.47		9.38	1			0	0.00
259	GOODWIN - TX	Distribution		138.00	13.09		25.00	1			0	0.00
260	GOODWIN - TX	Distribution		138.00	12.47		25.00	1			0	0.00
261	GOVERNMENT WELLS - TX	Distribution		24.94	0.00	0.00	0.00			STATCAP	2	4.80
262	GOVERNMENT WELLS - TX	Distribution		69.00	12.47		10.50	1			0	0.00
263	GOVERNMENT WELLS - TX	Distribution		26.00	12.47		3.40	1			0	0.00
264	GOVERNMENT WELLS - TX	Distribution		69.00	24.90		10.50	1			0	0.00
265	GOVERNMENT WELLS - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	2	4.80
266	GRAYBACK - TX	Distribution		69.00	13.09		5.01	3			0	0.00
267	GREENLAKE - TX	Distribution		69.00	7.20		3.34	2			0	0.00
268	GREENLAKE - TX	Distribution		69.00	12.47		5.01	3			0	0.00
269	GREGORY - TX	Distribution		69.00	13.09		50.00	2			0	0.00
270	GRETA - TX	Distribution		69.00	12.47		10.50	1			0	0.00
271	GRIMES FILTRATION PLAN - TX	Distribution		12.00	4.10		4.98	3			0	0.00
272	HAINE DRIVE - TX	Distribution		138.00	12.47		56.00	2			0	0.00
273	HAINE DRIVE - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	4.80
274	HALL ACRES ROAD - TX	Distribution		138.00	12.47		91.50	2			0	0.00
275	HAMLIN - TX	Distribution		69.00	13.00		7.50	3			0	0.00
276	HAMLIN PLASTERCO CELOTEX THR - TX	Distribution		69.00	13.00		2.01	3			0	0.00
277	HAMLIN REA - TX	Distribution		69.00	12.47		0.83	1			0	0.00
278	HAMLIN REA - TX	Distribution		69.00	12.40		1.67	2			0	0.00
279	HAMLIN SHELL PUMP - TX	Distribution		12.00	2.40		0.60	3			0	0.00
280	HAMLIN SHELL PUMP - TX	Distribution		69.00	7.20		1.00	3			0	0.00
281	HAMLIN TEXAS PIPE LINE - TX	Distribution		69.00	12.40		11.06	3			0	0.00
282	HAMLIN TEXAS PIPE LINE - TX	Distribution		69.00	13.09		0.83	1			0	0.00
283	HARLINGEN NO. 1 - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	2	9.60
284	HARLINGEN NO. 1 - TX	Distribution		69.00	12.47		56.00	2			0	0.00
285	HARLINGEN SW ST - TX	Transmission		138.00	69.00	13.09	130.00	1			0	0.00
286	HARLINGEN SW ST - TX	Transmission		69.00	13.09		50.00	2			0	0.00
287	HARLINGEN SW ST - TX	Transmission		12.00	0.00	0.00	0.00			STATCAP	2	9.60
288	HARROLD OIL FIELD - TX	Distribution		69.00	13.00		3.75	1			0	0.00
289	HARTFORD STREET - TX	Distribution		69.00	13.00		28.00	1			0	0.00
290	HASKELL - TX	Distribution		69.00	7.56		10.00	3			0	0.00
291	HASKELL TEXAS PIPE LINE - TX	Distribution		69.00	4.10		7.00	1			0	0.00
292	HATCHELL REA - TX	Distribution		69.00	12.47		0.83	1			0	0.00
293	HATCHELL REA - TX	Distribution		69.00	13.00		1.67	2			0	0.00
294	HAWLEY HUMBLE - EXXON - TX	Distribution		69.00	13.20		5.60	1			0	0.00
295	HEARD - TX	Distribution		69.00	2.40		4.50	3			0	0.00
296	HEARN ROAD - TX	Distribution		69.00	7.20		18.75	3			0	0.00
297	HEARN ROAD - TX	Distribution		69.00	12.47		28.00	1			0	0.00
298	HIDALGO - TX	Distribution		138.00	12.47		12.50	1			0	0.00
299	HIGHWAY 9 - TX	Transmission		138.00	70.50	12.47	200.00	1			0	0.00
300	HIGHWAY 9 - TX	Transmission		69.00	12.47		100.80	3			0	0.00
301	HOCHHEIM - TX	Distribution		69.00	2.40		2.49	3			0	0.00
302	HOLLY - TX	Distribution		138.00	12.47		44.80	1			0	0.00
303	HOMEPORT - TX	Distribution		138.00	12.47		28.00	1			0	0.00
304	HORNET 69KV - TX	Distribution		69.00	13.09		7.50	1			0	0.00
305	HUMBLE KEMPER EXXON - TX	Distribution		69.00	2.40		5.00	6			0	0.00
306	INDIAN MESA - TX	Distribution		138.00	13.09		3.33	2			0	0.00
307	INDUSTRIAL - TX	Distribution		69.00	12.47		56.00	2			0	0.00
308	INGLESIDE CITY - TX	Distribution		138.00	12.47		56.00	2			0	0.00
309	IRAAN - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	9.00
310	IRAAN - TX	Distribution		69.00	13.00		10.00	3			0	0.00
311	IRAAN AIR PRODUCTS - TX	Distribution		69.00	2.40		15.00	3			0	0.00
312	IRAAN AIR PRODUCTS - TX	Distribution		0.00	0.00	0.00	0.00			STATCAP	1	6.00
313	JAYTON - TX	Transmission		69.00	4.10		2.49	3			0	0.00
314	JOURDANTON - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	2.40
315	JOURDANTON - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	2	43.20
316	KARNES CITY - TX	Distribution		138.00	13.09		25.00	1			0	0.00
317	KENEDY - TX	Distribution		69.00	12.47		10.50	1			0	0.00
318	KENNEDY PONDER TAP - TX	Distribution		69.00	12.50		0.15	1			0	0.00
319	KINGSVILLE - TX	Distribution		138.00	12.47		56.00	2			0	0.00
320	KIRKLAND - TX	Distribution		69.00	2.40		0.75	3			0	0.00
321	KLEBERG - TX	Distribution		138.00	12.47		56.00	2			0	0.00
322	KLEBERG - TX	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	28.80
323	KNIPPA - TX	Distribution		69.00	7.20		5.00	3			0	0.00
324	KNOX CITY - TX	Distribution		69.00	13.00		6.60	2			0	0.00
325	KNOX CITY - TX	Distribution		69.00	13.09		2.50	1			0	0.00
326	KOCH UP RIVER - TX	Transmission		138.00	69.00	12.47	93.00	1			0	0.00
327	LA PALMA 138KV - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	100.00
328	LA PALMA 138KV - TX	Transmission		138.00	0.00	0.00	0.00			AIR CORE REACTOR	3	0.00
329	LA PALMA 345KV - TX	Transmission		345.00	138.00	13.80	672.00	1			0	0.00
330	LA PALMA 69 KV - TX	Transmission		138.00	69.00	12.00	297.00	2			0	0.00
331	LA PALMA STATCOM - TX	Transmission		23.00	0.00	0.00	0.00			AIR CORE REACTOR	6
332	LAKE PAULINE (TNC) - TX	Transmission		138.00	70.50	13.09	78.00	1			0	0.00
333	LAKESIDE (CP) - TX	Distribution		69.00	2.30		4.50	3			0	0.00
334	LANE CITY - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	28.80
335	LANE CITY PUMP - TX	Distribution		138.00	4.16		5.00	1			0	0.00
336	LAREDO HEIGHTS - TX	Distribution		138.00	12.47		80.00	2			0	0.00
337	LAREDO PLANT - TX	Transmission		138.00	12.47		28.00	1			0	0.00
338	LAREDO STATCOM - TX	Transmission		34.50	14.04		226.80	6			0	0.00
339	LEARY LANE - TX	Distribution		69.00	12.47		89.60	2			0	0.00
340	LIVE OAK - TX	Distribution		69.00	12.47		28.00	1			0	0.00
341	LOLITA - TX	Transmission		138.00	12.47		10.50	1			0	0.00
342	LON HILL - TX	Transmission		138.00	69.00	12.47	200.00	1			0	0.00
343	LON HILL - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	2
344	LON HILL - TX	Transmission		13.80	0.00	0.00	0.00			AIR CORE REACTOR	1	0.00
345	LON HILL - TX	Transmission		7.62	0.00	0.00	0.00			AIR CORE REACTOR	2	28.20
346	LON HILL - TX	Transmission		138.00	70.50	12.47	200.00	1			0	0.00
347	LONE STAR - TX	Distribution		69.00	12.47		2.49	3			0	0.00
348	LONE TREE - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.40
349	LONE TREE - TX	Distribution		69.00	12.47		1.00	1			0	0.00
350	LONGWORTH - TX	Distribution		69.00	12.47		6.25	1			0	0.00
351	LOS FRESNOS - TX	Distribution		138.00	12.47		50.00	2			0	0.00
352	LOTEBUSH - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	57.60
353	LOTEBUSH - TX	Transmission		20.78	0.00	0.00	0.00			REACTIVE SPECIAL	1	64.20
354	LYTLE - TX	Distribution		69.00	7.20		4.50	3			0	0.00
355	MAGILL 138KV - TX	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	28.80
356	MAGNOLIA - TX	Distribution		138.00	13.09		12.50	1			0	0.00
357	MAGRUDER - TX	Distribution		69.00	12.47		56.00	2			0	0.00
358	MALONE - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	2.40
359	MALONE - TX	Distribution		69.00	12.47		4.50	3			0	0.00
360	MAPLE STREET - TX	Distribution		138.00	13.09	13.20	25.00	1			0	0.00
361	MARATHON YATES - TX	Distribution		69.00	4.00		5.00	1			0	0.00
362	MARFA - TX	Transmission		69.00	13.00		3.33	2			0	0.00
363	MARFA - TX	Transmission		69.00	7.20		1.67	1			0	0.00
364	MARFA ALAMITO CREEK - TX	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	7.20
365	MARFA ALAMITO CREEK - TX	Transmission		138.00	69.00	13.80	46.70	1			0	0.00
366	MARFA ALAMITO CREEK - TX	Transmission		138.00	69.00	5.01	46.70	1			0	0.00
367	MARKHAM - TX	Distribution		69.00	12.47		6.00	1			0	0.00
368	MASON - TX	Transmission		138.00	70.50	13.09	78.00	1			0	0.00
369	MASON PHILLIPS - TX	Distribution		69.00	2.40		1.50	3			0	0.00
370	MASTERSON FIELD - TX	Distribution		69.00	13.00		6.25	1			0	0.00
371	MATADOR - TX	Transmission		69.00	13.00		5.01	3			0	0.00
372	MATHIS - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	2	2.40
373	MATHIS - TX	Distribution		69.00	12.47		19.90	2			0	0.00
374	MATTHEWS - TX	Distribution		69.00	12.47		5.01	3			0	0.00
375	MAVERICK - TX	Distribution		138.00	12.47		5.00	1			0	0.00
376	MAYBERRY - TX	Transmission		138.00	13.09		40.00	1			0	0.00
377	MAYBERRY - TX	Transmission		138.00	13.09		24.00	1			0	0.00
378	MAYO - TX	Distribution		138.00	13.09		25.00	1			0	0.00
379	MCCAMEY - TX	Transmission		138.00	12.47		9.38	1			0	0.00
380	MCCAMEY - TX	Transmission		12.00	4.10		2.49	3			0	0.00
381	MCCAMEY SHELL - TX	Distribution		69.00	4.10		7.50	1			0	0.00
382	MCCAMEY SHELL PUMP - TX	Distribution		12.00	4.16		1.00	3			0	0.00
383	MCCAMEY SHELL PUMP - TX	Distribution		12.00	2.40		1.00	2			0	0.00
384	MCCAMEY SHELL PUMP - TX	Distribution		12.00	4.10		0.50	1			0	0.00
385	MCCOLL ROAD - TX	Distribution		138.00	12.47		40.00	1			0	0.00
386	MCELROY - TX	Distribution		69.00	7.50		10.00	2			0	0.00
387	MCELROY - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	7.20
388	MCELROY - TX	Distribution		69.00	13.09		20.00	1			0	0.00
389	MCELROY - TX	Distribution		69.00	7.56		5.00	1			0	0.00
390	MCELROY - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	1.80
391	MCKENZIE ROAD - TX	Distribution		138.00	12.47		28.00	1			0	0.00
392	MCMURRY - TX	Distribution		69.00	13.00		45.00	2			0	0.00
393	MEDIO CREEK - TX	Distribution		138.00	12.47		10.50	1			0	0.00
394	MELVIN - TX	Distribution		69.00	13.09		9.38	1			0	0.00
395	MERKEL - TX	Distribution		69.00	13.00		9.40	1			0	0.00
396	MERKEL - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	12.00
397	MERTZON - TX	Distribution		69.00	13.09		5.00	1			0	0.00
398	MESA VIEW - TX	Distribution		138.00	13.09		50.00	1			0	0.00
399	MESQUITE - TX	Transmission		12.47	24.90	2.51	5.00	1			0	0.00
400	MIDWAY LANE - TX	Distribution		69.00	12.50		10.00	3			0	0.00
401	MILES (WT) - TX	Transmission		69.00	13.09		9.38	1			0	0.00
402	MILES (WT) - TX	Transmission		69.00	13.00		2.50	3			0	0.00
403	MILITARY HIGHWAY - TX	Transmission		34.50	14.04		151.27	4			0	0.00
404	MILITARY HIGHWAY - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	115.20
405	MILO - TX	Distribution		138.00	12.47		28.00	1			0	0.00
406	MINES ROAD - TX	Distribution		138.00	12.47		28.00	1			0	0.00
407	MINES ROAD - TX	Distribution		138.00	138.00	13.80	30.00	2			0	0.00
408	MINES ROAD - TX	Distribution		138.00	13.09	13.80	30.00	2			0	0.00
409	MOCKINGBIRD - TX	Distribution		138.00	13.09		25.00	1			0	0.00
410	MOORE FIELD - TX	Distribution		23.00	12.47	2.40	10.50	1			0	0.00
411	MOORE FIELD - TX	Distribution		26.00	12.47		10.50	1			0	0.00
412	MOORE FIELD - TX	Distribution		138.00	12.47		25.00	2			0	0.00
413	MORAN - TX	Distribution		69.00	13.10		3.00	3			0	0.00
414	MORRIS STREET - TX	Distribution		138.00	0.00	0.00	0.00			STATCAP	1
415	MORRIS STREET - TX	Distribution		138.00	12.47		179.20	4			0	0.00
416	MULBERRY CREEK - TX	Transmission		345.00	138.00	13.20	530.00	2			0	0.00
417	MULBERRY CREEK - TX	Transmission		12.00	0.00	0.00	0.00			REACTIVE SPECIAL	1
418	MULBERRY CREEK - TX	Transmission		138.00	0.00	0.00	0.00			AIR CORE REACTOR	3
419	MUNDAY (EAST-KNOX) - TX	Transmission		138.00	69.00	13.09	54.00	1			0	0.00
420	MUNDAY (EAST-KNOX) - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	28.80
421	MUNDAY (KNOX) - TX	Distribution		69.00	13.09		9.40	1			0	0.00
422	MUSTANG ISLAND - TX	Distribution		69.00	13.09		9.38	1			0	0.00
423	NAVAL BASE - TX	Distribution		138.00	70.50	13.09	120.00	1			0	0.00
424	NELSON SHARPE III - TX	Transmission		345.00	138.00	13.80	675.00	1			0	0.00
425	NELSON SHARPE III - TX	Transmission		138.00	138.00		150.00	1			0	0.00
426	NELSON SHARPE III - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	86.40
427	NORDHEIM - TX	Distribution		138.00	13.09		12.50	1			0	0.00
428	NORMANNA CST - TX	Distribution		69.00	12.47		2.49	3			0	0.00
429	NORTH ALAMO - TX	Distribution		138.00	13.09		25.00	1			0	0.00
430	NORTH ALAMO - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	2	4.80
431	NORTH ALAMO - TX	Distribution		138.00	12.47		22.40	1			0	0.00
432	NORTH BRADY - TX	Transmission		69.00			10.00	2			0	0.00
433	NORTH BRADY - TX	Transmission		69.00	2.20		10.00	2			0	0.00
434	NORTH EDINBURG - TX	Transmission		345.00	138.00	12.00	1200.00	2			0	0.00
435	NORTH EDINBURG - TX	Transmission		138.00	69.00	12.00	83.00	1			0	0.00
436	NORTH EDINBURG - TX	Transmission		138.00	69.00	13.20	72.80	1			0	0.00
437	NORTH EDINBURG - TX	Transmission		345.00	0.00	0.00	0.00			AIR CORE REACTOR	3
438	NORTH EDINBURG - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	50.00
439	NORTH EDINBURG - TX	Transmission		13.20						REACTOR	1	14.80
440	NORTH EDINBURG - TX	Transmission		345.00	0.00	0.00	0.00			STATCAP	1	933.00
441	NORTH EDINBURG - TX	Transmission		69.00	12.47		28.00	1			0	0.00
442	NORTH EDINBURG - TX	Transmission		69.00	13.09		25.00	1			0	0.00
443	NORTH ELLA - TX	Distribution		69.00	2.30		3.00	3			0	0.00
444	NORTH MCALLEN - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	3	12.00
445	NORTH MCALLEN - TX	Distribution		138.00	12.47		124.80	3			0	0.00
446	NORTH MCCAMEY - TX	Transmission		138.00	13.09		28.00	1			0	0.00
447	NORTH MERCEDES - TX	Distribution		138.00	13.09		50.00	2			0	0.00
448	NORTH MERCEDES - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	2.40
449	NORTH PADRE ISLE. 69 - TX	Distribution		69.00	13.00		28.00	1			0	0.00
450	NORTH PADRE ISLE. 69 - TX	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	14.40
451	NORTH PADRE ISLE. 69 - TX	Distribution		69.00	12.47		28.00	1			0	0.00
452	NORTH VICTORIA - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	2.40
453	NORTH VICTORIA - TX	Distribution		69.00	12.47		89.60	2			0	0.00
454	NORTH WESLACO - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	2.40
455	NORTH WESLACO - TX	Distribution		138.00	12.47		12.50	1			0	0.00
456	OCONNER - TX	Distribution		69.00	12.47		2.50	1			0	0.00
457	ODEM - TX	Distribution		69.00	12.47		10.50	1			0	0.00
458	OKLAUNION 345-TNC - TX	Transmission		138.00	13.09		8.40	1			0	0.00
459	OKLAUNION HVDC INTER - TX	Transmission		345.00	26.40	26.40	540.40	2			0	0.00
460	OKLAUNION HVDC INTER - TX	Transmission		345.00	0.00	0.00	0.00			REACTIVE SPECIAL	8
461	OKLAUNION HVDC INTER - TX	Transmission		345.00	26.40	26.40	270.20	0	1		0	0.00
462	OLEANDER - TX	Transmission		138.00	70.50	12.47	130.00	1			0	0.00
463	OLMITO - TX	Distribution		138.00	12.47		25.00	1			0	0.00
464	OVER STREET - TX	Distribution		69.00	13.09	4.16	25.00	1			0	0.00
465	OWLS - TX	Distribution		138.00	69.00	13.09	90.00	1			0	0.00
466	OZONA - TX	Distribution		69.00	13.00		12.50	1			0	0.00
467	PADUCAH - TX	Distribution		69.00	12.50		3.75	3			0	0.00
468	PAINT CREEK PLANT - TX	Transmission		138.00	70.50	36.20	90.00	1			0	0.00
469	PAINT ROCK - TX	Distribution		69.00	4.10		333.67	3			0	0.00
470	PAISANO - TX	Distribution		69.00	12.50		0.50	1			0	0.00
471	PALACIOS - TX	Distribution		69.00	12.47		10.50	1			0	0.00
472	PALMHURST - TX	Distribution		138.00	12.47		86.50	2			0	0.00
473	PALMHURST - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	2	7.20
474	PALMVIEW - TX	Distribution		138.00	12.47		68.00	2			0	0.00
475	PAN AMERICAN - TX	Distribution		69.00	2.40		0.15	1			0	0.00
476	PANDALE 69KV SUB - TX	Distribution		69.00	13.09		12.00	1			0	0.00
477	PARKER - TX	Distribution		69.00	12.47		4.50	3			0	0.00
478	PEACOCK (WT) - TX	Distribution		69.00	2.40		0.60	3			0	0.00
479	PEARSALL - TX	Distribution		69.00	12.47		18.80	2			0	0.00
480	PECAN BAYOU - TX	Distribution		138.00	12.47		28.00	1			0	0.00
481	PECOS VALLEY - TX	Distribution		69.00	12.50		1.00	3			0	0.00
482	PERKINS-PROTHO - TX	Distribution		69.00	12.50		1.00	3			0	0.00
483	PETTUS - TX	Distribution		69.00	24.90		10.50	1			0	0.00
484	PETTUS - TX	Distribution		69.00	13.09		12.50	1			0	0.00
485	PHARAOH - TX	Distribution		138.00	12.47		56.00	2			0	0.00
486	PHARR - TX	Transmission		138.00	12.47		74.60	2			0	0.00
487	PHARR STATCOM - TX	Transmission		23.00	0.00	0.00	0.00			AIR CORE REACTOR	6
488	PICACHO - TX	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	28.80
489	PLACEDO - TX	Distribution		69.00	12.47		6.00	1			0	0.00
490	PLEASANTON - TX	Transmission		138.00	70.50	13.09	54.00	1			0	0.00
491	PLEASANTON - TX	Transmission		138.00	12.47		56.00	2			0	0.00
492	POINT COMFORT - TX	Distribution		69.00	12.47		3.00	2			0	0.00
493	POINT COMFORT - TX	Distribution		69.00	12.00		1.50	1			0	0.00
494	POLK AVENUE - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	6	24.00
495	POLK AVENUE - TX	Distribution		138.00	12.47		91.50	2			0	0.00
496	PORT ARANSAS - TX	Distribution		69.00	12.47		56.00	2			0	0.00
497	PORT ISABEL SWITCH - TX	Transmission		138.00	12.47		9.40	1			0	0.00
498	PORT ISABEL SWITCH - TX	Transmission		12.00	0.00	0.00	0.00			STATCAP	2	4.80
499	PORT ISABEL SWITCH - TX	Transmission		138.00	13.09		25.00	1			0	0.00
500	PORT LAVACA - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	2.40
501	PORT LAVACA - TX	Distribution		69.00	13.09		9.38	1			0	0.00
502	PORT LAVACA - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	7.20
503	PORT LAVACA - TX	Distribution		69.00	12.47		7.50	1			0	0.00
504	PORTLAND (CP) - TX	Distribution		138.00	12.47		56.00	2			0	0.00
505	POWELL FIELD - TX	Distribution		69.00	13.09		15.00	1			0	0.00
506	POWELL FIELD - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	2	9.00
507	POWELL SHELL - TX	Distribution		69.00	4.00		5.00	3			0	0.00
508	PRAIRIE PUMP - TX	Distribution		69.00	12.47		4.50	3			0	0.00
509	PREMONT - TX	Distribution		13.20	0.00	0.00	0.00			REACTIVE SPECIAL	1
510	PREMONT - TX	Distribution		69.00	12.47		21.10	2			0	0.00
511	PRIMERA - TX	Distribution		138.00	13.09	138.00	160.00	6			0	0.00
512	PRIMERA - TX	Distribution		138.00	138.00	138.00	320.00	12			0	0.00
513	PUEBLO - TX	Distribution		138.00	12.47		30.00	1			0	0.00
514	PUNCHER 69KV - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	7.20
515	PUNCHER 69KV - TX	Distribution		69.00	13.09		7.50	1			0	0.00
516	PUTNAM - TX	Transmission		138.00	138.00		150.00	1			0	0.00
517	PUTNAM - TX	Transmission		138.00	70.50	12.47	90.00	1			0	0.00
518	PUTNAM - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	28.80
519	PUTNAM 69KV - TX	Distribution		69.00	12.50		3.75	1			0	0.00
520	QUANAH - TX	Distribution		69.00	12.00		15.00	3			0	0.00
521	RACHAL - TX	Distribution		138.00	12.47		12.50	1			0	0.00
522	RADIUM - TX	Transmission		138.00	69.00	7.83	62.50	1			0	0.00
523	RAINEY CREEK - TX	Distribution		138.00	13.09	13.80	28.00	1			0	0.00
524	RANDADO - TX	Distribution		138.00	12.47		12.50	1			0	0.00
525	RANGERVILLE - TX	Distribution		23.00	12.47		7.84	1			0	0.00
526	RANGERVILLE - TX	Distribution		69.00	13.09		9.38	1			0	0.00
527	RANGERVILLE - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	7.20
528	RANGERVILLE - TX	Distribution		69.00	12.47		8.40	1			0	0.00
529	RANKIN - TX	Distribution		69.00	13.09		10.00	1			0	0.00
530	REBECCA LANE - TX	Distribution		138.00	13.09	5.67	25.00	1			0	0.00
531	REFUGIO - TX	Distribution		138.00	70.50	13.09	54.00	1			0	0.00
532	REFUGIO - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	4	9.60
533	REFUGIO - TX	Distribution		69.00	12.47		21.00	2			0	0.00
534	RINCON - TX	Transmission		138.00	69.00	13.80	84.00	1			0	0.00
535	RIO BRAVO - TX	Distribution		138.00	24.90		10.50	1			0	0.00
536	RIO BRAVO - TX	Distribution		26.00	12.47		14.00	2			0	0.00
537	RIO BRAVO - TX	Distribution		138.00	24.94		12.50	1			0	0.00
538	RIO BRAVO - TX	Distribution		138.00	0.00	0.00	0.00			STATCAP	1
539	RIO BRAVO - TX	Distribution		26.00	12.47		7.00	0	1		0	0.00
540	RIO GRANDE CITY - TX	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	28.80
541	RIO GRANDE CITY - TX	Distribution		69.00	12.47		28.00	1			0	0.00
542	RIO GRANDE CITY - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	4	9.60
543	RIO GRANDE CITY - TX	Distribution		138.00	70.50	12.47	90.00	1			0	0.00
544	RIO HONDO SW STA - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	104.64
545	RIO HONDO SW STA - TX	Transmission		345.00	0.00	0.00	0.00			AIR CORE REACTOR	3
546	RIO HONDO SW STA - TX	Transmission		345.00	138.00	13.00	600.00	1			0	0.00
547	RIO HONDO SW STA - TX	Transmission		345.00	138.00	13.80	675.00	1			0	0.00
548	RIO PECOS PLANT (GIRVIN) - TX	Transmission		138.00	0.00	0.00	0.00			AIR CORE REACTOR	7	140.00
549	RIO PECOS PLANT (GIRVIN) - TX	Transmission		138.00	70.50	13.09	54.00	1			0	0.00
550	RIO PECOS PLANT (GIRVIN) - TX	Transmission		138.00	69.00	13.80	62.50	1			0	0.00
551	RIO PECOS PLANT (GIRVIN) - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	28.80
552	RIO RICO - TX	Distribution		69.00	12.47		18.00	2			0	0.00
553	RIO RICO - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	10.80
554	RIO RICO - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	2.40
555	RISING STAR - TX	Distribution		69.00	13.00		3.75	1			0	0.00
556	RIVERSIDE (CP) - TX	Distribution		69.00	2.30		4.50	3			0	0.00
557	ROARING SPRINGS - TX	Distribution		69.00	12.47		6.25	1			0	0.00
558	ROBERT LEE - TX	Distribution		69.00	13.00		10.50	1			0	0.00
559	ROBERTSON PRISON - TX	Distribution		69.00	7.50		9.30	3			0	0.00
560	ROBY - TX	Transmission		69.00	13.00		6.20	1			0	0.00
561	ROCHESTER - TX	Distribution		69.00	12.47		5.00	1			0	0.00
562	ROCKPORT (CP) - TX	Transmission		138.00	69.00	13.09	108.00	2			0	0.00
563	ROCKSPRINGS ATL - TX	Distribution		69.00	12.47		2.70	3			0	0.00
564	RODD FIELD - TX	Distribution		138.00	12.47		91.50	2			0	0.00
565	ROMA - TX	Transmission		138.00	12.47		25.00	2			0	0.00
566	ROMA - TX	Transmission		12.00	0.00	0.00	0.00			STATCAP	1	2.40
567	ROTAN - TX	Distribution		69.00	7.56		9.20	2			0	0.00
568	ROTAN - TX	Distribution		69.00	13.00		3.33	1			0	0.00
569	ROTAN GYP MILL EAST - TX	Distribution		12.00	0.48		3.00	6			0	0.00
570	ROUND TOP - TX	Distribution		69.00	13.00		12.50	1			0	0.00
571	ROWENA - TX	Distribution		69.00	13.00		4.69	1			0	0.00
572	RUNGE - TX	Distribution		138.00	13.09		12.50	1			0	0.00
573	RUSSEK STREET - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	3	46.80
574	RUSSEK STREET - TX	Transmission		138.00	13.09		50.00	2			0	0.00
575	RUSTHILL - TX	Transmission		138.00	70.50	13.09	78.00	1			0	0.00
576	S.A. AVENUE N. - TX	Distribution		69.00	13.00		22.40	1			0	0.00
577	S.A. BEN FICKLIN - TX	Distribution		138.00	13.09		28.00	1			0	0.00
578	S.A. COKE ST - TX	Distribution		138.00	13.09		28.00	1			0	0.00
579	S.A. COLLEGE HILLS WEST - TX	Transmission		138.00	69.00	13.53	62.50	1			0	0.00
580	S.A. COLLEGE HILLS WEST - TX	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	21.60
581	S.A. COLLEGE HILLS WEST - TX	Transmission		138.00	13.09		28.00	1			0	0.00
582	S.A. COLLEGE HILLS WEST - TX	Transmission		138.00	13.09		22.40	1			0	0.00
583	S.A. CONCHO PLANT - TX	Transmission		138.00	12.47		28.00	1			0	0.00
584	S.A. EMERSON ST. - TX	Distribution		69.00	13.00		28.00	1			0	0.00
585	S.A. EMERSON ST. - TX	Distribution		12.00	35.40	13.80	30.00	1			0	0.00
586	S.A. GRAPE CREEK - TX	Distribution		69.00	13.09		10.00	3			0	0.00
587	S.A. HIGHLAND - TX	Distribution		138.00	13.09		28.00	1			0	0.00
588	S.A. JACKSON ST. - TX	Distribution		69.00	13.00		56.00	2			0	0.00
589	S.A. LAKE DRIVE - TX	Distribution		138.00	13.09		28.00	1			0	0.00
590	S.A. MATHIS AIR FIELD - TX	Distribution		69.00	4.36		9.40	1			0	0.00
591	S.A. NORTH - TX	Transmission		0.00	0.00	0.00	0.00			STATCAP	2	24.00
592	S.A. NORTH - TX	Transmission		69.00	13.00		28.00	1			0	0.00
593	S.A. NORTH - TX	Transmission		138.00	69.00	6.57	62.50	1			0	0.00
594	S.A. PAULANN - TX	Distribution		138.00	12.47		25.00	1			0	0.00
595	S.A. RED CREEK - TX	Transmission		345.00	138.00	13.80	900.00	2			0	0.00
596	S.A. RED CREEK - TX	Transmission		345.00	138.00	13.20	250.00	0	1		0	0.00
597	S.A. RED CREEK - TX	Transmission		0.00	0.00	0.00	0.00			STATCAP	2	50.40
598	S.A. RED CREEK - TX	Transmission		345.00	345.00	345.00				REACTOR	1	100.00
599	S.A. SOUTH - TX	Distribution		0.00	0.00	0.00	0.00			STATCAP	1	2.40
600	S.A. SOUTH - TX	Distribution		69.00	12.47		28.00	1			0	0.00
601	S.A. SOUTH - TX	Distribution		138.00	13.09			1			0	0.00
602	S.A. SOUTHLAND HILLS - TX	Distribution		138.00	13.09		28.00	1			0	0.00
603	SABINAL - TX	Distribution		69.00	7.20		4.67	3			0	0.00
604	SAGE - TX	Distribution		69.00	12.50		25.00	1			0	0.00
605	SAN ANGELO POWER - TX	Transmission		138.00	69.00	13.09	416.00	4			0	0.00
606	SAN ANGELO POWER - TX	Transmission		138.00	70.50	13.09	416.00	4			0	0.00
607	SAN BENITO - TX	Distribution		69.00	12.47		25.00	1			0	0.00
608	SAN BENITO - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	3	12.00
609	SAN BENITO - TX	Distribution			13.09		25.00	1			0	0.00
610	SAN DIEGO - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	2	4.80
611	SAN DIEGO - TX	Distribution		69.00	13.09		12.50	1			0	0.00
612	SAN DIEGO - TX	Distribution		69.00	12.47		9.40	1			0	0.00
613	SAN YGNACIO - TX	Distribution		138.00	12.47		6.25	1			0	0.00
614	SANTA ANNA - TX	Transmission		69.00	13.09		6.25	1			0	0.00
615	SANTA ANNA - TX	Transmission		138.00	69.00	14.40	33.60	1			0	0.00
616	SANTA RITA - TX	Distribution		69.00	13.09		30.00	2			0	0.00
617	SANTO NINO - TX	Distribution		138.00	12.47		58.00	2			0	0.00
618	SARAGOSA - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	150.00
619	SARAGOSA - TX	Distribution		138.00	70.50	13.09	54.00	1			0	0.00
620	SARAGOSA - TX	Distribution		138.00	69.00	13.09	15.00	1			0	0.00
621	SEAWALL - TX	Distribution		69.00	12.47		9.40	1			0	0.00
622	SEAWALL - TX	Distribution		69.00	13.09		12.50	1			0	0.00
623	SHAFTER MINE - TX	Distribution		69.00	12.00		22.50	3			0	0.00
624	SHARYLAND - TX	Distribution		138.00	12.47		87.30	2			0	0.00
625	SHEFFIELD (WT) - TX	Distribution		69.00	7.56		10.01	12			0	0.00
626	SHELTON STREET - TX	Distribution		69.00	13.00		50.00	2			0	0.00
627	SIERRA VISTA - TX	Distribution		138.00	13.09		25.00	1			0	0.00
628	SILVER - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	7.20
629	SILVER - TX	Distribution			0.00	0.00	0.00			STATCAP	1
630	SILVER - TX	Distribution		69.00	12.47		25.00	1			0	0.00
631	SINTON - TX	Distribution		69.00	12.47		19.90	2			0	0.00
632	SKID TCC-1010 - TX	Distribution		138.00	69.00	36.20	18.00	1			0	0.00
633	SKIDMORE - TX	Distribution		69.00	13.09		5.75	1			0	0.00
634	SMITH - TX	Distribution		69.00	2.30		4.50	3			0	0.00
635	SOLSTICE - TX	Transmission		345.00	138.00	13.80		1			0	0.00
636	SOLSTICE - TX	Transmission		138.00	138.00		150.00	1			0	0.00
637	SOLSTICE - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	14.40
638	SOLSTICE - TX	Transmission		345.00	138.00	34.50	405.00	1			0	0.00
639	SONORA - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	57.60
640	SONORA - TX	Transmission		69.00	13.00		10.00	3			0	0.00
641	SONORA - TX	Transmission		138.00	69.00	13.20	41.67	1			0	0.00
642	SONORA ATLANTIC - TX	Distribution		69.00	13.09		5.00	1			0	0.00
643	SONORA ATLANTIC - TX	Distribution		69.00	12.00		1.50	3			0	0.00
644	SONORA CITY - TX	Transmission		69.00	13.00		12.50	1			0	0.00
645	SONORA CITY - TX	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	12.00
646	SOUTH CROSS - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	3.60
647	SOUTH CROSS - TX	Distribution		69.00	4.10		7.50	3			0	0.00
648	SOUTH MCALLEN - TX	Transmission		12.00	0.00	0.00	0.00			STATCAP	2	4.80
649	SOUTH MCALLEN - TX	Transmission		138.00	12.47		50.00	2			0	0.00
650	SOUTH MCALLEN - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	50.40
651	SOUTH MISSION - TX	Distribution		138.00	12.47		50.00	2			0	0.00
652	SOUTH PADRE ISLAND - TX	Distribution		138.00	12.47		56.00	2			0	0.00
653	SOUTH SANTA ROSA - TX	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	28.80
654	SOUTH SANTA ROSA - TX	Distribution		138.00	12.47		50.00	2			0	0.00
655	SOUTHEAST EDINBURG - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	1	2.40
656	SOUTHEAST EDINBURG - TX	Distribution		138.00	12.47		56.00	2			0	0.00
657	SOUTHSIDE - TX	Distribution		138.00	12.47		112.00	4			0	0.00
658	SOUTHWEST VERNON - TX	Transmission		138.00	69.00	13.09	130.00	1			0	0.00
659	SOUTHWEST VERNON - TX	Transmission		138.00	69.00	14.40	75.00	0	1		0	0.00
660	SPUDDER FLAT - TX	Distribution		138.00	12.47		9.38	1			0	0.00
661	SPUR - TX	Distribution		69.00	2.52		2.00	2			0	0.00
662	SPUR - TX	Distribution		69.00	4.10		1.00	1			0	0.00
663	SPUR - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	12.00
664	SPUR - TX	Distribution		138.00	69.00	5.10	56.00	1			0	0.00
665	SPUR - TX	Distribution		69.00	7.56		2.50	3			0	0.00
666	STAMFORD - TX	Distribution		69.00	13.00		28.00	1			0	0.00
667	STAMFORD PUMP - TX	Distribution		69.00	12.50		0.83	1			0	0.00
668	STAMFORD PUMP - TX	Distribution		69.00	13.10		1.00	1			0	0.00
669	STAMFORD PUMP - TX	Distribution		69.00	13.09		0.83	1			0	0.00
670	STERLING CITY - TX	Transmission		69.00	13.00		7.00	1			0	0.00
671	STEVENS - TX	Distribution		69.00	4.16		21.00	2			0	0.00
672	STEWART ROAD - TX	Transmission		345.00	138.00	34.50	675.00	2			0	0.00
673	STEWART ROAD - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	57.60
674	STEWART ROAD - TX	Transmission		138.00	69.00	12.00	33.00	1			0	0.00
675	STRATTON (CP) - TX	Transmission		138.00	69.00	12.00		1			0	0.00
676	SUN VALLEY - TX	Distribution		69.00	12.50		2.50	3			0	0.00
677	SUNCHASE - TX	Distribution		138.00	12.47		28.00	1			0	0.00
678	SWENSON - TX	Distribution		69.00	12.50		0.65	3			0	0.00
679	TAFT - TX	Distribution		69.00	7.20		5.01	3			0	0.00
680	TAFT - TX	Distribution		69.00	12.47		10.50	1			0	0.00
681	TALPA ATLANTIC - TX	Distribution		69.00	13.10		500.50	2			0	0.00
682	TALPA ATLANTIC - TX	Distribution		69.00	13.00		501.50	4			0	0.00
683	TALPA ATLANTIC - TX	Distribution		69.00	7.20		1.00	3			0	0.00
684	TANKERSLEY - TX	Distribution		69.00	13.00		4.69	1			0	0.00
685	TEXAS-NEW MEXICO - TX	Distribution		69.00	4.00		2.50	3			0	0.00
686	TEXAS-NEW MEXICO - TX	Distribution		69.00	13.09		20.00	1			0	0.00
687	THREE RIVERS (COR) - TX	Transmission		69.00	12.47		18.80	2			0	0.00
688	THREE RIVERS (COR) - TX	Transmission		12.00	0.00	0.00	0.00			STATCAP	3	7.20
689	THREE RIVERS (COR) - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	2
690	THREE RIVERS (COR) - TX	Transmission		138.00	70.50	13.09	78.00	1			0	0.00
691	THROCKMORTON - TX	Distribution		69.00	13.00		4.68	1			0	0.00
692	THROCKMORTON WOODSON OIL CO - TX	Distribution		69.00	7.20		1.00	3			0	0.00
693	TRENT (WT) - TX	Distribution		69.00	7.20		3.00	3			0	0.00
694	TRUSCOTT CITY - TX	Distribution		69.00	12.47		0.33	1			0	0.00
695	TRUSCOTT CITY - TX	Distribution		69.00	7.20		0.67	2			0	0.00
696	TRUSCOTT HUMBLE - TX	Distribution		34.50	2.30		0.90	3			0	0.00
697	TURKEY - TX	Distribution		69.00	13.00		4.20	1			0	0.00
698	TUSCOLA - TX	Distribution		69.00	12.47		9.38	1			0	0.00
699	TUSCOLA - TX	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.40
700	TUSCOLA - TX	Distribution		69.00	13.00		9.38	1			0	0.00
701	TWILIGHT TRAILS - TX	Distribution		138.00	13.09		20.00	1			0	0.00
702	TYNAN - TX	Distribution		69.00	13.09			1			0	0.00
703	UNIVERSITY - TX	Distribution		138.00	13.09		25.00	1			0	0.00
704	UNIVERSITY - TX	Distribution		138.00	12.47		28.00	1			0	0.00
705	UVALDE - TX	Transmission		138.00	0.00	0.00	0.00			AIR CORE REACTOR	3
706	UVALDE - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	14.40
707	UVALDE - TX	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.40
708	UVALDE - TX	Transmission		138.00	69.00	13.09	54.00	1			0	0.00
709	UVALDE - TX	Transmission		138.00	12.47		56.00	2			0	0.00
710	VALENTINE TAP - TX	Distribution		69.00	7.20		1.00	2			0	0.00
711	VALENTINE TAP - TX	Distribution		69.00	13.00		0.50	1			0	0.00
712	VALERA - TX	Distribution		69.00	12.47		0.50	3			0	0.00
713	VERNON MAIN ST. SUB. - TX	Transmission		138.00	69.00		62.50	1			0	0.00
714	VERNON MAIN ST. SUB. - TX	Transmission		69.00	13.00		10.00	1			0	0.00
715	VERNON MAIN ST. SUB. - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	28.80
716	VERNON PLANT SUB - TX	Distribution		69.00	12.47		14.00	1			0	0.00
717	VICTORIA PLANT - TX	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	28.80
718	VICTORIA PLANT - TX	Transmission		138.00	69.00	12.47	374.00	2			0	0.00
719	VICTORIA PLANT - TX	Transmission		69.00	12.00		9.38	1			0	0.00
720	VICTORIA PLANT - TX	Transmission		69.00	12.47		47.88	3			0	0.00
721	VILLA CAVAZOS - TX	Distribution		138.00	12.47		25.00	1			0	0.00
722	VOGEL STREET - TX	Distribution		69.00	13.00		25.00	1			0	0.00
723	WADSWORTH - TX	Distribution		138.00	12.47		10.50	1			0	0.00
724	WAGGONER REFINERY - TX	Distribution		69.00	7.20		2.00	2			0	0.00
725	WAGGONER REFINERY - TX	Distribution		69.00	7.00		1.00	1			0	0.00
726	WALNUT STREET - TX	Distribution		69.00	13.00		20.00	1			0	0.00
727	WASHINGTON STREET - TX	Distribution		69.00	12.47		100.80	3			0	0.00
728	WATERWORKS (CP) - TX	Distribution		69.00	2.30		3.00	3			0	0.00
729	WATERWORKS (CP) - TX	Distribution		69.00	0.46		1.50	3			0	0.00
730	WEAVER ROAD - TX	Distribution		69.00	12.47		9.38	1			0	0.00
731	WEIL TRACT - TX	Distribution		138.00	12.47		44.80	1			0	0.00
732	WEIL TRACT - TX	Distribution		138.00	0.00	0.00	0.00			STATCAP	2	57.60
733	WEINERT - TX	Distribution		69.00	13.09		2.50	1			0	0.00
734	WESLACO SWITCH - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	115.20
735	WESLACO SWITCH - TX	Transmission		138.00	0.00	0.00	0.00			REACTOR	3
736	WESLACO UNIT - TX	Distribution		138.00	12.47		89.60	2			0	0.00
737	WESLACO UNIT - TX	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	28.80
738	WESMER - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	2	9.60
739	WESMER - TX	Distribution		138.00	12.47		56.00	2			0	0.00
740	WEST HARLINGEN - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	3	11.25
741	WEST HARLINGEN - TX	Distribution		69.00	12.47		56.00	2			0	0.00
742	WEST MCALLEN - TX	Distribution		12.00	0.00	0.00	0.00			STATCAP	4	19.20
743	WEST MCALLEN - TX	Distribution		138.00	12.47		89.60	2			0	0.00
744	WEST OSO - TX	Distribution		138.00	12.47		28.00	1			0	0.00
745	WEST TEXAS GULF - TX	Distribution		69.00	4.36		6.00	3			0	0.00
746	WESTSIDE SW - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	57.60
747	WHITEPOINT - TX	Transmission		138.00	69.00	12.00	92.90	1			0	0.00
748	WHITEPOINT - TX	Transmission		345.00	138.00	13.80	480.00	1			0	0.00
749	WHITEPOINT - TX	Transmission		138.00	0.00	0.00	0.00			AIR CORE REACTOR	6	86.40
750	WINTERS - TX	Distribution		69.00	12.47		10.50	1			0	0.00
751	WOLFBERRY - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	28.80
752	WOODSBORO - TX	Distribution		69.00	12.47		8.40	1			0	0.00
753	WOOLDRIDGE - TX	Distribution		138.00	12.47		28.00	1			0	0.00
754	WORMSER ROAD SW - TX	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	14.40
755	YORKTOWN - TX	Distribution		138.00	13.09		25.00	2			0	0.00
756	ZACATE CREEK - TX	Distribution		138.00	12.47		40.00	1			0	0.00
757	ZAPATA - TX	Distribution		138.00	13.09		25.00	2			0	0.00
758	ZAPATA - TX	Distribution		138.00	12.47		25.00	1			0	0.00
759	TotalTransmissionSubstationMember											4,549
760	Total											4,549

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 212 East 6th Street, Tulsa, Oklahoma 740119
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: TX Date of Incorporation: 2016-12-31 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. AEP Texas is a public utility engaged in the purchase, sale, transmission and distribution of electricity in the State of Texas. Under the Texas electric restructuring legislation, we completed the final stage of exiting the generation business and have ceased serving retail load. AEP Texas' remaining generating capacity that is not deactivated has been transferred to an affiliated company at our cost pursuant to a 20-year agreement.
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	David M. Feinberg, Secretary	Columbus, Ohio
4	Paul Chodak III, Vice President	Columbus, Ohio
5	Charles R Patton, Vice President	Columbus, Ohio
6	Therace M. Risch, Viice President	Columbus, Ohio
7	Julia A.Sloat, Chief Financial Officer and Vice President	Columbus, Ohio
8	Toby L. Thomas, Vice President	Columbus, Ohio
9	Judith E. Talavera, President and Chief Operating Officer	Columbus, Ohio
10	The Respondent does not have an Executive Committee.

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


None
TCC-T acquired Rangerville Station from South Texas ElectricCo-operative for approximately $1,364,396.80 on December 2021.The amount was already reported on Work order, however the acquisition flowing through account 1020001
None
None

None
None
None
None
Not Used
Julia A Sloat elected as Chief Financial Officer and Director effective on Jan 01, 2021 Julie A Sherwood elected as Treasurer effective on Jan 01, 2021 Daniel E Mueller elected as Assistant Vice President - Tax effective on Mar 24, 2021 Judith E Talavera, elected as Director effective on 05-02-2021 William R Black, elected as Vice President - External Affairs effective on 04-01-2021 Scott P Moore, Resigned on 05-19-2021 Therace M Risch, elected as Vice President and Director effective on 07-03-2021 Charles E Zebula, elected as Vice President effective on 07-03-2021 Toby L Thomas, elected as Vice President and Director effective on 07-31-2021 Mark C McCullough, Resigned on 07-30-2021 Brian X Tierney, Resigned on 07-01-2021
Proprietary capital ratio exceeds 30%

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.

In 2016, AEP Utilities, Inc. (formerly Central and South West Corporation, a registered holding company) owned 100% of the outstanding shares of common stock of both AEP Texas Central Company and AEP Texas North Company. On December 31, 2016, those companies merged into AEP Utilities, Inc., and AEP Utilities, Inc. name was changed to AEP Texas. American Electric Power Company, Inc., a registered holding company, owned 100% of AEP Utilities, Inc.'s outstanding shares of common stock during 2016 and owns 100% of AEP Texas outstanding common stock.

CORPORATIONS CONTROLLED BY RESPONDENT
Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming any intermediaries involved. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests. Definitions See the Uniform System of Accounts for a definition of control. Direct control is that which is exercised without interposition of an intermediary. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line No.	NameOfCompanyControlledByRespondent Name of Company Controlled (a)	CompanyControlledByRespondentKindOfBusinessDescription Kind of Business (b)	VotingStockOwnedByRespondentPercentage Percent Voting Stock Owned (c)	FootnoteReferences Footnote Ref. (d)
1	AEP Texas North Generation Company, LLC	Non Regulated Generation	100
2	AEP Texas Central Transition Funding LLC	Financing	100
3	AEP Texas Central Transition Funding II LLC	Financing	100
4	AEP Texas Central Transition Funding III LLC	Financing	100
5	AEP Texas Restoration Funding LLC	Financing	100

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
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

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
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

INFORMATION ON FORMULA RATES - Formula Rate Variances
If a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from amounts reported in the Form 1. The footnote should provide a narrative description explaining how the "rate" (or billing) was derived if different from the reported amount in the Form 1. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.
Line No.	PageNumberOfFormulaRateVariances Page No(s). (a)	ScheduleOfFormulaRateVariances Schedule (b)	ColumnOfFormulaRateVariances Column (c)	LineNumberOfFormulaRateVariances Line No. (d)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44

COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line No.	Title of Account (a)	Ref. Page No. (b)	Current Year End of Quarter/Year Balance (c)	Prior Year End Balance 12/31 (d)
1	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlant Utility Plant (101-106, 114)	200	11,855,056,606	10,862,462,358
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	552,902,898.00	614,606,247
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		12,407,959,503	11,477,068,605
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	2,368,625,863.00	2,230,251,256
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		10,039,333,640	9,246,817,349
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)		10,039,333,640	9,246,817,349
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)		72,113,730	66,379,270
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)
17	OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS
18	NonutilityProperty Nonutility Property (121)		1,953,794	1,966,020
19	AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Prov. for Depr. and Amort. (122)		972,799	996,173
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224	26,348,158	26,552,137
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances	228
24	OtherInvestments Other Investments (124)		15,329,062	14,875,449
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)		116,978,318	90,675,002
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)		159,636,534	133,072,435
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)
36	SpecialDeposits Special Deposits (132-134)		678,845	471,187
37	WorkingFunds Working Fund (135)		100,000	100,000
38	TemporaryCashInvestments Temporary Cash Investments (136)
39	NotesReceivable Notes Receivable (141)
40	CustomerAccountsReceivable Customer Accounts Receivable (142)		121,846,932	109,930,891
41	OtherAccountsReceivable Other Accounts Receivable (143)		40,896	34,498
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		4,094,496	159,939
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)		7,688,270	4,928,438
45	FuelStock Fuel Stock (151)	227
46	FuelStockExpensesUndistributed Fuel Stock Expenses Undistributed (152)	227
47	Residuals Residuals (Elec) and Extracted Products (153)	227
48	PlantMaterialsAndOperatingSupplies Plant Materials and Operating Supplies (154)	227	73,867,192	70,046,376
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
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)		3,480,282	2,752,394
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)
60	RentsReceivable Rents Receivable (172)		1,592,729	2,877,091
61	AccruedUtilityRevenues Accrued Utility Revenues (173)		77,926,689	65,849,690
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)
63	DerivativeInstrumentAssets Derivative Instrument Assets (175)		1,052	1,044
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)		283,128,391	256,831,671
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		26,147,194	24,826,701
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	332,892,993	316,876,427
73	PreliminarySurveyAndInvestigationCharges Prelim. Survey and Investigation Charges (Electric) (183)		45,724	45,724
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)		13	13
77	TemporaryFacilities Temporary Facilities (185)
78	MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186)	233	3,020,368	1,639,380
79	DeferredLossesFromDispositionOfUtilityPlant Def. Losses from Disposition of Utility Plt. (187)
80	ResearchDevelopmentAndDemonstrationExpenditures Research, Devel. and Demonstration Expend. (188)	352
81	UnamortizedLossOnReacquiredDebt Unamortized Loss on Reaquired Debt (189)		4,292,086	4,943,263
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	172,497,896	182,370,032
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		538,896,274	530,701,540
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		10,948,881,109	10,101,043,725

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	1	1
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)		19,482	19,482
7	OtherPaidInCapital Other Paid-In Capital (208-211)	253	1,553,947,793	1,457,947,793
8	InstallmentsReceivedOnCapitalStock Installments Received on Capital Stock (212)	252
9	DiscountOnCapitalStock (Less) Discount on Capital Stock (213)	254
10	CapitalStockExpense (Less) Capital Stock Expense (214)	254b
11	RetainedEarnings Retained Earnings (215, 215.1, 216)	118	2,039,102,442	1,749,074,246
12	UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1)	118	7,699,867	7,903,846
13	ReacquiredCapitalStock (Less) Reaquired Capital Stock (217)	250	40,947	40,947
14	NoncorporateProprietorship Noncorporate Proprietorship (Non-major only) (218)
15	AccumulatedOtherComprehensiveIncome Accumulated Other Comprehensive Income (219)	122(a)(b)	6,531,511	8,950,724
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		3,594,197,128	3,205,953,697
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	4,813,520,781	4,363,529,787
22	UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225)
23	UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Debit (226)		11,198,006	10,918,679
24	LongTermDebt Total Long-Term Debt (lines 18 through 23)		4,802,322,775	4,352,611,108
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		85,491,011	97,796,653
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		128,812	82,580
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		8,640,158	8,303,723
30	AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4)
31	AccumulatedProvisionForRateRefunds Accumulated Provision for Rate Refunds (229)		269,015	7,738,190
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)		3,734,452	3,947,444
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		98,263,448	117,868,590
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)
38	AccountsPayable Accounts Payable (232)		306,069,403	231,538,055
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)		26,898,544	67,105,011
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		51,835,108	91,726,560
41	CustomerDeposits Customer Deposits (235)		399,790	329,168
42	TaxesAccrued Taxes Accrued (236)	262	70,331,594	61,395,304
43	InterestAccrued Interest Accrued (237)		42,325,990	41,392,477
44	DividendsDeclared Dividends Declared (238)
45	MaturedLongTermDebt Matured Long-Term Debt (239)
46	MaturedInterest Matured Interest (240)
47	TaxCollectionsPayable Tax Collections Payable (241)		32,449	36,904
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		43,414,084	66,090,674
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		20,648,406	20,764,486
50	DerivativesInstrumentLiabilities Derivative Instrument Liabilities (244)
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)		561,890,470	580,304,831
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)
57	AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255)	266	6,799,788	8,544,738
58	DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256)
59	OtherDeferredCredits Other Deferred Credits (253)	269	93,265,544	81,262,670
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	529,426,732	554,146,488
61	UnamortizedGainOnReacquiredDebt Unamortized Gain on Reaquired Debt (257)
62	AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty Accum. Deferred Income Taxes-Accel. Amort.(281)	272
63	AccumulatedDeferredIncomeTaxesOtherProperty Accum. Deferred Income Taxes-Other Property (282)		1,077,026,329	1,050,375,232
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		185,688,895	149,976,369
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		1,892,207,288	1,844,305,498
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		10,948,881,109	10,101,043,725

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	1,520,741,096	1,432,842,794			1,520,741,096	1,432,842,794
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	466,455,160	492,240,946			466,455,160	492,240,946
5	MaintenanceExpense Maintenance Expenses (402)	320	86,240,476	80,540,218			86,240,476	80,540,218
6	DepreciationExpense Depreciation Expense (403)	336	293,726,568	326,886,603			293,726,568	326,886,603
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336	58,482	6,980,201			58,482	6,980,201
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	33,865,744	30,596,744			33,865,744	30,596,744
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)			2,212,554				2,212,554
13	RegulatoryCredits (Less) Regulatory Credits (407.4)		4,266,253	554,914			4,266,253	554,914
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	155,086,240	136,412,754			155,086,240	136,412,753
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	3,201,600	8,516,679			3,201,600	8,516,679
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	2,997,427	122,014			2,997,427	122,014
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	217,147,370	325,368,456			217,147,370	325,368,456
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	173,846,687	338,625,655			173,846,687	338,625,655
19	InvestmentTaxCreditAdjustments Investment Tax Credit Adj. - Net (411.4)	266	1,744,950	1,068,975			1,744,950	1,068,975
20	GainsFromDispositionOfPlant (Less) Gains from Disp. of Utility Plant (411.6)		20,647	18,672,722			20,647	18,672,722
21	LossesFromDispositionOfServiceCompanyPlant Losses from Disp. of Utility Plant (411.7)
22	GainsFromDispositionOfAllowances (Less) Gains from Disposition of Allowances (411.8)		3	32			3	32
23	LossesFromDispositionOfAllowances Losses from Disposition of Allowances (411.9)
24	AccretionExpense Accretion Expense (411.10)		218,082	865,678			218,082	865,678
25	UtilityOperatingExpenses TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)		1,087,651,116	1,052,686,348			1,087,651,116	1,052,686,348
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		433,089,980	380,156,445			433,089,980	380,156,446
28	OtherIncomeAndDeductionsAbstract Other Income and Deductions
29	OtherIncomeAbstract Other Income
30	NonutilityOperatingIncomeAbstract Nonutilty Operating Income
31	RevenuesFromMerchandisingJobbingAndContractWork Revenues From Merchandising, Jobbing and Contract Work (415)
32	CostsAndExpensesOfMerchandisingJobbingAndContractWork (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)
33	RevenuesFromNonutilityOperations Revenues From Nonutility Operations (417)
34	ExpensesOfNonutilityOperations (Less) Expenses of Nonutility Operations (417.1)		224	1,828,951
35	NonoperatingRentalIncome Nonoperating Rental Income (418)		250	5,268
36	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1)	119	203,979	179,926
37	InterestAndDividendIncome Interest and Dividend Income (419)		740,719	1,112,943
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		21,458,618	19,369,235
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		3,045,896	2,698,480
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)		29,020
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		25,070,300	21,166,513
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)		8,677	3,900
44	MiscellaneousAmortization Miscellaneous Amortization (425)
45	Donations Donations (426.1)		526,568	352,064
46	LifeInsurance Life Insurance (426.2)		95,095	214,019
47	Penalties Penalties (426.3)		14,244	8,540
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		1,236,224	901,848
49	OtherDeductions Other Deductions (426.5)		8,133,779	10,960,550
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		9,824,397	11,995,802
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262	4,367,229	3,225,374
54	IncomeTaxesOther Income Taxes-Other (409.2)	262
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272	2,221,619	1,430,070
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272	2,438,126	3,396,500
57	InvestmentTaxCreditAdjustmentsNonutilityOperations Investment Tax Credit Adj.-Net (411.5)
58	InvestmentTaxCredits (Less) Investment Tax Credits (420)
59	TaxesOnOtherIncomeAndDeductions TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)		4,583,736	5,191,804
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		19,829,639	14,362,515
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		165,947,862	153,961,445
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		4,637,261	4,305,349
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)		651,177	1,722,965
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)		292,731	801,508
68	OtherInterestExpense Other Interest Expense (431)		2,074,735	5,281,842
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		10,508,366	12,505,248
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		163,095,400	153,567,861
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		289,824,219	240,951,099
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)		289,824,219	240,951,099

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		1,749,074,246	1,507,901,566
2	ChangesAbstract Changes
3	AdjustmentsToRetainedEarningsAbstract Adjustments to Retained Earnings (Account 439)
4	AdjustmentsToRetainedEarningsCreditAbstract Adjustments to Retained Earnings Credit
4.1	AdjustmentsToRetainedEarningsCredit			41,655
9	AdjustmentsToRetainedEarningsCredit TOTAL Credits to Retained Earnings (Acct. 439)			41,655
10	AdjustmentsToRetainedEarningsDebitAbstract Adjustments to Retained Earnings Debit
15	AdjustmentsToRetainedEarningsDebit TOTAL Debits to Retained Earnings (Acct. 439)
16	BalanceTransferredFromIncome Balance Transferred from Income (Account 433 less Account 418.1)		290,028,196	241,131,025
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)
36	DividendsDeclaredCommonStock TOTAL Dividends Declared-Common Stock (Acct. 438)
37	TransfersFromUnappropriatedUndistributedSubsidiaryEarnings Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
38	UnappropriatedRetainedEarnings Balance - End of Period (Total 1,9,15,16,22,29,36,37)		2,039,102,442	1,749,074,246
39	AppropriatedRetainedEarningsAbstract APPROPRIATED RETAINED EARNINGS (Account 215)
45	AppropriatedRetainedEarnings TOTAL Appropriated Retained Earnings (Account 215)
	AppropriatedRetainedEarningsAmortizationReserveFederalAbstract APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46	AppropriatedRetainedEarningsAmortizationReserveFederal TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
47	AppropriatedRetainedEarningsIncludingReserveAmortization TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
48	RetainedEarnings TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)		2,039,102,442	1,749,074,246
	UnappropriatedUndistributedSubsidiaryEarningsAbstract UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49	UnappropriatedUndistributedSubsidiaryEarnings Balance-Beginning of Year (Debit or Credit)		7,903,846	8,083,772
50	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings for Year (Credit) (Account 418.1)		203,979	179,926
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)		7,699,867	7,903,846

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)	289,824,219	240,951,099
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	327,650,795	364,463,548
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of	4,266,253	2,767,468
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	43,084,176	15,223,629
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)	1,744,950	1,068,975
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	9,463,352	5,562,069
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	3,820,816	7,434,321
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	9,590,247	94,775,764
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	47,834,476	34,175,048
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	163,993	3,243,030
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	21,458,618	19,369,235
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies	203,979	179,926
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription (a) Other (provide details in footnote):	69,263,295	172,813,607
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	502,017,662	455,372,030
24	CashFlowsFromInvestmentActivitiesAbstract Cash Flows from Investment Activities:
25	ConstructionAndAcquisitionOfPlantIncludingLandAbstract Construction and Acquisition of Plant (including land):
26	GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities Gross Additions to Utility Plant (less nuclear fuel)	1,057,066,491	1,316,843,794
27	GrossAdditionsToNuclearFuelInvestingActivities Gross Additions to Nuclear Fuel
28	GrossAdditionsToCommonUtilityPlantInvestingActivities Gross Additions to Common Utility Plant
29	GrossAdditionsToNonutilityPlantInvestingActivities Gross Additions to Nonutility Plant
30	AllowanceForOtherFundsUsedDuringConstructionInvestingActivities (Less) Allowance for Other Funds Used During Construction	21,458,618	19,369,235
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
31.1	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Other (provide details in footnote):	1,340,551	620,534
31.2	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Acquired Assets
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	1,036,948,424	1,298,095,094
36	AcquisitionOfOtherNoncurrentAssets Acquisition of Other Noncurrent Assets (d)
37	ProceedsFromDisposalOfNoncurrentAssets Proceeds from Disposal of Noncurrent Assets (d)	1,123,152	853,054
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 (b) CIAC Proceeds	32,613,619	29,307,353
53.2	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription (Increase) Decrease in Other Special Deposits	43,673	2,251
53.3	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Notes Receivable from Associated Companies		199,660,740
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	1,003,255,326	1,068,276,197
59	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
60	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
61	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b)	450,000,000	660,000,000
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	5,758,297	7,324,813
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
67.1	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Proceeds on Capital Leaseback	1,211,435	809,640
67.2	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Notes Payable to Associated Companies - Issued		67,105,011
67.3	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Capital Contributions from Parent	96,000,000
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	541,453,138	720,589,838
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)	9,006	110,648,610
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	40,206,467
78	NetDecreaseInShortTermDebt Net Decrease in Short-Term Debt (c)
80	DividendsOnPreferredStock Dividends on Preferred Stock
81	DividendsOnCommonStock Dividends on Common Stock
83	CashFlowsProvidedFromUsedInFinancingActivities Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)	501,237,665	609,941,228
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	2,962,939
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	100,000	3,062,940
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	100,001	100,000

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	A. Ray King Transmission Training Facility	(a) OPCo	921	304,663
3	Administrative and General Expenses - Maintenance	AEPSC	935	4,075,555
4	Administrative and General Expenses - Operation	AEPSC	920,921,922,923,925,926,928,930.1,930.2,931	1,614,980
5	Audit Services	AEPSC	920, 923	1,121,211
6	Bus Ops & Perf Assurance	AEPSC	920, 923	982,701
7	Civil & Political Activities and Other Svcs	AEPSC	426.1,426.3,426.4,426.5	795,480
8	Construction Services	AEPSC	107, 108	113,924,890
9	Construction Services	SWEPCo	107, 108	359,244
10	Corp Safety & Health	AEPSC	920, 923	1,709,960
11	Corporate Accounting	AEPSC	920, 923	2,380,356
12	Corporate Communications	AEPSC	920, 923	1,103,480
13	Corporate Human Resources	AEPSC	920, 923	3,717,381
14	Corporate Planning & Budgeting	AEPSC	920, 923	1,292,296
15	Customer Accounts Expenses	AEPSC	901,902,903,905	6,377,654
16	Customer Service and Informational Expenses	AEPSC	907, 908, 910	412,165
17	Customer Support	AEPSC	920, 923	2,401,193
18	Distribution Expenses - Maintenance	AEPSC	590,591,592,593,594,596,597,598	253,487
19	Distribution Expenses - Maintenance	PSO	592,593,594,595,596	256,927
19
20	Non-power Goods or Services Provided for Affiliated
21	Non-power Goods or Services Provided for Affiliate
22	Building and Property Leases	AEPSC	454	3,922,256
23	Construction Services	ETT	105, 107, 108	2,813,415
24	Construction Services	SWEPCo	107, 108	460,441
25	Fleet and Vehicle Charges	AEPSC	Various	284,221
26	HVDC North Tie	PSO	560, 562, 566, 570, 922, 925, 926	884,075
27	Materials and Supplies	ETT	154	1,147,227
28	Materials and Supplies	OPCO	154	253,283
29	Materials and Supplies	SWEPCo	154	785,421
30	Transmission Expenses - Maintenance	ETT	568, 569, 570, 571, 573	1,386,189
31	Transmission Expenses - Operation	ETT	560,561.2,562,563,566	2,267,092
32	Fuel & Storeroom Services	AEPSC	152, 163	6,440,599
33	Grid Solutions	AEPSC	920, 923	307,116
34	HVDC East Tie	SWEPCo	186,561.3,562,570,922,924,925	607,566
35	Information Technology	AEPSC	920,923	8,950,118
36	Infrastructure Ops & Support	AEPSC	920,923	1,312,364
37	Legal GC/Administration	AEPSC	920,923	2,564,324
38	Materials and Supplies	OPCo	107,570,592	516,030
39	Materials and Supplies	PSO	107,154,562,935	911,087
40	Materials and Supplies	SWEPCo	107,570,592	334,995
41	Physical & Cyber Security	AEPSC	920,923	1,325,182
42	Real Estate & Workplace Svcs	AEPSC	920,923	2,773,647
43	Regulatory Services	AEPSC	920,923	1,141,734
44	Research and Other Services	AEPSC	183,186,188	1,686,473
45	Steam Power Generation - Operation	AEPSC	500,501,506	268,646
46	Strategy & Transformation	AEPSC	920,923	934,094
47	Tax Services	AEPSC	920,923	1,004,215
48	Transmission Expenses - Maintenance	AEPSC	568,569,569.1,569.2,570,571,572,573	1,597,616
49	Transmission Expenses - Operation	AEPSC	560,561.2,561.3,561.4,561.5,562,563,564,566,920,923	26,952,573
50	Treasury & Risk	AEPSC	920, 923	1,832,429
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