This report made by the Registrants contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.  Many forward-looking statements appear in “Part 1I – Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this quarterly report, but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook.  These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected.  Forward-looking statements in this document are presented as of the date of this document.  Except to the extent required by applicable law, management undertakes no obligation to update or revise any forward-looking statement.  Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:

The forward-looking statements of the Registrants speak only as of the date of this report or as of the date they are made.  The Registrants expressly disclaim any obligation to update any forward-looking information, except as required by law.  For a more detailed discussion of these factors, see “Risk Factors” in Part I of the 2020 Annual Report and in Part II of this report.

Investors should note that the Registrants announce material financial information in SEC filings, press releases and public conference calls. Based on guidance from the SEC, the RegistrantsThe Company may use its website as a distribution channel for material company information. Financial and other important information regarding the Investors section of AEP’sCompany is routinely posted on and accessible through the Company’s website (www.aep.com) to communicate with investors about the Registrants. It is possible that the financialat www.aep.com/investors/. In addition, you may automatically receive email alerts and other information posted there could be deemed to be material information. The information on AEP’s website is not part of this report.about the Company when you enroll your email address by visiting the “Email Alerts” section at www.aep.com/investors/.

In February 2021, severe winter weather impacted the service territories of APCo, KPCo, PSO and SWEPCo resulting in power outages, extensive damage to infrastructure and disruptions to SPP market conditions. Impacts of the severe winter weather are included below. See Note 4 - Rate Matters for additional information.

The severe winter weather also had a significant impact in SPP resulting in the declaration of Energy Emergency Alert Levels 2 and 3 for the first time in SPP’s history. The winter storm increased the demand for natural gas and restricted the available natural gas supply resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system.

As of March 31,September 30, 2021, PSO and SWEPCo have deferred regulatory assets of $689$673 million and $496$433 million, respectively, relating to estimated natural gas expenses and purchases of electricity incurred from February 9, 2021, to February 20, 2021, as a result of severe winter weather. These amounts represent estimates asSWEPCo’s deferred regulatory asset consists of March 31, 2021,$107 million, $151 million and are subject$175 million related to final settlement as additional information becomes available.the Arkansas, Louisiana and Texas jurisdictions, respectively. PSO and SWEPCo have active fuel clauses that allow for the recovery of prudently incurred fuel and purchased power expenses. Given the significance of these costs, PSO and SWEPCo expect the costs to be subject to prudency reviews. Management believes these costs are probable of future recovery, but expects the recovery period to be extended to mitigate the impact on customer bills.

In March 2021, the APSC issued an order authorizing recovery of the Arkansas jurisdictional share of the retail customer fuel costs over five years, with the appropriate carrying charge to be determined at a later date. Accordingly, in April 2021, SWEPCo began recovery of its Arkansas jurisdictional share of these fuel costs, which are subject to true-up by the APSC. SWEPCo is recovering these fuel costs at an interim carrying charge of 0.8%. Also in April 2021, SWEPCo filed testimony supporting a five-year recovery with a pretax ratecarrying charge of return6.05% which has been supported by APSC staff. Various other parties have recommended recovery periods ranging from 5-20 years with a carrying charge of 6.05%1.65%. A hearingThe APSC ordered more testimony regarding the option of utilizing

securitization to recover the fuel costs. SWEPCo is awaiting a decision from the APSC. The prudency of these fuel costs is expected to be addressed in the third quarter of 2021. Aa separate proceeding will address the prudency of the fuel costs.proceeding.

Also inIn March 2021, the LPSC approved a special order granting a temporary modification to the FAC that allows SWEPCo to recover the Louisiana jurisdictional share of thethese retail fuel costs over a longer period.period than what the FAC traditionally allows. In April 2021, SWEPCo began recovery of its Louisiana jurisdictional share of these fuel costs based on a five year recovery

In April 2021, the OCC approved a waiver for PSO allowing the deferral of the extraordinary fuel and purchase of electricity costs, including a carrying costs,charge at an interim rate of 0.75%, over a longer time period than what the FAC traditionally allows. A time frame for recovery and the appropriate carrying charge will be decided at a later date. Also in April 2021, legislation was introducedenacted in Oklahoma proposing to securitizepermit securitization of the extraordinary fuel and purchase of electricity costs impacting the utilities within the state. Under the proposal,legislation, the StateOCC has the authority to determine, after receiving an application from a rate-regulated utility, if the extraordinary fuel and purchase of Oklahoma would issueelectricity costs incurred in February 2021 may be mitigated through securitization to reduce the impact on customer bills. PSO has filed an application for a financing order to pursue securitization. The application requests an order on the prudency of the extraordinary fuel and purchase of electricity costs and a carrying charge of the commission authorized weighted average cost of capital until securitization bonds can be issued. In October 2021, OCC staff and provideintervenors filed testimony supporting securitization of these costs and a carrying charge until costs are securitized ranging from the proceedsinterim rate of 0.75% to utilitiesthe actual cost of capital used to recover their sharefinance the costs of 2.32%. In addition, OCC staff supported the costs. PSO will continueprudency of PSO's requested costs while one intervenor recommended disallowances of up to evaluate and monitor$40 million. A procedural schedule has been set with an ALJ report to be filed in January 2022. An order from the advancementOCC is expected in the first quarter of the proposed legislation.2022.

In August 2021, SWEPCo expects to make a filingfiled an application with the PUCT in the second quarter of 2021 to seekimplement a recovery mechanism and an appropriate carrying chargenet interim fuel surcharge for the Texas jurisdictional share of thethese retail fuel costs. The application supported a five-year recovery at a carrying charge of 7.18%. In October 2021, various intervenors filed testimony supporting a five-year recovery with a carrying charge ranging from 0.082% to 1.625%. A hearing with the PUCT is scheduled for November 2021.

During the first quarter of 2021, SWEPCo is also workingbilled wholesale customers $104 million resulting from the severe winter weather events. SWEPCo worked with certain wholesale customers to establish payment terms for $88the outstanding accounts receivable. As of September 30, 2021, $56 million of accounts receivable resulting from the severe winter weather events.wholesale customers are outstanding. Management believes these receivables are probable of future collection.

PSO and SWEPCo evaluated financing alternatives to address the timing difference between the payment of the estimated natural gas expenses and purchases of electricity to suppliers and subsequent recovery from customers. In March 2021, PSO drew $100 million on its revolving credit facility and SWEPCo issued $500 million of Senior Unsecured Notes. In March 2021, Parent entered into a $500 million 364-day Term Loan and borrowed the full amount. The proceeds from this loan were used to help fund capital contributions to PSO and SWEPCo totaling $425 million and $100 million, respectively. In April 2021, PSO received an additional capital contribution from Parent of $125 million to further address these costs.

Although the February 2021 severe winter weather did not materially impact AEP’s results of operations for the three and nine months ended March 31,September 30, 2021, if either PSO or SWEPCo is unable to recover these fuel and purchased power costs, or obtain authorization of a reasonable carrying charge on these costs, it could reduce future net income and cash flows and impact financial condition.

The growth of AEP’s renewable generation portfolio reflects the company’s strategy to diversify generation resources to provide clean energy options to customers that meet both their energy and capacity needs.

AEP continues to develop its renewable portfolio within the Generation & Marketing segment.  Activities include working directly with wholesale and large retail customers to provide tailored solutions based upon market knowledge, technology innovations and deal structuring which may include distributed solar, wind, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other forms of cost reducing energy technologies.  The Generation & Marketing segment also develops and/or acquires large scale renewable generation projects that are backed with long-term contracts with creditworthy counterparties.

In May 2020,June 2021, the IRS issued a notice extending the “Continuity Safe Harbor” deadlines for qualifying renewable energy projects that began construction in 2016 and 2017 by one year as many projects are facing supply chain and other project development delays caused by COVID-19.projects. Under the May 2020June 2021 IRS notice, the Continuity Safe Harbor for qualifying renewable energy projects that began construction in calendar years 2016 and 2017 and which are placed in-service by the end of 2021 and 2022, respectively, will satisfythrough 2019 is extended to six years. Additionally, the Continuity Safe Harbor.Harbor is extended to five years for qualifying projects that began construction in calendar year 2020. Provided that each facility does satisfy the Continuity Safe Harbor, under the current IRS guidance, the 199 MWSundance wind facility will qualify for 100% of the federal PTC, and the remaining twoMaverick and Traverse wind facilities totaling 1,286 MWs, will qualify for 80% of the federal PTC.

In April 2021, PSO and SWEPCo acquired respective undivided ownership interests in the 199 MW wind facilityentity that owned Sundance during its development and construction for $270 million, the first of the three NCWF acquisitions. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Sundance assets in proportion to their undivided ownership interests. Sundance was acquired and placed in-service with an estimated investment of $307 million. The 287 MW wind facility is targeted to be acquired and placed in-service in DecemberApril 2021. In September 2021, PSO and SWEPCo acquired respective undivided ownership interests in the 999 MWentity that owned Maverick during its development and construction for $383 million, the second of the three NCWF acquisitions. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Maverick assets in proportion to their undivided ownership interests. Maverick was placed in-service in September 2021. As of September 30, 2021, PSO and SWEPCo had approximately $314 million and $376 million, of Property, Plant and Equipment on the balance sheets, respectively, related to the Sundance and Maverick NCWF projects. The Traverse wind facility is targeted to be acquired and placed in-service between December 2021January and April 2022. See Note 6 - Acquisitions for additional information.

Strategic EvaluationIn June 2021, SWEPCo issued requests for proposals to acquire up to 3,000 MWs of KPCowind and 300 MWs of solar generation resources. The wind and solar generation projects would be subject to regulatory approval.

In October 2021, AEP entered into a strategic evaluationStock Purchase Agreement to sell KPCo and KTCo to Liberty Utilities Co., a subsidiary of Oakville, Ontario, Canada based Algonquin Power & Utilities Corp. (Liberty), for itsapproximately a $2.85 billion enterprise value. The sale is subject to regulatory approvals from the FERC, the KPSC, clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, and clearance from the Committee on Foreign Investment in the United States.

KPCo currently operates and owns a 50% interest in the 1,560 MW coal-fired Mitchell Power Plant (Mitchell Plant) with the remaining 50% owned by WPCo. The Stock Purchase Agreement is further contingent upon approval by the KPSC, WVPSC and FERC of a new proposed Mitchell Plant Operations and Maintenance Agreement and Mitchell Plant Ownership Agreement between KPCo and WPCo pursuant to which WPCo will replace KPCo as the operator of the Mitchell Plant and KPCo employees at the Mitchell Plant will become employees of WPCo at closing of the transaction. Under the proposed Ownership Agreement, WPCo is obligated to purchase KPCo’s 50% interest in the Mitchell Plant on December 31, 2028 unless KPCo and WPCo have agreed to retire the Mitchell Plant earlier or, absent such agreement, if WPCo elects prior to December 31, 2027 to retire the Mitchell Plant on December 31, 2028. The Ownership Agreement provides that the purchase price for KPCo’s 50% ownership interest in KPCo, a wholly-owned regulated generation, transmission and distribution utility with approximately 166,000 retail customers in eastern Kentucky. Potential alternatives may include continued ownership or a sale of KPCo. Management has not made a decision regarding the potential alternatives, but expects a decisionMitchell Plant will be made during 2021. Asdetermined through the mutual agreement of March 31, 2021,WPCo and KPCo has total(subject to approval from the KPSC and WVPSC) or through a fair market valuation determination conducted by independent appraisals if KPCo and WPCo are unable to reach agreement as to the purchase price.

The sale is expected to close in the second quarter of 2022 with Liberty acquiring the assets and assuming the liabilities of approximately $2.7 billionKPCo and total equityKTCo, excluding pension and other post-retirement benefit plan assets and liabilities. AEP expects to provide customary transition services to Liberty for a period of approximately $837 million.time after closing of the transaction.

In February 2021, AEP signed an agreement to sell Racine to a nonaffiliated party. As of March 31,September 30, 2021, the net book value of Racine was $45 million. The sale of Racine requires approval from the FERC andwas approved by the U.S. Army Corps of Engineers.Engineers in the third quarter of 2021. The sale also requires approval from the FERC. The sale is expected to close in the secondfourth quarter of 2021 and result in an immaterial gain. Racine was not presented as Held for Sale on AEP’s balance sheets due to immateriality.

DHLC provides 100% of the fuel supply to Dolet Hills Power Station. During the second quarter of 2019, the Dolet Hills Power Station initiated a seasonal operating schedule. In January 2020, in accordance with the terms of SWEPCo’s settlement of its base rate review filed with the APSC, management announced that SWEPCo will seek regulatory approval to retire the Dolet Hills Power Station by the end of 2026. DHLC provides 100% of the fuel supply to Dolet Hills Power Station. After careful consideration of current economic conditions, and particularly for the benefit of their customers, management of SWEPCo and CLECO determined DHLC would not proceed developing additional Oxbow Lignite Company (Oxbow) mining areas for future lignite extraction and ceased extraction of lignite at the mine in May 2020. Based on these actions, management revised the estimated useful life of DHLC’s and Oxbow’s assets to coincide with the date at which extraction was discontinued in the second quarter of 2020 and the date at which delivery of lignite is expected to ceaseceased in SeptemberOctober 2021. ManagementIn addition, management also revised the useful life of the Dolet Hills Power Station to 2021 based on the remaining estimated fuel supply available for continued seasonal operation. In March 2020, primarily due to the revision in the useful life of DHLC, SWEPCo recorded a revision to increase estimated ARO liabilities by $21 million. In April 2020, SWEPCo and CLECO jointly filed a notification letter to the LPSC providing notice of the cessation of lignite mining.

The Dolet Hills Power Station non-fuel costs are recoverable by SWEPCo through base rates. As of September 30, 2021, SWEPCo’s share of the net investment in the Dolet Hills Power Station is $150$146 million, including CWIP and materials and supplies, before cost of removal.

Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses. Under the fuel agreements, SWEPCo’s fuel inventory and unbilled fuel costs from mining related activities were $126$44 million as of March 31,September 30, 2021. Also, as of March 31,September 30, 2021, SWEPCo had a net over-recoveredunder-recovered fuel balance of $20$39 million, excluding impacts of the February 2021 severe winter weather event, which includes fuel consumed at the Dolet Hills Power Station. Additional operational, reclamation and other land-related costs are expected to be incurred by DHLC and Oxbow andwill be billed to SWEPCo prior to the closure of the Dolet Hills Power Station and recovered throughincluded in future fuel clauses.

In June 2020, SWEPCo filed a fuel reconciliation with the PUCT for its retail operations in Texas, including Dolet Hills, for the reconciliation period of March 1, 2017 to December 31, 2019. See “2020 Texas Fuel Reconciliation” section of Note 4 for additional information.

In October 2020, SWEPCo filed a request with the LPSC seeking approval to close the mines and to recover the Louisiana jurisdictional share of the additional fuel costs. In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $20 million of fuel costs in 2021 and defer approximately $30 million of additional costs with a recovery period to be determined at a later date.

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

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

In the ordinary course of business, AEP is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases that have a probable likelihood of loss if the loss can be estimated.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition. See Note 4 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies for additional information.

In 2013, the Wilmington Trust Company filed a complaintsuit in the U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it would be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022.  The terms of the consent decree allow the installation of environmental emission control equipment, repowering, refueling or retirement of the unit.  The plaintiffs seeksought a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio.

OnAfter the litigation proceeded at the District Court and Circuit Court levels, on April 20, 2021, I&M and AEGCo reached an agreement to acquire 100% of the interests in Rockport Plant, Unit 2 for $115.5 million from certain financial institutions that own the unit through trusts established by Wilmington Trust, the nonaffiliated owner trustee of the ownership interests in the unit, with closing to occur as of the end of the Rockport Plant, Unit 2 lease in December 2022. As a result, the parties have submitted a stipulation and order of dismissal requesting that the district court dismiss the case without prejudice to plaintiffs asserting their claims in a re-filed action or in a new action. The agreement is subject to customary closing conditions, including regulatory approvals and as of the closing will result in a final settlement of, and release of claims in, the lease litigation. As a result, in May 2021, at the parties’ request, the district court entered a stipulation and order dismissing the case without prejudice to plaintiffs asserting their claims in a re-filed action or a new action. Management believes its financial statements appropriately reflect the expected resolution of the pending litigation.

The American Electric Power System Retirement Plan (the Plan) has received a letter written on behalf of four participants (the Claimants) making a claim for additional plan benefits and purporting to advance such claims on behalf of a class. 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 Claimants have asserted claims 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) the company failed to provide required notice regarding the changes to the Plan.  AEP has responded to the Claimants providing a reasoned explanation for why each of their claims have been denied. The denial of those claims was appealed to the AEP System Retirement Plan Appeal Committee and the Committee upheld the denial of claims. Management will continue to defend against the claims.  Management is unable to determine a range of potential losses that is reasonably possible of occurring.

AEP has a substantial capital investment program and incurs additional operational costs to comply with environmental control requirements.  Additional investments and operational changes will be made in response to existing and anticipated requirements to reduce emissions from fossil generation and in response to rules governing the beneficial use and disposal of coal combustion by-products, clean water and renewal permits for certain water discharges.

AEP is engaged in litigation about environmental issues, was notified of potential responsibility for the clean-up of contaminated sites and incurred costs for disposal of SNF and future decommissioning of the nuclear units.  AEP, along with other parties, challenged a portion of the Federal EPA requirements.  Management is engaged in the development of possible future requirements including the items discussed

below.  Management believes that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

AEP will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances.  If AEP cannot recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.

The rules and proposed environmental controls discussed below will have a material impact on AEP System generating units.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of March 31,September 30, 2021, the AEP System owned generating capacity of approximately 24,60025,000 MWs, of which approximately 12,100 MWs were coal-fired.  Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on fossil generation. Based upon management estimates, AEP’s future investment to meet these existing and proposed requirements ranges from approximately $350 million to $700 million through 2027.

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in finalizing proposed rules or revising certain existing requirements.  The cost estimates will also change based on: (a) potential state rules that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) actual performance of the pollution control technologies installed, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.  In addition, management continues to evaluate the economic feasibility of environmental investments on regulated and competitive plants.

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions. The states implement and administer many of these programs and could impose additional or more stringent requirements. The primary regulatory programs that continue to drive investments in AEP’s existing generating units include: (a) periodic revisions to NAAQS and the development of SIPs to achieve any more

The Federal EPA periodically reviews and revises the NAAQS for criteria pollutants under the CAA. Revisions tend to increase the stringency of the standards, which in turn may require AEP to make investments in pollution control equipment at existing generating units, or, since most units are already well controlled, to make changes in how units are dispatched and operated. Most recently, the Biden administration has indicated that it is likely to

revisit the NAAQS for ozone and PM, which were left unchanged by the prior administration following its review. Management cannot currently predict if any changes to either standard are likely or what such changes may be, but will continue to monitor this issue and any future rulemakings.

The Federal EPA issued a Clean Air Visibility Rule (CAVR) in 2005, which could require power plants and other facilities to install best available retrofit technology to address regional haze in federal parks and other protected areas. CAVR is implemented by the states, through SIPs, or by the Federal EPA, through FIPs. In 2017, the Federal EPA revised the rules governing submission of SIPs to implement the visibility programs, including a provision that postpones the due date for the next comprehensive SIP revisions until 2021. Petitions for review of the final rule revisions have been filed in the U.S. Court of Appeals for the District of Columbia Circuit.

Arkansas has an approved regional haze SIP and all of SWEPCo's affected units are in compliance with the relevant requirements.

In 2019, the Affordable Clean Energy (ACE) rule established a framework for states to adopt standards of performance for utility boilers based on heat rate improvements for such boilers. However, in January 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE rule and remanded it to the Federal EPA. Management is unable to predict how the Federal EPA will respond to the court’s remand.

2050. Management is taking steps to comply with these requirements, including increasing wind and solar installations, purchasing renewable power and broadening AEP System’s portfolio of energy efficiency programs.

Excessive costs to comply with future legislation or regulations hashave led to the announcement of early plant closures and could force AEP to close additional coal-fired generation facilities earlier than their estimateestimated useful life. If AEP is unable to recover the costs of its investments, it would reduce future net income and cash flows and impact financial condition.

The Federal EPA’s CCR rule regulates the disposal and beneficial re-use of CCR, including fly ash and bottom ash created from coal-fired generating units and FGD gypsum generated at some coal-fired plants.  The rule applies to active and inactive CCR landfills and surface impoundments at operatingfacilities of active electric utility or independent generation facilities.power producers.

In August 2020, the Federal EPA revised the CCR rule to include a requirement that unlined CCR storage ponds cease operations and initiate closure by April 11, 2021. The revised rule provides two options that allow facilities to extend the date by which they must cease receipt of coal ash and close the ponds.

The first option provides an extension to cease receipt of CCR no later than October 15, 2023 for most units, and October 15, 2024 for a narrow subset of units; however, the Federal EPA’s grant of such an extension will be based upon a satisfactory demonstration of the need for additional time to develop alternative ash disposal capacity and will be limited to the soonest timeframe technically feasible to cease receipt of CCR. Additionally, each request must undergo formal review, including public comments, and be approved by the Federal EPA. AEP filed applications for additional time to develop alternative disposal capacity at the following plants:

In December 2020, APCoaddition, AGR owns Cardinal Plant, Unit 1 a competitive generation unit. A nonaffiliate owns Cardinal Plant, Unit 2 and Unit 3 and operates all three units at the Cardinal Plant. The nonaffiliate filed requests with the Virginia SCC and WVPSCan application for additional time to obtain the regulatory approvals necessary to implement the compliance plans and seek recovery of the estimated $240 million investmentdevelop alternative disposal capacity for the AmosCardinal Plant. As of September 30, 2021, the net book value of Cardinal Plant, Unit 1, including materials and Mountaineer plants. In December 2020supplies and February 2021, WPCo and KPCo filed requests with the WVPSC and KPSC, respectively, to obtain the regulatory approvals necessary to implement the compliance plans and seek recovery of the estimated $132 million investment for the Mitchell Plant. Within those requests, WPCo and KPCo also filed a $25 million alternative with the WVPSC and KPSC, respectively, which would allow the Mitchell Plant to continue operating only through 2028.CWIP, was approximately $43 million.

The second option is a retirement option, which provides a generating facility an extended operating time without developing alternative CCR disposal. Under the retirement option, a generating facility would have until October 17, 2023 to cease operation and to close CCR storage ponds 40 acres or less in size, or through October 17, 2028 for facilities with CCR storage ponds greater than 40 acres in size. Pursuant to this option, AEP informed the Federal EPA of its intent to retire the Pirkey Power Plant and cease using coal at the Welsh Plant:

AEP may incur significant costs to upgrade or close and replace surface impoundments and landfills used to manage CCR and to conduct any required remedial actions. Under the retirement option above, AEP may need to recover remaining depreciation and estimated closure costs associated with retiring plants over a shorter period. If AEP cannot ultimately recover the costs of environmental compliance and/or the remaining depreciation and estimated closure costs associated with retiring plants in a timely manner, it would reduce future net income and cash flows and impact financial condition.

If removal of ash is required without providing similar assurances of cost recovery in regulated jurisdictions, it would impose significant additional operating costs on AEP, which could lead to increased financing costs and liquidity needs. Other units in Virginia, Ohio, West Virginia and Kentucky have already been closed in place in accordance with state law programs. Management will continue to participate in rulemaking activities and make adjustments based on new federal and state requirements affecting its ash disposal units.

The Federal EPA’s ELG rule for generating facilities establishes limits on FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater, which are to be implemented through each facility’s wastewater discharge permit. A recent revision to the ELG rule, published in October 2020, establishes additional options for reusing and discharging small volumes of bottom ash transport water, provides an exception for retiring units and extends the compliance deadline to a date as soon as possible beginning one year after the rule was published but no later than December 2025. Management has assessed technology additions and retrofits to comply with the rule and the impacts of the Federal EPA’s recent actions on facilities’ wastewater discharge permitting for FGD wastewater and bottom ash transport water. Permit modifications for affected facilities were filed in January 2021 that reflect the outcome of that assessment. We continue to work with state agencies to finalize permit terms and conditions.

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

In addition to the November 2020 announcement related to the Federal EPA’s CCR rules, management also decided not to renew the Rockport Plant, Unit 2 lease when it expires in 2022. Previously, management retired or announced early closure plans for Welsh Unit 2, Oklaunion Power Station, Dolet Hills Power Station and Northeastern Plant Unit 3.

AEP’s primary business is the generation, transmission and distribution of electricity.  Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

AEP’s reportable segments and their related business activities are outlined below:

The remainder of AEP’s activities are presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.

The following discussion of AEP’s results of operations by operating segment includes an analysis of Gross Margin, which is a non-GAAP financial measure. Gross Margin includes Total Revenues less the costs of Fuel and Other Consumables Used for Electric Generation, as well as Purchased Electricity for Resale, and Amortization of Generation Deferrals as presented in the Registrants’ statements of income as applicable. Under the various state utility rate making processes, these expenses are generally reimbursable directly from and billed to customers. As a result, they do not typically impact Operating Income or Earnings Attributable to AEP Common Shareholders. Management believes that Gross Margin provides a useful measure for investors and other financial statement users to analyze AEP’s financial performance in that it excludes the effect on Total Revenues caused by volatility in these expenses. Operating Income, which is presented in accordance with GAAP in AEP’s statements of income, is the most directly comparable GAAP financial measure to the presentation of Gross Margin. AEP’s definition of Gross Margin may not be directly comparable to similarly titled financial measures used by other companies.

The following table presents Earnings (Loss) Attributable to AEP Common Shareholders by segment:

Earnings Attributable to AEP Common Shareholders increased from $495$749 million in 2020 to $575$796 million in 2021 primarily due to:

Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.  In general, degree day changes in the eastern region have a larger effect on revenues than changes in the western region due to the relative size of the two regions and the number of customers within each region.