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.information, except as required by law.  For a more detailed discussion of these factors, see “Risk Factors” in Part I of the 20192020 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 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 carrying charge of 6.05% which has been supported by APSC staff. Various other parties have recommended recovery periods ranging from 5-20 years with a carrying charge of 1.65%. The APSC ordered more testimony regarding the option of utilizing

In 2020, COVID-19 was declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention. Its rapid spread around the world and throughout the United States prompted many countries, including the United States, to institute restrictions on travel, public gatherings and certain business operations. These restrictions significantly disrupted economic activity in AEP’s service territory and could reduce futureresulted in reduced demand for energy, particularly from commercial and industrial customers. Although AEP cannot predict the severity or duration of the impact of the COVID-19 pandemic, AEP currently anticipates a 2.7% reduction inIn 2021, weather-normalized retail sales volume in 2020 as compared to the prior year. For the nine months ended September 30, 2020, AEP experienced a reduction in weather-normalized retail sales volume of 3.0% as compared to the same period in the prior year primarily driven by a 7.0% decrease in the industrial customer class and a 4.9% decrease in the commercial customer class offset by an increase in demand of 2.6%has improved from the residential customer class. The reductionpandemic levels experienced in weather-normalized retail sales volume2020. Management expects continued improvement during the remainder of 3.0% did not result in a significant decrease in the corresponding retail margins for the nine months ended 20202021 as the increase in higher margin residential sales volumes partially offset the decreases in the industrialadditional vaccinations occur and commercial sales volumes. Furthermore, the rate design for certain industrial customers includes demand provisions designed to cover the fixed portion of utility costs minimizing the impact of the fluctuations in usage on revenues. AEP’s load forecast is highly dependent on many factors including, but not limited to, the speed and strength of economic recovery and the extent and duration of the next wave of COVID-19 infection. If the severity of the economic disruption increases, AEP’s future results of operations, financial condition, and cash flows could be further adversely impacted. See Customer Demand for additional information.activity improves.

During the first quarter of 2020, AEP’s electric operating companies informed both retail customers and state regulators that disconnections for non-payment were temporarily suspended. Shortly thereafter, AEP’s state regulators also imposed temporary moratoria on customary disconnection practices. During the third and the fourth quarter of 2020, certain state regulators began to lift restrictions on disconnects. As of September 30, 2020, AEP2021, AEP’s electric operating companies have resumed disconnectionscustomary disconnection practices in itsall regulated jurisdictions with the exception of Virginia, West Virginia, Kentucky, Arkansas, Louisiana and Tennessee. AEP’s electric operating companies continueresidential customers in Virginia. AEP continues to work with regulators and stakeholders in these statesVirginia and management currently anticipates resuming customary disconnection practices inonce available relief funds are received from the fourth quarter of 2020. However, this timing could change if there is new legislation or other regulatory directives issuedstate.

AEP has been and continues to be proactive in the future. Continuing adverse economic conditions may result in the inability of customers to pay for electric service, which could affect revenue recognition and the collectability of accounts receivable. During the third quarter of 2020, the Registrants reviewed current collections experience with historical trends, specifically reviewing metrics such as cash collections, days sales outstanding, daily customer deposits, and aging summaries. In addition, the Registrants reviewed historical loss information generally comprised of a rolling 12-month average, in conjunction with a qualitative assessment of elements that impact the collectability of receivables, such as changes in economic factors, regulatory matters, industry trends, customer credit factors, payment plan options and other programs available to customers. Based on this review, the Registrants’ accounts receivable aging was negatively impacted primarily due to the suspension of customer disconnects. However, as disconnect moratoriums ended or are approaching their end dates, AEP is proactively engaging with customers to collect payments or establish payment arrangements for outstanding balances. As of September 30, 2020,2021, AEP currently does not expect the deterioration inaccounts receivable aging to have a material adverse impact on the Registrants’ allowance for uncollectible accounts based on considerations of the COVID-19 impacts and past trends during times of economic instability. Management continues to monitor developments affecting suspensions of disconnections and itsthat could have an impact on customer collections. Further deterioration in AEP’s ability to collect from its customers could significantly impact AEP’s future results of operations, financial conditions, and cash flows.

The Registrants have worked with their state commissions to achieve deferral authority for incremental expenses incurred due to COVID-19. All of AEP’s regulated jurisdictions have issued initial COVID-19 orders with the exception of Tennessee. If any costs related to COVID-19 are not recoverable, it could reduce future net income and cash flows and impact financial condition.

In 2021, the Registrants have experienced certain supply chain disruptions driven by several factors including staffing and travel issues caused by the COVID-19 pandemic, increased demand due to the economic recovery from the pandemic, labor shortages in certain trades and shortages in the availability of certain raw materials. These supply chain disruptions have not had a material impact on the Registrants net income, cash flows and financial condition, but have extended lead times for certain goods and services. Management has implemented risk mitigation strategies in an attempt to mitigate the ultimate impactimpacts of COVID-19 also depends on factors beyond management’s knowledgethese supply chain disruptions. However, a prolonged continuation or control, includinga future increase in the duration and severity of this outbreak as well as third-party actions taken to contain its spreadsupply chain disruptions could impact the cost of certain goods and mitigate its public health effects. Therefore, management cannot estimate the potentialservices and extend lead times which could reduce future impact to financial position, results of operationsnet income and cash flows but the impacts could be material.and impact financial condition.

AEP’s weather-normalized retail sales volumes for the third quarter of 2020 decreased2021 increased by 2.6%3% from the third quarter of 2019.2020. Weather-normalized residential sales increaseddecreased by 3.8%1.6% in the third quarter of 20202021 from the third quarter of 2019.2020. AEP’s third quarter 20202021 industrial sales volumes decreasedincreased by 7.8%7% compared to the third quarter of 2019.2020. The declineincrease in industrial sales was spread across many industries. Weather-normalized commercial sales decreased 4.6%increased 5% in the third quarter of 20202021 from the third quarter of 2019.2020.

AEP’s weather-normalized retail sales volumes for the nine months ended September 30, 2020 decreased2021 increased by 3.0%2.3% compared to the nine months ended September 30, 2019.2020. Weather-normalized residential sales increaseddecreased by 2.6%0.9% for the nine months ended September 30, 20202021 compared to the nine months ended September 30, 2019.2020. AEP’s industrial sales volumes for the nine months ended September 30, 2020 decreased 7.0%2021 increased 4.2% compared to the nine months ended September 30, 2019.2020. The declinerecovery in industrial sales volumes was spread across many industries. Weather-normalized commercial sales decreased 4.9%increased 4.3% for the nine months ended September 30, 20202021 compared to the nine months ended September 30, 2019.2020.

AsThe current year increase in industrial and commercial sales volumes is primarily driven by a resultrecovery from the COVID-19 pandemic. In 2020, public health restrictions significantly disrupted economic activity and industrial and commercial demand for energy in AEP’s service territory. Similarly, the current year decline in weather-normalized residential sales volumes is driven by the cessation of stay at home restrictions that were in place in 2020 and the impactgradual return of COVID-19, customers to the workplace.

AEP revised its forecast for 20202021 weather-normalized retail sales volumes in April 2020 and September 20202021 from the forecast presented in the 20192020 10-K. In 2020,2021, AEP currently anticipates weather-normalized retail sales volumes will decreaseincrease by 2.7%2.2%. AEP expects industrial class sales volumes to decreaseincrease by 6.5%4.3% in 2020,2021, while weather-normalized residential sales volumes are projected to increasedecrease by 3.1%0.9%. Finally, AEP currently projects weather-normalized commercial sales volumes to decreaseincrease by 4.8%3.7%.

AEP’s public utility subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  Depending on the outcomes, these rate and regulatory proceedings can have a material impact on results of operations, cash flows and possibly financial condition. AEP is currently involved in the following key proceedings. See Note 4 - Rate Matters for additional information.

The Registrants file rate cases with their regulatory commissions in order to establish fair and appropriate electric service rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Registrants’ current and future results of operations, cash flows and financial position.

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.

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 $153$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 Lignite Mining Agreement, DHLC bills SWEPCo its proportionate share of incurred lignite extractionfuel agreements, SWEPCo’s fuel inventory and associated mining-relatedunbilled fuel costs from mining related activities were $44 million as fuel is delivered. As of September 30, 2020,2021. Also, as of September 30, 2021, SWEPCo had a net under-recovered fuel balance of $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 incurred by DHLC has unbilled lignite inventory and fixed costs of $36 million thatOxbow will be billed to SWEPCo prior to the closure of the Dolet Hills Power Station. In 2009, SWEPCo acquired interestsand included in Oxbow, which owns mineral rights and leases land. Under a Joint Operating Agreement pertaining to the Oxbow mineral rights and land leases, Oxbow bills SWEPCo its proportionate share of incurred costs. As of September 30, 2020, Oxbow has unbilled fixed costs of $10 million that will be billed to SWEPCo prior to the closure of the Dolet Hills Power Station. DHLC and Oxbow have billed SWEPCo $111 million for lignite deliveries from April 2020 through September 2020, which primarily includes accelerated depreciation and amortization of fixed costs. Additional operational and land-related costs are expected to be incurred by DHLC and Oxbow and billed to SWEPCo prior to the closure of the Dolet Hills Power Station and recovered throughfuture fuel clauses.

In OctoberJune 2020, SWEPCo filed a requestfuel 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 March 2021, the LPSC for recovery of the Louisiana share of these additional fuel costs. SWEPCo’s filing proposesissued an order allowing SWEPCo to defer $36recover up to $20 million of fuel costs in 2021 and recoverdefer approximately $30 million of additional costs with a recovery period to be determined at a later date.

In March 2021, the deferral plus carryingAPSC approved fuel rates that provide recovery of the Arkansas share of the 2021 Dolet Hills Power Station fuel costs over five years beginning in 2022.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. TheSee “Obligations under the New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio.

ManagementAfter 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. The agreement is subject to customary closing conditions, including regulatory approvals and as of the closing will continue to defend againstresult in a final settlement of, and release of claims in, the claims. Given thatlease litigation. As a result, in May 2021, at the parties’ request, the district court dismissed plaintiffs’entered a stipulation and order dismissing the case without prejudice to plaintiffs asserting their claims seeking compensatory relief as premature, and that plaintiffs have yet to presentin a methodology for determiningre-filed action or any analysis supporting any alleged damages, management cannot determine a rangenew action. Management believes its financial statements appropriately reflect the resolution of potential losses that is reasonably possible of occurring.

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 thatthat: (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;career, (b) the Plan violates the age discrimination prohibitions of ERISA and the Age Discrimination in Employment Act;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 areis 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 some 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 September 30, 2020,2021, the AEP System hadowned generating capacity of approximately 24,30025,000 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 $500$350 million to $1 billion$700 million through 2026.2027.

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 stringent standards, (b) implementation of the regional haze program by the states and the Federal EPA, (c) regulation of hazardous air pollutant emissions under MATS, (d) implementation and review of CSAPR and (e) the Federal EPA’s regulation of greenhouse gas emissions from fossil generation under Section 111 of the CAA. Notable developments in significant CAA regulatory requirements affecting AEP’s operations are discussed in the following sections.

The Federal EPA finalized non-attainment designationsrevisit the NAAQS for the 2015 ozone standard in 2018. The Federal EPA confirmed that for states included in the CSAPR program, there are no additional interstate transport obligations, as all areas of the country are expected to attain the 2008 ozone standard before 2023. Challenges to the 2015 ozone standard and the Federal EPA’s determination that CSAPR satisfies certain states’ interstate transport obligationsPM, which were filed in the U.S. Court of Appeals for the District of Columbia Circuit. In August 2019, the court upheld the 2015 primary ozone standard, but remanded the secondary welfare-based standard for further review. The court vacated the Federal EPA’s determination that CSAPR fulfilled the states’ interstate transport obligations, because the Federal EPA’s modeling analysis did not demonstrate that all significant contributions would be eliminatedleft unchanged by the attainment deadlines for downwind states. Any further changes will require additional rulemaking.prior administration following its review. Management cannot currently predict the nature, stringencyif any changes to either standard are likely or timing of additional requirements for AEP’s facilities based on the outcome of these activities.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), detailing how the CAA’s requirement that certain in 2005, which could require power plants and other facilities to install best available retrofit technology (BART) wouldto address regional haze in federal parks and other protected areas. BART requirements apply to certain power plants.  CAVR will beis 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.

The Federal EPA initially disapproved portions of the Arkansas has an approved regional haze SIP, but has approved a revised SIP and all of SWEPCo's affected units are in compliance with the relevant requirements.

In 2018, the Federal EPA filed a proposed rule revising the standards for new sources and determined that partial carbon capture and storage is not the best system of emission reduction because it is not available throughout the U.S. and is not cost-effective. That rule has not been finalized. Management continues to actively monitor these rulemaking activities.

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.

In 2015, theThe Federal EPA published a finalEPA’s CCR rule to regulateregulates 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. The rule imposes construction and operating obligations, including location restrictions, liner criteria, structural integrity requirements for impoundments, operating criteria and additional groundwater monitoring requirements to be implemented on a schedule spanning an approximate four-year implementation period. In 2018, some of AEP’s facilities were required to begin monitoring programs to determine if unacceptable groundwater impacts will trigger future corrective measures. Based on additional groundwater data, further studies to design and assess appropriate corrective measures have been undertaken at two facilities.

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 deadline for seeking an extension under either option is November 30, 2020.

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:

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 currently uses surface impoundments and landfills to manage CCR materials at generating facilities,may incur significant costs may be incurred to upgrade or close and replace these existing facilitiessurface impoundments and landfills used to manage CCR and to conduct any required remedial actions. Management is evaluating various compliance options. 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.

Closure and post-closure costs have been included in ARO in accordance with the requirements in the final rule. Additional ARO revisions will occur on a site-by-site basis if groundwater monitoring activities conclude that corrective actions are required to mitigate groundwater impacts, which could include costs to remove ash from some unlined units.

In 2014, theThe Federal EPA issued a finalEPA’s ELG rule setting forth standards for existing power plants that is intended to reduce mortality of aquatic organisms impinged or entrained in the cooling water.  The rule was upheld on review by the U.S. Court of Appeals for the Second Circuit. Compliance timeframes are established by the permit agency through each facility’s NPDES permit as those permits are renewed and have been incorporated into permits at several AEP facilities. AEP facilities that have had their wastewater discharge permits renewed have been asked to monitor intake flows or to enhance monitoring practices to assure the current technology is being properly managed to ensure compliance with this rule.

In 2015,August 2021, the Federal EPA and the U.S. Army Corps of Engineers jointly issued a final ruleannounced their plan to clarifyreconsider and revise the scope of the regulatory definition ofNavigable Waters Protection Rule, which defines “waters of the United States” in light of recent U.S. Supreme Court cases. Various parties challengedunder the 2015 rule in different U.S. District Courts, which resulted in a patchwork of applicability ofClean Water Act. Shortly thereafter, the 2015 rule and its predecessor. In December 2018, the Federal EPA and the U.S. Army Corps of Engineers proposed a replacement rule. In September 2019, the Federal EPA repealed the 2015 rule. The final replacement rule was published in the Federal Register in April 2020 and became effective in June 2020. The final rule limits the scope of CWA jurisdiction to four categories of waters, and clarifies exclusions for ground water, ephemeral streams, artificial ponds and waste treatment systems. Challenges to the final rule and requests for a preliminary injunction have been brought by states and other groups in multiple U.S. District Courts. At this time, none of the jurisdictions in which AEP operates are impacted by a stay. Management is monitoring these various proceedings but is unable to predict the actions of the various courts.

KPCo and WPCo each own a 50% interest in the Mitchell Plant. In December 2020 and February 2021, WPCo and KPCo filed requests with the WVPSC and KPSC, respectively, to obtain the regulatory approvals necessary to implement CCR and ELG compliance plans and seek recovery of the United States having minimal adverse environmental impacts. The Court foundestimated $132 million investment for the Mitchell Plant that in reissuing NWP 12 in 2017,would allow the Corps failedplant to comply with Section 7 ofcontinue operating beyond 2028. Within those requests, WPCo and KPCo also filed a $25 million alternative to implement only the Endangered Species Act (ESA), which requires the Corps to consultCCR-related investments with the U.S. FishWVPSC and Wildlife Service regarding potential impacts on endangered species. The Court remandedKPSC, respectively, which would allow the permit backMitchell Plant to the Corps to complete its ESA consultation, and also enjoined the Corps from authorizing any dredge or fill activities under NWP 12 pending completion of the consultation process. The Department of Justice filed a motion to stay the injunction and tailor the remedy imposed by the Court. In May 2020, the Court revised its order lifting the injunction for non-oil and gas pipeline construction activities and routine maintenance, inspection and repair activities on existing NWP 12 projects. The Department of Justice appealed the Court’s decision to the Court of Appeals for the Ninth Circuit and moved for stay pending appeal, which was denied. In June 2020, the Department of Justice submitted an application to the U.S. Supreme Court requesting a stay of the District Court’s Order, and the Court granted the request with respect to all oil and gas pipelines except the Keystone Pipeline. Management is monitoring the litigation and evaluating other permitting alternatives, but is currently unable to predict the impact of future proceedings on current and planned projects.continue operating only through 2028.

In July 2021, the KPSC issued an order approving the CCR only alternative and rejecting the full CCR and ELG compliance plan. In August 2021, the WVPSC approved the full CCR and ELG compliance plan for the WPCo share of the Mitchell Plant. In September 2020,2021, WPCo submitted a filing with the Corps issued for public commentWVPSC to reopen the proposed renewalCCR/ELG case that was approved by the WVPSC in August 2021. Due to the rejection by the KPSC of the KPCo share of the ELG investments, WPCo requested the WVPSC consider approving the construction and recovery of all General Nationwide Permits. As partELG costs at the plant. In October 2021, the WVPSC affirmed its August 2021 order approving the construction of CCR/ELG investments and directed WPCo to proceed with CCR/ELG compliance plans that proposalwould allow the Corps has narrowedplant to continue operating beyond 2028. The WVPSC’s order further states WPCo will not share capacity and energy from the focus of NWP 12plant with KPCo customers if those customers are not paying for ELG compliance costs, or for any new capital investment or continuing operations costs incurred, to only oilallow the plant to operate beyond 2028 or prevent downgrades prior to 2028. The WVPSC also ordered that WPCo will be given the opportunity to recover, from its customers, the new capital and natural gas pipeline activities. The Corps is proposing two new Nationwide Permits governing electric utility lineoperating costs arising solely from the WVPSC's directive to operate the plant beyond 2028 if the WVPSC finds that the costs are reasonably and telecommunications activities, and other utility lines (e.g., conveyance of potable water, sewage, other substances), respectively. Management is currently assessing impactsprudently incurred. In October 2021, an intervenor filed a petition for reconsideration at the WVPSC requesting clarification on certain aspects of the proposal on currentorder, primarily the jurisdictional allocation of future operating expenses and planned projects.plant costs.

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 RegistrantsRegistrants’ 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 $734 million in 2019 to $749 million in 2020 to $796 million in 2021 primarily due to:

Earnings Attributable to AEP Common Shareholders decreasedincreased from $1,768 million in 2019 to $1,765 million in 2020 to $1,949 million in 2021 primarily due to: