AMERICAN ELECTRIC POWER CO INC (AEP) FY 2021 MD&A

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 224,000 circuit miles of distribution lines that deliver electricity to 5.5 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 22,500 MWs of regulated owned generating capacity and approximately 4,600 MWs of regulated PPA capacity in 3 RTOs as of December 31, 2021, one of the largest complements of generation in the United States.

COVID-19

In 2020, COVID-19 was declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention. Its rapid spread around the world and throughout the United States prompted many countries, including the United States, to institute restrictions on travel, public gatherings and certain business operations. These restrictions significantly disrupted economic activity in AEP’s service territory and resulted in reduced demand for energy, particularly from commercial and industrial customers. In 2021, weather-normalized customer demand improved from the pandemic levels experienced in 2020.

During 2020, AEP’s electric operating companies informed both retail customers and state regulators that disconnections for non-payment were temporarily suspended. Shortly thereafter, AEP’s state regulators also imposed temporary moratoria on customary disconnection practices. AEP’s electric operating companies have since resumed customary disconnection practices in all regulated jurisdictions.

AEP has been and continues to be proactive in engaging with customers to collect payments or establish payment arrangements for outstanding balances. As of December 31, 2021, AEP currently does not expect accounts receivable aging to have a material adverse impact on the Registrants’ allowance for uncollectible accounts based on considerations of the COVID-19 impacts and past trends during times of economic instability. Management continues to monitor developments that could have an impact on customer collections.

The Registrants continue to take steps to mitigate the potential risks to customers, suppliers and employees posed by the spread of COVID-19 variants. In the second quarter of 2021, management announced a Future of Work model designating employees as: (a) On-Site employees, (b) Hybrid employees and (c) Remote employees. Management began transitioning On-Site employees back to their AEP workplace and Hybrid employees with set schedules back to their AEP workplace in October 2021. Remote employees began transitioning back to their AEP workplace in November 2021 on an as-needed basis. As of December 31, 2021, there has been no material adverse impact to the Registrants’ business operations and customer service as a result of COVID-19 variants or the Future of Work model. Management will continue to review and modify plans as conditions change.

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In 2021, the Registrants have experienced certain supply chain disruptions driven by several factors including staffing and travel issues caused by the COVID-19 pandemic, increased demand due to the economic recovery from the pandemic, labor shortages in certain trades and shortages in the availability of certain raw materials. These supply chain disruptions have not had a material impact on the Registrants net income, cash flows and financial condition, but have extended lead times for certain goods and services. Management has implemented risk mitigation strategies in an attempt to mitigate the impacts of these supply chain disruptions. However, a prolonged continuation or a future increase in the severity of supply chain disruptions could impact the cost of certain goods and services and extend lead times which could reduce future net income and cash flows and impact financial condition.

Customer Demand

AEP’s weather-normalized retail sales volumes for the year ended December 31, 2021 increased by 2.1% from the year ended December 31, 2020. Weather-normalized residential sales decreased 1.1% for the year ended December 31, 2021 compared to the year ended December 31, 2020. Weather-normalized commercial sales increased by 4.3% in 2021 compared to 2020. AEP’s 2021 industrial sales volumes increased 3.7% compared to 2020. The growth in industrial sales was spread across many industries.

In 2022, AEP anticipates weather-normalized retail sales volumes will increase by 1.5%. The industrial class is expected to increase by 5.5% in 2022, while weather-normalized residential sales volumes are projected to decrease by 0.5%. Finally, AEP projects weather-normalized commercial sales volumes to decrease by 0.8%.

(a)Percentage change for the year ended December 31, 2021 as compared to the year ended December 31, 2020.

(b)Forecasted percentage change for the year ended December 31, 2022 compared to the year ended December 31, 2021.

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Regulatory Matters

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

•2017-2019 Virginia Triennial Review - In November 2020, the Virginia SCC issued an order on APCo’s 2017-2019 Triennial Review filing concluding that APCo earned above its authorized ROE but within its ROE band for the 2017-2019 period, resulting in no refund to customers and no change to APCo base rates on a prospective basis. The Virginia SCC approved a prospective 9.2% ROE for APCo's 2020-2022 triennial review period with the continuation of a 140 basis point band (8.5% bottom, 9.2% midpoint, 9.9% top).

In December 2020, an intervenor filed a petition at the Virginia SCC requesting reconsideration of: (a) the failure of the Virginia SCC to apply a threshold earnings test to the approved regulatory asset for APCo’s closed coal-fired generation assets, (b) the Virginia SCC’s use of a 2011 benchmark study to measure the replacement value of capacity for purposes of APCo’s 2017 – 2019 earnings test and (c) the reasonableness and prudency of APCo’s investments in AMI meters.

In December 2020, APCo filed a petition at the Virginia SCC requesting reconsideration of: (a) certain issues related to APCo’s going-forward rates and (b) the Virginia SCC’s decision to deny APCo tariff changes that align rates with underlying costs. For APCo’s going-forward rates, APCo requested that the Virginia SCC clarify its final order and clarify whether APCo’s current rates will allow it to earn a fair return. If the Virginia SCC’s order did conclude on APCo’s ability to earn a fair return through existing base rates, APCo further requested that the Virginia SCC clarify whether it has the authority to also permit an increase in base rates.

In March 2021, the Virginia SCC issued an order confirming certain of its decisions from the November 2020 order and rejecting the various requests for reconsideration from APCo and an intervenor. In confirming its decision to reject an intervenor’s recommendation that APCo’s AMI costs incurred during the triennial period be disallowed, the Virginia SCC clarified that APCo established the need to replace its existing AMR meters, and that based on the uncertainty surrounding the continued manufacturing and support of AMR technology, APCo reasonably chose to replace them with AMI meters. In March 2021, APCo filed a notice of appeal of the reconsideration order with the Virginia Supreme Court. In September 2021, APCo submitted its brief before the Virginia Supreme Court. The brief was in alignment with the assignments of error filed by APCo in March 2021. In October 2021, the Virginia SCC and additional intervenors filed briefs with the Virginia Supreme Court disagreeing with APCo’s assignments of error in its appeal of the Triennial Review decision. Additionally, the Virginia SCC and APCo filed briefs disagreeing with an intervenor’s assignments of error in a separate appeal of the same decision. Oral arguments are scheduled to be held at the Virginia Supreme Court in March 2022.

APCo ultimately seeks an increase in base rates through its appeal to the Virginia Supreme Court. Among other issues, this appeal includes APCo’s request for proper treatment of the closed coal-fired plant assets in APCo’s 2017-2019 triennial period, reducing APCo’s earnings below the bottom of its authorized ROE band. If APCo’s appeals regarding treatment of the closed coal plants are granted by the Virginia Supreme Court, it could initially reduce future net income and impact financial condition. A Virginia Supreme Court decision in favor of APCo’s original expensing of the closed coal-fired plant asset balances would likely result in a remand to the Virginia SCC. Upon a subsequent Virginia SCC order, the initial negative impact for the write-off of the closed coal-fired plant asset balances could potentially be offset by an increase in base rates for earning below APCo’s 2017-2019 authorized ROE band.

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•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. 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 July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court.

In March 2021, the Texas Supreme Court issued an opinion reversing the July 2018 judgment of the Texas Third Court of Appeals and agreeing with the PUCT’s judgment affirming the prudence of the Turk Plant. In addition, the Texas Supreme Court remanded the AFUDC dispute back to the Texas Third Court of Appeals. In August 2021, the Texas Third Court of Appeals reversed the Texas District Court judgement 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. SWEPCo disagrees with the Court of Appeals decision and submitted a Petition for Review with the Texas Supreme Court in November 2021. The Texas Supreme Court requested responses to the Petition for Review, which are due by the end of March 2022.

If SWEPCo is ultimately unable to recover capitalized Turk Plant costs including AFUDC in excess of the Texas jurisdictional capital cost cap it would be expected to result in a pretax net disallowance ranging from $80 million to $100 million. In addition, if AFUDC is ultimately determined to be included in the Texas jurisdictional capital cost cap, SWEPCo estimates it may be required to make customer refunds ranging from $0 to $160 million related to revenues collected from February 2013 through December 2021 and such determination may reduce SWEPCo’s future revenues by approximately $15 million on an annual basis.

•In July 2019, Ohio House Bill 6 (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 phased out current energy efficiency programs as of December 31, 2020, including OPCo’s shared savings revenues of $26 million annually and renewable mandates after 2026. HB 6 also provided for the recovery of existing renewable energy contracts on a bypassable basis through 2032 and included a provision for recovery of OVEC costs through 2030 which will be allocated to all electric distribution utilities 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 have since pleaded guilty. In August 2020, an AEP shareholder filed a putative class action lawsuit against AEP and certain of its officers for alleged violations of securities laws in connection with HB 6. In May 2021, the defendants filed a motion to dismiss the securities litigation for failure to state a claim, which was granted with prejudice in December 2021. In addition, four AEP shareholders have 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, rescinded 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 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.

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•In April 2021, the FERC issued a supplemental Notice of Proposed Rulemaking (NOPR) proposing to modify its incentive for transmission owners that join RTOs (RTO Incentive). Under the supplemental NOPR, the RTO Incentive would be modified such that a utility would only be eligible for the RTO Incentive for the first three years after the utility joins a FERC-approved Transmission Organization. This is a significant departure from a previous NOPR issued in 2020 seeking to increase the RTO Incentive from 50 basis points to 100 basis points. The supplemental NOPR also required utilities that have received the RTO Incentive for three or more years to submit, within 30 days of the effective date of a final rule, a compliance filing to eliminate the incentive from its tariff prospectively. The supplemental NOPR was subject to a 60 day comment period followed by a 30 day period for reply comments. In July 2021, AEP submitted reply comments. AEP is awaiting a final rule from the FERC.

In July 2021, the FERC issued an order denying Dayton Power and Light’s request for a 50 basis point RTO incentive on the basis that its RTO participation was not voluntary, but rather is required by Ohio law. This precedent could have an impact on AEP’s transmission owning subsidiaries.

In 2019, the FERC approved settlement agreements establishing base ROEs of 9.85% (10.35% inclusive of RTO Incentive adder of 0.5%) and 10% (10.5% inclusive of RTO Incentive adder of 0.5%) for AEP’s PJM and SPP transmission-owning subsidiaries, respectively. In 2020, the FERC determined the base ROE for MISO’s transmission owning subsidiaries should be 10.02% (10.52% inclusive of RTO Incentive adder of 0.5%).

If the FERC modifies its RTO Incentive policy, it would be applied, as applicable, to AEP’s PJM, SPP and MISO transmission owning subsidiaries on a prospective basis, and could affect future net income and cash flows and impact financial condition. Based on management’s preliminary estimates, if a final rule is adopted consistent with the April 2021 supplemental NOPR, it could reduce AEP’s pretax income by approximately $55 million to $70 million on an annual basis.

•In 2020, Hurricanes Laura and Delta caused power outages and extensive damage to the SWEPCo service territories, primarily impacting the Louisiana jurisdiction. Following both hurricanes, the LPSC issued orders allowing Louisiana utilities, including SWEPCo, to establish regulatory assets to track and defer expenses associated with these storms. In February 2021, severe winter weather impacted the Louisiana jurisdiction and in March 2021 the LPSC approved the deferral of incremental storm restoration expenses related to the winter storm. In October 2021, SWEPCo filed a request with the LPSC for recovery of $145 million in deferred storm costs associated with the three storms. As part of the filing, SWEPCo requested recovery of the carrying charges on the deferred regulatory asset at a weighted average cost of capital through a rider beginning in January 2022. LPSC staff testimony is due to the LPSC in May 2022 and an order is expected before the end of 2022. If any of the storm costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

•In February 2021, severe winter weather had a significant impact in SPP, resulting in the declaration of Energy Emergency Alert Levels 2 and 3 for the first time in SPP’s history. The winter storm increased the demand for natural gas and restricted the available natural gas supply resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system. As of December 31, 2021, PSO and SWEPCo have deferred regulatory assets of $679 million and $430 million, respectively, relating to natural gas expenses and purchases of electricity incurred from February 9, 2021, to February 20, 2021, as a result of severe winter weather. SWEPCo’s deferred regulatory asset consists of $103 million, $148 million and $179 million related to the Arkansas, Louisiana and Texas jurisdictions, respectively.

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In January 2022, PSO, OCC staff and certain intervenors filed a joint stipulation and settlement agreement with the OCC to approve PSO’s securitization of the extraordinary fuel and purchases of electricity. The agreement includes a determination that all of PSO’s extraordinary fuel and purchases of electricity were prudent and reasonable and a 0.75% carrying charge, subject to true-up based on actual financing costs. In February 2022, the OCC approved the joint stipulation and settlement agreement in its financing order.

In March 2021, the APSC issued an order authorizing recovery of the Arkansas jurisdictional share of the retail customer fuel costs over five years, with the appropriate carrying charge to be determined at a later date. Subsequently, SWEPCo began recovery of these fuel costs. SWEPCo is currently recovering the fuel costs at an interim carrying charge of 0.3%. In April 2021, SWEPCo filed testimony supporting a five-year recovery with a carrying charge of 6.05%, which has been supported by APSC staff. Various other parties have recommended recovery periods ranging from 5-20 years with a carrying charge of 1.65%. The APSC ordered more testimony regarding the option of utilizing securitization to recover the fuel costs. SWEPCo is awaiting a decision from the APSC. The prudence of these fuel costs is expected to be addressed in a separate proceeding.

In March 2021, the LPSC approved a special order granting a temporary modification to the FAC and shortly after SWEPCo began recovery of its Louisiana jurisdictional share of these fuel costs based on a five-year recovery period inclusive of an interim carrying charge of 3.25%. SWEPCo will work with the LPSC to finalize the actual recovery period and determine the appropriate carrying charge in future proceedings.

In August 2021, SWEPCo filed an application with the PUCT to implement a net interim fuel surcharge for the Texas jurisdictional share of these retail fuel costs. The application requested a five-year recovery with a carrying charge of 7.18%. In October 2021, various intervenors filed testimony supporting a five-year recovery with a carrying charge ranging from 0.82% to 1.625%. In January 2022, an ALJ issued a PFD recommending a four-year recovery with a carrying charge the same as the annually set interest rate used for under-recovered fuel. In February 2022, SWEPCo filed exceptions to the PFD, disagreeing with the short-term interest rate recommended by the ALJ. SWEPCo is awaiting an order from the PUCT.

If SWEPCo is unable to recover any of the costs relating to the extraordinary fuel and purchases of electricity, or obtain authorization of a reasonable carrying charge on these costs, it could reduce future net income and cash flows and impact financial condition.

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Utility Rates and Rate Proceedings

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

The following tables show the Registrants’ completed and pending base rate case proceedings in 2021. See Note 4 - Rate Matters for additional information.

Completed Base Rate Case Proceedings

(a)See “2020 Kentucky Base Rate Case” section of Note 4 - Rate Matters in the 2020 Annual Report for additional information.

(b)Primarily due to a reduction in the ROE, the removal of proposed future energy efficiency costs and a decrease in vegetation management expenses moved to recovery in riders.

(c)In February 2022, SWEPCo filed a motion for rehearing with the PUCT challenging several errors in the final order, which includes a challenge of the approved ROE.

(d)Interim rates were implemented in November 2021.

(e)Approved increase will be phased-in with a $3 million increase effective February 2022 and the remaining $58 million effective January 2023. Rockport Plant, Unit 2 costs will be recovered through riders until the lease expiration in December 2022.

Pending Base Rate Case Proceedings

(a)The procedural schedule is on hold due to ongoing settlement discussions.

(b)Intervenor testimony is scheduled to be filed in March 2022.

Dolet Hills Power Station and Related Fuel Operations

In 2020, management of SWEPCo and CLECO determined DHLC would not proceed developing additional Oxbow Lignite Company (Oxbow) mining areas for future lignite extraction and ceased extraction of lignite at the mine in May 2020. In April 2020, SWEPCo and CLECO jointly filed a notification letter to the LPSC providing notice of the cessation of lignite mining. In December 2021, the Dolet Hills Power Station was retired.

The Dolet Hills Power Station non-fuel costs are recoverable by SWEPCo through base rates. As of December 31, 2021, SWEPCo’s share of the net investment in the Dolet Hills Power Station is $108 million, including materials and supplies, net of cost of removal collected in rates.

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Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses. As of December 31, 2021, SWEPCo had a net under-recovered fuel balance of $144 million, excluding impacts of the February 2021 severe winter weather event, which includes fuel consumed at the Dolet Hills Power Station. Additional reclamation and other land-related costs incurred by DHLC and Oxbow will be billed to SWEPCo and included in existing fuel clauses.

In June 2020, SWEPCo filed a fuel reconciliation with the PUCT for its retail operations in Texas, including Dolet Hills, for the reconciliation period of March 1, 2017 to December 31, 2019. See “2020 Texas Fuel Reconciliation” section of Note 5 for additional information.

In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $20 million of fuel costs in 2021 and defer approximately $30 million of additional costs with a recovery period to be determined at a later date. In November 2021, the LPSC issued a directive which deferred the issues regarding modification of the level and timing of recovery of the Dolet Hills Power Station from SWEPCo’s pending rate case to a separate existing docket. In addition, the recovery of the deferred fuel costs are planned to be addressed.

In March 2021, the APSC approved fuel rates that provide recovery of the Arkansas share of the 2021 Dolet Hills Power Station fuel costs over five years through the existing fuel clause. In the Arkansas base case, Staff proposed an extension of the recovery period to 25 years. See “2021 Arkansas Base Rate Case” section of Note 4 for additional information.

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

Pirkey Power Plant and Related Fuel Operations

In 2020, management announced plans to retire the Pirkey Power Plant in 2023. The Pirkey Power Plant non-fuel costs are recoverable by SWEPCo through base rates and fuel costs are recovered through active fuel clauses. As of December 31, 2021, SWEPCo’s share of the net investment in the Pirkey Power Plant is $207 million, including CWIP, before cost of removal. Sabine is a mining operator providing mining services to the Pirkey Power Plant. Under the provisions of the mining agreement, SWEPCo is required to pay, as part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. SWEPCo expects fuel deliveries, including billings of all fixed and operating costs, from Sabine to cease during the first quarter of 2023. Under the fuel agreements, SWEPCo’s fuel inventory and unbilled fuel costs from mining related activities were $91 million as of December 31, 2021. Also, as of December 31, 2021, SWEPCo had a net under-recovered fuel balance of $144 million, excluding impacts of the February 2021 severe winter weather event, which includes fuel consumed at the Pirkey Power Plant. Additional operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in existing fuel clauses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Renewable Generation

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

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Contracted Renewable Generation Facilities

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

As of December 31, 2021, subsidiaries within AEP’s Generation & Marketing segment had approximately 1,761 MWs of contracted renewable generation projects in-service.  In addition, as of December 31, 2021, these subsidiaries had approximately 27 MWs of renewable generation projects under construction with total estimated capital costs of $27 million related to these projects.

In February 2022, AEP management announced the beginning of a process to sell all or a portion of AEP Renewables’ competitive contracted renewables portfolio within the Generation & Marketing segment. As of December 31, 2021, the competitive contracted renewable portfolio assets totaled 1.6 gigawatts of generation resources.

Regulated Renewable Generation Facilities

In 2020, PSO received approval from the OCC and SWEPCo received approval from the APSC and LPSC to acquire the NCWF, comprised of three Oklahoma wind facilities totaling 1,484 MWs, on a fixed cost turn-key basis at completion. Both the APSC and LPSC approved the flex-up option, agreeing to acquire the Texas portion, which the PUCT denied. PSO will own 45.5% and SWEPCo will own 54.5% of the project, which will cost approximately $2 billion.

In June 2021, the IRS issued a notice extending the “Continuity Safe Harbor” deadlines for qualifying renewable energy projects. Under the June 2021 IRS notice, the Continuity Safe Harbor for qualifying renewable energy projects that began construction in calendar years 2016 through 2019 is extended to six years. Additionally, the Continuity Safe Harbor is extended to five years for qualifying projects that began construction in calendar year 2020. Provided that each facility does satisfy the Continuity Safe Harbor, under the current IRS guidance, the Sundance wind facility will qualify for 100% of the federal PTC, and the Maverick and Traverse wind facilities will qualify for 80% of the federal PTC.

In April 2021, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Sundance during its development and construction for $270 million, the first of the three NCWF acquisitions. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Sundance assets in proportion to their undivided ownership interests. Sundance was placed in-service in April 2021. In September 2021, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Maverick during its development and construction for $383 million, the second of the three NCWF acquisitions. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Maverick assets in proportion to their undivided ownership interests. Maverick was placed in-service in September 2021. As of December 31, 2021, PSO and SWEPCo had approximately $316 million and $378 million, of gross Property, Plant and Equipment on the balance sheets, respectively, related to the Sundance and Maverick NCWF projects. The Traverse wind facility is targeted to be acquired and placed in-service in the first quarter of 2022. See “North Central Wind Energy Facilities” section of Note 7 for additional information.

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

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In November 2021, PSO issued requests for proposals to acquire up to 2,800 MWs of wind and 1,350 MWs of solar generation resources. The wind and solar generation projects would be subject to regulatory approval.

In December 2021, APCo petitioned for approval to purchase a 204 MW wind project and three solar facilities totaling 205 MWs. Additionally, APCo executed PPAs for another 89 MWs of solar generation resources. In January 2022, APCo issued additional requests for proposals to acquire up to 1,000 MWs of wind and/or 100 MWs of solar generation resources. These wind and solar generation projects would also be subject to regulatory approval.

Disposition of KPCo and KTCo

In October 2021, AEP entered into a Stock Purchase Agreement 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 sale is subject to regulatory approvals from the FERC and KPSC. Clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and clearance from the Committee on Foreign Investment in the United States has been received.

KPCo currently operates and owns a 50% interest in the 1,560 MW coal-fired Mitchell Power Plant (Mitchell Plant) with the remaining 50% owned by WPCo. The Stock Purchase Agreement is further contingent upon the issuance by the KPSC, WVPSC and FERC of orders regarding a new proposed Mitchell Plant Operations and Maintenance Agreement and Mitchell Plant Ownership Agreement between KPCo and WPCo pursuant to which WPCo would replace KPCo as the operator of the Mitchell Plant and KPCo employees at the Mitchell Plant would become employees of WPCo. Under the proposed Ownership Agreement, WPCo is obligated to purchase KPCo’s 50% interest in the Mitchell Plant on December 31, 2028 unless KPCo and WPCo have agreed to retire the Mitchell Plant earlier or, absent such agreement, if WPCo elects prior to December 31, 2027 to retire the Mitchell Plant on December 31, 2028. The Ownership Agreement provides that the purchase price for KPCo’s 50% ownership interest in the Mitchell Plant will be determined through the mutual agreement of WPCo and KPCo (subject to approval from the KPSC and WVPSC) or through a fair market valuation determination conducted by independent appraisals, with offsets for estimated decommissioning costs and the cost of ELG investments made by WPCo, if KPCo and WPCo are unable to reach agreement as to the purchase price.

In November 2021, AEP made filings with the KPSC, WVPSC, and FERC seeking approval of the new proposed Mitchell Plant Operations and Maintenance Agreement and Mitchell Plant Ownership Agreement. Subsequently, the KPSC and WVPSC intervened in the FERC proceeding and have recommended that FERC dismiss or reject AEP’s request, or defer ruling on AEP’s request until both the retail commissions have rendered decisions. In February 2022, AEP filed a motion to withdraw its filing with the FERC, noting that AEP intends to re-file its request after the KPSC and WVPSC have reviewed the agreements. In the WVPSC proceeding, intervenor testimony is expected in March 2022 and a hearing is scheduled to occur in April 2022.

In December 2022, Liberty, KPCo and KTCo sought approval from the FERC under Section 203 of the Federal Power Act for the sale. In February 2022 several intervenors in the case filed protests related to whether the sale will negatively impact the wholesale transmission and generation rates of applicants. An order from the FERC is expected in the matter in April 2022.

In January 2022, intervenor testimony was filed with the KPSC, recommending the KPSC either reject the new proposed Mitchell Plant Ownership Agreement or approve the agreement with certain modifications including a revision to the buyout provision that would set WPCo’s Mitchell Plant purchase price at the greater of fair market value or net book value. The intervenor testimony also recommends the KPSC reject the proposed Mitchell Plant Operations and Maintenance Agreement, which the testimony stated should be modified to remove references to the Mitchell Plant Ownership Agreement. In February 2022, AEP filed rebuttal testimony with the KPSC opposing the intervenor testimony filed in January 2022. AEP’s rebuttal testimony also discusses an alternative proposal to the fair market value provision included in the proposed Mitchell Plant Ownership Agreement. Under the alternative proposal, KPCo’s and WPCo’s interest in the Mitchell Plant would be divided by unit if the plant is not retired before the end of 2028 and a mutual agreement cannot be reached on a buyout price. Under the alternative proposal, mutual agreement on the buyout price or unit disposition would need to be finalized by May 2025, with a

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division of plant ownership by unit effective January 1, 2029, unless otherwise agreed. A hearing on the Mitchell Plant agreements is scheduled with the KPSC in March 2022.

In January 2022, KPCo and Liberty filed a joint application requesting the KPSC authorize the transfer of ownership of KPCo to Liberty. In February 2022, certain intervenors filed testimony recommending that the KPSC not approve the transfer of ownership. If, however, the KPSC does approve the transfer, these intervenors recommend that the KPSC require AEP to compensate KPCo customers $578 million for alleged future increased costs and higher rates that the intervenors claim will exist under Liberty’s ownership. AEP disagrees with the recommendation and will file rebuttal testimony in March 2022. Intervenors also recommended imposing certain conditions on Liberty, including conditions related to recovering certain costs, inter-company agreement filing requirements, KPCo’s capital structure and future generation resource planning processes and analyses. In addition, certain intervenors argue that the commission should not approve the new proposed Mitchell Plant Ownership Agreement and Mitchell Plant Operations and Maintenance Agreement, and that deciding the request to transfer ownership of KPCo should be separated from approval of the Mitchell agreements even though such approval is a condition to the transaction closing. AEP also disagrees with this argument. A hearing is scheduled with the KPSC in March 2022 and a final order is expected in the second quarter of 2022.

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

AEP expects to receive approximately $1.45 billion in cash, net of taxes and transaction fees. AEP plans to use the proceeds to eliminate forecasted equity needs in 2022 as the company invests in regulated renewables, transmission and other projects. AEP and AEPTCo expect the sale to have a one-time impact on after tax earnings that is not material.

Hydroelectric Generation

Racine

In February 2021, AEP signed an agreement to sell Racine to a nonaffiliated party. The sale of Racine closed in the fourth quarter of 2021 resulting in an immaterial gain which is recorded in Other Operation on AEP’s statements of income.

Federal Tax Reform

Based on current regulatory orders received, management anticipates amortization of $164 million of Excess ADIT in 2022 ($67 million of Excess ADIT subject to normalization requirements and $97 million of Excess ADIT that is not subject to normalization requirements). Customer usage or new regulatory orders could result in changes to these estimates. Management anticipates amortizing the following ranges of Excess ADIT that is not subject to normalization requirements during the years 2023 through 2027:

Annual Amortization of Excess ADIT

Not Subject to Normalization Requirements

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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 the Turk Plant output is currently not subject to cost-based rate recovery due to not having rate recovery approval in Arkansas. This output is being sold into the wholesale market. Approximately 80% of the Turk Plant investment is recovered under cost-based rate recovery in Texas, Louisiana and through SWEPCo’s wholesale customers under FERC-based rates. As of December 31, 2021, 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 Turk Plant, it could reduce future net income and cash flows and impact financial condition.

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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.

Rockport Plant Litigation

In 2013, the Wilmington Trust Company filed suit in the U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it would be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022.  The terms of the consent decree allow the installation of environmental emission control equipment, repowering, refueling or retirement of the unit.  The plaintiffs sought a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs.  See “Obligations under the New Source Review Litigation Consent Decree” section below for additional information.

After the litigation proceeded at the district court and appellate court, in April 2021, I&M and AEGCo reached an agreement to acquire 100% of the interests in Rockport Plant, Unit 2 for $116 million from certain financial institutions that own the unit through trusts established by Wilmington Trust, the nonaffiliated owner trustee of the ownership interests in the unit, with closing to occur as of the end of the Rockport Plant, Unit 2 lease in December 2022. The agreement is subject to customary closing conditions, including regulatory approvals and as of the closing will result in a final settlement of, and release of claims in, the lease litigation. As a result, in May 2021, at the parties’ request, the district court entered a stipulation and order dismissing the case without prejudice to plaintiffs asserting their claims in a re-filed action or a new action. The required regulatory approvals at the IURC and FERC have been obtained that would allow the closing to occur as of the end of the lease in December 2022. The IURC order approved a settlement agreement addressing the future use of Rockport Plant, Unit 2 as a capacity and energy resource and associated adjustments to I&M’s Indiana retail rates, along with certain other matters. Management believes its financial statements appropriately reflect the resolution of the litigation. See Note 13 - Leases for additional information.

Claims Challenging Transition of American Electric Power System Retirement Plan to Cash Balance Formula

Four participants in The American Electric Power System Retirement Plan (the Plan) filed a class action complaint in December 2021 in the U.S. District Court for the Southern District of Ohio against AEPSC and the Plan. When the Plan’s benefit formula was changed in the year 2000, AEP provided a special provision for employees hired before January 1, 2001, allowing them to continue benefit accruals under the then benefit formula for a full 10 years alongside of the new cash balance benefit formula then being implemented.  Employees who were hired on or after January 1, 2001 accrued benefits only under the new cash balance benefit formula.  The Plaintiffs assert a number of claims on behalf of themselves and the purported class, including that: (a) the Plan violates the requirements under the Employee Retirement Income Security Act (ERISA) intended to preclude back-loading the accrual of benefits to the end of a participant’s career, (b) the Plan violates the age discrimination prohibitions of ERISA and the Age Discrimination in Employment Act and (c) AEP failed to provide required notice regarding the changes to the Plan. Among other relief, the Complaint seeks reformation of the Plan to provide additional benefits and the recovery of plan benefits for former employees under such reformed plan. The Plaintiffs previously had submitted claims for additional plan benefits to AEP, which were denied. On February 15, 2022, AEPSC and the Plan filed a motion to dismiss the complaint for failure to state a claim. AEP will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

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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 United States District Court for the Southern District of Ohio against AEP and certain of its officers for alleged violations of securities laws. The amended complaint alleged misrepresentations or omissions by AEP regarding: (a) its alleged participation in or connection to public corruption with respect to the passage of HB 6 and (b) its regulatory, legislative, political contribution, 501(c)(4) organization contribution and lobbying activities in Ohio. The complaint sought monetary damages, among other forms of relief. In December 2021, the District Court issued an opinion and order dismissing the securities litigation complaint with prejudice, determining that the complaint fails 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 United States 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 New York state court derivative action is stayed. The Ohio state court derivative action was stayed until February 18, 2022, and the parties to that case filed a stipulation seeking to extend the stay. The two derivative actions pending in federal court have been consolidated, and the parties to the consolidated action have filed a joint motion for the court to enter a scheduling order pursuant to which plaintiffs will file an amended complaint and the parties will then propose a briefing schedule for defendants’ motion to dismiss the amended complaint. 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 is directed to the Board of Directors of AEP 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 directors and officers, and that, following such investigation, AEP commence a civil action for breaches of fiduciary duty and related claims and take appropriate disciplinary action against those individuals who allegedly harmed the company. The shareholder that sent the letter has agreed that AEP and the AEP Board may defer consideration of the litigation demand until the resolution of the motion to dismiss the securities litigation. 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 benefits to AEP from the passage of HB 6 and documents relating to AEP’s financial processes and controls. AEP is cooperating fully with the SEC’s subpoena. Although the outcome of the SEC’s investigation cannot be predicted, management does not believe the results of this inquiry will have a material impact on our financial condition, results of operations, or cash flows.

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

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

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed below will have a material impact on AEP System generating units.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of December 31, 2021, the AEP System owned generating capacity of approximately 25,000 MWs, of which approximately 11,900 MWs were coal-fired.  Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on fossil generation. Based upon management estimates, AEP’s future investment to meet these existing and proposed requirements ranges from approximately $325 million to $550 million through 2028.

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in finalizing proposed rules or 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.  In addition, management continues to evaluate the economic feasibility of environmental investments on regulated and competitive plants.

Obligations under the New Source Review Litigation Consent Decree

In 2007, the U.S. District Court for the Southern District of Ohio approved a consent decree between AEP subsidiaries in the eastern area of the AEP System and the Department of Justice, the Federal EPA, eight northeastern states and other interested parties to settle claims that the AEP subsidiaries violated the NSR provisions of the CAA when they undertook various equipment repair and replacement projects over a period of nearly 20 years.  The consent decree’s terms include installation of environmental control equipment on certain generating units, a declining cap on SO2 and NOX emissions from the AEP System and various mitigation projects. The consent decree has been modified six times, for various reasons, most recently in 2020. All of the environmental control equipment required by the consent decree has been installed.

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

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

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, including a provision that postponed the due date for the next comprehensive SIP revisions until 2021. Petitions for review of the final rule revisions have been filed in the U.S. Court of Appeals for the District of Columbia Circuit.

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

In 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 designed to address interstate transport of emissions that contributed significantly to downwind non-attainment with the 1997 ozone and PM NAAQS.  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 sub-regional basis.

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In January 2021, the Federal EPA finalized a revised CSAPR rule, which substantially reduces the ozone season NOX budgets in 2021-2024. Several utilities and other entities potentially subject to the Federal EPA’s NOX regulations have challenged that final rule in the U.S. Court of Appeals for the District of Columbia Circuit and briefing is underway. Management cannot predict the outcome of that litigation, but believes it can meet the requirements of the rule in the near term, and is evaluating its compliance options for later years, when the budgets are further reduced.

Climate Change, CO2 Regulation and Energy Policy

In 2019, the Affordable Clean Energy (ACE) rule established a framework for states to adopt standards of performance for utility boilers based on heat rate improvements for such boilers. However, in January 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE rule and remanded it to the Federal EPA. Management is unable to predict how the Federal EPA will respond to the court’s remand. In October 2021 the United States Supreme Court granted certiorari and combined four separate petitions seeking review of the D.C. Circuit Court decisions. Briefing is underway but management is unable to predict the outcome of that litigation.

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

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.  In April 2020, Virginia enacted clean energy legislation to allow the state to participate in the Regional Greenhouse Gas Initiative, require the retirement of all fossil-fueled generation by 2045 and require 100% renewable energy to be provided to Virginia customers by 2050. Management is taking steps to comply with these requirements, including increasing wind and solar installations, purchasing renewable power and broadening AEP System’s portfolio of energy efficiency programs.

In February 2021, AEP announced new intermediate and long-term CO2 emission reduction goals, based on the output of the company’s integrated resource plans, which take into account economics, customer demand, grid reliability and resiliency, regulations and the company’s current business strategy. The intermediate goal is an 80% reduction from 2000 CO2 emission levels from AEP generating facilities by 2030; the long-term goal is net-zero CO2 emissions from AEP generating facilities by 2050. AEP’s total estimated CO2 emissions in 2021 were approximately 50 million metric tons, a 70% reduction from AEP’s 2000 CO2 emissions. AEP has made significant progress in reducing CO2 emissions from its power generation fleet and expects its emissions to continue to decline. Technological advances, including energy storage, will determine how quickly AEP can achieve zero emissions while continuing to provide reliable, affordable power for 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.

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Coal Combustion Residual (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.

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

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

(a)Net book value before cost of removal including CWIP and inventory.

(b)Amount includes a $171 million regulatory asset related to the retired Tanners Creek Plant. The IURC and MPSC authorized recovery of the Tanners Creek Plant regulatory asset over the useful life of Rockport Plant, Unit 1 in 2015 and 2014, respectively.

In addition, AGR owns Cardinal Plant, Unit 1 a competitive generation unit. A nonaffiliated electric cooperative owns Cardinal Plant, Unit 2 and Unit 3 and operates all three units at the Cardinal Plant. The nonaffiliate filed an application for additional time to develop alternative disposal capacity for the Cardinal Plant. As of December 31, 2021, the net book value of Cardinal Plant, Unit 1, including materials and supplies and CWIP, before cost of removal, was approximately $46 million.

In January 2022, the Federal EPA began responding to applications for extension requests and has proposed to deny several extension requests based on allegations that the utilities that received such responses are not in compliance with the CCR Rule. The Federal EPA’s allegations of noncompliance rely on new interpretations of the CCR Rule requirements, are subject to a 30 day public comment period prior to final determination and could ultimately be challenged in court. While the Federal EPA has not yet proposed any action on pending extension requests submitted by AEP, statements made by the Federal EPA in proposed denials of extension requests submitted by other utilities indicate that there is a risk that the Federal EPA may similarly conclude that AEP is not eligible for an extension of time to cease use of its CCR impoundments and/or that one or more of AEP’s facilities is not in compliance with the CCR Rule. If that occurs, AEP may incur material additional costs to change its plans for complying with the CCR Rule, including the potential to have to temporarily cease operation of one or more facilities until an acceptable compliance alternative can be implemented. Such temporary cessation of operation could materially impact the cost of serving customers of the affected utility. Further, actions by the Federal EPA could require AEP to remove coal ash from CCR impoundments in Kentucky, Ohio, Virginia and West Virginia that have already been closed in accordance with state law programs or would require AEP to incur costs related to CCR impoundments at various facilities.

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Closure and post-closure 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 related to competitive units or in regulated jurisdictions without providing similar assurances of cost recovery, it would impose significant additional operating costs on AEP, which could 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.

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

(a)Net book value including CWIP excluding cost of removal and materials and supplies.

(b)Pirkey Power Plant is currently being recovered through 2025 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.

(c)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028.

(d)Unit 1 is currently being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Unit 3 is currently being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.

Under the retirement option above, AEP may need to recover remaining depreciation and estimated closure costs associated with retiring plants over a shorter period. If AEP cannot ultimately recover the costs of environmental compliance and/or the remaining depreciation and estimated closure costs associated with retiring plants in a timely manner, it would reduce future net income and cash flows and impact financial condition.

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, establishes additional options for reusing and discharging small volumes of bottom ash transport water, provides an exception for retiring units and extends the compliance deadline to a date as soon as possible beginning one year after the rule was published but no later than December 2025. Management has assessed technology additions and retrofits to comply with the rule and the impacts of the Federal EPA’s recent actions on facilities’ wastewater discharge permitting for FGD wastewater and bottom ash transport water. 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. We continue 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. The Federal EPA has announced its intention to reconsider the 2020 rule and to further revise limits applicable to discharges of landfill and impoundment leachate. A proposed rule is expected in late 2022. Management cannot predict whether the Federal EPA will actually finalize further revisions or what such revisions might be, but we will continue to monitor this issue and will participate in further rulemaking activities as they arise.

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In August 2021, the Federal EPA and the Army Corps of Engineers announced their plan to reconsider and revise the Navigable Waters Protection Rule, which defines “waters of the United States” under the Clean Water Act. Shortly thereafter, the United States District Court for the District of Arizona vacated and remanded the Navigable Waters Protection Rule, which had the effect of reinstating the prior, much broader, version of the rule. Because the scope of waters subject to the Federal EPA and Army Corps of Engineers jurisdictions is broader under the prior rule, permitting decisions made in recent years are subject to reevaluation; permits may now be necessary where none were previously required, and issued permits may need to be reopened to impose additional obligations. In December 2021, the Federal EPA proposed a rule that would roll back the definition of “waters of the United States” to the pre-2015 definition. The Federal EPA also announced that it would be considering further changes through a future rulemaking, which would build upon the foundation of the proposed rule. Management will continue to monitor rulemaking on this issue.

CCR and ELG Compliance Plan Filings

Mitchell Plant (Applies to AEP)

KPCo and WPCo each own a 50% interest in the Mitchell Plant. In December 2020 and February 2021, WPCo and KPCo filed requests with the WVPSC and KPSC, respectively, to obtain the regulatory approvals necessary to implement CCR and ELG compliance plans and seek recovery of the estimated $132 million investment for the Mitchell Plant that would allow the plant to continue operating beyond 2028. Within those requests, WPCo and KPCo also filed a $25 million alternative to implement only the CCR-related investments with the WVPSC and KPSC, respectively, which would allow the Mitchell Plant to continue operating only through 2028.

In July 2021, the KPSC issued an order approving the CCR only alternative and rejecting the full CCR and ELG compliance plan. In August 2021, the WVPSC approved the full CCR and ELG compliance plan for the WPCo share of the Mitchell Plant. In September 2021, WPCo submitted a filing with the WVPSC to reopen the CCR/ELG case that was approved by the WVPSC in August 2021. Due to the rejection by the KPSC of the KPCo share of the ELG investments, WPCo requested the WVPSC consider approving the construction and recovery of all ELG costs at the plant. In October 2021, the WVPSC affirmed its August 2021 order approving the construction of CCR/ELG investments and directed WPCo to proceed with CCR/ELG compliance plans that would allow the plant to continue operating beyond 2028. The WVPSC’s order further states WPCo will not share capacity and energy from the plant with KPCo customers if those customers are not paying for ELG compliance costs, or for any new capital investment or continuing operations costs incurred, to allow the plant to operate beyond 2028 or prevent downgrades prior to 2028. The WVPSC also ordered that WPCo will be given the opportunity to recover, from its customers, the new capital and operating costs arising solely from the WVPSC's directive to operate the plant beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred. In October and November 2021, intervenors filed petitions for reconsideration at the WVPSC requesting clarification on certain aspects of the

order, primarily the jurisdictional allocation of future operating expenses and plant costs.

In November 2021, AEP made filings with the KPSC, WVPSC and FERC seeking approval for a new proposed Mitchell Plant Operations and Maintenance Agreement and Mitchell Plant Ownership Agreement between KPCo and WPCo pursuant to which WPCo would replace KPCo as the operator of the Mitchell Plant. In February 2022, AEP filed a motion to withdraw its filing with the FERC, noting that AEP intends to re-file its request after the KPSC and WVPSC reviews have been completed. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.

As of December 31, 2021, the Mitchell Plant ELG investment balance in CWIP was $6 million split equally between KPCo and WPCo. As of December 31, 2021, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $586 million.

If any of the ELG costs are not approved for recovery and/or the retirement date of the Mitchell Plant is accelerated to 2028 without commensurate cost recovery, it would reduce future net income and cash flows and impact financial condition.

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Amos and Mountaineer Plants (Applies to AEP and APCo)

In December 2020, APCo submitted filings with the Virginia SCC and WVPSC requesting regulatory approvals necessary to implement CCR and ELG compliance plans and seek recovery of the estimated $240 million investment for the Amos and Mountaineer plants. Intervenors in Virginia and West Virginia recommended that only the CCR-related investments be constructed at Amos and Mountaineer and, as a consequence, that APCo close these generating facilities at the end of 2028.

In August 2021, the Virginia SCC issued an order approving APCo’s request to construct CCR-related investments at the Amos and Mountaineer Plants and approved recovery of CCR-related other operation and maintenance expenses and investments through an active rider. The order denied APCo’s request to construct the ELG investments and denied recovery of previously incurred ELG costs. APCo plans to refile for approval of the ELG investments and previously incurred ELG costs in the first quarter of 2022.

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

APCo expects total Amos and Mountaineer Plant ELG investment, excluding AFUDC, to be approximately $197 million. As of December 31, 2021, APCo’s Virginia jurisdictional share of the net book value, before cost of removal including CWIP and inventory, of the Amos and Mountaineer Plants was approximately $1.5 billion and APCo’s Virginia jurisdictional share of its ELG investment balance in CWIP for these plants was $26 million.

If any of the ELG costs are not approved for recovery and/or the retirement dates of the Amos and Mountaineer plants are accelerated to 2028 without commensurate cost recovery, it would reduce future net income and cash flows and impact financial condition.

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.

Previously, management retired or announced early closure plans for Welsh Unit 2, Oklaunion Power Station, Dolet Hills Power Station and Northeastern Plant Unit 3.

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The table below summarizes the net book value, as of December 31, 2021, of generating facilities retired or planned for early retirement in advance of the retirement date currently authorized for ratemaking purposes:

(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)Dolet Hills Power Station is currently being recovered through 2026 in the Louisiana jurisdiction and through 2046 in the Arkansas jurisdiction. In December 2021, the PUCT authorized the recovery of SWEPCo’s Texas jurisdictional share of the Dolet Hills Power Station through 2046 without providing a return on the investment which resulted in a disallowance of $12 million. See Note 4 - Rate Matters for additional information.

(e)Pirkey Power Plant is currently being recovered through 2025 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.

(f)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028.

(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.

(h)Welsh Plant, Unit 2 is being recovered over the blended useful life of Welsh Plant, Units 1 and 3.

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 are not deemed recoverable, it could materially reduce future net income, cash flows and impact financial condition.

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RESULTS OF OPERATIONS

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 and their related business activities are outlined below:

Vertically Integrated Utilities

•Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.

Transmission and Distribution Utilities

•Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo.

•OPCo purchases energy and capacity at auction to serve standard service offer customers and provides transmission and distribution services for all connected load.

AEP Transmission Holdco

•Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved ROE.

•Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved ROE.

Generation & Marketing

•Contracted renewable energy investments and management services.

•Marketing, risk management and retail activities in ERCOT, MISO, PJM and SPP.

•Competitive generation in PJM.

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

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

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A detailed discussion of AEP’s 2020 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 2020 Annual Report on Form 10-K filed with the SEC on February 25, 2021.

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

Note: 2021 Earnings Attributable to AEP Common Shareholders by Segment excludes Corporate and Other which is not considered a reportable segment.

AEP CONSOLIDATED

2021 Compared to 2020

Earnings Attributable to AEP Common Shareholders increased from $2.2 billion in 2020 to $2.5 billion in 2021 primarily due to:

•Favorable rate proceedings in AEP’s various jurisdictions.

•An increase in transmission investment, which resulted in higher revenues and income.

•An increase in weather-related usage.

These increases were partially offset by:

•An increase in Other Operation and Maintenance expenses not subject to regulatory rider mechanisms.

AEP’s results of operations by reportable segment are discussed below.

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VERTICALLY INTEGRATED UTILITIES

(a)Other AEP Segments excludes Corporate and Other which is not considered a reportable segment.

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(a)Includes Off-system Sales, municipalities and cooperatives, unit power and other wholesale customers.

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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.

(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.

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2021 Compared to 2020

Reconciliation of Year Ended December 31, 2020 to Year Ended December 31, 2021

Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities

(in millions)

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:

•Retail Margins increased $470 million primarily due to the following:

•A $104 million increase due to rider revenues of $99 million for APCo and $5 million for WPCo, respectively, which includes the WV modified rate base cost surcharge, effective September 2021. This increase was partially offset in other expense items below.

•A $78 million increase in weather-related usage primarily in the residential class.

•A $51 million increase at PSO due to rider revenues. This increase was partially offset in other expense items below.

•A $48 million increase in rider revenues at I&M. This increase was partially offset in other expense items below.

•A $47 million increase at SWEPCo primarily due to a base rate revenue increase in Texas and rider increases in all Retail jurisdictions. This increase was partially offset in other expense items below.

•A $46 million increase at KPCo due to rider revenues. This increase was partially offset in other expense items below.

•A $44 million increase due to the cumulative impact of the implementation of APCo’s 2017 and 2019 generation and distribution depreciation studies as ordered in the Virginia triennial base rate case in 2020.

•A $44 million increase due to lower customer refunds related to Tax Reform primarily at APCo and SWEPCo. This increase was partially offset in Income Tax Benefit below.

•A $30 million increase at I&M in Indiana and Michigan base rate revenues. This increase was partially offset in expense items below.

•A $27 million increase at KPCo due to base rate case revenues implemented in January 2021.

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•A $19 million increase due to the annual wholesale formula rate true-up at I&M. This increase was partially offset in expense items below.

•A $16 million increase in recoverable fuel costs at SWEPCo primarily due to timing of recovery.

•A $13 million increase in deferred fuel at WPCo primarily due to the timing of recoverable expenses. This increase was offset in other expense items below.

•An $11 million increase in weather-normalized municipal and cooperative revenues at SWEPCo primarily due to the February 2021 severe winter weather event.

•A $10 million increase at SWEPCo due to the prior year fuel cost disallowance in the 2020 Texas Fuel Reconciliation.

•A $9 million increase in municipal and cooperative revenues at SWEPCo due to the annual generation formula rate true-up.

•A $7 million increase at PSO due to new base rates implemented in November 2021.

These increases were partially offset by:

•A $79 million decrease in weather-normalized retail margins primarily in the residential class.

•A $24 million decrease in weather-normalized wholesale margins, including the loss of a significant wholesale contract at I&M.

•An $18 million decrease in deferred fuel at APCo primarily due to the timing of recoverable expenses. This decrease was offset in other expense items below.

•Margins from Off-system Sales increased $25 million primarily due to increased Turk Plant merchant sales as a result of the February 2021 severe winter weather event at SWEPCo.

•Transmission Revenues increased $31 million primarily due to the following:

•A $19 million increase due to increased transmission investment at APCo.

•A $15 million increase due to increased load and increased transmission investment at SWEPCo.

These increases were partially offset by:

•A $7 million decrease as a result of the annual transmission formula rate true-up.

•Other Revenues decreased $6 million primarily due to the following:

•A $12 million decrease at PSO primarily due to lower business development revenue. This decrease was partially offset in Other Operation and Maintenance expense items below.

This decrease was partially offset by:

•A $5 million increase primarily due to the reinstatement of late fees and disconnections in 2021, which were suspended in 2020.

Expenses and Other and Income Tax Benefit changed between years as follows:

•Other Operation and Maintenance expenses increased $289 million primarily due to the following:

•A $185 million increase in PJM transmission services including increased formula rate true-up activity.

•A $62 million increase in vegetation management expenses.

•A $59 million increase in SPP transmission services including the annual formula rate true-up.

•A $49 million increase due to the prior year impact of the 2017-2019 Virginia triennial review which authorized regulatory recovery of previously retired coal-fired generation assets.

•A $27 million increase in administrative overheads.

•An $18 million increase related to a 2020 insurance settlement primarily at SWEPCo and PSO.

•A $7 million increase due to the capitalization of previously expensed North Central Wind Energy Facilities costs at SWEPCo and PSO in 2020.

These increases were partially offset by:

•A $78 million decrease in employee-related expenses primarily driven by the prior year impact of the voluntary retirement incentive program, severance expense and COVID-19 incentives provided to front line employees.

•A $28 million decrease at I&M in Indiana jurisdictional Demand Side Management expenses. This decrease was offset in Retail Margins above.

•A $15 million decrease in factoring expenses.

•Asset Impairments and Other Related Charges increased $12 million due to a partial regulatory disallowance of SWEPCo’s investment in the Dolet Hills Power Station as a result of an order received in the 2020 Texas Base Rate Case.

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•Depreciation and Amortization expenses increased $147 million primarily due to a higher depreciable base at APCo, I&M, PSO and SWEPCo and increased depreciation rates at APCo, I&M and SWEPCo. This increase was partially offset in Gross Margin above.

•Taxes Other Than Income Taxes increased $25 million primarily due to the following:

•A $15 million increase at SWEPCo primarily due to increased property taxes resulting from the expiration of the Louisiana Industrial Tax Exemption related to Stall Plant.

•A $4 million increase at APCo primarily due to an increase in West Virginia business and occupational taxes.

•Other Income increased $11 million primarily due to carrying charges on regulatory assets at PSO and SWEPCo resulting from the February 2021 severe winter weather event.

•Interest Expense increased $9 million primarily due to the following:

•An $11 million increase primarily due to higher long-term debt balances at SWEPCo and I&M.

This increase was partially offset by:

•A $4 million decrease primarily due to lower short-term debt balances at APCo.

•Income Tax Benefit increased $4 million primarily due to the following:

•A $19 million decrease in state tax expense.

•A $13 million increase in PTC.

•A $10 million increase in amortization of Excess ADIT partially offset in Retail Margin above.

These increases in Income Tax Benefit were partially offset by:

•A $15 million decrease in parent company loss benefit.

•A $10 million decrease due to an increase in pretax book income.

•A $7 million decrease due to an out of period adjustment related to deferred taxes.

•A $6 million decrease related to tax return to provision adjustments.

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TRANSMISSION AND DISTRIBUTION UTILITIES

(a)Other AEP Segments excludes Corporate and Other which is not considered a reportable segment.

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(a)Represents energy delivered to distribution customers.

(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold into PJM.

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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.

(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.

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2021 Compared to 2020

Reconciliation of Year Ended December 31, 2020 to Year Ended December 31, 2021

Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities

(in millions)

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:

•Retail Margins increased $198 million primarily due to the following:

•A $164 million increase in Basic Transmission Cost Rider revenues and recoverable PJM expenses in Ohio. This increase was partially offset in Other Operation and Maintenance expenses below.

•A $91 million increase related to various rider revenues in Ohio. This increase was partially offset in Margins from Off-system Sales, Other Revenues and other expense items below.

•A $44 million increase from interim rate increases driven by increased distribution investment in Texas.

•A $21 million increase due to prior year refunds in Texas of Excess ADIT and excess federal income taxes collected as a result of Tax Reform. This increase was offset in Income Tax Expense below.

•A $15 million increase in weather-normalized margins in Ohio primarily in the residential class.

•A $13 million increase from interim rate increases driven by increased transmission investment in Texas.

•A $7 million increase in weather-related usage in Texas primarily due to an 80% increase in heating degree days.

These increases were partially offset by:

•An $87 million decrease due to the ending of the Energy Efficiency and Peak Demand Reduction Rider in Ohio in December 2020. This decrease was partially offset in Other Operation and Maintenance expenses below.

•A $55 million decrease in revenues associated with the Universal Service Fund (USF) in Ohio. This decrease was offset in Other Operations and Maintenance expenses below.

•A $14 million decrease in weather-related usage in Ohio primarily due to the end of decoupling and mild December weather.

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•Margins from Off-system Sales decreased $95 million primarily due to the following:

•A $67 million decrease in deferrals of OVEC costs in Ohio. This decrease was offset in Retail Margins above and Other Revenues below.

•A $51 million decrease in Texas primarily due to the retirement of the Oklaunion Power Station in September 2020. This decrease was offset in Depreciation and Amortization expenses below.

These decreases were partially offset by:

•A $24 million increase in off-system sales at OVEC in Ohio due to higher market prices and volume. This increase was offset in Retail Margins above and Other Revenues below.

•Transmission Revenues increased $90 million primarily due to the following:

•An $80 million increase from interim rate increases driven by increased transmission investment in Texas.

•A $14 million increase in Texas due to a prior year one-time credit to transmission customers as a result of Tax Reform and the most recent base rate case. This increase was offset in Income Tax Expense below.

•Other Revenues decreased $93 million primarily due to the following:

•A $118 million decrease in securitization revenues primarily due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset in Depreciation and Amortization expenses and Interest Expense below.

This decrease was partially offset by:

•A $17 million increase in Ohio primarily due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins and Margins from Off-system Sales above.

Expenses and Other and Income Tax Expense changed between years as follows:

•Other Operation and Maintenance expenses decreased $2 million primarily due to the following:

•A $56 million decrease in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This decrease was offset in Retail Margins above.

•A $50 million decrease in energy efficiency/demand side management expenses in Ohio. This decrease was partially offset in Retail Margins above.

•A $41 million decrease in Texas due to the Oklaunion Power Station retirement in September 2020 and its sale to a nonaffiliated third-party in October 2020. This decrease was offset in Gross Margin above.

•A $30 million decrease in employee-related expenses primarily driven by the prior year impact of the voluntary retirement incentive program, severance expense and COVID-19 incentives provided to front line employees.

•A $23 million decrease in factored customer accounts receivable expenses in Ohio primarily due to lower bad debt expenses and a current year favorable adjustment to allowance for doubtful accounts.

These decreases were partially offset by:

•A $152 million net increase in transmission expenses, in Ohio due to a $115 million increase in recoverable PJM expenses and a $37 million increase in transmission formula rate true-up activity. This increase in recoverable PJM expenses was offset in Gross Margin.

•A $29 million increase in vegetation management expenses. This increase was offset in Retail Margins above.

•A $10 million increase in distribution related expenses.

•An $8 million increase in storm expenses.

•Depreciation and Amortization expenses decreased $61 million primarily due to the following:

•A $107 million decrease in securitization amortizations in Texas primarily related to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset in Other Revenues above.

This decrease were partially offset by:

•A $35 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.

•A $13 million increase in amortization of capitalized software in Ohio.

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•A $5 million increase in recoverable Gridsmart depreciation expenses in Ohio. This increase was offset in Retail Margins above.

•Taxes Other Than Income Taxes increased $54 million primarily due to property taxes driven by additional investments in transmission and distribution assets and higher tax rates.

•Interest Expense increased $12 million primarily due to higher long-term debt balances.

•Income Tax Expense increased $48 million primarily due to an increase in pretax book income and state tax expense, as well as a decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT was partially offset in Gross Margin above.

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AEP TRANSMISSION HOLDCO

(a)Other AEP Segments excludes Corporate and Other which is not considered a reportable segment.

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Summary of Investment in Transmission Assets for AEP Transmission Holdco

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2021 Compared to 2020

Reconciliation of Year Ended December 31, 2020 to Year Ended December 31, 2021

Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco

(in millions)

The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and nonaffiliates were as follows:

•Transmission Revenues increased $327 million primarily due to the following:

•A $263 million increase due to continued investment in transmission assets.

•A $45 million increase as a result of the affiliated annual transmission formula rate true-up which is offset in Other Operation and Maintenance expense across the other Registrant subsidiaries.

•A $16 million increase as a result of the nonaffiliated annual transmission formula rate true-up.

Expenses and Other, Income Tax Expense and Equity Earnings of Unconsolidated Subsidiary changed between years as follows:

•Other Operation and Maintenance expenses increased $13 million primarily due to the following:

•A $6 million increase in vegetation management expenses.

•A $3 million increase in affiliated rent expense.

•A $2 million increase in an accrual for NERC compliance costs.

•Depreciation and Amortization expenses increased $48 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $34 million primarily due to higher property taxes as a result of increased transmission investment.

•Allowance for Equity Funds Used During Construction decreased $7 million primarily due to lower CWIP.

•Interest Expense increased $13 million primarily due to higher long-term debt balances.

•Income Tax Expense increased $29 million primarily due to an increase in pretax book income partially offset by an increase in parent company loss benefit.

•Equity Earnings of Unconsolidated Subsidiary decreased $7 million primarily due to lower pretax equity earnings at PATH-WV and ETT.

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GENERATION & MARKETING

(a)Other AEP Segments excludes Corporate and Other which is not considered a reportable segment.

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2021 Compared to 2020

Reconciliation of Year Ended December 31, 2020 to Year Ended December 31, 2021

Earnings Attributable to AEP Common Shareholders from Generation & Marketing

(in millions)

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, purchased electricity and certain cost-of-service for retail operations were as follows:

•Merchant Generation decreased $12 million primarily due to increased outage days at Cardinal Plant, partially offset by higher market prices in PJM.

•Renewable Generation increased $9 million primarily due to new wind and solar projects placed in service.

•Retail, Trading and Marketing increased $38 million primarily due to higher mark-to-market economic hedge activity driven by higher commodity prices. This increase was partially offset by lower trading and retail margins due to unprecedented cold temperatures and record ERCOT market prices in February 2021.

Expenses and Other, Income Tax Benefit and Equity Earnings of Unconsolidated Subsidiaries changed between years as follows:

•Other Operation and Maintenance expenses decreased $27 million primarily due to the following:

•A $39 million decrease due to the gain on sale of certain merchant generation assets.

•A $10 million decrease due to the retirement of Conesville Plant Unit 4 in 2020.

•An $8 million decrease in employee-related expenses.

•A $5 million decrease due to the gain on sale of substations to Amazon.

•A $4 million decrease due to the retirement of Oklaunion Plant in 2020.

These decreases were partially offset by:

•A $26 million increase from lower gains recorded on the sale of land.

•A $17 million increase related to the Oklaunion PPA with AEP Texas primarily due to an ARO revision in 2020.

•Depreciation and Amortization expenses increased $8 million primarily due to a higher depreciable base from increased investments in renewable energy sources.

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•Interest Expense decreased $8 million primarily due to lower borrowing costs in 2021.

•Income Tax Benefit decreased $59 million primarily due to the recognition of a discrete tax adjustment in 2020 attributable to the CARES Act and an increase due to an out of period adjustment related to deferred taxes.

•Equity Earnings of Unconsolidated Subsidiaries decreased $14 million primarily due to lower revenues driven by lower wind production from jointly owned assets.

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CORPORATE AND OTHER

2021 Compared to 2020

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $90 million in 2020 to a loss of $64 million in 2021 primarily due to:

•A $57 million increase in Income Tax Benefit due to an out of period adjustment related to deferred taxes partially offset by an increase in state deferred taxes due to legislative changes for Oklahoma and West Virginia.

•A $21 million increase in equity earnings from unrealized investment gains.

•A $16 million decrease in interest expense.

These items were partially offset by:

•A $25 million decrease in interest income primarily due to lower interest income from affiliates.

•A $22 million decrease in gains relating to an investment in ChargePoint. In 2021, a $10 million gain was recorded, $5 million of which was unrealized.

•An $8 million increase in the EIS reserve.

•A $7 million increase in general corporate expenses.

•A $6 million increase in estimated health care benefits for certain retirees.

AEP SYSTEM INCOME TAXES

2021 Compared to 2020

•Income Tax Expense increased $75 million primarily due to the following:

•A $77 million increase due to an increase in pretax book income.

•A $48 million increase due to the recognition of a discrete tax adjustment in 2020 attributable to the CARES Act.

•A $25 million increase in state deferred taxes due to legislative changes for Oklahoma and West Virginia.

These increases were partially offset by:

•A $55 million decrease to tax expense due to an out of period adjustment related to deferred taxes.

•A $19 million increase in tax credits primarily related to PTC.

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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 Kentucky operations sale 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, 2021, the weighted-average interest rate applicable to each debt category and a schedule of debt maturities over the next five years.

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.

The AEP System has 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, 2021, AEP expected to make contributions to the pension plans totaling $134 million in 2022. Estimated contributions of $129 million in 2023 and $7 million in 2024 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 103.2% funded as of December 31, 2021. 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.

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LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization

AEP’s ratio of debt-to-total capital decreased from 61.8% to 61.4% as of December 31, 2020 and 2021, respectively, primarily due to an increase in earnings in 2021 as compared to 2020, partially offset by an increase in debt to support distribution, transmission and renewable investment growth.

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, 2021, 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. In February 2021, severe winter weather impacted certain AEP service territories resulting in disruptions to SPP market conditions. In March 2021, AEP entered into a $500 million 364-day Term Loan and borrowed the full amount to help address the cash flow implications resulting from the February 2021 severe winter weather event. See Note 4 - Rate Matters for additional information.

Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments.  As of December 31, 2021, available liquidity was approximately $4 billion as illustrated in the table below:

(a)AEP intends to extend the maturity of this loan to the third quarter of 2022.

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 2021 was $2.5 billion.  The weighted-average interest rate for AEP’s commercial paper during 2021 was 0.24%.

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Other Credit Facilities

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under five uncommitted facilities totaling, as of December 31, 2021, $375 million.  Subsequently, in February 2022, the uncommitted facilities total was increased to $400 million.  The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of December 31, 2021, was $169 million with maturities ranging from January 2022 to December 2022.

Financing Plan

As of December 31, 2021, AEP had $2.2 billion of long-term debt due within one year, excluding $200 million classified as Liabilities Held for Sale on the balance sheet. This also included $440 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 $117 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 $750 million from bank conduits to purchase receivables and was amended in September 2021 to include a $125 million and a $625 million facility, which expire in September 2023 and 2024, respectively. As of December 31, 2021, the affiliated utility subsidiaries are 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, 2021, this contractually-defined percentage was 58.2%. 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.

The revolving credit facility does 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 billion of its common stock, including shares of common stock that may be sold pursuant to an equity forward sales agreement. As of December 31, 2021, approximately $511 million 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

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amount of AEP’s 1.30% Junior Subordinated Notes due in 2025 and a forward equity purchase contract which settles after three years in 2023. The proceeds were used to support AEP’s overall capital expenditure plan.

In March 2019, AEP issued 16.1 million Equity Units initially in the form of corporate units, at a stated amount of $50 per unit, for a total stated amount of $805 million. Net proceeds from the issuance were approximately $785 million. Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 3.40% Junior Subordinated Notes due in 2024 and a forward equity purchase contract which settles after three years in 2022. The proceeds from this issuance were used to support AEP’s overall capital expenditure plans including the recent acquisition of Sempra Renewables LLC. In January 2022, AEP successfully remarketed the notes on behalf of holders of the corporate units and did not directly receive any proceeds therefrom. Instead, the holders of the corporate units may use the debt remarketing proceeds towards settling the forward equity purchase contract with AEP in March 2022. The interest rate on the notes was reset to 2.031% with the maturity remaining in 2024.

See Note 14 - Financing Activities for additional information.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.78 per-share in January 2022.  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.

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.

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Operating Activities

(a)Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Rockport Plant, Unit 2 Lease Amortization, Deferred Income Taxes, Asset Impairments and Other Related Charges, Allowance for Equity Funds Used During Construction, Amortization of Nuclear Fuel and Pension and Postemployment Benefit Reserves.

2021 Compared to 2020

Net Cash Flows from Operating Activities increased by $7 million primarily due to the following:

•A $745 million increase in cash from Changes in Certain Components of Working Capital. The increase is primarily due to a decrease in fuel, material and supplies balances driven by a decrease in coal and lignite inventory on hand, the timing of accounts payable and an income tax refund received in 2021 for taxes paid in 2014 under the NOL carryback provision for the CARES Act, partially offset by margin deposits paid to PJM.

•A $377 million increase in cash from Net Income, after non-cash adjustments. See Results of Operations for further detail.

•A $261 million increase in cash from Changes in Other Noncurrent Liabilities. The increase is primarily due to changes in regulatory liabilities driven by timing differences between collections from and refunds to customers under rate rider mechanisms. See Note 5 - Effects of Regulation for additional information.

•A $110 million increase in cash due to a discretionary contribution to the qualified pension plan in 2020. See Note 8 - Benefit Plans for additional information.

•A $99 million increase in cash from Changes in Regulatory Assets driven by timing differences between collections from customers and costs incurred under rate rider recovery mechanisms. See Note 5 - Effects of Regulation for additional information.

•A $46 million increase primarily due to collateral held against risk management contracts due to pricing movement in the commodities market.

These increases in cash were offset by:

•A $1.6 billion decrease in cash primarily due to increased fuel and purchased power expenses not yet recovered from customers. Approximately $1.1 billion of these expenses are attributable to retail customers and are recorded as deferred fuel regulatory assets. PSO and SWEPCo are working with their respective regulatory commissions to determine the recovery mechanisms, recovery periods as well as the appropriate carrying charges on the regulatory assets. See Note 4 - Rate Matters for additional information.

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Investing Activities

2021 Compared to 2020

Net Cash Flows Used for Investing Activities increased by $200 million primarily due to the following:

•A $767 million increase due to the acquisition of the Dry Lake Solar Project and the NCWF. See Note 7 - Acquisitions, Assets and Liabilities Held for Sale, Dispositions and Impairments for additional information.

This increase in cash used was partially offset by:

•A $587 million decrease in construction expenditures, primarily due to decreases in Transmission and Distribution Utilities of $342 million, AEP Transmission Holdco of $181 million and Generation & Marketing of $79 million.

Financing Activities

2021 Compared to 2020

Net Cash Flows from Financing Activities increased by $200 million primarily due to the following:

•An $860 million increase in issuances of long-term debt. See Note 14 - Financing Activities for additional information.

•A $494 million increase in short-term debt primarily due to decreased repayments of commercial paper. See Note 14 - Financing Activities for additional information.

•A $446 million increase in issuances of common stock primarily under AEP’s ATM offering program. See Note 14 - Financing Activities for additional information.

•A $100 million increase due to the redemption of noncontrolling interests in Desert Sky Wind Farm LLC and Trent Wind Farm LLC as well as the acquisition of an additional 10% interest in Santa Rita East in 2020. See Note 7 - Acquisitions, Assets and Liabilities Held for Sale, Dispositions and Impairments for additional information.

These increases in cash were partially offset by:

•A $1.6 billion decrease due to increased retirements of long-term debt. See Note 14 - Financing Activities for additional information.

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The following financing activities occurred during 2021:

AEP Common Stock:

•During 2021, AEP issued 7.6 million shares of common stock under the ATM offering program, incentive compensation, employee saving and dividend reinvestment plans and received net proceeds of $601 million.

Debt:

•During 2021, AEP issued approximately $6.5 billion of long-term debt, including $5 billion of senior unsecured notes at interest rates ranging from 1.625% to 3.45%, $750 million of junior subordinated debenture notes at an interest rate of 3.875%, $40 million of pollution control bonds at an interest rate of 0.75% and $743 million of other debt at various interest rates.  The proceeds from these issuances were primarily used to fund long-term debt maturities, construction programs and to help address working capital needs.

•During 2021, AEP entered into interest rate derivatives with notional amounts totaling $300 million that were designated as cash flow hedges.  During 2021, settlements of AEP’s interest rate derivatives resulted in net cash received of $17 million for derivatives designated as cash flow hedges.  As of December 31, 2021, AEP had a total notional amount of $950 million of outstanding interest rate derivatives designated as fair value 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, 2021 through February 24, 2022, the date that the 10-K was issued.

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BUDGETED CAPITAL EXPENDITURES

Management forecasts approximately $7.6 billion of capital expenditures in 2022.  For the four year period, 2023 through 2026, management forecasts capital expenditures of $30.7 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 and the ability to access capital.  Management expects to fund these capital expenditures through cash flows from operations, proceeds from the sale of Kentucky operations 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 2022 estimated capital expenditures include generation, transmission and distribution related investments, as well as expenditures for compliance with environmental regulations as follows:

(a)Amount primarily consists of facilities, software and telecommunications.

(b)Amount includes $66 million and $3 million of budgeted capital expenditures for KPCo and KTCo, respectively, which are expected to occur prior to the anticipated closing of the sale transaction in the second quarter of 2022. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.

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The table below represents estimated capital investments by business segment for the years 2023 to 2026:

The 2022 estimated capital expenditures by Registrant Subsidiary include distribution, transmission and generation-related investments, as well as expenditures for compliance with environmental regulations as follows:

(a) Amount primarily consists of facilities, software and telecommunications.

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CYBER SECURITY

The electric utility industry is an identified critical infrastructure function with mandatory cyber security requirements under the authority of FERC. The NERC, which FERC certified as the nation’s Electric Reliability Organization, developed mandatory critical infrastructure protection cyber security reliability standards. AEP’s service territory covers multiple NERC regions, and is audited at least annually by one or more of the regions. AEP began participating in the NERC grid security and emergency response exercises, GridEx, in 2013 and continues to participate in the bi-yearly exercises. These efforts, led by NERC, test and further develop the coordination, threat sharing and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid. AEP also conducts internal exercises to test and further develop AEP’s cyber response plans. These internal scenarios are chosen based on real world events and often include coordination with and communication to AEP’s Chief Executive Officer and executive team.

The operations of AEP’s electric utility subsidiaries are subject to extensive and rigorous mandatory cyber and physical security requirements that are developed and enforced by NERC to protect grid security and reliability. AEP’s Enterprise Security program includes cyber and physical security and uses the National Institute of Standards and Technology Cybersecurity Framework as a guideline. AEP’s Chief Security & Privacy Officer (CSPO) is also its NERC Critical Infrastructure Protection Senior Manager, ensuring alignment of compliance with the Enterprise Security program.

Critical cyber assets, such as data centers, power plants, transmission operations centers and business networks are protected using multiple layers of cyber security controls and authentication. Cyber hackers and other malicious actors have caused material disruption by successfully breaching a number of very secure facilities, including federal agencies, banks and retailers. As understanding of these events develop, AEP has adopted a defense in depth approach to cyber security and continually assesses its cyber security tools and processes to determine where to strengthen its defenses. These strategies include monitoring, alerting and emergency response, forensic analysis, disaster recovery, threat sharing and criminal activity reporting. This approach has allowed AEP to deal with cyber and related threats, intrusions and attempted breaches in real-time and to limit their impact to levels that would be expected in the ordinary course of business in the absence of such malicious activity.

AEP has undertaken a variety of actions to monitor and address cyber-related risks. Cyber security and the effectiveness of AEP’s cyber security processes are reviewed annually with the Board of Directors and at several meetings throughout the year with the committees of the Board that exercise oversight with respect to these matters, including the Audit Committee and the Technology Committee. AEP’s Chief Executive Officer and executive team participate in interactive threat briefings from AEP’s CSPO and security leadership team on a monthly basis. AEP’s strategy and procedure for managing cyber-related risks is integrated within its enterprise risk management processes. These procedures are designed to include that any material information regarding potentially relevant cyber incidents are elevated both to the appropriate leadership in a timely manner as well as, where applicable, our external financial reporting and disclosure team. AEP enterprise security continually adjusts staff and resources in response to the evolving threat landscape, and while such costs are material, they have remained stable and that pattern is expected to continue. In addition, AEP maintains cyber liability insurance to cover certain damages caused by cyber incidents.

AEP’s CSPO leads the cyber security and physical security teams and is responsible for the design, implementation and execution of AEP’s security risk management strategy, which includes cyber security. AEP’s cyber security team operates a 24/7 Cyber Security Intelligence and Response Center responsible for monitoring the AEP System for cyber risks and threats. The cyber security team constantly scans the AEP System for risks and threats. In addition, under the direction of the CSPO, the cyber security team actively monitors best practices, performs penetration testing, leads response exercises and internal campaigns and provides training and communication across the organization. AEP’s security awareness training is mandatory for all employees, and includes monthly phish email testing to train employees to identify malicious emails that could put AEP at risk.

AEP also continually reviews its business continuity plan to develop an effective recovery strategy that seeks to decrease response times, limit financial impacts and maintain customer confidence during any business interruption. The cyber security team administers a third-party risk governance program that identifies potential risks introduced

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through third-party relationships, such as vendors, software and hardware manufacturers or professional service providers. As warranted, AEP obtains certain contractual security guarantees and assurances with these third-party relationships to help ensure the security and safety of its information. The cyber security team works closely with a broad range of departments, including legal, regulatory, corporate communications, audit services, information technology and operational technology functions critical to the power grid.

The cyber security team collaborates with partners from both industry and government, and routinely participates in industry-wide programs that exchange knowledge of threats with utility peers, industry and federal agencies. AEP is an active member of a number of industry specific threat and information sharing communities including the Department of Homeland Security and the Electricity Information Sharing and Analysis Center. AEP continues to work with nonaffiliated entities to do penetration testing and to design and implement appropriate remediation strategies. There can be no assurance, however, that these efforts will be effective to prevent interruption of services or other damages to AEP's business or operations in connection with any cyber-related incident.

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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.

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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.

Accrued unbilled revenues for the Vertically Integrated Utilities segment were $246 million and $288 million as of December 31, 2021 and 2020, respectively. The changes in unbilled electric utility revenues for AEP’s Vertically Integrated Utilities segment were $(42) million, $40 million and $(7) million for the years ended December 31, 2021, 2020 and 2019, 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 $172 million and $171 million as of December 31, 2021 and 2020, respectively. The changes in unbilled electric utility revenues for AEP’s Transmission and Distribution Utilities segment were $1 million, $5 million and $(12) million for the years ended December 31, 2021, 2020 and 2019, 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 $110 million and $86 million as of December 31, 2021 and 2020, respectively. The changes in unbilled electric utility revenues for AEP’s Generation & Marketing segment were $24 million, $11 million and $16 million for the years ended December 31, 2021, 2020 and 2019, 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 KWh and estimated line losses, plus the prior month’s unbilled KWh. 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 KWh 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 KWh. 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 KWh and estimated line losses, plus the prior month’s unbilled KWh. 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.

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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.

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.

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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 carrying amount of the asset is not recoverable, 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 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.  Fluctuations 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.

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Pension and OPEB

AEP 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).  AEP 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:

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 2022, 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 5.25% for the Qualified Plan and 5.5% 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:

Management regularly reviews the actual asset allocation and periodically rebalances the investments to the targeted allocation.  Management believes that 5.25% for the Qualified Plan and 5.5% 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 5.41% and 16.91% for the years ended December 31, 2021 and 2020, respectively.  The OPEB plans’ assets had an actual gain of 8.67% and 16.33% for the years ended December 31, 2021 and 2020, 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.

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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, 2021, AEP had cumulative gains of approximately $389 million for the Qualified Plan that remain to be recognized in the calculation of the market-related value of assets.  These unrecognized 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, 2021 under this method was 2.9% for the Qualified Plan, 2.75% for the Nonqualified Plans and 2.9% for the OPEB plans.  Due to the effect of the unrecognized net actuarial losses and based on an expected rate of return on the Pension Plans’ assets of 5.25%, discount rates of 2.9% and 2.75% and various other assumptions, management estimates that the pension costs for the Pension Plans will approximate $85 million, $64 million and $34 million in 2022, 2023 and 2024, respectively.  Based on an expected rate of return on the OPEB plans’ assets of 5.5%, a discount rate of 2.9% and various other assumptions, management estimates OPEB plan credits will approximate $145 million, $138 million and $90 million in 2022, 2023 and 2024, 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 decreased to $5.4 billion as of December 31, 2021 from $5.6 billion as of December 31, 2020 primarily due to lower investment returns than benefit payments made in 2021.  During 2021, the Qualified Plan paid $443 million and the Nonqualified Plans paid $7 million in benefits to plan participants.  The value of AEP’s OPEB plans’ assets increased to $2.0 billion as of December 31, 2021 from $1.9 billion as of December 31, 2020 primarily due to higher investment returns than benefit payments made in 2021.  The OPEB plans paid $126 million in benefits to plan participants during 2021.

Nature of Estimates Required

AEP 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 include the following key factors:

•Discount rate

•Compensation increase rate

•Cash balance crediting rate

•Health care cost trend rate

•Expected return on plan assets

Other assumptions, such as retirement, mortality and turnover, are evaluated periodically and updated to reflect actual experience.

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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:

NA    Not applicable.

SIGNIFICANT TAX LEGISLATION

In March 2021, the American Rescue Plan Act of 2021 (the “American Rescue Plan”) was signed into law. The American Rescue Plan was a COVID-19 relief package that addressed a variety of topics, including the non-deductibility of certain executive compensation. Specifically, the American Rescue Plan changes the officers subject to IRS Section 162(m) from the CEO, CFO, and three top paid officers to the CEO, CFO, and eight top paid officers beginning in 2027.

IRS Notice 2021-41 was issued on June 29, 2021 by the IRS providing further extension of the continuity safe harbor for PTC and ITC-eligible projects and revising the facts and circumstances rules. For PTC and ITC-eligible projects for which construction began in calendar years 2016 through 2019, the continuity safe harbor was extended to six years. Prior guidance (Notice 2020-41) had only extended the safe harbor for projects beginning in 2016 and 2017 to 5 years. Furthermore, for PTC and ITC-eligible projects for which construction began in 2020, the continuity safe harbor was extended to five years. Under a facts and circumstances analysis, the continuity requirement may be satisfied under either the continuous construction test or the continuous efforts test, regardless of whether the physical work test or the five percent safe harbor is applied.

ACCOUNTING STANDARDS

See Note 2 - New Accounting Standards for information related to accounting standards. There are no new standards expected to have a material impact to the Registrants’ financial statements.

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