# AMERICAN ELECTRIC POWER CO INC (AEP) FY 2023 MD&A Verbatim Item 7 Management's Discussion and Analysis from AMERICAN ELECTRIC POWER CO INC's 10-K for fiscal year 2023. SEC filing source: https://www.sec.gov/Archives/edgar/data/4904/000000490424000020/aep-20231231.htm Accession: 0000004904-24-000020 Filing date: 2024-02-26 Report date: 2023-12-31 Extracted from a later financial-section MD&A body after the formal Item 7 span was a short reference. Published MD&A gate trimmed front/tail over-capture. Confidence: high Company profile: /company/AEP/ All MD&A years: /company/AEP/mda/ Previous year: /company/AEP/mda/fy2022/ (FY 2022) Next year: /company/AEP/mda/fy2024/ (FY 2024) RESULTS OF OPERATIONS EXECUTIVE OVERVIEW Company Overview AEP is one of the largest investor-owned electric public utility holding companies in the United States.  AEP’s electric utility operating companies provide generation, transmission and distribution services to more than five million retail customers in Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. AEP’s subsidiaries operate an extensive portfolio of assets including: •Approximately 225,000 circuit miles of distribution lines that deliver electricity to 5.6 million customers. •Approximately 40,000 circuit miles of transmission lines, including approximately 2,200 circuit miles of 765 kV lines, the backbone of the electric interconnection grid in the eastern United States. •Approximately 23,000 MWs of regulated owned generating capacity as of December 31, 2023, one of the largest complements of generation in the United States. AEP CONSOLIDATED RESULTS OF OPERATIONS 2023 Compared to 2022 Earnings Attributable to AEP Common Shareholders decreased from $2.3 billion in 2022 to $2.2 billion in 2023 primarily due to: •A decrease in weather-related sales volumes. •An increase in interest expense due to higher interest rates and debt balances. •Unfavorable mark-to-market economic hedge activity driven by a decrease in commodity prices. •A loss on the sale of the competitive contracted renewables portfolio in 2023. •Unfavorable regulatory decisions in Texas, West Virginia and at FERC. •A gain on the sale of mineral rights in 2022. These decreases were partially offset by: •Favorable rate proceedings in AEP’s various jurisdictions. •Investment in transmission assets, which resulted in higher revenues and income. •A loss related to the expected sale of the Kentucky Operations in 2022. The expected sale was terminated in April 2023. •An impairment of AEP’s equity investment in Flat Ridge 2 in 2022. See “Results of Operations” section for additional information by operating segment. Customer Demand AEP’s weather-normalized retail sales volumes for the year ended December 31, 2023 increased by 2.5% from the year ended December 31, 2022. Weather-normalized residential sales decreased 0.9% for the year ended December 31, 2023 compared to the year ended December 31, 2022. Weather-normalized commercial sales increased by 7.8% in 2023 compared to 2022. The increase in commercial sales was primarily due to new data center loads and economic development. AEP’s 2023 industrial sales volumes increased 1.6% compared to 2022. The growth in industrial sales was spread across many industries. In 2024, AEP anticipates weather-normalized retail sales volumes will increase by 1.5%. Weather-normalized residential sales volumes are projected to decrease by 0.4% in 2024, while weather-normalized commercial sales volumes are projected to increase by 4.5%. The projected increase in commercial sales volumes is driven by new loads associated with data centers and cryptocurrency operations. Finally, AEP projects the industrial sales volumes to increase by 0.6% in 2024. 44 (a)Percentage change for the year ended December 31, 2023 as compared to the year ended December 31, 2022. (b)Forecasted percentage change for the year ended December 31, 2024 compared to the year ended December 31, 2023. Supply Chain Disruption and Inflation The Registrants have experienced certain supply chain disruptions driven by several factors including international tensions and the ramifications of regional conflict, increased demand due to the economic recovery from the pandemic, inflation, 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 and have contributed to higher prices for fuel, materials, labor, equipment and other needed commodities. Management has implemented risk mitigation strategies in an attempt to mitigate the impacts of these supply chain disruptions. The United States economy has experienced a significant level of inflation that has contributed to increased uncertainty in the outlook of near-term economic activity, including whether the pace of inflation will continue to moderate. A prolonged continuation or a further increase in the severity of supply chain and inflationary disruptions could result in additional increases in the cost of certain goods, services and cost of capital and further extend lead times which could reduce future net income and cash flows and impact financial condition. 2023 SIGNIFICANT DEVELOPMENTS AND TRANSACTIONS Disposition of the Competitive Contracted Renewables Portfolio In February 2022, AEP management announced the initiation of a process to sell all or a portion of AEP Renewables’ competitive contracted renewables portfolio (the portfolio) within the Generation & Marketing segment. In late January 2023, AEP received final bids from interested parties. In February 2023, AEP’s Board of Directors approved management’s plan to sell the portfolio and AEP signed an agreement with a nonaffiliated party. In August 2023, AEP completed the sale of the entire portfolio to the nonaffiliated party and received cash proceeds of approximately $1.2 billion, net of taxes and transaction costs. AEP recorded a pretax loss of approximately $93 million ($73 million after-tax) for the year ended December 31, 2023 related to the sale. See the "Disposition of the Competitive Contracted Renewables Portfolio" section of Note 7 for additional information. Planned Sale of AEP Energy and AEP Onsite Partners AEP management has continued a strategic evaluation of AEP’s portfolio of businesses with a focus on core regulated utility operations, risk mitigation and simplification. As a result of these efforts, the following decisions have been made with respect to AEP Energy and AEP Onsite Partners. 45 AEP Energy In October 2022, AEP initiated a strategic evaluation for its ownership in AEP Energy, a wholly-owned retail energy supplier that supplies electricity and/or natural gas on a price risk managed basis to residential, commercial and industrial customers. AEP Energy provides various energy solutions in Illinois, Pennsylvania, Delaware, Maryland, New Jersey, Ohio and Washington, D.C. AEP Energy had approximately 929,000 customer accounts as of December 31, 2023. In April 2023, AEP management completed the strategic evaluation of AEP Energy and initiated a sales process. The timing of the completion of the sales process is dependent upon a number of factors. AEP is currently targeting the sales process to be completed in the first half of 2024. Depending on the outcome of the sales process, it could reduce future net income and impact financial condition. AEP Onsite Partners In April 2023, AEP also made a decision to include AEP Onsite Partners in a sales process. AEP OnSite Partners targets opportunities in distributed solar, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other energy solutions. As of December 31, 2023, AEP OnSite Partners owned projects located in 22 states, including approximately 195 MWs of installed solar capacity and two solar projects under construction totaling approximately 4 MWs. As of December 31, 2023, the net book value of these assets was $352 million. The timing of the completion of the sales process is dependent upon a number of factors. AEP is currently targeting the sales process to be completed in the first half of 2024. If AEP is unable to recover the net book value of these assets as part of the sale process, it could reduce future net income and impact financial condition. AEP Onsite Partners also owns a 50% interest in NMRD totaling $101 million accounted for as an equity method investment. The NMRD portfolio consists of 9 operating solar projects totaling 185 MWs and 6 projects totaling 440 MWs in development. Separate from the remainder of AEP Onsite Partners, AEP and the joint owner agreed to a joint sales process for their respective interests in NMRD. In December 2023, AEP and the joint owner signed an agreement to sell NMRD to a nonaffiliated third party for $230 million. AEP expects to receive cash proceeds of $104 million, net of taxes, transaction fees and other customary closing adjustments. AEP recorded a pretax loss of $19 million in the fourth quarter of 2023 as a result of entering into the sales agreement. The transaction has received all required regulatory approvals and is expected to close in the first quarter of 2024. See the “NMRD” section of Note 7 for additional information. Planned Sale and Strategic Evaluation of Certain Transmission Joint Ventures In April 2023, AEP also initiated a strategic evaluation for its ownership in certain transmission joint ventures in the AEP Transmission Holdco segment including Pioneer Transmission, LLC, Prairie Wind Transmission, LLC and Transource Energy. In July 2023, AEP made a decision to initiate a sales process for its investment in Pioneer Transmission, LLC and Prairie Wind Transmission, LLC. In February 2024, AEP management determined it would retain its ownership of its investment in Pioneer Transmission, LLC and Prairie Wind Transmission, LLC. As of December 31, 2023, AEP’s investment in Pioneer Transmission, LLC and Prairie Wind Transmission, LLC was $46 million and $19 million, respectively. As of December 31, 2023, the net book value of Transource Energy was $289 million inclusive of $39 million related to noncontrolling interest on AEP’s balance sheet. AEP management recently completed its strategic review and determined it would retain this business due to its fit within the goals and objectives of AEP and its overall leadership role in the U.S. electric transmission space. 46 Termination of Planned Disposition of KPCo and KTCo In October 2021, AEP entered into a Stock Purchase Agreement (SPA) to sell KPCo and KTCo to Liberty Utilities Co., a subsidiary of Algonquin Power & Utilities Corp. (Liberty), for approximately a $2.85 billion enterprise value. The SPA was subsequently amended in September 2022 to reduce the purchase price to approximately $2.646 billion. An impairment of $363 million was recorded for the year ended December 31, 2022. The sale required approval from the KPSC and from the FERC under Section 203 of the Federal Power Act. The SPA contained certain termination rights if the closing of the sale did not occur by April 26, 2023. In May 2022, the KPSC approved the sale of KPCo to Liberty subject to certain conditions contingent upon the closing of the sale. In December 2022, the FERC issued an order denying, without prejudice, authorization of the proposed sale stating the applicants failed to demonstrate the proposed transaction will not have an adverse effect on rates. In February 2023, a new filing for approval under Section 203 of the Federal Power Act was submitted. In March 2023, the KPSC and other intervenors made filings recommending the FERC reject AEP and Liberty’s new Section 203 application seeking approval of the sale. As a result of delays in the anticipated timing of the closing of the transaction and other factors, AEP recorded a $363 million pretax loss on the expected sale of the Kentucky Operations for the year ended December 31, 2022. In April 2023, AEP, AEPTCo and Liberty entered into a Mutual Termination Agreement (Termination Agreement) terminating the SPA. The parties entered into the Termination Agreement as all of the conditions precedent to closing the sale could not be satisfied prior to April 26, 2023. Upon termination of the sale and reverting to a held and used model, in the first quarter of 2023, AEP reversed $28 million of expected transaction costs included in the $363 million pretax loss and was required to present its investment in the Kentucky Operations at the lower of fair value or historical carrying value which resulted in a $335 million reduction recorded in Property, Plant and Equipment. The reduced investment in KPCo’s assets is being amortized over the 30-year average useful life of the KPCo assets. Renewable Generation The growth of AEP’s regulated renewable generation portfolio reflects the company’s strategy to diversify generation resources to provide clean energy to customers that meet both their energy and capacity needs. Significant Renewable Generation Placed Into Service In 2023, AEP acquired and placed into service 159 MWs of owned renewable generation facilities totaling approximately $155 million. Significant Approved Renewable Generation Filings AEP has received regulatory approvals from various state regulatory commissions to acquire approximately 2,811 MWs of owned renewable generation facilities, totaling approximately $6.6 billion, in addition to 377 MWs of renewable purchase power agreements, as included in the following table: [[GREPCENT_TABLE]] [["Company","","Generation Type","","Expected Commercial Operation","","Owned/PPA","","Generating Capacity"],["","","","","","","","","(in MWs)"],["APCo","","Solar","","Year End 2024 through Year End 2026","","PPA","","204"],["APCo","","Wind","","Year End 2025 through Year End 2026","","Owned","","347"],["I&M","","Solar","","Year End 2025","","PPA","","100"],["I&M","","Solar","","Year End 2026","","Owned","","469"],["PSO","","Solar","","Year End 2025","","Owned","","443"],["PSO","","Wind","","Year End 2025 through Year End 2026","","Owned","","553"],["SWEPCo (a)","","Solar","","Year End 2025 through Year End 2027","","Owned/PPA","","273"],["SWEPCo (a)","","Wind","","Year End 2024 through Year End 2025","","Owned","","799"],["Total Approved Renewable Projects","","","","3,188"]] [[/GREPCENT_TABLE]] (a)Includes approvals by the APSC and LPSC for 999 MWs of owned projects. Additionally, the LPSC approved the flex-up option, allowing SWEPCo to provide additional service to Louisiana customers and recover the portion of the projects denied by the PUCT. 47 Significant Renewable Generation Requests for Proposal (RFP) As part of AEP’s transition to diversify the company’s regulated generation resources and build its renewable generation portfolio, RFPs have been issued in order to satisfy the need for additional capacity resources. The table below includes RFPs recently issued for both owned and purchased power generation. Unless otherwise noted, RFPs issued are all-source solicitations for accredited capacity with consideration made for renewable projects. Projects selected will be subject to regulatory approval. [[GREPCENT_TABLE]] [["Company","","Issuance Date","","Projected In-Service Dates","","","","Generating Capacity"],["","","","","","","","","(in MWs)"],["I&M (a)","","March 2023","","Year End 2027","","","","2,505"],["APCo (b)","","April 2023","","Year End 2026","","","","800"],["KPCo (c)","","September 2023","","Year End 2026/2027","","","","1,300"],["PSO","","November 2023","","Year End 2027/2028","","","","1,500"],["SWEPCo","","January 2024","","Year End 2028","","","","2,100"],["Total Significant RFPs","","","","","","","","8,205"]] [[/GREPCENT_TABLE]] (a)RFP is seeking nameplate capacity proposals from various types of generation. Actual MWs by technology type depends on the portfolio of projects selected and individual contribution toward meeting I&M’s overall capacity need. (b)RFP is seeking nameplate capacity proposals for up to 600 MWs of owned wind or solar and 200 MWs of wind or solar PPAs. Also includes an option for battery storage. (c)RFP is seeking proposals for PPAs only. Regulatory Matters - Utility Rates and Rate Proceedings The Registrants are involved in rate cases and other proceedings 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.  Depending on the outcomes, these rate cases and 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. The following tables show the Registrants’ completed and pending base rate case proceedings in 2023. See Note 4 - Rate Matters for additional information. Completed Base Rate Case Proceedings [[GREPCENT_TABLE]] [["","","","","Annual"],["","","","","Base Revenue","","","Approved","","New Rates"],["Company","","Jurisdiction","","Increase","","","ROE","","Effective"],["","","","","(in millions)"],["SWEPCo","","Louisiana","","$","21.0","","(a)","","9.5%","","February 2023"],["PSO","","Oklahoma","","131.0","","","","9.3%","","January 2024"],["APCo","","Virginia","","127.0","","","","9.5%","","January 2024"],["KPCo","","Kentucky","","60.0","","","","9.75%","","January 2024"]] [[/GREPCENT_TABLE]] (a)See “2020 Louisiana Base Rate Case” section of Note 4 for additional information. Pending Base Rate Case Proceedings [[GREPCENT_TABLE]] [["","","","","","","Annual"],["","","","","Filing","","Base Revenue","","Requested"],["Company","","Jurisdiction","","Date","","Increase Request","","ROE"],["","","","","","","(in millions)"],["I&M","","Indiana","","August 2023","","$","116.0","","","10.5%"],["I&M","","Michigan","","September 2023","","34.0","","","10.5%"],["PSO","","Oklahoma","","January 2024","","218.0","","","10.8%"]] [[/GREPCENT_TABLE]] 48 Other Significant Regulatory Matters 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. In 2017, the Texas District Court upheld the PUCT’s 2014 order and intervenors filed appeals with the Texas Third Court of Appeals. In August 2021, the Texas Third Court of Appeals reversed the Texas District Court judgment affirming the PUCT’s order on AFUDC, concluding that the language of the PUCT’s original 2008 order intended to include AFUDC in the Texas jurisdictional capital cost cap, and remanded the case to the PUCT for future proceedings. In November 2021, SWEPCo and the PUCT submitted Petitions for Review with the Texas Supreme Court. In October 2022, the Texas Supreme Court denied the Petitions for Review submitted by SWEPCo and the PUCT. In December 2022, SWEPCo and the PUCT filed requests for rehearing with the Texas Supreme Court. In June 2023, the Texas Supreme Court denied SWEPCo’s request for rehearing and the case was remanded to the PUCT for future proceedings. In October 2023, SWEPCo filed testimony with the PUCT in the remanded proceeding recommending no refund or disallowance. On December 14, 2023, the PUCT approved a preliminary order stating the PUCT will not address SWEPCo’s request that would allow the PUCT to find cause to allow SWEPCo to exceed the Texas jurisdictional capital cost cap in the current remand proceeding. As a result of the PUCT’s approval of the preliminary order, SWEPCo believes it is probable the PUCT will disallow capitalized AFUDC in excess of the Texas jurisdictional capital cost cap and recorded a pretax, non-cash disallowance of $86 million in the fourth quarter of 2023. Such determination may reduce SWEPCo’s future revenues by approximately $15 million on an annual basis. On December 21, 2023, SWEPCo filed a motion with the PUCT for reconsideration of the preliminary order. In January 2024, the PUCT denied the motion for reconsideration of the preliminary order. The PUCT’s December 2023 approval of the preliminary order determined that it will address, in the ongoing PUCT remand proceeding, any potential revenue refunds to customers that may be required by future PUCT orders. In January 2024, the PUCT established a procedural schedule for the remand proceeding. Supplemental testimony from SWEPCo is due in March 2024, intervenor and staff testimony is due in April 2024 and a hearing is scheduled for May 2024. Although SWEPCo does not currently believe any refunds are probable of occurring, SWEPCo estimates it could be required to make customer refunds, including interest, ranging from $0 to $200 million related to revenues collected from February 2013 through December 2023. FERC 2021 PJM and SPP Transmission Formula Rate Challenge The Registrants transitioned to stand-alone treatment of NOLCs in its PJM and SPP transmission formula rates beginning with the 2022 projected transmission revenue requirements and 2021 true-up to actual transmission revenue requirements and provided notice of this change in informational filings made with the FERC. Stand-alone treatment of the NOLCs for transmission formula rates increased the annual revenue requirements for years 2023, 2022 and 2021 by $60 million, $69 million and $78 million, respectively. In March 2023 and May 2023, certain joint customers submitted a complaint and a formal challenge at the FERC related to the 2022 Annual Update of the 2021 Transmission Formula Rates of the AEP transmission owning subsidiaries within PJM and SPP, respectively. These challenges primarily relate to stand-alone treatment of NOLCs in the transmission formula rates of the AEP transmission owning subsidiaries. AEPSC, on behalf of the AEP transmission owning subsidiaries within PJM and SPP, filed answers to the joint formal challenge and complaint with the FERC in the second quarter of 2023. In January 2024, the FERC issued two orders, granting the joint customers’ challenges related to stand-alone treatment of NOLCs in the 2021 Transmission Formula Rates of the AEP transmission owning subsidiaries within PJM and SPP. The FERC directed the AEP transmission owning subsidiaries within PJM and SPP to provide refunds with interest on all amounts collected for the 2021 rate year, and for such refunds to be reflected in the annual update for the next rate year. In February 2024, AEPSC on behalf of the AEP transmission owning subsidiaries within PJM and SPP filed requests with the FERC that it grant rehearing and reverse findings in its January 2024 orders or establish hearing procedures to address outstanding factual issues. As a result of the January 2024 FERC orders, the Registrants’ 2022 and 2023 income statements cumulatively reflect a provision for refund for the probable refund of all NOLC revenues included in transmission formula rates for years 2023, 2022 and 2021. The probable refunds to affiliated and nonaffiliated customers are reflected as Deferred Credits and Other Noncurrent Liabilities on the balance sheets. Refunds probable to be received by affiliated companies, resulting in a reduction to affiliated transmission expense, were deferred as an increase to Regulatory Liabilities or a reduction to Regulatory Assets on 49 the balance sheets where management expects that refunds would be returned to retail customers through authorized retail jurisdiction rider mechanisms. The FERC directed cash refunds with interest related to the 2021 rate year to occur through the annual update for the next rate year, which will be invoiced by PJM and SPP primarily in 2025. The Registrants have not yet been directed to make cash refunds related to the 2022 or 2023 rate years. The FERC's January 2024 orders reduced AEP and AEPTCo's 2023 pretax net income by approximately $76 million and $74 million, respectively. The impact of the FERC's orders on the pretax net income of AEP's remaining Registrant Subsidiaries was not material. Kentucky Securitization Case In conjunction with KPCo’s June 2023 base rate case filing, KPCo requested to finance, through the issuance of securitization bonds, approximately $471 million of regulatory assets recorded as of June 2023 including: (a) $289 million of plant retirement costs, (b) $79 million of deferred storm costs related to 2020, 2021, 2022 and 2023 major storms, (c) $52 million of deferred purchased power expenses and (d) $51 million of under-recovered purchased power rider costs. In January 2024, the KPSC issued a financing order approving KPCo’s securitization request and concluding that costs requested for recovery were prudently incurred. The KPSC’s financing order includes certain additional requirements related to securitization bond structuring, marketing, placement, and issuance that were not reflected in KPCo’s proposal. As a result, in January 2024, KPCo filed a request for rehearing with the KPSC to clarify certain aspects of these additional requirements. In February 2024, the KPSC denied KPCo’s rehearing requests. In accordance with Kentucky statutory requirements and the financing order, the issuance of the securitized bonds is subject to final review by the KPSC after bond pricing. KPCo expects to proceed with the securitized bond issuance process and to complete the securitization process in the second half of 2024, subject to market conditions. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Deferred Fuel Costs Increases in fuel and purchased power costs in excess of amounts included in fuel-related revenues has led to an increase in the under collection of fuel costs from customers in several jurisdictions in recent years. To help ease the burden on customers, certain state commissions have issued orders allowing recovery of these costs over periods exceeding the traditional jurisdictional FAC terms. The table below illustrates the current and noncurrent under-recovered fuel regulatory asset balances, by jurisdiction, impacted by these orders. If any of these deferred fuel costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See Note 4 - Rate Matters and Note 5 - Effects of Regulation for additional information. [[GREPCENT_TABLE]] [["","","","","Expected/Authorized","","As of","","As of","","Increase/"],["Company","","Jurisdiction","","Recovery Period","","December 31, 2023","","December 31, 2022","","(Decrease)"],["","","","","","","(in millions)"],["APCo","","Virginia","","2025","","$","254.4","","(a)","$","407.9","","","$","(153.5)"],["APCo","","West Virginia","","2034","","162.2","","(b)","288.5","","","(126.3)"],["PSO","","Oklahoma","","2024","","118.3","","(c)","431.5","","","(313.2)"],["SWEPCo","","Texas","","2035","","80.9","","(d)","80.7","","","0.2"],["WPCo","","West Virginia","","2034","","181.3","","(b)","231.1","","","(49.8)"],["","","","","Total","","$","797.1","","","$","1,439.7","","","$","(642.6)"]] [[/GREPCENT_TABLE]] (a)In September 2023, APCo submitted a filing with the Virginia SCC requesting to extend the previously authorized recovery period through October 2024 to October 2025. Interim Virginia FAC rates were implemented in November 2023. An order from the Virginia SCC is expected in the first quarter of 2024. (b)In January 2024, the WVPSC issued a final order which resulted in a December 2023 write-off of $222 million ($127 million attributable to APCo and $95 million attributable to WPCo) of under-recovered ENEC regulatory assets as of February 28, 2023. The order approved the recovery of $321 million ($174 million attributable to APCo and $147 million attributable to WPCo) of under-recovered ENEC regulatory assets as of February 28, 2023 over 10 years beginning September 1, 2024. The recovery of the remaining under-recovered ENEC regulatory assets as of December 31, 2023 will be addressed in APCo and WPCo’s 2024 ENEC filing. In February 2024, the Companies filed briefs with the West Virginia Supreme Court to initiate an appeal of this order. (c)In September 2022, the Director of the Public Utility Division of the OCC approved a Fuel Cost Adjustment rate designed to collect a $402 million deferred fuel balance through December 2024. PSO’s fuel and purchased power expenses are subject to an annual prudency review by the OCC. (d)In September 2023, the PUCT issued an order approving an unopposed settlement agreement that provides recovery of $81 million of Oxbow mine and Sabine related fuel costs through 2035. 50 Merchant Portion of Turk Plant SWEPCo constructed the Turk Plant, a base load 600 MW (650 MW net maximum capacity) pulverized coal ultra-supercritical generating unit in Arkansas, which was placed in-service in December 2012 and is included in the Vertically Integrated Utilities segment. SWEPCo owns 73% (440 MWs/477 MWs) of the Turk Plant and operates the facility. Approximately 20% of SWEPCo’s portion of the Turk Plant output is currently not subject to cost-based rate recovery in Arkansas. This portion of the plant’s output is being sold into the wholesale market. Approximately 80% of the Turk Plant investment is recovered under retail cost-based rate recovery in Texas, Louisiana and through SWEPCo’s wholesale customers under FERC-approved rates. In November 2022, SWEPCo filed a Certificate of Public Convenience and Necessity with the APSC for approval to operate the Turk plant to serve Arkansas customers and recover the associated costs through a cost recovery rider. Cost-based recovery of the Turk Plant would aid SWEPCo’s near-term capacity needs and support compliance with SPP’s 2023 increased capacity planning reserve margin requirements. In April 2023, intervenors filed testimony recommending the APSC deny the Certificate of Public Convenience and Necessity on the basis that the Turk Plant is not the least cost alternative. In June 2023, SWEPCo filed rebuttal testimony with the APSC. In July 2023, additional intervenor testimony was filed with the APSC by the Attorney General of Arkansas and the APSC staff with recommendations consistent with the previously filed April 2023 intervenor testimony. A hearing was held in October 2023 and an order is expected in the first quarter of 2024. As of December 31, 2023, the net book value of the Turk Plant was $1.4 billion, before cost of removal including CWIP and inventory. If SWEPCo cannot ultimately recover its investment and expenses related to the Arkansas retail portion of the Turk Plant, it could reduce future net income and cash flows and impact financial condition. Litigation Related to Ohio House Bill 6 (HB 6) In July 2019, HB 6, which offered incentives for power-generating facilities with zero or reduced carbon emissions, was signed into law by the Ohio Governor. HB 6 terminated energy efficiency programs as of December 31, 2020, including OPCo’s shared savings revenues of $26 million annually and phased out renewable mandates after 2026. HB 6 also provided for continued recovery of existing renewable energy contracts on a bypassable basis through 2032 and included a provision for continued recovery of OVEC costs through 2030 which is allocated to all electric distribution utility customers in Ohio on a non-bypassable basis. OPCo’s Inter-Company Power Agreement for OVEC terminates in June 2040. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of the Speaker of the Ohio House of Representatives, Larry Householder, four other individuals, and Generation Now, an entity registered as a 501(c)(4) social welfare organization, in connection with an alleged racketeering conspiracy involving the adoption of HB 6. Certain defendants in that case had previously plead guilty and, in March 2023, a federal jury convicted Larry Householder and another individual of participating in the racketeering conspiracy. In 2021, four AEP shareholders filed derivative actions purporting to assert claims on behalf of AEP against certain AEP officers and directors. See “Litigation Related to Ohio House Bill 6” section of Litigation below for additional information. In March 2021, the Governor of Ohio signed legislation that, among other things, repealed the payments to the nonaffiliated owner of Ohio’s nuclear power plants that were previously authorized under HB 6. The new legislation, House Bill 128, went into effect in May 2021 and leaves unchanged other provisions of HB 6 regarding energy efficiency programs, recovery of renewable energy costs and recovery of OVEC costs. To the extent that the law changes or OPCo is unable to recover the costs of renewable energy contracts on a bypassable basis by the end of 2032, recover costs of OVEC after 2030 or incurs significant costs associated with the derivative actions, it could reduce future net income and cash flows and impact financial condition. 51 LITIGATION 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 6 – Commitments, Guarantees and Contingencies for additional information. Litigation Related to Ohio House Bill 6 (HB 6) In 2019, Ohio adopted and implemented HB 6 which benefits OPCo by authorizing rate recovery for certain costs including renewable energy contracts and OVEC’s coal-fired generating units. OPCo engaged in lobbying efforts and provided testimony during the legislative process in connection with HB 6. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of an Ohio legislator and associates in connection with an alleged racketeering conspiracy involving the adoption of HB 6. After AEP learned of the criminal allegations against the Ohio legislator and others relating to HB 6, AEP, with assistance from outside advisors, conducted a review of the circumstances surrounding the passage of the bill. Management does not believe that AEP was involved in any wrongful conduct in connection with the passage of HB 6. In August 2020, an AEP shareholder filed a putative class action lawsuit in the U. S. District Court for the Southern District of Ohio against AEP and certain of its officers for alleged violations of securities laws. In December 2021, the district court issued an opinion and order dismissing the securities litigation complaint with prejudice, determining that the complaint failed to plead any actionable misrepresentations or omissions. The plaintiffs did not appeal the ruling. In January 2021, an AEP shareholder filed a derivative action in the U.S. District Court for the Southern District of Ohio purporting to assert claims on behalf of AEP against certain AEP officers and directors. In February 2021, a second AEP shareholder filed a similar derivative action in the Court of Common Pleas of Franklin County, Ohio. In April 2021, a third AEP shareholder filed a similar derivative action in the U.S. District Court for the Southern District of Ohio and a fourth AEP shareholder filed a similar derivative action in the Supreme Court for the State of New York, Nassau County. These derivative complaints allege the officers and directors made misrepresentations and omissions similar to those alleged in the putative securities class action lawsuit filed against AEP. The derivative complaints together assert claims for: (a) breach of fiduciary duty, (b) waste of corporate assets, (c) unjust enrichment, (d) breach of duty for insider trading and (e) contribution for violations of sections 10(b) and 21D of the Securities Exchange Act of 1934; and seek monetary damages and changes to AEP’s corporate governance and internal policies among other forms of relief. The court entered a scheduling order in the New York state court derivative action staying the case other than with respect to briefing the motion to dismiss. AEP filed substantive and forum-based motions to dismiss in April 2022. In June 2022, the Ohio state court entered an order continuing the stays of that case until the final resolution of the consolidated derivative actions pending in Ohio federal district court. In September 2022, the New York state court granted the forum-based motion to dismiss with prejudice and the plaintiff subsequently filed a notice of appeal with the New York appellate court. In January 2023, the New York plaintiff filed a motion to intervene in the pending Ohio federal court action and withdrew his appeal in New York. The two derivative actions pending in federal district court in Ohio have been consolidated and the plaintiffs in the consolidated action filed an amended complaint. AEP filed a motion to dismiss the amended complaint and subsequently filed a brief in opposition to the New York plaintiffs’ motion to intervene in the consolidated action in Ohio. In March 2023, the federal district court issued an order granting the motion to dismiss with prejudice and denying the New York plaintiffs’ motion to intervene. In April 2023, one of the plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Sixth Circuit of the Ohio federal district court order dismissing the consolidated action and denying the intervention. The defendants will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring. In March 2021, AEP received a litigation demand letter from counsel representing a purported AEP shareholder. The litigation demand letter was directed to the Board of Directors of AEP (AEP Board) and contained factual allegations involving HB 6 that were generally consistent with those in the derivative litigation filed in state and federal court. The shareholder that sent the letter has since withdrawn the litigation demand, which is now terminated and of no further effect. In April 2023, AEP received a litigation demand from counsel representing the purported AEP shareholder who filed the dismissed derivative action in New York state court and unsuccessfully tried to intervene in the consolidated derivative actions in Ohio federal court. The litigation demand letter is directed to the AEP Board and contains factual allegations involving HB 6 that are generally consistent with those in the derivative litigation filed in state and federal court. The letter demands, among other things, that the AEP Board undertake an independent investigation into alleged legal violations by certain current and former directors and officers, and that AEP commence a civil action for breaches of fiduciary duty and related claims against any individuals who allegedly 52 harmed AEP. The AEP Board considered the 2023 litigation demand letter and formed a committee of the Board (the “Demand Review Committee”) to investigate, review, monitor and analyze the allegations in the letter and make a recommendation to the AEP Board regarding a reasonable and appropriate response to the same. The AEP Board will act in response to the letter as appropriate. Management is unable to determine a range of potential losses that is reasonably possible of occurring. In May 2021, AEP received a subpoena from the SEC’s Division of Enforcement seeking various documents, including documents relating to the passage of HB 6 and documents relating to AEP’s policies and financial processes and controls. In August 2022, AEP received a second subpoena from the SEC seeking various additional documents relating to its ongoing investigation. AEP is cooperating fully with the SEC’s investigation, which has included taking testimony from certain individuals and inquiries regarding Empowering Ohio’s Economy, Inc., which is a 501(c)(4) social welfare organization, and related disclosures. The SEC staff has advanced its discussions with certain parties involved in the investigation, including AEP, concerning the staff’s intentions regarding potential claims under the securities laws. AEP and the SEC are engaged in discussions about a possible resolution of the SEC’s investigation and potential claims under the securities laws. Any resolution or filed claims, the outcome of which cannot be predicted, may subject AEP to civil penalties and other remedial measures. Discussions are continuing and management is unable to determine a range of potential losses that is reasonably possible of occurring, but management does not believe the results of this investigation or a possible resolution thereof will have a material impact on results of operations, cash flows or financial condition. Claims for Indemnification Made by Owners of the Gavin Power Station In November 2022, the Federal EPA issued a final decision denying Gavin Power LLC’s requested extension to allow a CCR surface impoundment at the Gavin Power Station to continue to receive CCR and non-CCR waste streams after April 11, 2021 until May 4, 2023 (the Gavin Denial). As part of the Gavin Denial, the Federal EPA made several assertions related to the CCR Rule (see “CCR Rule” section below for additional information), including an assertion that the closure of the 300 acre unlined fly ash reservoir (FAR) is noncompliant with the CCR Rule in multiple respects. The Gavin Power Station was formerly owned and operated by AEP and was sold to Gavin Power LLC and Lightstone Generation LLC in 2017. Pursuant to the PSA, AEP maintained responsibility to complete closure of the FAR in accordance with the closure plan approved by the Ohio EPA which was completed in July 2021. The PSA contains indemnification provisions, pursuant to which the owners of the Gavin Power Station have notified AEP they believe they are entitled to indemnification for any damages that may result from these claims, including any future enforcement or litigation resulting from any determinations of noncompliance by the Federal EPA with various aspects of the CCR Rule consistent with the Gavin Denial. The owners of the Gavin Power Station have also sought indemnification for landowner claims for property damage allegedly caused by modifications to the FAR. Management does not believe that the owners of the Gavin Power Station have any valid claim for indemnity or otherwise against AEP under the PSA. In addition, Gavin Power LLC, several AEP subsidiaries, and other parties have filed Petitions for Review of the Gavin Denial with the U.S. Court of Appeals for the District of Columbia Circuit. Management is unable to determine a range of potential losses that is reasonably possible of occurring. Gavin Power LLC has also filed a complaint with the United States District Court for the Southern District of Ohio, alleging various violations of the Administrative Procedure Act and asserting that the Federal EPA, through its prior inaction, has waived and is estopped from raising certain objections raised in the Gavin Denial. Management cannot predict the outcome of that litigation. ENVIRONMENTAL ISSUES 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.  Management is engaged in the development of possible future requirements including the items discussed below.  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. Environmental Controls Impact on the Generating Fleet The rules and proposed environmental controls discussed below will have a material impact on AEP’s operations.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of December 31, 2023, AEP owned generating capacity of approximately 23,300 MWs, of which approximately 10,700 MWs were coal-fired.  Management continues to evaluate the economic feasibility of environmental investments on AEP’s fossil 53 generation fleet and to refine the cost estimates of complying with these rules and evaluate other impacts of the environmental proposals on fossil generation. 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, (g) compliance with the Federal EPA’s revised coal combustion residual rules and (h) other factors. Clean Air Act Requirements 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 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. National Ambient Air Quality Standards The Federal EPA periodically reviews and revises the NAAQS for criteria pollutants under the CAA. Revisions tend to increase the stringency of the standards, which in turn may require AEP to make investments in pollution control equipment at existing generating units, or, since most units are already well controlled, to make changes in how units are dispatched and operated. In February 2024, the Federal EPA finalized a new more stringent annual primary PM2.5 standard. Areas with air quality that does not meet the new standard will be designated by the Federal EPA as “nonattainment,” which will trigger an obligation for states to revise their SIPs to obtain further emission reductions to ensure that the new standard will be met. Areas around some of AEP’s generating facilities may be deemed nonattainment, which may subject those facilities to additional pollution controls or operational constraints. The nonattainment designations by the Federal EPA and the subsequent SIP revisions by the affected states will take some time to complete, therefore, it is too soon to predict how SIP requirements may impact AEP’s operations. Management will continue to monitor the issue. Regional Haze The Federal EPA issued a Clean Air Visibility Rule (CAVR) in 2005, which could require power plants and other facilities to install best available retrofit technology to address regional haze in federal parks and other protected areas. CAVR is implemented by the states, through SIPs, or by the Federal EPA, through FIPs. In 2017, the Federal EPA revised the rules governing submission of SIPs to implement the visibility programs. Petitions for review of the final rule revisions have been filed in the U.S. Court of Appeals for the District of Columbia Circuit. In Texas, the Federal EPA disapproved portions of the Texas regional haze SIP and finalized a FIP that allows participation in the CSAPR ozone season program to satisfy the NOX regional haze obligations for electric generating units in Texas. Additionally, the Federal EPA finalized an intrastate SO2 emissions trading program based on CSAPR allowance allocations. Legal challenges to these various rulemakings are pending in both the U.S. Court of Appeals for the Fifth Circuit and the U.S. Court of Appeals for the District of Columbia Circuit. Management cannot predict the outcome of that litigation, although management supports the intrastate trading program as a compliance alternative to source-specific controls and has intervened in the litigation in support of the Federal EPA. Cross-State Air Pollution Rule CSAPR is a regional trading program that the Federal EPA began implementing in 2015, which was designed to address interstate transport of emissions that contribute significantly to non-attainment and interfere with maintenance of the 1997 ozone NAAQS and the 1997 and 2006 PM NAAQS in downwind states.  CSAPR relies on SO2 and NOX allowances and individual state budgets to compel further emission reductions from electric utility generating units.  Interstate trading of allowances is allowed on a restricted basis. The Federal EPA has revised, or updated, the CSAPR trading programs several times since they were established. In January 2021, the Federal EPA finalized a revised CSAPR, which substantially reduced the ozone season NOX budgets for several states, including states where AEP operates, beginning in ozone season 2021. Management believes it can meet the 54 requirements of the rule in the near term, and is evaluating its compliance options for later years, when the budgets are further reduced. In addition, in February 2023, the Federal EPA Administrator finalized the disapproval of interstate transport SIPs submitted by 19 states addressing the 2015 Ozone NAAQS. Disapproval of the SIPs provides the Federal EPA with authority to impose a FIP for those states, replacing the SIPs that were disapproved. In August 2023, a FIP went into effect that further revises the ozone season NOX budgets under the existing CSAPR program in states to which the FIP applies. The disapproval of SIPs and implementation of FIPs continues to be subject to extensive litigation. Management will continue to monitor the outcome of this litigation and any potential impact to operations. Climate Change, CO2 Regulation and Energy Policy In May 2023, the Federal EPA proposed greenhouse gas standards and guidelines for new and existing fossil-fuel fired sources. The proposal relies heavily on carbon capture and sequestration and natural gas co-firing as means to reduce CO2 emissions from coal fired plants and hydrogen co-firing and carbon capture and sequestration to reduce CO2 emissions from gas turbines. Management is evaluating the proposed rule. While no federal regulatory requirements to reduce CO2 emissions are in place, AEP has taken action to reduce and offset CO2 emissions from its generating fleet. AEP expects CO2 emissions from its operations to continue to decline due to the retirement of some of its coal-fired generation units, and actions taken to diversify the generation fleet and increase energy efficiency where there is regulatory support for such activities. The majority of the states where AEP has generating facilities passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements that can assist in reducing carbon emissions. AEP routinely submits IRPs in various regulatory jurisdictions to address future generation and capacity needs. These IRPs take into account economics, customer demand, grid reliability and resilience, regulations and RTO capacity requirements. The objective of the IRPs is to recommend future generation and capacity resources that provide the most cost-efficient and reliable power to customers. Based on the output of the company’s IRPs, in October 2022, AEP announced new intermediate and long-term CO2 emission reduction goals. AEP adjusted its near-term CO2 emission reduction target from a 2000 baseline to a 2005 baseline, upgraded its 80% reduction by 2030 target to include full Scope 1 emissions and accelerated its net-zero goal by five years to 2045 for Scope 1 and Scope 2 emissions. AEP’s total Scope 1 GHG estimated emissions in 2023 were approximately 42.8 million metric tons, a 68% reduction according to the GHG Protocol, which excludes emission reductions that result from assets that have been sold, or a 72% reduction from AEP’s 2005 Scope 1 GHG emissions (inclusive of emission reductions that result from plants that have been sold). AEP has made significant progress in reducing CO2 emissions from its power generation fleet and expects its emissions to continue to decline over the long-term. AEP also expects Scope 1 GHG emissions to vary annually depending on the mix of its own generation and purchased power used to serve customers. AEP’s ability to achieve these goals is dependent upon a number of factors including the ability to execute on renewable resource plans, evolving RTO requirements, constructive regulatory support, the advancement of carbon-free generation technologies, customer demand for carbon-free energy, potential tariffs, carbon policy and regulation, operational performance of renewable generation and supply chain costs and constraints, all while continuing to provide the most cost-efficient and reliable power to customers. Excessive costs to comply with future legislation or regulations have led to the announcement of early plant closures and could force AEP to close additional coal-fired generation facilities earlier than their estimated useful life. If AEP is unable to recover the costs of its investments, it would reduce future net income and cash flows and impact financial condition. MATS Rule In April 2023, the Federal EPA issued a proposed rule that would revise the MATS for power plants. The proposed rule includes a more stringent standard for emissions of filterable PM for coal-fired electric generating units, as well as a new mercury standard for lignite-fired electric generating units. The proposed rule also requires the installation and operation of continuous emissions monitors for PM. Management is evaluating the impacts of the rule as proposed and will continue to monitor the rulemaking. CCR Rule The Federal EPA’s CCR rule regulates the disposal and beneficial re-use of CCR, including fly ash and bottom ash created from coal-fired generating units and FGD gypsum generated at some coal-fired plants.  The rule applies to active and inactive CCR landfills and surface impoundments at facilities of active electric utility or independent power producers. 55 In 2020, the Federal EPA revised the CCR rule to include a requirement that unlined CCR storage ponds cease operations and initiate closure by April 11, 2021. The revised rule provides two options that allow facilities to extend the date by which they must cease receipt of coal ash and close the ponds. The first option provides an extension to cease receipt of CCR no later than October 15, 2023 for most units, and October 15, 2024 for a narrow subset of units; however, the Federal EPA’s grant of such an extension requires 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 various plants. In January 2022, the Federal EPA proposed to deny several extension requests filed by the other utilities based on allegations that those utilities are not in compliance with the CCR Rule (the January Actions). In November 2022, the Federal EPA finalized one of these denials (the Gavin Denial, discussed above). The Federal EPA’s allegations of noncompliance rely on new interpretations of the CCR Rule requirements. The January Actions of the Federal EPA and the Gavin Denial have been challenged in the U.S. Court of Appeals for the District of Columbia Circuit as unlawful rulemaking that revises the existing CCR Rule requirements without proper notice and without opportunity for comment. Management is unable to predict the outcome of that litigation or how it may impact the Federal EPA’s interpretation of the CCR Rule. In July 2022, the Federal EPA proposed conditional approval of the pending extension request for APCo’s Mountaineer Plant. The Federal EPA alleged that the Mountaineer Plant was not fully compliant with the CCR Rule. In December 2022, AEP withdrew the pending extension request for the Mountaineer Plant as work to construct new CCR disposal facilities was completed and the extension was no longer needed. In addition, AEP ceased receiving ash in the other ponds subject to the extension requests, completed construction of new, CCR Rule compliant facilities and withdrew all of the remaining applications for additional time to develop alternative disposal capacity. Under the second option for obtaining an extension of the April 11, 2021 deadline to cease operation of unlined impoundments, a generating facility may 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 had 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 Plant and cease using coal at the Welsh Plant. In March 2023, the Pirkey Plant was retired. To date, the Federal EPA has not taken any action on the pending extension request for the Welsh Plant. Closure and post-closure estimated costs have been included in ARO in accordance with the requirements in the Federal EPA’s final CCR 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. AEP may incur significant additional costs complying with the Federal EPA’s CCR Rule, including costs to upgrade or close and replace surface impoundments and landfills used to manage CCR and to conduct any required remedial actions including removal of coal ash. If additional costs are incurred and AEP is unable to obtain cost recovery, it would reduce future net income and cash flows and impact financial condition. Management will continue to participate in rulemaking activities and make adjustments based on new federal and state requirements affecting its ash disposal units. In May 2023, the Federal EPA proposed revisions to the CCR Rule to expand the scope of the rule to include inactive impoundments at inactive facilities (“legacy CCR surface impoundments”) as well as to establish requirements for currently exempt solid waste management units that involve the direct placement of CCR on the land (“CCR management units”). The Federal EPA is proposing that owners and operators of legacy surface impoundments comply with all of the existing CCR Rule requirements applicable to inactive CCR surface impoundments at active facilities, except for the location restrictions and liner design criteria. The proposal establishes accelerated compliance deadlines for legacy surface impoundments to meet regulatory requirements, including a requirement to initiate closure within one year after the effective date of the final rule. The Federal EPA's proposal would require evaluations to be completed at both active facilities and inactive facilities with one or more legacy surface impoundments. If finalized, AEP may incur material, additional costs complying with the Federal EPA’s proposal, including costs to upgrade or close and replace legacy CCR surface impoundments and to conduct any required remedial actions including removal of coal ash. In addition, AEP would need to seek cost recovery through regulated rates, including proposing new regulatory mechanisms for cost recovery, for which regulatory approval cannot be assured. The proposed rule, if finalized, could have a material adverse impact on net income, cash flows and financial condition if AEP cannot ultimately recover any additional costs of compliance. 56 Clean Water Act Regulations The Federal EPA’s ELG rule for generating facilities establishes limits for FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater, which are to be implemented through each facility’s wastewater discharge permit. A revision to the ELG rule, published in October 2020, established additional options for reusing and discharging small volumes of bottom ash transport water, provided an exception for retiring units and extended the compliance deadline to a date as soon as possible beginning one year after the rule was published but no later than December 2025. Management has assessed technology additions and retrofits to comply with the rule and the impacts of the Federal EPA’s actions on facilities’ wastewater discharge 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 controls to meet ELG limits provided they make commitments to cease coal combustion by a date certain. In March 2023, the Federal EPA proposed further revisions to the ELG rule which, if finalized, would establish a zero discharge standard for FGD wastewater and bottom ash transport water, and more stringent discharge limits for combustion residual leachate. Management is evaluating the impacts of the proposed rule to operations. Management cannot predict whether the Federal EPA will actually finalize further revisions, but will continue to monitor this issue and will participate in further rulemaking activities as they arise. The definition of “waters of the United States” has been subject to rule making and litigation which has led to inconsistent scope among the states. Management will continue to monitor developments in rule making and litigation for any potential impact to operations. Impact of Environmental Regulation on Coal-Fired Generation 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 decision to retire coal-fired generating facilities earlier than their currently estimated useful lives. The table below summarizes the net book value, as of December 31, 2023, of generating facilities retired or planned for early retirement in advance of the retirement date currently authorized for ratemaking purposes: [[GREPCENT_TABLE]] [["Company","","Plant","","","","","","Net Investment (a)","","Accelerated Depreciation Regulatory Asset","","","","","Actual/Projected Retirement Date","","Current Authorized Recovery Period","","Annual Depreciation (b)"],["","","","","","","","","(in millions)","","","","","","","(in millions)"],["PSO","","Northeastern Plant, Unit 3","","","","","","$","104.5","","","$","164.2","","","","","","","2026","","","(c)","","$","15.0"],["SWEPCo","","Pirkey Plant","","","","","","\u2014","","","114.4","","(d)","","","","","2023","","","(e)","","\u2014"],["SWEPCo","","Welsh Plant, Units 1 and 3","","","","","","352.0","","","125.6","","","","","","","2028","(f)","","(g)","","38.6"]] [[/GREPCENT_TABLE]] (a)Net book value including CWIP excluding cost of removal and materials and supplies. (b)These amounts represent the amount of annual depreciation that has been collected from customers over the prior 12-month period. (c)Northeastern Plant, Unit 3 is currently being recovered through 2040. (d)Represents Arkansas and Texas jurisdictional share. (e)As part of the 2021 Arkansas Base Rate Case, the APSC granted SWEPCo regulatory asset treatment. SWEPCo will request recovery including a weighted average cost of capital carrying charge through a future proceeding. The Texas share of the Pirkey Plant will be addressed in SWEPCo’s next base rate case. See the “Coal-Fired Generation Plants” section of Note 5 for additional information. (f)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028. Management is evaluating a potential conversion to natural gas after 2028 for both units. (g)Welsh Plant, Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Welsh Plant, Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions. Management is seeking or will seek regulatory recovery, as necessary, for any net book value remaining when the plants are retired. To the extent the net book value of these generation assets is not deemed recoverable, it could materially reduce future net income, cash flows and impact financial condition. 57 RESULTS OF OPERATIONS AEP’s Reportable Segments 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 are as follows: •Vertically Integrated Utilities •Transmission and Distribution Utilities •AEP Transmission Holdco •Generation & Marketing The remainder of AEP’s activities are presented as Corporate and Other, which is not considered a reportable segment. See Note 9 - Business Segments for additional information on AEP’s segments. The following discussion of AEP’s results of operations by operating segment provides a comparison of Earnings Attributable to AEP Common Shareholders for the year ended December 31, 2023 as compared to the year ended December 31, 2022. For AEP’s Vertically Integrated Utilities and Transmission and Distribution Utilities segment and subsidiary registrants within these segments, the results include revenues from rate rider mechanisms designed to recover fuel, purchased power and other recoverable expenses such that the revenues and expenses associated with these items generally offset and do not affect Earnings Attributable to AEP Common Shareholders. For additional information regarding the financial results for the years ended December 31, 2023 and 2022 see the discussions of Results of Operations by Subsidiary Registrant. A detailed discussion of AEP’s 2022 results of operations by operating segment can be found in Management’s Discussion and Analysis of Financial Condition and Results of Operation section included in the 2022 Annual Report on Form 10-K filed with the SEC on February 23, 2023. The following tables present Earnings (Loss) Attributable to AEP Common Shareholders by segment: [[GREPCENT_TABLE]] [["","","Years Ended December 31,"],["","","2023","","2022","","2021"],["","","(in millions)"],["Vertically Integrated Utilities","","$","1,090.4","","","$","1,292.0","","","$","1,113.6"],["Transmission and Distribution Utilities","","698.7","","","595.7","","","543.4"],["AEP Transmission Holdco","","702.9","","","673.5","","","677.8"],["Generation & Marketing","","(26.3)","","","283.6","","","217.5"],["Corporate and Other","","(257.6)","","","(537.6)","","","(64.2)"],["Earnings Attributable to AEP Common Shareholders","","$","2,208.1","","","$","2,307.2","","","$","2,488.1"]] [[/GREPCENT_TABLE]] 58 [[GREPCENT_TABLE]] [["Year Ended December 31, 2023"],["","","Vertically Integrated Utilities","","Transmission and Distribution Utilities","","AEP Transmission Holdco","","Generation & Marketing"],["","","(in millions)"],["Revenues","","$","11,449.5","","","$","5,713.3","","","$","1,728.5","","","$","1,632.2"],["Fuel, Purchased Electricity and Other","","4,150.3","","","1,214.8","","","\u2014","","","1,487.8"],["Other Operation and Maintenance","","3,211.1","","","1,947.8","","","141.6","","","132.9"],["Asset Impairments and Other Related Charges","","85.6","","","\u2014","","","\u2014","","","\u2014"],["Loss on the Sale of the Competitive Contracted Renewables Portfolio","","\u2014","","","\u2014","","","\u2014","","","92.7"],["Depreciation and Amortization","","1,876.4","","","784.7","","","402.6","","","42.7"],["Taxes Other Than Income Taxes","","512.5","","","668.0","","","290.1","","","6.6"],["Operating Income (Loss)","","1,613.6","","","1,098.0","","","894.2","","","(130.5)"],["Other Income","","25.6","","","2.8","","","8.9","","","44.8"],["Allowance for Equity Funds Used During Construction","","46.3","","","45.5","","","83.1","","","\u2014"],["Non-Service Cost Components of Net Periodic Benefit Cost","","126.3","","","56.2","","","6.2","","","26.2"],["Interest Expense","","(764.5)","","","(363.6)","","","(202.6)","","","(76.0)"],["Income (Loss) Before Income Tax Expense (Benefit) and Equity Earnings (Loss)","","1,047.3","","","838.9","","","789.8","","","(135.5)"],["Income Tax Expense (Benefit)","","(45.2)","","","140.2","","","166.0","","","(122.9)"],["Equity Earnings (Loss) of Unconsolidated Subsidiary","","1.4","","","\u2014","","","82.9","","","(16.5)"],["Net Income (Loss)","","1,093.9","","","698.7","","","706.7","","","(29.1)"],["Net Income (Loss) Attributable to Noncontrolling Interests","","3.5","","","\u2014","","","3.8","","","(2.8)"],["Earnings (Loss) Attributable to AEP Common Shareholders","","$","1,090.4","","","$","698.7","","","$","702.9","","","$","(26.3)"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["Year Ended December 31, 2022"],["","","Vertically Integrated Utilities","","Transmission and Distribution Utilities","","AEP Transmission Holdco","","Generation & Marketing"],["","","(in millions)"],["Revenues","","$","11,477.5","","","$","5,512.0","","","$","1,677.0","","","$","2,466.9"],["Fuel, Purchased Electricity and Other","","4,007.9","","","1,287.3","","","\u2014","","","1,984.3"],["Other Operation and Maintenance","","3,287.2","","","1,864.2","","","165.7","","","118.7"],["Asset Impairments and Other Related Charges","","24.9","","","\u2014","","","\u2014","","","\u2014"],["Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset","","(37.0)","","","\u2014","","","\u2014","","","\u2014"],["Gain on Sale of Mineral Rights","","\u2014","","","\u2014","","","\u2014","","","(116.3)"],["Depreciation and Amortization","","2,007.2","","","746.7","","","355.0","","","93.0"],["Taxes Other Than Income Taxes","","504.9","","","659.9","","","277.6","","","11.1"],["Operating Income","","1,682.4","","","953.9","","","878.7","","","376.1"],["Other Income","","30.2","","","4.9","","","2.0","","","38.9"],["Allowance for Equity Funds Used During Construction","","29.5","","","33.6","","","70.6","","","\u2014"],["Non-Service Cost Components of Net Periodic Benefit Cost","","109.8","","","47.6","","","5.0","","","20.6"],["Interest Expense","","(650.9)","","","(328.0)","","","(169.3)","","","(51.8)"],["Income Before Income Tax Expense (Benefit) and Equity Earnings (Loss)","","1,201.0","","","712.0","","","787.0","","","383.8"],["Income Tax Expense (Benefit)","","(93.8)","","","116.9","","","193.6","","","(83.1)"],["Equity Earnings (Loss) of Unconsolidated Subsidiary","","1.4","","","0.6","","","83.4","","","(192.4)"],["Net Income","","1,296.2","","","595.7","","","676.8","","","274.5"],["Net Income (Loss) Attributable to Noncontrolling Interests","","4.2","","","\u2014","","","3.3","","","(9.1)"],["Earnings Attributable to AEP Common Shareholders","","$","1,292.0","","","$","595.7","","","$","673.5","","","$","283.6"]] [[/GREPCENT_TABLE]] 59 [[GREPCENT_TABLE]] [["Year Ended December 31, 2021"],["","","Vertically Integrated Utilities","","Transmission and Distribution Utilities","","AEP Transmission Holdco","","Generation & Marketing"],["","","(in millions)"],["Revenues","","$","9,998.5","","","$","4,492.9","","","$","1,526.2","","","$","2,163.7"],["Fuel, Purchased Electricity and Other","","3,144.2","","","729.9","","","\u2014","","","1,806.8"],["Other Operation and Maintenance","","3,043.1","","","1,573.9","","","132.3","","","97.5"],["Asset Impairments and Other Related Charges","","11.6","","","\u2014","","","\u2014","","","\u2014"],["Depreciation and Amortization","","1,747.6","","","690.3","","","306.0","","","80.9"],["Taxes Other Than Income Taxes","","497.3","","","640.9","","","245.0","","","10.5"],["Operating Income","","1,554.7","","","857.9","","","842.9","","","168.0"],["Other Income","","13.5","","","2.6","","","0.7","","","4.2"],["Allowance for Equity Funds Used During Construction","","40.2","","","32.3","","","67.2","","","\u2014"],["Non-Service Cost Components of Net Periodic Benefit Cost","","67.9","","","29.0","","","2.1","","","15.4"],["Interest Expense","","(574.2)","","","(300.9)","","","(146.3)","","","(15.6)"],["Income Before Income Tax Expense (Benefit) and Equity Earnings (Loss)","","1,102.1","","","620.9","","","766.6","","","172.0"],["Income Tax Expense (Benefit)","","(11.2)","","","77.5","","","159.6","","","(48.8)"],["Equity Earnings (Loss) of Unconsolidated Subsidiary","","3.4","","","\u2014","","","75.0","","","(10.6)"],["Net Income","","1,116.7","","","543.4","","","682.0","","","210.2"],["Net Income (Loss) Attributable to Noncontrolling Interests","","3.1","","","\u2014","","","4.2","","","(7.3)"],["Earnings Attributable to AEP Common Shareholders","","$","1,113.6","","","$","543.4","","","$","677.8","","","$","217.5"]] [[/GREPCENT_TABLE]] 60 VERTICALLY INTEGRATED UTILITIES [[GREPCENT_TABLE]] [["Summary of KWh Energy Sales for Vertically Integrated Utilities"],["","","Years Ended December 31,"],["","","2023","","2022","","2021"],["","","(in millions of KWhs)"],["Retail:"],["Residential","","30,290","","","32,835","","","32,149"],["Commercial","","23,481","","","23,770","","","22,833"],["Industrial","","34,148","","","34,532","","","33,181"],["Miscellaneous","","2,229","","","2,316","","","2,214"],["Total Retail","","90,148","","","93,453","","","90,377"],["Wholesale (a)","","13,401","","","16,099","","","19,025"],["Total KWhs","","103,549","","","109,552","","","109,402"]] [[/GREPCENT_TABLE]] (a)Includes Off-system Sales, municipalities and cooperatives, unit power and other wholesale customers. Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.  In general, degree day changes in the eastern region have a larger effect on revenues than changes in the western region due to the relative size of the two regions and the number of customers within each region. [[GREPCENT_TABLE]] [["Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities"],["","","Years Ended December 31,"],["","","2023","","2022","","2021"],["","","(in degree days)"],["Eastern Region"],["Actual \u2013 Heating (a)","","1,992","","","2,709","","","2,438"],["Normal \u2013 Heating (b)","","2,719","","","2,717","","","2,720"],["Actual \u2013 Cooling (c)","","1,003","","","1,187","","","1,268"],["Normal \u2013 Cooling (b)","","1,119","","","1,106","","","1,110"],["Western Region"],["Actual \u2013 Heating (a)","","1,068","","","1,523","","","1,241"],["Normal \u2013 Heating (b)","","1,464","","","1,455","","","1,461"],["Actual \u2013 Cooling (c)","","2,590","","","2,695","","","2,370"],["Normal \u2013 Cooling (b)","","2,277","","","2,247","","","2,246"]] [[/GREPCENT_TABLE]] (a)Heating degree days are calculated on a 55 degree temperature base. (b)Normal Heating/Cooling represents the thirty-year average of degree days. (c)Cooling degree days are calculated on a 65 degree temperature base. 61 Reconciliation of Year Ended December 31, 2022 to Year Ended December 31, 2023 Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities (in millions) [[GREPCENT_TABLE]] [["Year Ended December 31, 2022","","$","1,292.0"],["Changes in Revenues:"],["Retail Revenues","","(12.8)"],["Off-system Sales","","56.7"],["Transmission Revenues","","(51.3)"],["Other Revenues","","(20.6)"],["Total Change in Revenues","","(28.0)"],["Changes in Expenses and Other:"],["Purchased Electricity, Fuel and Other Consumables Used for Electric Generation","","(142.4)"],["Other Operation and Maintenance","","76.1"],["Asset Impairments and Other Related Charges","","(60.7)"],["Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset","","(37.0)"],["Depreciation and Amortization","","130.8"],["Taxes Other Than Income Taxes","","(7.6)"],["Other Income","","(4.6)"],["Allowance for Equity Funds Used During Construction","","16.8"],["Non-Service Cost Components of Net Periodic Pension Cost","","16.5"],["Interest Expense","","(113.6)"],["Total Change in Expenses and Other","","(125.7)"],["Income Tax Benefit","","(48.6)"],["Net Income Attributable to Noncontrolling Interests","","0.7"],["Year Ended December 31, 2023","","$","1,090.4"]] [[/GREPCENT_TABLE]] The major components of the decrease in Revenues were as follows: •Retail Revenues decreased $13 million primarily due to the following: •A $182 million decrease in weather-related usage primarily in the residential class driven by a 28% decrease in heating degree days and a 7% decrease in cooling degree days. •An $80 million decrease in fuel revenues primarily due to decreases at I&M, SWEPCo and KPCo, partially offset by increases at APCo and PSO. •A $54 million decrease in rider revenues at I&M. These decreases were partially offset by: •A $71 million increase in base rate revenues at PSO. •A $70 million increase at SWEPCo primarily due to base rate revenue increases in Louisiana and Arkansas and rider increases in all retail jurisdictions. •A $68 million increase at APCo and WPCo due to rider revenues in Virginia and West Virginia. •A $41 million increase in weather-normalized retail margins primarily in the commercial and residential classes. •A $34 million increase at APCo due to lower customer refunds related to Tax Reform. •A $20 million increase at APCo due to a base rate increase in Virginia implemented in October 2022 following the Virginia Supreme Court remand. •Off-system Sales increased $57 million primarily due to an increase at I&M primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales. This increase was partially offset by decreases at APCo and SWEPCo. •Transmission Revenues decreased $51 million primarily due to the following: •A $33 million decrease in transmission formula rate true-up activity. •A $13 million decrease due to a FERC order which denied stand-alone treatment of NOLCs in transmission formula rates. •Other Revenues decreased $21 million primarily due to a decrease in pole attachment revenue at APCo and WPCo. 62 Expenses and Other and Income Tax Benefit changed between years as follows: •Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $142 million primarily due to increases at APCo, PSO and WPCo, partially offset by decreases at I&M, SWEPCo and KPCo. The increase at APCo and WPCo includes the disallowance of under-recovered ENEC regulatory assets in West Virginia. •Other Operation and Maintenance expenses decreased $76 million primarily due to the following: •A $76 million decrease in transmission services. •A $67 million decrease in employee-related expenses. •A $40 million decrease due to a charitable contribution to the AEP Foundation in 2022. These decreases were partially offset by: •A $34 million increase in Demand Side Management expenses at I&M. •A $33 million increase in accounts receivable factoring expenses as a result of increased interest rates. •A $21 million increase at APCo due to the amortization of the regulatory asset established in accordance with the August 2022 Virginia Supreme Court opinion related to under-earnings during the 2017-2019 Triennial Review. •A $20 million increase due to a FERC order which denied stand-alone treatment of NOLCs in transmission formula rates. •Asset Impairments and Other Related Charges increased $61 million primarily due to the following: •An $86 million increase at SWEPCo due to the probable disallowance of Turk Plant capitalized AFUDC in excess of the Texas jurisdictional capital cost cap as a result of the PUCT’s December 2023 preliminary order in the 2012 Texas Base Rate Case. This increase was partially offset by: •A $25 million decrease at APCo due to a prior year write-off of a regulatory asset in accordance with the August 2022 Virginia Supreme Court opinion related to the 2017-2019 Virginia Triennial Review. •Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset decreased $37 million at APCo due to a prior year establishment of a regulatory asset in accordance with the August 2022 Virginia Supreme Court opinion related to under-earning during the 2017-2019 Triennial Review. •Depreciation and Amortization expenses decreased $131 million primarily due to a $170 million decrease at AEGCo and I&M due to the expiration of the Rockport Plant, Unit 2 lease in December 2022, partially offset by an increase in depreciation expense due to the acquisition of Rockport Plant, Unit 2 at the end of the lease. •Taxes Other Than Income Taxes increased $8 million primarily due to the following: •A $15 million increase at PSO and SWEPCo primarily due to increased property taxes driven by the investment in NCWF. •A $5 million increase at APCo primarily due to an increase in Virginia state minimum taxes. These increases were partially offset by: •A $13 million decrease at I&M primarily due to the repeal of the Indiana Utility Receipts Tax in July 2022. •Allowance for Equity Funds Used During Construction increased $17 million primarily due to higher AFUDC equity rates and CWIP at PSO and SWEPCo. •Non-Service Cost Components of Net Periodic Benefit Cost decreased $17 million primarily due to the change in loss amortization for the plans and an increase in the expected return on asset assumption, partially offset by higher interest costs due to increased discount rates. •Interest Expense increased $114 million primarily due to higher long-term debt balances and interest rates. •Income Tax Benefit decreased $49 million primarily due to the following: •A $29 million increase in state taxes. •A $27 million decrease due to a decrease in amortization of Excess ADIT. •A $19 million decrease related to tax return to provision adjustments. These decreases were partially offset by: •A $27 million increase due to PTCs. 63 TRANSMISSION AND DISTRIBUTION UTILITIES [[GREPCENT_TABLE]] [["Summary of KWh Energy Sales for Transmission and Distribution Utilities"],["","","Years Ended December 31,"],["","","2023","","2022","","2021"],["","","(in millions of KWhs)"],["Retail:"],["Residential","","26,099","","","27,479","","","26,830"],["Commercial","","30,419","","","27,448","","","25,514"],["Industrial","","26,571","","","25,435","","","23,919"],["Miscellaneous","","745","","","753","","","737"],["Total Retail (a)","","83,834","","","81,115","","","77,000"],["Wholesale (b)","","1,922","","","2,198","","","2,018"],["Total KWhs","","85,756","","","83,313","","","79,018"]] [[/GREPCENT_TABLE]] (a)Represents energy delivered to distribution customers. (b)Primarily Ohio’s contractually obligated purchases of OVEC power sold into PJM. Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.  In general, degree day changes in the eastern region have a larger effect on revenues than changes in the western region due to the relative size of the two regions and the number of customers within each region. [[GREPCENT_TABLE]] [["Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities"],["","","Years Ended December 31,"],["","","2023","","2022","","2021"],["","","(in degree days)"],["Eastern Region"],["Actual \u2013 Heating (a)","","2,380","","","3,116","","","2,815"],["Normal \u2013 Heating (b)","","3,185","","","3,185","","","3,190"],["Actual \u2013 Cooling (c)","","842","","","1,121","","","1,222"],["Normal \u2013 Cooling (b)","","1,026","","","1,011","","","1,016"],["Western Region"],["Actual \u2013 Heating (a)","","197","","","450","","","341"],["Normal \u2013 Heating (b)","","318","","","312","","","310"],["Actual \u2013 Cooling (d)","","3,208","","","2,984","","","2,653"],["Normal \u2013 Cooling (b)","","2,737","","","2,714","","","2,712"]] [[/GREPCENT_TABLE]] (a)Heating degree days are calculated on a 55 degree temperature base. (b)Normal Heating/Cooling represents the thirty-year average of degree days. (c)Eastern Region cooling degree days are calculated on a 65 degree temperature base. (d)Western Region cooling degree days are calculated on a 70 degree temperature base. 64  Reconciliation of Year Ended December 31, 2022 to Year Ended December 31, 2023 Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities (in millions) [[GREPCENT_TABLE]] [["Year Ended December 31, 2022","","$","595.7"],["Changes in Revenues:"],["Retail Revenues","","186.2"],["Off-system Sales","","(86.4)"],["Transmission Revenues","","56.6"],["Other Revenues","","44.9"],["Total Change in Revenues","","201.3"],["Changes in Expenses and Other:"],["Purchased Electricity for Resale","","149.4"],["Purchased Electricity from AEP Affiliates","","(77.0)"],["Other Operation and Maintenance","","(83.6)"],["Depreciation and Amortization","","(38.0)"],["Taxes Other Than Income Taxes","","(8.1)"],["Other Income","","(2.1)"],["Allowance for Equity Funds Used During Construction","","11.9"],["Non-Service Cost Components of Net Periodic Benefit Cost","","8.6"],["Interest Expense","","(35.6)"],["Total Change in Expenses and Other","","(74.5)"],["Income Tax Expense","","(23.3)"],["Equity Earnings of Unconsolidated Subsidiaries","","(0.6)"],["Year Ended December 31, 2023","","$","698.6"]] [[/GREPCENT_TABLE]] The major components of the increase in Revenues were as follows: •Retail Revenues increased $186 million primarily due to the following: •A $225 million increase in Ohio rider revenues. •A $25 million increase in interim rates driven by increased distribution investment in Texas. These increases were partially offset by: •A $59 million decrease in weather-related usage primarily due to a 28% decrease in heating degree days. •A $13 million decrease in weather-normalized revenues in all retail classes in Texas. •A $7 million decrease in revenue from rate riders in Texas. •Off-system Sales decreased $86 million primarily due to decreased sales at OVEC driven by lower market prices and volume. •Transmission Revenues increased $57 million primarily due to the following: •A $28 million increase in load in Texas. •A $27 million increase in interim rates primarily due to transmission investments in Texas. •Other Revenues increased $45 million primarily due to refundable sales of renewable energy credits in Ohio. Expenses and Other and Income Tax Expense changed between years as follows: •Purchased Electricity for Resale expenses decreased $149 million primarily due to the following: •A $129 million increase in deferrals of OVEC costs. •A $69 million decrease in auction volumes primarily due to decreased load, partially offset by higher prices in Ohio. These decreases were partially offset by: •A $36 million increase in recoverable expenses due to creation, consumption and liquidation of renewable energy credits and recoverable renewable energy purchase agreement expenses. •Purchased Electricity from AEP Affiliates expenses increased $77 million due to increased affiliated auction volumes driven by AEP Energy auctions won in June 2023 in Ohio. 65 •Other Operation and Maintenance expenses increased $84 million primarily due to the following: •A $96 million increase due to an energy assistance program for qualified Ohio customers. •A $34 million increase in transmission expenses due to an increase in recoverable PJM expenses driven by additional transmission investment. •A $23 million increase in recoverable distribution expenses primarily related to vegetation management in Ohio. •A $13 million increase in distribution-related expenses in Texas. These increases were partially offset by: •A $32 million decrease due to legislation passed in Texas in May 2023 allowing employee financially based incentives to be recovered in Texas. •A $22 million decrease in employee-related expenses. •An $18 million decrease due to a charitable contribution to the AEP Foundation in 2022. •An $11 million decrease in recoverable transmission expenses in Texas. •Depreciation and Amortization expenses increased $38 million primarily due to a higher depreciable base, partially offset by a decrease in recoverable rider depreciable expenses in Ohio. •Taxes Other Than Income Taxes increased $8 million primarily due to an increase in Ohio in property taxes driven by additional investments in transmission and distribution assets and higher tax rates. •Allowance for Equity Funds Used During Construction increased $12 million due to a higher AFUDC base. •Non-Service Cost Components of Net Period Benefit Cost decreased $9 million primarily due to the change in loss amortization for the plans and an increase in the expected return on asset assumption, partially offset by higher interest costs due to increased discount rates. •Interest Expense increased $36 million primarily due to a $58 million increase related to higher debt balances and interest rates, partially offset by a $19 million decrease related to higher AFUDC base and rates. •Income Tax Expense increased $23 million primarily due to an increase in pretax book income. 66 AEP TRANSMISSION HOLDCO Summary of Investment in Transmission Assets for AEP Transmission Holdco [[GREPCENT_TABLE]] [["","","December 31,"],["","","2023","","2022"],["","","(in millions)"],["Plant in Service","","$","14,630.2","","","$","13,217.3"],["Construction Work in Progress","","1,733.8","","","1,667.5"],["Accumulated Depreciation and Amortization","","1,332.8","","","1,062.5"],["Total Transmission Property, Net","","$","15,031.2","","","$","13,822.3"]] [[/GREPCENT_TABLE]] Reconciliation of Year Ended December 31, 2022 to Year Ended December 31, 2023 Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco (in millions) [[GREPCENT_TABLE]] [["Year Ended December 31, 2022","","$","673.5"],["Changes in Transmission Revenues:"],["Transmission Revenues","","51.5"],["Total Change in Transmission Revenues","","51.5"],["Changes in Expenses and Other:"],["Other Operation and Maintenance","","24.1"],["Depreciation and Amortization","","(47.6)"],["Taxes Other Than Income Taxes","","(12.5)"],["Interest and Investment Income","","6.9"],["Allowance for Equity Funds Used During Construction","","12.5"],["Non-Service Cost Components of Net Periodic Pension Cost","","1.2"],["Interest Expense","","(33.3)"],["Total Change in Expenses and Other","","(48.7)"],["Income Tax Expense","","27.6"],["Equity Earnings of Unconsolidated Subsidiary","","(0.5)"],["Net Income Attributable to Noncontrolling Interests","","(0.5)"],["Year Ended December 31, 2023","","$","702.9"]] [[/GREPCENT_TABLE]] The major components of the increase in Transmission Revenues, which consists of wholesale sales to affiliates and nonaffiliates were as follows: •Transmission Revenues increased $52 million primarily due to a $172 million increase driven by continued investment in transmission assets, partially offset by a $120 million decrease due to a FERC order which denied stand-alone treatment of NOLCs in transmission formula rates. Expenses and Other and Income Tax Expense changed between years as follows: •Other Operation and Maintenance expenses decreased $24 million primarily due to the following: •A $13 million decrease in employee-related expenses. •An $11 million decrease due to a charitable contribution to the AEP Foundation in 2022. •Depreciation and Amortization expenses increased $48 million primarily due to a higher depreciable base. •Taxes Other Than Income Taxes increased $13 million primarily due to higher property taxes as a result of increased transmission investments, partially offset by lower property tax rates. •Interest and Investment Income increased $7 million primarily due to higher advances to affiliates and interest rates. •Allowance for Equity Funds Used During Construction increased $13 million primarily due to higher CWIP balances throughout 2023. •Interest Expense increased $33 million primarily due to higher long-term debt balances and interest rates. •Income Tax Expense decreased $28 million primarily due to a decrease in state taxes primarily driven by tax adjustments and deferred state tax remeasurements. 67 GENERATION & MARKETING Reconciliation of Year Ended December 31, 2022 to Year Ended December 31, 2023 Earnings Attributable to AEP Common Shareholders from Generation & Marketing (in millions) [[GREPCENT_TABLE]] [["Year Ended December 31, 2022","","$","283.6"],["Changes in Revenues:"],["Merchant Generation","","(162.9)"],["Renewable Generation","","(55.3)"],["Retail, Trading and Marketing","","(616.5)"],["Total Change in Revenues","","(834.7)"],["Changes in Expenses and Other:"],["Purchased Electricity, Fuel and Other Consumables Used for Electric Generation","","496.5"],["Other Operation and Maintenance","","(14.2)"],["Loss on the Sale of the Competitive Contracted Renewables Portfolio","","(92.7)"],["Gain on Sale of Mineral Rights","","(116.3)"],["Depreciation and Amortization","","50.3"],["Taxes Other Than Income Taxes","","4.5"],["Interest and Investment Income","","5.9"],["Non-Service Cost Components of Net Periodic Benefit Cost","","5.6"],["Interest Expense","","(24.2)"],["Total Change in Expenses and Other","","315.4"],["Income Tax Benefit","","39.8"],["Equity Earnings of Unconsolidated Subsidiaries","","175.9"],["Net Loss Attributable to Noncontrolling Interests","","(6.3)"],["Year Ended December 31, 2023","","$","(26.3)"]] [[/GREPCENT_TABLE]] The major components of the decrease in Revenues were as follows: •Merchant Generation decreased $163 million primarily due to lower market prices in 2023. •Renewable Generation decreased $55 million primarily due to the sale of competitive contracted renewables portfolio in August 2023. •Retail, Trading and Marketing decreased $617 million primarily due to a $314 million unrealized loss on economic hedge activity in 2023 and an $87 million unrealized gain on economic hedge activity in 2022 driven by changes in commodity prices. Expenses and Other, Income Tax Benefit and Equity Earnings of Unconsolidated Subsidiaries changed between years as follows: •Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $497 million primarily due to a reduction in energy costs in 2023. •Other Operation and Maintenance expenses increased $14 million primarily due to a decrease in land sales and a prior year sale of renewable development projects. •Loss on the Sale of the Competitive Contracted Renewables Portfolio increased $93 million due to the pretax loss on the sale in 2023. •Gain on Sale of Mineral Rights decreased $116 million due to the prior year sale of mineral rights. •Depreciation and Amortization expenses decreased $50 million primarily due to the ceasing of depreciation on the competitive contracted renewables portfolio as a result of held for sale classification and subsequent sale in 2023. •Interest and Investment Income increased $6 million primarily due to higher interest rates on advances to affiliates. •Non-Service Cost Components of Net Periodic Benefit Cost decreased $6 million primarily due to the elimination of loss amortization for the Qualified plan and an increase in the Qualified expected return on asset assumption from 5.25% for 2022 to 7.50% for 2023. •Interest Expense increased $24 million primarily due to higher interest rates in 2023. 68 •Income Tax Benefit increased $40 million primarily due to: • A $74 million increase due to a decrease in pretax book income. This increase was partially offset by: •A $19 million decrease due to the remeasurement of deferred state taxes. •A $9 million decrease due to a decrease in tax credits. •Equity Earnings of Unconsolidated Subsidiaries increased $176 million primarily due to: •A $182 million impairment of AEP’s investment in Flat Ridge 2 Wind LLC in 2022. This increase was partially offset by: •A $19 million impairment of AEP’s investment in New Mexico Renewable Development joint venture in 2023. •Net Loss Attributable to Noncontrolling Interests increased $6 million primarily due to the sale of the competitive contracted renewables portfolio in August 2023. 69 CORPORATE AND OTHER 2023 Compared to 2022 Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $538 million in 2022 to a loss of $258 million in 2023 primarily due to: •A $363 million pretax loss in 2022 related to the anticipated sale of the Kentucky Operations which was terminated in 2023. •An $81 million increase in interest income, primarily due to higher interest rates on advances to affiliates. •A $56 million decrease in corporate expenses, primarily due to adjustments driven by the termination of the sale of the Kentucky Operations. •A $49 million increase in factoring revenues from the affiliates. •A $30 million increase at EIS, primarily due to higher returns on investments. •A $24 million increase due to asset impairments and other related charges in 2022. These increases in earnings were partially offset by: •A $286 million increase in interest expense due to higher interest rates and an increase in debt balances. •A $46 million increase in Income Tax Expense primarily due to the following: •A $66 million increase due to the loss on the anticipated sale of the Kentucky Operations in 2022. This increase was partially offset by: •A $15 million decrease due to favorable permanent tax adjustments in the current year and unfavorable permanent tax adjustments in 2022. AEP CONSOLIDATED INCOME TAXES 2023 Compared to 2022 •Income Tax Expense increased $49 million primarily due to the following: •A $58 million increase in state tax expense primarily driven by consolidated tax adjustments and deferred state tax remeasurements. •A $22 million decrease in amortization of Excess ADIT. •A $22 million decrease in PTCs. These increases in Income Tax Expense were partially offset by: •A $36 million increase in amortization of deferred ITCs resulting from the sale of the competitive contracted renewables portfolio. •A $16 million decrease due to favorable permanent tax adjustments in the current year and unfavorable permanent tax adjustments in 2022. FINANCIAL CONDITION AEP measures financial condition by the strength of its balance sheet and the liquidity provided by its cash flows. SIGNIFICANT CASH REQUIREMENTS AEP’s contractual cash obligations include amounts reported on the balance sheets and other obligations disclosed in the footnotes. It is anticipated that these obligations will be satisfied through a combination of cash flows from operations, long-term debt issuances, short-term debt through AEP’s Commercial Paper Program or bank term loans, proceeds from the sale of competitive contracted renewables and the use of the ATM Program or other equity issuances. Capital Expenditures Continued capital investments reflect AEP’s commitment to enhance service and deliver reliable, clean energy and advanced technologies that exceed customer expectations. See “Budgeted Capital Expenditures” herein, for additional information. Long-term Debt Long-term debt maturities, including interest, represent a significant cash requirement for AEP and the Registrant Subsidiaries. See Note 14 - Financing Activities for additional information relating to the Registrant Subsidiaries’ long-term debt outstanding as of December 31, 2023, the weighted-average interest rate applicable to each debt category and a schedule of debt maturities over the next five years. 70 Other Significant Cash Requirements Operating and finance leases represent a significant component of funding requirements for AEP and the Registrant Subsidiaries. See Note 13 - Leases for additional information. AEP subsidiaries have substantial commitments for fuel, energy and capacity contracts as part of the normal course of business. See Note 6 - Commitments, Guarantees and Contingencies for additional information. As of December 31, 2023, AEP expected to make contributions to the pension plans totaling $7 million in 2024. Estimated contributions of $110 million in 2025 and $6 million in 2026 may vary significantly based on market returns, changes in actuarial assumptions and other factors. Based upon the projected benefit obligation and fair value of assets available to pay pension benefits, the pension plans were 99% funded as of December 31, 2023. See “Estimated Future Benefit Payments and Contributions” section of Note 8 for additional information. Standby letters of credit are entered into with third-parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt security reserves. There is no collateral held in relation to any guarantees in excess of the ownership percentages. In the event any letters of credit are drawn, there is no recourse to third-parties. See “Letters of Credit” section of Note 6 for additional information. LIQUIDITY AND CAPITAL RESOURCES Debt and Equity Capitalization [[GREPCENT_TABLE]] [["","","December 31,"],["","","2023","","2022"],["","","(dollars in millions)"],["Long-term Debt, including amounts due within one year","","$","40,143.2","","","58.8","%","","$","36,801.0","","","56.6","%"],["Short-term Debt","","2,830.2","","","4.2","","","4,112.2","","","6.3"],["Total Debt","","42,973.4","","","63.0","","","40,913.2","","","62.9"],["AEP Common Equity","","25,246.7","","","37.0","","","23,893.4","","","36.7"],["Noncontrolling Interests","","39.2","","","\u2014","","","229.0","","","0.4"],["Total Debt and Equity Capitalization","","$","68,259.3","","","100.0","%","","$","65,035.6","","","100.0","%"]] [[/GREPCENT_TABLE]] AEP’s ratio of debt-to-total capital increased slightly from 62.9% to 63.0% as of December 31, 2022 and December 31, 2023, respectively, primarily due to an increase in Long-term Debt to support distribution, transmission and renewable investment growth in addition to working capital needs. This was partially offset by the issuance of common equity in connection with the settlement of the forward equity purchase contracts related to the 2020 Equity Units and the utilization of cash proceeds received from the sale of the competitive contracted renewables portfolio to reduce Short-term Debt. Liquidity Liquidity, or access to cash, is an important factor in determining AEP’s financial stability.  Management believes AEP has adequate liquidity under its existing credit facilities. As of December 31, 2023, AEP had $5 billion in revolving credit facilities to support its commercial paper program. Additional liquidity is available from cash from operations and a receivables securitization agreement.  Management is committed to maintaining adequate liquidity.  AEP generally uses short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged. Sources of long-term funding include issuance of long-term debt, leasing agreements, hybrid securities or common stock. AEP and its utilities finance its operations with commercial paper and other variable rate instruments that are subject to fluctuations in interest rates. To the extent that there is an increase in interest rates, it could reduce future net income and cash flows and impact financial condition. Market volatility and reduced liquidity in the financial markets could affect AEP’s ability to raise capital on reasonable terms to fund capital needs, including construction costs and refinancing maturing indebtedness. AEP is also monitoring the current bank environment and any impacts thereof. AEP was not materially impacted by these conditions during the year ended December 31, 2023. In August 2023, AEP completed the sale of the entire Competitive Contracted Renewables Portfolio to a nonaffiliated party and received cash proceeds of approximately $1.2 billion, net of taxes and transaction costs. The proceeds were used to pay down debt balances and support AEP’s overall capital expenditure plans. See the “Dispositions” section of Note 7 for additional information. 71 AEP continues to address the cash flow implications of increased fuel and purchased power costs, see “Deferred Fuel Costs” section of Executive Overview for additional information. In January 2024, AEP made a capital contribution to APCo and WPCo, totaling $100 million and $75 million, respectively. These contributions were made to help address the impact of the January 2024 WVPSC order that resulted in the December write-off of $222 million ($127 million attributable to APCo and $95 million attributable to WPCo) of under-recovered ENEC regulatory assets. See “ENEC (Expanded Net Energy Cost) Filings” of Note 4 for additional information. Net Available Liquidity AEP manages liquidity by maintaining adequate external financing commitments.  As of December 31, 2023, available liquidity was approximately $3.4 billion as illustrated in the table below: [[GREPCENT_TABLE]] [["","","Amount","","Maturity"],["","","(in millions)"],["Commercial Paper Backup:"],["Revolving Credit Facility","","$","4,000.0","","","March 2027"],["Revolving Credit Facility","","1,000.0","","","March 2025"],["Cash and Cash Equivalents","","330.1"],["Total Liquidity Sources","","5,330.1"],["Less: AEP Commercial Paper Outstanding","","1,937.9"],["Net Available Liquidity","","$","3,392.2"]] [[/GREPCENT_TABLE]] AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries.  The program funds a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and the short-term debt requirements of subsidiaries that are not participating in either money pool for regulatory or operational reasons, as direct borrowers.  The maximum amount of commercial paper outstanding during 2023 was $3.2 billion.  The weighted-average interest rate for AEP’s commercial paper during 2023 was 5.38%. Other Credit Facilities An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. As of December 31, 2023, AEP issued letters of credit on behalf of subsidiaries under six uncommitted facilities with a total capacity of $450 million.  The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities, as of December 31, 2023, was $257 million with maturities ranging from January 2024 to November 2024. Financing Plan As of December 31, 2023, AEP had $2.5 billion of long-term debt due within one year. This included $510 million of Pollution Control Bonds with mandatory tender dates and credit support for variable interest rates that requires the debt be classified as current and $205 million of securitization bonds and DCC Fuel notes.  Management plans to refinance the majority of the maturities due within one year on a long-term basis. Securitized Accounts Receivables AEP Credit’s receivables securitization agreement provides a commitment of $900 million from bank conduits to purchase receivables. The agreement was amended in August 2023 to increase the commitment from $750 million and expires in September 2025. As of December 31, 2023, the affiliated utility subsidiaries were in compliance with all requirements under the agreement. Debt Covenants and Borrowing Limitations AEP’s credit agreements contain certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%.  The method for calculating outstanding debt and capitalization is contractually-defined in AEP’s credit agreements.  Debt as defined in the revolving credit agreement excludes securitization bonds and debt of AEP Credit. As of December 31, 2023, this contractually-defined percentage was 59.9%. Non-performance under these covenants could result in an event of default under these credit agreements.  In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of AEP’s major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements.  This condition also applies in a majority of AEP’s non-exchange-traded commodity contracts and would similarly allow lenders and counterparties to declare the outstanding amounts payable.  However, a default under AEP’s non-exchange-traded commodity contracts would not cause an event of default under its credit agreements. 72 The revolving credit facilities do not permit the lenders to refuse a draw on any facility if a material adverse change occurs. Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders and AEP manages its borrowings to stay within those authorized limits. ATM Program AEP participates in an ATM offering program that allows AEP to issue, from time to time, up to an aggregate of $1.7 billion of its common stock, including shares of common stock that may be sold pursuant to an equity forward sales agreement. There were no issuances under the ATM program for the year ended December 31, 2023. As of December 31, 2023, approximately $1.7 billion of equity is available for issuance under the ATM offering program. See Note 14 - Financing Activities for additional information. Equity Units In August 2020, AEP issued 17 million Equity Units initially in the form of corporate units, at a stated amount of $50 per unit, for a total stated amount of $850 million. Net proceeds from the issuance were approximately $833 million. Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 1.30% Junior Subordinated Notes due in 2025 and a forward equity purchase contract which settled after three years in August 2023. The proceeds were used to support AEP’s overall capital expenditure plans. In June 2023, AEP successfully remarketed the Junior Subordinated Notes on behalf of holders of the corporate units. AEP did not receive any proceeds from the remarketing which were used to purchase a portfolio of treasury securities that matured on August 14, 2023. On August 15, 2023, the proceeds from the treasury portfolio were used to settle the forward equity purchase contract with AEP. The interest rate on the Junior Subordinated Notes was reset to 5.699% with the maturity remaining in 2025. In August 2023, AEP issued 10,048,668 shares of AEP common stock and received proceeds totaling $850 million under the settlement of the forward equity purchase contracts. AEP common stock held in treasury was used to settle the forward equity purchase contracts. The proceeds were used to pay down debt balances and support AEP’s overall capital expenditure plans. See Note 14 - Financing Activities for additional information. Dividend Policy and Restrictions The Board of Directors declared a quarterly dividend of $0.88 per share in January 2024.  Future dividends may vary depending upon AEP’s profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. Management does not believe these restrictions will have any significant impact on its ability to access cash to meet the payment of dividends on its common stock. See “Dividend Restrictions” section of Note 14 for additional information. Credit Ratings AEP and its utility subsidiaries do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit downgrade, but its access to the commercial paper market may depend on its credit ratings.  In addition, downgrades in AEP’s credit ratings by one of the rating agencies could increase its borrowing costs.  Counterparty concerns about the credit quality of AEP or its utility subsidiaries could subject AEP to additional collateral demands under adequate assurance clauses under its derivative and non-derivative energy contracts. 73 CASH FLOW AEP relies primarily on cash flows from operations, debt issuances and its existing cash and cash equivalents to fund its liquidity and investing activities. AEP’s investing and capital requirements are primarily capital expenditures, repaying of long-term debt and paying dividends to shareholders. AEP uses short-term debt, including commercial paper, as a bridge to long-term debt financing. The levels of borrowing may vary significantly due to the timing of long-term debt financings and the impact of fluctuations in cash flows. [[GREPCENT_TABLE]] [["","","Years Ended December 31,"],["","","2023","","2022","","2021"],["","","(in millions)"],["Cash, Cash Equivalents and Restricted Cash at Beginning of Period","","$","556.5","","","$","451.4","","","$","438.3"],["Net Cash Flows from Operating Activities","","5,012.2","","","5,288.0","","","3,839.9"],["Net Cash Flows Used for Investing Activities","","(6,266.7)","","","(7,751.8)","","","(6,433.9)"],["Net Cash Flows from Financing Activities","","1,077.0","","","2,568.9","","","2,607.1"],["Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash","","(177.5)","","","105.1","","","13.1"],["Cash, Cash Equivalents and Restricted Cash at End of Period","","$","379.0","","","$","556.5","","","$","451.4"]] [[/GREPCENT_TABLE]] Operating Activities [[GREPCENT_TABLE]] [["","","Years Ended December 31,"],["","","2023","","2022","","2021"],["","","(in millions)"],["Net Income","","$","2,212.6","","","$","2,305.6","","","$","2,488.1"],["Non-Cash Adjustments to Net Income (a)","","3,394.5","","","3,461.6","","","3,025.9"],["Mark-to-Market of Risk Management Contracts","","8.8","","","15.5","","","112.3"],["Property Taxes","","(41.1)","","","(41.2)","","","(68.0)"],["Deferred Fuel Over/Under Recovery, Net","","892.8","","","(319.2)","","","(1,647.9)"],["Change in Other Noncurrent Assets (b)","","(780.9)","","","(234.4)","","","(365.5)"],["Change in Other Noncurrent Liabilities","","29.0","","","337.8","","","206.4"],["Change in Certain Components of Working Capital","","(703.5)","","","(237.7)","","","88.6"],["Net Cash Flows from Operating Activities","","$","5,012.2","","","$","5,288.0","","","$","3,839.9"]] [[/GREPCENT_TABLE]] (a)Includes Depreciation and Amortization, Rockport Plant, Unit 2 Lease Amortization, Deferred Income Taxes, Loss on the Expected Sale of the Kentucky Operations, Loss on the Sale of the Competitive Contracted Renewables Portfolio, Asset Impairments and Other Related Charges, Impairment of Equity Method Investment, Allowance for Equity Funds Used During Construction, Amortization of Nuclear Fuel, Gain on Sale of Mineral Rights and Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset. (b)Includes Change in Regulatory Assets. 2023 Compared to 2022 Net Cash Flows from Operating Activities decreased by $276 million primarily due to the following: •A $547 million decrease in cash from Change in Other Noncurrent Assets primarily due to incremental other operation and maintenance storm restoration expenses incurred in several jurisdictions in addition to timing differences in collections from customers under rate rider mechanisms. See Note 4 - Rate Matters and Note 5 - Effects of Regulation for additional information. •A $466 million decrease in cash from the Change in Certain Components of Working Capital. The decrease is primarily due to fuel, material and supplies driven by current year increases in coal inventory, the return of margin deposits from PJM in 2022 and the timing of accounts payable. These decreases were partially offset by the timing of accounts receivable. •A $309 million decrease in cash from Changes in Other Noncurrent Liabilities. The decrease is primarily due to changes in provisions for refunds and regulatory liabilities driven by timing differences in refunds to customers under rate rider mechanisms in addition to an increase in ARO settlements in 2023. See Note 5 - Effects of Regulation and Note 18 - Property, Plant and Equipment for additional information. •A $160 million decrease in cash from Net Income, after non-cash adjustments. See Results of Operations for further detail. These decreases in cash were offset by: •A $1.2 billion increase in cash primarily due to the timing of fuel and purchased power revenues and expenses. See the “Deferred Fuel Costs” section of Executive Overview for additional information. 74 Investing Activities [[GREPCENT_TABLE]] [["","","Years Ended December 31,"],["","","2023","","2022","","2021"],["","","(in millions)"],["Construction Expenditures","","$","(7,378.3)","","","$","(6,671.7)","","","$","(5,659.6)"],["Acquisitions of Nuclear Fuel","","(128.2)","","","(100.7)","","","(104.5)"],["Acquisition of Renewable Energy Facilities","","(155.2)","","","(1,207.3)","","","(767.2)"],["Proceeds on Sale of Assets","","1,341.4","","","218.0","","","118.9"],["Other","","53.6","","","9.9","","","(21.5)"],["Net Cash Flows Used for Investing Activities","","$","(6,266.7)","","","$","(7,751.8)","","","$","(6,433.9)"]] [[/GREPCENT_TABLE]] 2023 Compared to 2022 Net Cash Flows Used for Investing Activities decreased by $1.5 billion primarily due to the following: •A $1.1 billion decrease due to the 2022 acquisition of Traverse, partially offset by the 2023 acquisition of the Rock Falls Wind Facility. See “Acquisitions” section of Note 7 for additional information. •A $1.1 billion increase in Proceeds from Sale of Assets, primarily due to the sale of the competitive contracted renewables portfolio in 2023, partially offset by the sale of certain mineral rights in 2022. See “Dispositions” section of Note 7 for additional information. These decreases in cash used were partially offset by: •A $707 million increase in Construction Expenditures, primarily due to increases in Vertically Integrated Utilities of $374 million and Transmission and Distribution Utilities of $290 million. Financing Activities [[GREPCENT_TABLE]] [["","","Years Ended December 31,"],["","","2023","","2022","","2021"],["","","(in millions)"],["Issuance of Common Stock","","$","999.6","","","$","826.5","","","$","600.5"],["Issuance/Retirement of Debt, Net","","1,984.7","","","3,802.5","","","3,631.7"],["Dividends Paid on Common Stock","","(1,760.4)","","","(1,645.2)","","","(1,519.5)"],["Principal Payments for Finance Lease Obligations","","(68.3)","","","(309.5)","","","(64.0)"],["Other","","(78.6)","","","(105.4)","","","(41.6)"],["Net Cash Flows from Financing Activities","","$","1,077.0","","","$","2,568.9","","","$","2,607.1"]] [[/GREPCENT_TABLE]] 2023 Compared to 2022 Net Cash Flows from Financing Activities decreased by $1.5 billion primarily due to the following: •A $2.8 billion decrease due to changes in short-term debt. See Note 14 - Financing Activities for additional information. •A $115 million decrease due to an increase in dividends paid on common stock. These decreases in cash were partially offset by: •An $813 million increase in issuances of long-term debt. See Note 14 - Financing Activities for additional information. •A $241 million increase due to a decrease in Principal Payments for Finance Lease Obligations primarily driven by Rockport Plant, Unit 2 final lease payments in 2022. •A $173 million increase in issuances of common stock primarily due to the settlement of the 2020 equity units. See “Equity Units” section of Note 14 for additional information. •A $149 million increase due to decreased retirements of long-term debt. See Note 14 - Financing Activities for additional information. The following financing activities occurred during 2023: AEP Common Stock: •During 2023, AEP issued 2.3 million shares of common stock under the incentive compensation, employee saving and dividend reinvestment plans. Additionally in 2023, AEP reissued 10 million shares of treasury stock to fulfill share commitments related to AEP’s Equity Units. See “Common Stock” and “Equity Units” section of Note 14 for additional information. AEP received net proceeds of $1 billion related to these issuances. 75 Debt: •During 2023, AEP issued approximately $5.5 billion of long-term debt, including $5.1 billion of senior unsecured notes at interest rates ranging from 5% to 7%, $296 million of other debt at various interest rates and $125 million of pollution control bonds at interest rates ranging from 4.25% to 4.7%.  The proceeds from these issuances were primarily used to fund long-term debt maturities, construction programs and to help address working capital needs. •During 2023, AEP entered into interest rate derivatives with notional amounts totaling $1.9 billion that were designated as cash flow hedges.  During 2023, settlements of AEP’s interest rate derivatives resulted in net cash paid of $44 million for derivatives designated as fair value hedges and net cash received of $20 million designated as cash flow hedges.  As of December 31, 2023, AEP had a total notional amount of $950 million of outstanding interest rate derivatives designated as fair value hedges and $350 million designated as cash flow hedges. See “Long-term Debt Subsequent Events” section of Note 14 for Long-term debt and other securities issued, retired and principal payments made after December 31, 2023 through February 26, 2024, the date that the 10-K was issued. BUDGETED CAPITAL EXPENDITURES Management forecasts approximately $7.5 billion of capital expenditures in 2024.  For the four year period, 2025 through 2028, management forecasts capital expenditures of $35 billion. The expenditures are generally for transmission, generation, distribution, regulated renewables and required environmental investment to comply with the Federal EPA rules.  Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, supply chain issues, weather, legal reviews, inflation and the ability to access capital.  Management expects to fund these capital expenditures through cash flows from operations, proceeds from the strategic sale of assets and financing activities.  Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged. The estimated capital expenditures by Business Segment are as follows: [[GREPCENT_TABLE]] [["","","2024 Budgeted Capital Expenditures","","2025-2028"],["Segment","","Environmental","","Generation","","Renewables","","Transmission","","Distribution","","Other (a)","","Total","","Total"],["","","(in millions)"],["Vertically Integrated Utilities","","$","49","","","$","367","","","$","531","","","$","990","","","$","1,311","","","$","332","","","$","3,580","","","$","20,407"],["Transmission and Distribution Utilities","","\u2014","","","\u2014","","","\u2014","","","1,272","","","1,087","","","208","","","2,567","","","9,201"],["AEP Transmission Holdco","","\u2014","","","\u2014","","","\u2014","","","1,313","","","\u2014","","","25","","","1,338","","","4,902"],["Generation & Marketing (b)","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014"],["Corporate and Other","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","59","","","59","","","501"],["Total","","$","49","","","$","367","","","$","531","","","$","3,575","","","$","2,398","","","$","624","","","$","7,544","","","$","35,011"]] [[/GREPCENT_TABLE]] (a)Amount primarily consists of facilities, software and telecommunications. (b)No capital expenditures expected based on the anticipated sale of AEP Energy and AEP Onsite Partners in 2024. The 2024 estimated capital expenditures by Registrant Subsidiary are as follows: [[GREPCENT_TABLE]] [["","","2024 Budgeted Capital Expenditures"],["Company","","Environmental","","Generation","","Renewables","","Transmission","","Distribution","","Other (a)","","Total"],["","","(in millions)"],["AEP Texas","","$","\u2014","","","$","\u2014","","","$","\u2014","","","$","897","","","$","549","","","$","87","","","$","1,533"],["AEPTCo","","\u2014","","","\u2014","","","\u2014","","","1,313","","","\u2014","","","25","","","1,338"],["APCo","","22","","","104","","","8","","","324","","","375","","","130","","","963"],["I&M","","\u2014","","","91","","","15","","","76","","","327","","","70","","","579"],["OPCo","","\u2014","","","\u2014","","","\u2014","","","375","","","538","","","121","","","1,034"],["PSO","","\u2014","","","61","","","36","","","133","","","289","","","50","","","569"],["SWEPCo","","3","","","77","","","473","","","349","","","214","","","60","","","1,176"]] [[/GREPCENT_TABLE]] (a) Amount primarily consists of facilities, software and telecommunications. 76 CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING STANDARDS CRITICAL ACCOUNTING POLICIES AND ESTIMATES The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect reported amounts and related disclosures, including amounts related to legal matters and contingencies.  Management considers an accounting estimate to be critical if: •It requires assumptions to be made that were uncertain at the time the estimate was made; and •Changes in the estimate or different estimates that could have been selected could have a material effect on net income or financial condition. Management discusses the development and selection of critical accounting estimates as presented below with the Audit Committee of AEP’s Board of Directors and the Audit Committee reviews the disclosures relating to them. Management believes that the current assumptions and other considerations used to estimate amounts reflected in the financial statements are appropriate.  However, actual results can differ significantly from those estimates. The sections that follow present information about critical accounting estimates, as well as the effects of hypothetical changes in the material assumptions used to develop each estimate. Regulatory Accounting Nature of Estimates Required The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. The Registrants recognize regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) for the economic effects of regulation.  Specifically, the timing of expense and income recognition is matched with regulated revenues.  Liabilities are also recorded for refunds, or probable refunds, to customers that have not been made. Assumptions and Approach Used When incurred costs are probable of recovery through regulated rates, regulatory assets are recorded on the balance sheets.  Management reviews the probability of recovery at each balance sheet date and whenever new events occur.  Similarly, regulatory liabilities are recorded when a determination is made that a refund is probable or when ordered by a commission.  Examples of new events that affect probability include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation.  The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs as well as the return of revenues, rate of return earned on invested capital and timing and amount of assets to be recovered through regulated rates.  If recovery of a regulatory asset is no longer probable, that regulatory asset is written-off as a charge against earnings.  A write-off of regulatory assets or establishment of a regulatory liability may also reduce future cash flows since there will be no recovery through regulated rates. Effect if Different Assumptions Used A change in the above assumptions may result in a material impact on net income.  See Note 5 - Effects of Regulation for additional information related to regulatory assets and regulatory liabilities. Revenue Recognition – Unbilled Revenues Nature of Estimates Required AEP recognizes revenues from customers as the performance obligations of delivering energy to customers are satisfied.  The determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month.  At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue accrual is recorded.  This estimate is reversed in the following month and actual revenue is recorded based on meter readings.  PSO and SWEPCo do not include the fuel portion in unbilled revenue in accordance with the applicable state commission regulatory treatment in Arkansas, Louisiana, Oklahoma and Texas. 77 Accrued unbilled revenues for the Vertically Integrated Utilities segment were $288 million and $354 million as of December 31, 2023 and 2022, respectively. The changes in unbilled electric utility revenues for AEP’s Vertically Integrated Utilities segment were $(66) million, $108 million and $(42) million for the years ended December 31, 2023, 2022 and 2021, respectively.  The changes in unbilled electric revenues are primarily due to changes in weather and rates.   Accrued unbilled revenues for the Transmission and Distribution Utilities segment were $191 million and $221 million as of December 31, 2023 and 2022, respectively. The changes in unbilled electric utility revenues for AEP’s Transmission and Distribution Utilities segment were $(30) million, $49 million and $1 million for the years ended December 31, 2023, 2022 and 2021, respectively.  The changes in unbilled electric revenues are primarily due to changes in weather and rates.   Accrued unbilled revenues for the Generation & Marketing segment were $111 million and $109 million as of December 31, 2023 and 2022, respectively. The changes in unbilled electric utility revenues for AEP’s Generation & Marketing segment were $2 million, $(1) million and $24 million for the years ended December 31, 2023, 2022 and 2021, respectively.   Assumptions and Approach Used For each Registrant except AEPTCo, the monthly estimate for unbilled revenues is based upon a primary computation of net generation (generation plus purchases less sales) less the current month’s billed KWhs and estimated line losses, plus the prior month’s unbilled KWhs. However, due to the potential for meter reading issues, meter drift and other anomalies, a secondary computation is made, based upon an allocation of billed KWhs to the current month and previous month, on a billing cycle-by-cycle basis, and by dividing the current month aggregated result by the billed KWhs. The two methodologies are evaluated to confirm that they are not statistically different. For AEP’s Generation & Marketing segment, management calculates unbilled revenues based on a primary computation of load as provided by PJM less the current month’s billed KWhs and estimated line losses, plus the prior month’s unbilled KWhs. However, due to the potential for meter reading issues, meter drift and other anomalies, a secondary computation is made, based upon using the most recent historic daily activity on a per contract basis. The two methodologies are evaluated to confirm that they are not statistically different. Effect if Different Assumptions Used If the two methodologies used to estimate unbilled revenue are statistically different, a limiter adjustment is made to bring the primary computation within one standard deviation of the secondary computation. Additionally, significant fluctuations in energy demand for the unbilled period, weather, line losses or changes in the composition of customer classes could impact the estimate of unbilled revenue.   Accounting for Derivative Instruments Nature of Estimates Required Management considers fair value techniques, valuation adjustments related to credit and liquidity and judgments related to the probability of forecasted transactions occurring within the specified time period to be critical accounting estimates.  These estimates are considered significant because they are highly susceptible to change from period to period and are dependent on many subjective factors. Assumptions and Approach Used The Registrants measure the fair values of derivative instruments and hedge instruments accounted for using MTM accounting based primarily on exchange prices and broker quotes.  If a quoted market price is not available, the fair value is estimated based on the best market information available including valuation models that estimate future energy prices based on existing market and broker quotes and other assumptions.  Fair value estimates, based upon the best market information available, involve uncertainties and matters of significant judgment.  These uncertainties include forward market price assumptions. The Registrants reduce fair values by estimated valuation adjustments for items such as discounting, liquidity and credit quality.  Liquidity adjustments are calculated by utilizing bid/ask spreads to estimate the potential fair value impact of liquidating open positions over a reasonable period of time.  Credit adjustments on risk management contracts are calculated using estimated default probabilities and recovery rates relative to the counterparties or counterparties with similar credit profiles and contractual netting agreements. 78 With respect to hedge accounting, management assesses hedge effectiveness and evaluates a forecasted transaction’s probability of occurrence within the specified time period as provided in the original hedge documentation. Effect if Different Assumptions Used There is inherent risk in valuation modeling given the complexity and volatility of energy markets.  Therefore, it is possible that results in future periods may be materially different as contracts settle. The probability that hedged forecasted transactions will not occur by the end of the specified time period could change operating results by requiring amounts currently classified in Accumulated Other Comprehensive Income (Loss) to be classified into Operating Income. For additional information see Note 10 - Derivatives and Hedging and Note 11 - Fair Value Measurements.  See “Fair Value Measurements of Assets and Liabilities” section of Note 1 for AEP’s fair value calculation policy. Long-Lived Assets Nature of Estimates Required In accordance with the requirements of “Property, Plant and Equipment” accounting guidance and “Regulated Operations” accounting guidance, the Registrants evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of any such assets may not be recoverable. Such events or changes in circumstance include planned abandonments, probable disallowances for rate-making purposes of assets determined to be recently completed plant and assets that meet the held-for-sale criteria.  The Registrants utilize a group composite method of depreciation to estimate the useful lives of long-lived assets.   An impairment evaluation of a long-lived, held and used asset may result from an abandonment, significant decreases in the market price of an asset, a significant adverse change in the extent or manner in which an asset is being used or in its physical condition, a significant adverse change in legal factors or in the business climate that could affect the value of an asset, as well as other economic or operations analyses.  If the book value of the asset is not recoverable through estimated, future undiscounted cash flows, the Registrants record an impairment to the extent that the fair value of the asset is less than its book value.  Performing an impairment evaluation involves a significant degree of estimation and judgment in areas such as identifying circumstances that indicate an impairment may exist, identifying and grouping affected assets and developing the non-discounted and discounted future cash flows (used to estimate fair value in the absence of market-based value, in some instances) associated with the asset.  Assets held for sale must be measured at the lower of the book value or fair value less cost to sell. An impairment is recognized if an asset’s fair value less costs to sell is less than its book value. Any impairment charge is recorded as a reduction to earnings. Assumptions and Approach Used The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties other than in a forced or liquidation sale.  Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available.  In the absence of quoted prices for identical or similar assets in active markets, the Registrants estimate fair value using various internal and external valuation methods including cash flow projections or other market indicators of fair value such as bids received, comparable sales or independent appraisals.  Cash flow estimates are based on relevant information available at the time the estimates are made.  Estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.  Also, when measuring fair value, management evaluates the characteristics of the asset or liability to determine if market participants would take those characteristics into account when pricing the asset or liability at the measurement date.  Such characteristics include, for example, the condition and location of the asset or restrictions on the use of the asset.  The Registrants perform depreciation studies that include a review of any external factors that may affect the useful life to determine composite depreciation rates and related lives which are subject to periodic review by state regulatory commissions for regulated assets.  The fair value of the asset could be different using different estimates and assumptions in these valuation techniques. Effect if Different Assumptions Used In connection with the evaluation of long-lived assets in accordance with the requirements of “Property, Plant and Equipment” accounting guidance, the fair value of the asset can vary if different estimates and assumptions are used in the applied valuation 79 techniques.  Estimates for depreciation rates contemplate the history of interim capital replacements and the amount of salvage expected.  In cases of impairment, the best estimate of fair value was made using valuation methods based on the most current information at that time.  Differences in realized sales proceeds versus the estimated fair value of the asset are generally due to a variety of factors including, but not limited to, differences in subsequent market conditions, the level of bidder interest, the timing and terms of the transactions and management’s analysis of the benefits of the transaction. Pension and OPEB AEPSC maintains a qualified, defined benefit pension plan (Qualified Plan), which covers substantially all nonunion and certain union employees, and unfunded, non-qualified supplemental plans (Nonqualified Plans) to provide benefits in excess of amounts permitted under the provisions of the tax law for participants in the Qualified Plan (collectively the Pension Plans).  AEPSC also sponsors OPEB plans to provide health and life insurance benefits for retired employees.  The Pension Plans and OPEB plans are collectively referred to as the Plans. For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Investments Held in Trust for Future Liabilities” and “Fair Value Measurements of Assets and Liabilities” sections of Note 1.  See Note 8 - Benefit Plans for information regarding costs and assumptions for the Plans. The following table shows the net periodic cost (credit) of the Plans: [[GREPCENT_TABLE]] [["","","Years Ended December 31,"],["Net Periodic Cost (Credit)","","2023","","2022","","2021"],["","","(in millions)"],["Pension Plans","","$","(24.3)","","","$","80.9","","","$","138.2"],["OPEB","","(107.1)","","","(144.8)","","","(122.0)"]] [[/GREPCENT_TABLE]] The net periodic benefit cost is calculated based upon a number of actuarial assumptions, including expected long-term rates of return on the Plans’ assets.  In developing the expected long-term rate of return assumption for 2024, management evaluated input from actuaries and investment consultants, including their reviews of asset class return expectations as well as long-term inflation assumptions.  Management also considered historical returns of the investment markets and tax rates which affect a portion of the OPEB plans’ assets.  Management anticipates that the investment managers employed for the Plans will invest the assets to generate future returns averaging 7.25% for the Qualified Plan and 6.75% for the OPEB plans. The expected long-term rate of return on the Plans’ assets is based on management’s targeted asset allocation and expected investment returns for each investment category.  Assumptions for the Plans are summarized in the following table: [[GREPCENT_TABLE]] [["","Pension Plans","","OPEB"],["","","","Assumed/Expected","","","","Assumed/Expected"],["","2024 Target","","Long-Term","","2024 Target","","Long-Term"],["","Asset Allocation","","Rate of Return","","Asset Allocation","","Rate of Return"],["Equity","30","%","","8.77","%","","58","%","","7.76","%"],["Fixed Income","54","%","","6.02","%","","41","%","","5.77","%"],["Other Investments","15","%","","9.39","%","","\u2014","","","\u2014"],["Cash and Cash Equivalents","1","%","","3.79","%","","1","%","","3.79","%"],["Total","100","%","","","","100","%"]] [[/GREPCENT_TABLE]] Management regularly reviews the actual asset allocation and periodically rebalances the investments to the targeted allocation.  Management believes that 7.25% for the Qualified Plan and 6.75% for the OPEB plans are reasonable estimates of the long-term rate of return on the Plans’ assets.  The Pension Plans’ assets had an actual gain of 9.50% and a loss of 16.88% for the years ended December 31, 2023 and 2022, respectively.  The OPEB plans’ assets had an actual gain of 15.48% and a loss of 19.53% for the years ended December 31, 2023 and 2022, respectively.  Management will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the assumptions as necessary. AEP bases the determination of pension expense or income on a market-related valuation of assets, which reduces year-to-year volatility.  This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur.  Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets.  Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded.  As of December 31, 2023, AEP had cumulative gains of approximately $526 million for the Qualified Plan that remain to be recognized in the calculation of the market-related value of assets.  These unrecognized 80 market-related net actuarial gains may result in decreases in the future pension costs depending on several factors, including whether such gains at each measurement date exceed the corridor in accordance with “Compensation – Retirement Benefits” accounting guidance. The method used to determine the discount rate that AEP utilizes for determining future obligations is a duration-based method in which a hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability.  The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.  The discount rate as of December 31, 2023 under this method was 5.15% for the Qualified Plan, 5.2% for the Nonqualified Plans and 5.15% for the OPEB plans.  Due to the effect of the unrecognized net actuarial losses and based on an expected rate of return, discount rates and various other assumptions, management estimates costs (credits) for the Pension Plans will approximate $(6) million, $39 million and $77 million in 2024, 2025 and 2026, respectively.  Based on an expected rate of return discount rate and various other assumptions, management estimates OPEB plan credits will approximate $72 million, $60 million and $66 million in 2024, 2025 and 2026, respectively. Future actual costs will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Plans.  The actuarial assumptions used may differ materially from actual results.  The effects of a 50 basis point change to selective actuarial assumptions are included in the “Effect if Different Assumptions Used” section below. The value of AEP’s Pension Plans’ assets is $4.1 billion as of December 31, 2023 and $4.1 billion as of December 31, 2022.  During 2023, the Qualified Plan paid $361 million and the Nonqualified Plans paid $8 million in benefits to plan participants.  The value of AEP’s OPEB plans’ assets increased to $1.7 billion as of December 31, 2023 from $1.5 billion as of December 31, 2022 primarily due to positive investment returns.  During 2023, the OPEB plans paid $138 million in benefits to plan participants. Nature of Estimates Required AEPSC sponsors pension and OPEB plans in various forms covering all employees who meet eligibility requirements.  These benefits are accounted for under “Compensation” and “Plan Accounting” accounting guidance.  The measurement of pension and OPEB obligations, costs and liabilities is dependent on a variety of assumptions. Assumptions and Approach Used The critical assumptions used in developing the required estimates includes discount rate, compensation increase rate, cash balance crediting rate, health care cost trend rate and expected return on plan assets. Other assumptions, such as retirement, mortality and turnover, are evaluated periodically and updated to reflect actual experience. Effect if Different Assumptions Used The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, longer or shorter life spans of participants or higher or lower lump sum versus annuity payout elections by plan participants.  These differences may result in a significant impact to the amount of pension and OPEB expense recorded.  If a 50 basis point change were to occur for the following assumptions, the approximate effect on the financial statements would be as follows: [[GREPCENT_TABLE]] [["","","Pension Plans","","OPEB"],["","","+0.5%","","-0.5%","","+0.5%","","-0.5%"],["","","(in millions)"],["Effect on December 31, 2023 Benefit Obligations"],["Discount Rate","","$","(177.9)","","","$","193.7","","","$","(36.2)","","","$","39.3"],["Compensation Increase Rate","","226.0","","","(21.1)","","","NA","","NA"],["Cash Balance Crediting Rate","","60.2","","","(56.9)","","","NA","","NA"],["Health Care Cost Trend Rate","","NA","","NA","","5.1","","","(4.4)"],["Effect on 2023 Periodic Cost"],["Discount Rate","","$","(9.3)","","","$","10.1","","","$","1.6","","","$","(1.7)"],["Compensation Increase Rate","","4.9","","","(4.5)","","","NA","","NA"],["Cash Balance Crediting Rate","","11.1","","","(10.5)","","","NA","","NA"],["Health Care Cost Trend Rate","","NA","","NA","","0.5","","","(0.3)"],["Expected Return on Plan Assets","","(22.6)","","","22.6","","","(7.6)","","","7.6"]] [[/GREPCENT_TABLE]] NA    Not applicable. 81 SIGNIFICANT TAX LEGISLATION In August 2022, President Biden signed H.R. 5376 into law, commonly known as the Inflation Reduction Act of 2022, or IRA. Most notably this budget reconciliation legislation creates a 15% minimum tax on adjusted financial statement income (Corporate Alternative Minimum Tax or CAMT), extends and increases the value of PTCs and ITCs, adds a nuclear and clean hydrogen PTC, an energy storage ITC and allows the sale or transfer of tax credits to third parties for cash. In June 2023, the IRS issued temporary regulations related to the transfer of tax credits. In the third and fourth quarter of 2023, AEP, on behalf of PSO, SWEPCo and AEP Energy Supply, LLC, entered into transferability agreements with nonaffiliated parties to sell 2023 generated PTCs resulting in cash proceeds of approximately $102 million received in the fourth quarter of 2023 and an additional $76 million expected in early 2024. AEP expects to continue to explore the ability to efficiently monetize its tax credits through third party transferability agreements. See Note 12 - Income Taxes for additional information. ACCOUNTING STANDARDS See Note 2 - New Accounting Standards for information related to accounting standards. 82