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.  For details on the regulatory proceedings and pending litigation see Note 4 - Rate Matters, Note 6 - Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2016 Annual Report. Additionally, see Note 4 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies included herein. 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 July 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 willwould 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 further allege that the defendants’ actions constitute breach of the lease and participation agreement.  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. See “Obligations under the New Source Review Litigation Consent Decree” section below for additional information.

After the litigation proceeded at the district court and appellate court, in April 2021, I&M and AEGCo reached an agreement to acquire 100% of the interests in Rockport Plant, Unit 2 for $116 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 New Yorkagreement is subject to customary closing conditions 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 grantedentered a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismissstipulation and order dismissing the case was filed on behalf of AEGCowithout prejudice to plaintiffs asserting their claims in a re-filed action or a new action. The required regulatory approvals at the IURC and I&M.

Four participants in The American Electric Power System Retirement Plan (the Plan) filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, plaintiffs filed an appealclass action complaint in the U.S. Court of Appeals for the Sixth Circuit on whether AEGCo and I&M areDecember 2021 in breach of certain contract provisions that plaintiffs allege operate to protect the plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing.

AEP has a substantial capital investment program and is incurringincurs additional operational costs to comply with environmental control requirements.  Additional investments and operational changes will need to be made in response to existing and anticipated requirements such as new CAA requirements to reduce emissions from fossil fuel-fired power plants,generation and in response to rules governing the beneficial use and disposal of coal combustion products,by-products, clean water rules 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 various industry groups, affected states and other parties challenged some of the Federal EPA requirements in court.  Management is also 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.

See a complete discussion of these matters in the “Environmental Issues” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2016 Annual Report. 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 is unable tocannot 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 in the next several sectionsbelow will have a material impact on theAEP System generating units in the AEP System.units.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of SeptemberJune 30, 2017,2022, the AEP System had a totalowned generating capacity of approximately 25,60025,800 MWs, of which approximately 13,50011,900 MWs arewere coal-fired.  Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on the fossil generating facilities.generation. Based upon management estimates, AEP’s future investment to meet these existing and proposed requirements ranges from approximately $2.2 billion$325 million to $2.8 billion between 2017 and 2025.$550 million through 2028.

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in finalizing proposed rules or reviewing and revising certain existing requirements.  The cost estimates will also change based on: (a) the states’ implementation of these regulatory programs, including the potential for state implementation plans (SIPs) or federal implementation plans (FIPs)rules that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed, on the units, (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, (g) compliance with the Federal EPA’s revised coal combustion residual rules and (g)(h) other factors.  In addition, management is continuingcontinues to evaluate the economic feasibility of environmental investments on both 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 the National Ambient Air Quality Standards (NAAQS)NAAQS and the development of SIPs to achieve any more stringent standards;standards, (b) implementation of the regional haze program by the states and the Federal EPA;EPA, (c) regulation of hazardous air pollutant emissions under the Mercury and Air Toxics Standards (MATS) Rule;MATS, (d) implementation and review of the Cross-State Air Pollution Rule (CSAPR), a FIP designed to eliminate significant contributions from sources in upwind states to nonattainment or maintenance areas in downwind statesCSAPR and (e) the Federal EPA’s regulation of greenhouse gas emissions from fossil-fueled electric generating unitsfossil generation under Section 111 of the CAA.

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) willto address regional haze in federal parks and other protected areas. BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants.  CAVR will beis implemented by the states, through SIPs, or if SIPs are not adequate or are not developed on schedule,by the Federal EPA, through FIPs. In January 2017, the Federal EPA revised the rules governing submission of SIPs to implement the visibility programs, including a provision that postponespostponed 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 proposed disapproval ofArkansas has an approved regional haze SIPsSIP and all of SWEPCo's affected units are in a few states, including Arkansas and Texas.  In March 2012, the Federal EPA disapproved certain portions of the Arkansas regional haze SIP. In April 2015, the Federal EPA published a proposed FIP to replace the disapproved portions, including revised BART determinations for the Flint Creek Plant that were consistentcompliance with the environmental controls currently under construction. relevant requirements.

In 2018, the Federal EPA requestedfiled a proposed rule revising the standards for new sources and determined that oral argument be postponedpartial 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 facilitateactively monitor these rulemaking activities.

In April 2015, theThe Federal EPA published a finalEPA’s CCR rule to regulateregulates the disposal and beneficial re-use of coal combustion residuals (CCR),CCR, including fly ash and bottom ash generated atcreated from coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants.  The final rule has been challenged in the courts.

In December 2016, the U.S. Congress passed legislation authorizing states to submit programs to regulate CCR facilities, and2020, the Federal EPA to approve such programs if they are no less stringent than the minimum federal standards. The Federal EPA may also enforce compliance with the minimum standards until a state program is approved or if states fail to adopt their own programs. In September 2017, the Federal EPA granted industry petitions to reconsiderrevised the CCR rule to include a requirement that unlined CCR storage ponds cease operations and askedinitiate closure by April 11, 2021. The revised rule provides two options that litigation regardingallow facilities to extend the rule be held in abeyance. date by which they must cease receipt of coal ash and close the ponds.

The court has ordered oral argumentfirst option provides an extension to proceed in November 2017cease receipt of CCR no later than October 15, 2023 for most units, and thatOctober 15, 2024 for a narrow subset of units; however, the motion for abeyance be addressed during oral argument.

In addition, AGR owns Cardinal Plant, Unit 1 a competitive generation unit. A nonaffiliated electric cooperative owns Cardinal Plant, Unit 2 and Unit 3 and operates all three units at the future asCardinal Plant. The nonaffiliate filed an application for additional time to develop alternative disposal capacity for the new rule is implemented. Management recorded a $95 million increase in asset retirement obligations inCardinal Plant. As of June 30, 2022, the net book value of Cardinal Plant, Unit 1, including materials and supplies and CWIP, was approximately $48 million. In the second quarter of 2015 primarily due2022, AGR filed and FERC approved an application requesting authorization of the sale of Cardinal Plant, Unit 1 to the publicationnonaffiliated electric cooperative previously discussed. The sale is expected to close in the third quarter of 2022 with AGR concurrently executing a PPA with the final rule. Management will continuenonaffiliated electric cooperative for rights to evaluate the rule’s impactpower and capacity through 2028 and retaining certain obligations related to environmental remediation. The transaction is not expected to have a material effect on operations.AEP’s financial statements.

In 2014,January 2022, the Federal EPA issued a final rule setting forth standardsbegan responding to applications for existing power plantsextension requests and has proposed to deny several extension requests based on allegations that is intended to reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrainedthe utilities that received such responses are not in the cooling water.  Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress.  The final rule affects all plants withdrawing more than two million gallons of cooling water per day. The rule offers seven technology options to complycompliance with the impingement standard and requires site-specific studies to determine appropriate entrainment compliance measures at facilities withdrawing more than

The second option to obtain an extension of the April 11, 2021 deadline to cease operation of unlined impoundments allows a generating facilities.  A finalfacility to continue operating its existing impoundments without developing alternative CCR disposal, provided the facility commits to cease combustion of coal by a date certain. Under this option, a generating facility would have until October 17, 2023 to cease coal-fired operations 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:

The Federal EPA’s ELG rule was issued in November 2015. The final rulefor generating facilities establishes limits onfor FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater, as soon as possible after November 2018 and no later than December 2023. These new requirements willwhich are to be implemented through each facility’s wastewater discharge permit. TheA revision to the ELG rule, has been challengedpublished in the U.S. CourtOctober 2020, establishes additional options for reusing and discharging small volumes of Appeals for the Fifth Circuit. In March 2017, industry associations filed a petition for reconsideration of the rule with the Federal EPA. In April 2017, the Federal EPA granted reconsideration of the rule and issued a stay of the rule’s future compliance deadlines, which has now expired. In April 2017, the U.S. Court of Appeals for the Fifth Circuit granted a stay of the litigation for 120 days. In June 2017, the Federal EPA also issued a proposal to temporarily postpone certain compliance deadlines in the rule. A final rule revising the compliance deadlines for FGD wastewater and bottom ash transport water, provides an exception for retiring units and extends the compliance deadline to bea date as soon as possible beginning one year after the rule was published but no earlierlater than 2020 was issued in September 2017.December 2025. Management submitted comments supporting the proposed postponement. Management continues to assesshas 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.permitting for FGD wastewater and bottom ash transport water. For affected facilities that must install additional technologies to meet the ELG rule limits, permit modifications were filed in January 2021 that reflect the outcome of that assessment. AEP continues to work with state agencies to finalize permit terms and conditions. Other facilities opted to file Notices of Planned Participation (NOPP), pursuant to which the facilities are not required to install additional

In June 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. The CWA provides for federal jurisdiction over “navigable waters” defined as “the waters ofunder the United States.” This jurisdictional definition applies to all CWA programs, potentially impacting generation, transmission and distribution permitting and compliance requirements. Among those programs are permits for wastewater and storm water discharges, permits for impacts to wetlands and water bodies and oil spill prevention planning. The final definition continues to recognize traditional navigable waters of the U.S. as jurisdictional as well as certain exclusions. The rule also contains a number of new specific definitions and criteria for determining whether certain other waters are jurisdictional because of a “significant nexus.” Management believes that clarity and efficiency in the permitting process is needed. Management remains concerned that the rule introduces new concepts and could subject more of AEP’s operations to CWA jurisdiction, thereby increasing the time and complexity of permitting. The final rule is being challenged in both courts of appeal and district courts. Challengers include industry associations of which AEP is a member. The U.S. Court of Appeals for the Sixth Circuit granted a nationwide stay of the rule pending jurisdictional determinations. In February 2016, the U.S. Court of Appeals for the Sixth Circuit issued a decision holding that it has exclusive jurisdiction to decide the challenges to the “waters of the United States” rule. Industry, state and related associations have filed petitions for a rehearing of the jurisdictional decision. In April 2016, the U.S. Court of Appeals for the Sixth Circuit denied the petitions. In January 2017, the decision was appealed to the U.S. Supreme Court, which granted certiorari to review the jurisdictional issue. The U.S. Supreme Court denied the Federal EPA’s motion to hold briefing in abeyance pending further Federal EPA actions on the rule and the appeal on the jurisdictional issue continues.

In August 2021, the WVPSC approved the full CCR and ELG compliance plan for the WPCo share of the Mitchell Plant. In September 2021, WPCo submitted a filing with the WVPSC to reopen the CCR/ELG case that was adoptedapproved by the WVPSC in June 2015,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 ELG 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 re-codifyproceed with CCR/ELG compliance plans that would allow the definition of that phrase as it existed immediatelyplant to continue operating beyond 2028. The WVPSC’s order further states WPCo will not share capacity and energy from the plant 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 allow the plant to operate beyond 2028 or prevent downgrades prior to 2028. The WVPSC also ordered that action. This actionWPCo will be given the opportunity to recover, from its customers, the new capital and operating costs arising solely from the WVPSC's directive to operate the plant beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred.

Also in August 2021, the WVPSC approved the request to construct CCR/ELG investments at the Amos and Mountaineer Plants and approved recovery of the West Virginia jurisdictional share of these costs through an active rider. In October 2021, due to the Virginia SCC previously rejecting the ELG investments, the WVPSC issued an order directing APCo to proceed with CCR/ELG compliance plans that would effectively retainallow the status quo untilplants to continue operating beyond 2028. The October 2021 order further states that APCo will not share capacity and energy from the plants with customers from Virginia if those customers are not paying for ELG compliance costs, or for any new capital investment or continuing operations costs incurred, to allow the plants to operate beyond 2028 or prevent downgrades prior to 2028. The WVPSC also ordered that APCo will be given the opportunity to recover, from West Virginia customers, the new capital and operating costs arising solely from the WVPSC's directive to operate the plants beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred.

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

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 isare 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, Generation Deferrals 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,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: