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 1 – 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 Registrants may use the Investors section of AEP’s website (www.aep.com) to communicate with investors about the Registrants. It is possible that the financial and other information posted there could be deemed to be material information. The information on AEP’s website is not part of this report.

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. Also in April 2021, SWEPCo filed testimony supporting a five-year recovery with a pretax rate of return of 6.05%. A hearing is expected in the third quarter of 2021. A separate proceeding will address the prudency of the fuel costs.

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 3.4% reduction inManagement expects weather-normalized retail sales volume in 2020customer demand to continue to improve during 2021 as compared to the prior year. During the first half of 2020, AEP experienced a reduction in weather-normalized retail sales volume of 3.1% as compared to the first half of 2019 primarily driven by a 6.6% decrease in the industrial customer classadditional vaccinations occur and a 5.0% decrease in the commercial customer class offset by an increase in demand of 1.9% from the residential customer class. The reduction in weather-normalized retail sales volume of 3.1% did not result in a significant decrease in the corresponding retail margins for the six months ended 2020 as the increase in higher margin residential sales volumes partially offset the decreases in the industrial 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 extent and duration of the stay at home restrictions, the speed and strength of economic recovery and the extent and duration of the second wave of COVID-19 infection. Ifactivity improves. However, 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.

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. Disconnections were reinstatedShortly thereafter, AEP’s state regulators also imposed temporary moratoria on customary disconnection practices. As of March 31, 2021, AEP’s electric operating companies have resumed customary disconnection practices in July 2020all regulated jurisdictions with the exception of Arkansas and Virginia. In March 2021, the APSC issued an order allowing electric utilities in MichiganArkansas to begin disconnections for non-payment beginning on May 3, 2021. AEP continues to work with regulators and Oklahoma. Disconnections are anticipated to be reinstated startingstakeholders in August or SeptemberVirginia and management currently anticipates resuming customary disconnection practices in the third quarter of 2020 in Tennessee, Texas (applies to SWEPCo jurisdiction only), Louisiana, Virginia, West Virginia, Ohio, and Indiana. Current continuing2021. 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 second quarter of 2020, the

The Registrants reviewedcontinue to review current collectionsaccounts receivable collection experience with historical trends, specifically reviewing metrics such as customer receivables and 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, AEP’s accounts receivable aging was negatively impacted primarily dueAEP has been and continues to the suspensionbe proactive in engaging with customers to collect payments or establish payment arrangements for outstanding balances. As of the customer disconnects.March 31, 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 recentCOVID-19 impacts of COVID-19 and past trends during times of economic instability. Management will continuecontinues 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.

Market volatility and reduction indelayed customer accounts receivable collections coupled with longer collection periods due to the expansion of customer payment arrangements could reduce cash from operations and cause an adverse impact to liquidity. During the first six months of 2020, AEP increased its liquidity position to mitigate the market and the collections risk due to COVID-19. The Registrants’ access to funding was limited for a period of time during the first quarter and therefore AEP entered into a $1 billion 364–day term loan to reduce reliance on commercial paper and help mitigate potential future liquidity risks. In addition, for the first six months of 2020, AEP issued approximately $2.4 billion in long-term debt. As of June 30, 2020,March 31, 2021, AEP’s available liquidity is $2.9was $3.4 billion. Management believes the Registrants have adequate liquidity under existing credit facilities. In the first quarter of 2020, AEP shifted capital expenditures of $500 million out of 2020 into future periods to further mitigate adverse liquidity impacts. In the second quarter of 2020, AEP reinstated $100 million of capital expenditures back into 2020. To the extent that future access to the capital markets or the cost of funding is adversely affected by COVID-19, future results of operations, financial condition, and cash flows may be adversely impacted.

In March 2020, President Trump signed into law legislation referred to as the "Coronavirus Aid, Relief, and Economic Security Act" (the CARES Act). The CARES Act includes tax relief provisions such as: (a) an Alternative Minimum Tax (AMT) Credit Refund, (b) a 5-year net operating losses (NOL) carryback from years 2018-2020 and (c) delayed payment of employer payroll taxes. In May 2020, the House passed the “Health and Economic Recovery Omnibus Emergency Solutions Act” (the HEROES Act) pending decision by the Senate.  If enacted, the HEROES Act would disallow NOL carrybacks to any tax year beginning before January 1, 2018.  As of June 30, 2020, AEP has a $20 million AMT credit refund recognized in anticipation of a refund from the U.S. Treasury. Management is evaluating the ability to recover taxes paid in 2014 under the 5-year NOL carryback provision. The Registrants currently expectcontinue to defer payments of the employer share of payroll taxes for the period March 27, 2020 through December 31, 2020 and pay 50% of the obligation by December 31, 2021 and the remaining 50% by December 31, 2022.

AEP’s weather-normalized retail sales volumes for the secondfirst quarter of 20202021 decreased by 5.9%1.9% from the secondfirst quarter of 2019.2020. Weather-normalized residential sales increased by 6.2%1.5% in the secondfirst quarter of 20202021 from the secondfirst quarter of 2019.2020. AEP’s secondfirst quarter 20202021 industrial sales volumes decreased by 12.4%6.1% compared to the secondfirst quarter of 2019.2020. The decline in industrial sales was spread across many industries. Industrial sales were also negatively impacted by the severe winter event in AEP’s western operating territories in February 2021. Weather-normalized commercial sales decreased 10.1%1.6% in the secondfirst quarter of 20202021 from the secondfirst quarter of 2019.

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 following tables show the Registrants’ completed and pending base rate case proceedings in 2020.2021. See Note 4 - Rate Matters for additional information.

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.

As of June 30, 2020,March 31, 2021, subsidiaries within AEP’s Generation & Marketing segment had approximately 1,4231,549 MWs of contracted renewable generation projects in-service.  In addition, as of June 30, 2020,March 31, 2021, these subsidiaries had approximately 160239 MWs of renewable generation projects under construction with total estimated capital costs of $235$349 million related to these projects.

In May 2020, 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 bornecaused by COVID-19. Under the May 2020 IRS notice, qualifying renewable energy projects that began construction in 2016 and 2017 and which are placed in-service by the end of 2021 and 2022, respectively, will satisfy the Continuous EffortsContinuity Safe Harbor. As a result of this change byProvided that each facility does satisfy the IRS, the three North Central Wind Energy Facilities projects each have an additional year to achieve commercial operationsContinuity Safe Harbor, under the “Continuity Safe Harbor,” should there be a delay incurrent IRS guidance, the development199 MW wind facility will qualify for 100% of the projects.federal PTC, and the remaining two wind facilities, totaling 1,286 MWs, will qualify for 80% of the federal PTC.

In February 2021, AEP signed an agreement to sell Racine to a nonaffiliated party. As of March 2020, management placed 10 hydroelectric generation plants under study for a potential sale. In April 2020, the Virginia Clean Economy Act was signed into law by the Virginia Governor. The new law will provide renewable credits to APCo for its existing hydroelectric generation plants. As a result of the new law, management removed the three APCo hydroelectric generation plants (London, Marmet and Winfield) from the list of plants identified for potential sale. The table below shows31, 2021, the net book value of each plant, including CWIPRacine was $45 million. The sale of Racine requires approval from the FERC and materials and supplies, before costthe U.S. Army Corps of removal of the remaining plants includedEngineers. The sale is expected to close in the study.

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 cease in September 2021. Management also revised the useful life of the Dolet Hills Power Station to September 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.

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 extraction and associated mining-related costs as fuel is delivered. As of June 30, 2020, DHLC has unbilled ligniteagreements, SWEPCo’s fuel inventory and fixedunbilled fuel costs from mining related activities were $126 million as of $94March 31, 2021. Also, as of March 31, 2021, SWEPCo had a net over-recovered fuel balance of $20 million, that will be billed to SWEPCo prior toexcluding impacts of the closure ofFebruary 2021 severe winter weather event, which includes fuel consumed at the Dolet Hills Power Station. In 2009, SWEPCo acquired interests 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 June 30, 2020, Oxbow has unbilled fixed costs of $11 million that will be billed to SWEPCo prior to the closure of the Dolet Hills Power Station. DHLC and Oxbow have billed SWEPCo $49 million for lignite deliveries from April 2020 through June 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 through fuel clauses.

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 complaint 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 seek 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.

AEGCo and I&M sought and were granted dismissal by the U.S. District Court for the Southern District of Ohio of certain of the plaintiffs’ claims, including claims for compensatory damages, breach of contract, breach of the implied covenant of good faith and fair dealing and indemnification of costs. Plaintiffs voluntarily dismissed the surviving claims that AEGCo and I&M failed to exercise prudent utility practices with prejudice, and the court issued a final judgment. The plaintiffs subsequently filed an appeal in the U.S. Court of Appeals for the Sixth Circuit.

In 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion and judgment affirming the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims, reversing the district court’s dismissal of the breach of contract claims and remanding the case for further proceedings.

Thereafter, AEP filed a motion with the U.S. District Court for the Southern District of Ohio in the original NSR litigation, seeking to modify the consent decree. The district court granted the owners’ unopposed motion to stay the lease litigation to afford time for resolution of AEP’s motion to modify the consent decree. The consent decree was modified based on an agreement among the parties in July 2019. The district court’s stay of the lease litigation expired in February 2020, but the court later extendedAugust 2020. Upon expiration of the stay, through August 13,plaintiffs filed a motion for partial summary judgment,

arguing that the consent decree violates the facility lease and the participation agreement and requesting that the district court enter a judgment for the plaintiffs on their breach of contract claim. AEP’s memorandum in opposition to plaintiffs’ motion for partial summary judgment was filed in October 2020. At the parties’ request, the district court stayed the case until April 19, 2021 to provide the parties an opportunity to resolve the case. See “Modification of“Obligations under the NSRNew Source Review Litigation Consent Decree” section below for additional information.

Management will continueOn April 20, 2021, I&M and AEGCo reached an agreement to defend againstacquire 100% of the claims. Giveninterests 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 dismissed plaintiffs’dismiss the case without prejudice to plaintiffs asserting their claims seeking compensatory reliefin a re-filed action or in a new action. The agreement is subject to customary closing conditions, including regulatory approvals, and as premature,of the closing will result in a final settlement of, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management cannot determine a rangerelease of potential losses that is reasonably possibleclaims in, the lease litigation. Management believes its financial statements appropriately reflect the expected resolution of occurring.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 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 (ADEA); 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 somea 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 June 30, 2020,March 31, 2021, the AEP System hadowned generating capacity of approximately 24,70024,600 MWs, of which approximately 12,60012,100 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 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.

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 CCR landfills and surface impoundments at operating 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 a challenge to the final 2015 rule, the parties initially agreed to settle some of the issues.  In 2018, the U.S. Court of Appeals for the District of Columbia Circuit addressed or dismissed the remaining issues in its decision vacating and remanding certain provisions of the 2015 rule.  The provisions addressed by the court’s decision, including changes to the provisions for unlined impoundments and legacy sites, will be the subject of further rulemaking consistent with the court’s decision.

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. Additional AEP facilities are reviewing these requirements as their wastewater discharge permits are renewed and making appropriate adjustments to their intake structures.

In 2015,addition to the November 2020 announcement related to the Federal EPAEPA’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 the U.S. Army Corps of Engineers jointly issued a final rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases. Various parties challenged the 2015 rule in different U.S. District Courts, which resulted in a patchwork of applicability of 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.

Earnings Attributable to AEP Common Shareholders increased from $461 million in 2019 to $521$495 million in 2020 to $575 million in 2021 primarily due to: