EDGAR 10-K Filing

Company CIK: 1721781
Filing Year: 2022
Filename: 1721781_10-K_2022_0000004904-22-000024.json

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ITEM 1. BUSINESS
ITEM 1. BUSINESS
GENERAL
Overview and Description of Major Subsidiaries
AEP was incorporated under the laws of the State of New York in 1906 and reorganized in 1925. It is a public utility holding company that owns, directly or indirectly, all of the outstanding common stock of its public utility subsidiaries and varying percentages of other subsidiaries.
The service areas of AEP’s public utility subsidiaries cover portions of the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. Transmission networks are interconnected with extensive distribution facilities in the territories served. The public utility subsidiaries of AEP have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers. Restructuring laws in Michigan, Ohio and the ERCOT area of Texas have caused AEP public utility subsidiaries in those states to unbundle previously integrated regulated rates for their retail customers.
The member companies of the AEP System have contractual, financial and other business relationships with the other member companies, such as participation in the AEP System savings and retirement plans and tax returns, sales of electricity and transportation and handling of fuel. The companies of the AEP System also obtain certain accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost from a common provider, AEPSC.
As of December 31, 2021, the subsidiaries of AEP had a total of 16,688 employees. Because it is a holding company rather than an operating company, AEP has no employees. The material subsidiaries of AEP are as follows:
AEP Texas
Organized in Delaware in 1925, AEP Texas is engaged in the transmission and distribution of electric power to approximately 1,082,000 retail customers through REPs in west, central and southern Texas. As of December 31, 2021, AEP Texas had 1,575 employees. Among the principal industries served by AEP Texas are petroleum and coal products manufacturing, chemical manufacturing, oil and gas extraction, pipeline transportation and support activities for mining. The territory served by AEP Texas also includes several military installations. AEP Texas is a member of ERCOT. AEP Texas is part of AEP’s Transmission and Distribution Utilities segment.
AEPTCo
Organized in Delaware in 2006, AEPTCo is a holding company for the State Transcos. The State Transcos develop and own new transmission assets that are physically connected to the AEP System. Individual State Transcos (a) have obtained the approvals necessary to operate in Indiana, Kentucky, Michigan, Ohio, Oklahoma and West Virginia, subject to any applicable siting requirements, (b) are authorized to submit projects for commission approval in Virginia and (c) have been granted consent to enter into a joint license agreement that will support investment in Tennessee. Neither AEPTCo nor its subsidiaries have any employees. Instead, AEPSC and certain AEP utility subsidiaries provide services to these entities. AEPTCo is part of the AEP Transmission Holdco segment.
APCo
Organized in Virginia in 1926, APCo is engaged in the generation, transmission and distribution of electric power to approximately 966,000 retail customers in the southwestern portion of Virginia and southern West Virginia, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. APCo owns 6,681 MWs of generating capacity. APCo uses its generation to serve its retail and other customers. As of December 31, 2021, APCo had 1,617 employees. Among the principal industries served by APCo are coal-mining, primary metals, pipeline transportation, chemical manufacturing and paper manufacturing. APCo is a member of PJM. APCo is part of AEP’s Vertically Integrated Utilities segment.
I&M
Organized in Indiana in 1907, I&M is engaged in the generation, transmission and distribution of electric power to approximately 607,000 retail customers in northern and eastern Indiana and southwestern Michigan, and in supplying and marketing electric power at wholesale to other electric utility companies, rural electric cooperatives, municipalities and other market participants. I&M owns or leases 3,662 MWs of generating capacity, which it uses to serve its retail and other customers. As of December 31, 2021, I&M had 1,978 employees. Among the principal industries served are primary metals, transportation equipment, chemical manufacturing, plastics and rubber products and fabricated metal product manufacturing. I&M is a member of PJM. I&M is part of AEP’s Vertically Integrated Utilities segment.
KPCo
Organized in Kentucky in 1919, KPCo is engaged in the generation, transmission and distribution of electric power to approximately 165,000 retail customers in eastern Kentucky, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. KPCo owns 1,075 MWs of generating capacity. KPCo uses its generation to serve its retail and other customers. As of December 31, 2021, KPCo had 433 employees. Among the principal industries served are petroleum and coal products manufacturing, chemical manufacturing, coal-mining, oil and gas extraction and pipeline transportation. KPCo is a member of PJM. KPCo is part of AEP’s Vertically Integrated Utilities segment. In October 2021, AEP entered into a Stock Purchase Agreement to sell KPCo to Liberty Utilities Co. Subject to satisfying closing conditions and obtaining regulatory approvals, the sale is expected to close in the second quarter of 2022. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
KGPCo
Organized in Virginia in 1917, KGPCo provides electric service to approximately 49,000 retail customers in Kingsport and eight neighboring communities in northeastern Tennessee. KGPCo does not own any generating facilities and is a member of PJM. It purchases electric power from APCo for distribution to its customers. As of December 31, 2021, KGPCo had 54 employees. KGPCo is part of AEP’s Vertically Integrated Utilities segment.
OPCo
Organized in Ohio in 1907 and re-incorporated in 1924, OPCo is engaged in the transmission and distribution of electric power to approximately 1,515,000 retail customers in Ohio. OPCo purchases energy and capacity at auction to serve generation service customers who have not switched to a competitive generation supplier. As of December 31, 2021, OPCo had 1,694 employees. Among the principal industries served by OPCo are primary metals, petroleum and coal products manufacturing, plastics and rubber products, chemical manufacturing, pipeline transportation and data centers. OPCo is a member of PJM. OPCo is part of AEP’s Transmission and Distribution Utilities segment.
PSO
Organized in Oklahoma in 1913, PSO is engaged in the generation, transmission and distribution of electric power to approximately 570,000 retail customers in eastern and southwestern Oklahoma, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. PSO owns 3,931 MWs of generating capacity, which it uses to serve its retail and other customers. As of December 31, 2021, PSO had 1,018 employees. Among the principal industries served by PSO are paper manufacturing, oil and gas extraction, petroleum and coal products manufacturing, plastics and rubber products and pipeline transportation. PSO is a member of SPP. PSO is part of AEP’s Vertically Integrated Utilities segment.
SWEPCo
Organized in Delaware in 1912, SWEPCo is engaged in the generation, transmission and distribution of electric power to approximately 548,000 retail customers in northeastern and panhandle of Texas, northwestern Louisiana and western Arkansas and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. SWEPCo owns 5,040 MWs of generating capacity, which it uses to serve its retail and other customers. As of December 31, 2021, SWEPCo had 1,369 employees. Among the principal industries served by SWEPCo are petroleum and coal products manufacturing, food manufacturing, paper manufacturing, oil and gas extraction and chemical manufacturing. The territory served by SWEPCo includes several military installations, colleges and universities. SWEPCo also owns and operates a lignite coal-mining operation. SWEPCo is a member of SPP. SWEPCo is part of AEP’s Vertically Integrated Utilities segment.
WPCo
Organized in West Virginia in 1883 and re-incorporated in 1911, WPCo provides electric service to approximately 42,000 retail customers in northern West Virginia and in supplying and marketing electric power at wholesale to other market participants. WPCo owns 780 MWs of generating capacity which it uses to serve its retail and other customers. As of December 31, 2021, WPCo had 45 employees. Among the principal industries served by WPCo are coal-mining, primary metals, pipeline transportation, chemical manufacturing and paper manufacturing. WPCo is a member of PJM. WPCo is part of AEP’s Vertically Integrated Utilities segment.
Service Company Subsidiary
AEPSC is a service company subsidiary that provides accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost to AEP subsidiaries. The executive officers of AEP and certain of the executive officers of its public utility subsidiaries are employees of AEPSC. As of December 31, 2021, AEPSC had 6,364 employees.
Public Utility Subsidiaries by Jurisdiction
The following table illustrates certain regulatory information with respect to the jurisdictions in which the public utility subsidiaries of AEP operate:
Principal Jurisdiction AEP Utility Subsidiaries Operating in that Jurisdiction Authorized Return on Equity (a)
FERC AEPTCo - PJM 10.35%
AEPTCo - SPP 10.50%
Ohio OPCo 9.70%
West Virginia APCo 9.75%
WPCo 9.75%
Virginia APCo 9.20%
Indiana I&M 9.70%
Michigan I&M 9.86%
Texas AEP Texas 9.40%
SWEPCo 9.25% (b)
Tennessee KGPCo 9.85%
Kentucky KPCo 9.30% (c)
Louisiana SWEPCo 9.80%
Arkansas SWEPCo 9.45%
Oklahoma PSO 9.40%
(a)Identifies the predominant current authorized ROE, and may not include other, less significant, permitted recovery. Actual ROE varies from authorized ROE.
(b)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.
(c)Final order received and made effective in January 2021 that approved an authorized ROE of 9.30%. The authorized ROE for riders with an approved equity return (Decommissioning Rider and the Environmental Surcharge) is 9.10%.
(a)Pretax income does not include intercompany eliminations.
CLASSES OF SERVICE
The principal classes of service from which AEP’s subsidiaries derive revenues and the amount of such revenues during the years ended December 31, 2021, 2020 and 2019 are as follows:
Years Ended December 31,
Description 2021 2020 2019
(in millions)
Vertically Integrated Utilities Segment
Retail Revenues
Residential Sales $ 3,952.2 $ 3,614.8 $ 3,641.2
Commercial Sales 2,208.6 2,021.0 2,151.1
Industrial Sales 2,169.2 2,023.5 2,178.3
Other Retail Sales 170.0 155.8 179.2
Total Retail Revenues 8,500.0 7,815.1 8,149.8
Wholesale Revenues
Off-system Sales 949.7 589.3 814.5
Transmission 239.0 249.5 200.7
Total Wholesale Revenues 1,188.7 838.8 1,015.2
Other Electric Revenues 138.4 85.8 93.8
Provision for Rate Refund (3.1) (21.7) (44.7)
Other Operating Revenues 28.3 35.2 31.6
Sales to Affiliates 146.2 126.2 121.4
Total Revenues Vertically Integrated Utilities Segment $ 9,998.5 $ 8,879.4 $ 9,367.1
Transmission and Distribution Utilities Segment
Retail Revenues
Residential Sales $ 2,136.7 $ 2,114.9 $ 2,084.5
Commercial Sales 1,083.4 1,049.5 1,148.8
Industrial Sales 397.8 390.0 426.5
Other Retail Sales 44.0 42.5 43.7
Total Retail Revenues 3,661.9 3,596.9 3,703.5
Wholesale Revenues
Off-system Sales 100.8 60.6 93.0
Transmission 574.5 471.8 437.7
Total Wholesale Revenues 675.3 532.4 530.7
Other Electric Revenues 112.9 95.0 58.6
Provision for Rate Refund - 2.3 12.5
Other Operating Revenues 14.0 12.1 13.7
Sales to Affiliates 28.8 107.2 163.5
Total Revenues Transmission and Distribution Utilities Segment $ 4,492.9 $ 4,345.9 $ 4,482.5
AEP Transmission Holdco Segment
Transmission Revenues $ 358.7 $ 315.5 $ 265.4
Other Operating Revenues 0.4 0.6 0.1
Sales to Affiliates 1,175.1 901.4 812.9
Provision for Rate Refund (8.0) (18.7) (5.2)
Total Revenues AEP Transmission Holdco Segment $ 1,526.2 $ 1,198.8 $ 1,073.2
Generation & Marketing Segment
Generation Revenues - Nonaffiliated $ 146.5 $ 136.4 $ 264.4
Renewable Generation - Nonaffiliated 110.8 85.7 77.7
Retail, Trading and Marketing
Affiliated 55.4 104.6 135.7
Nonaffiliated 1,851.0 1,398.9 1,379.8
Total Revenues Generation & Marketing Segment $ 2,163.7 $ 1,725.6 $ 1,857.6
AEP Texas
Years Ended December 31,
Description 2021 2020 2019
(in millions)
Retail Revenues
Residential Sales $ 550.3 $ 562.3 $ 588.9
Commercial Sales 358.5 365.9 424.0
Industrial Sales 108.9 119.9 133.3
Other Retail Sales 31.3 29.4 30.8
Total Retail Revenues 1,049.0 1,077.5 1,177.0
Wholesale Revenues
Transmission 497.5 399.9 379.2
Other Electric Revenues 39.9 45.2 24.4
Provision for Rate Refund - 2.3 (34.7)
Total Electric Transmission and Distribution Revenues 1,586.4 1,524.9 1,545.9
Sales to Affiliates 3.9 90.8 160.5
Other Revenues 3.5 3.2 2.9
Total Revenues $ 1,593.8 $ 1,618.9 $ 1,709.3
AEPTCo
Years Ended December 31,
Description 2021 2020 2019
(in millions)
Transmission Revenues $ 317.5 $ 264.8 $ 217.5
Other Operating Revenues 0.3 0.6 0.1
Sales to Affiliates 1,153.9 896.3 806.7
Provision for Rate Refund (2.4) (16.0) (2.9)
Total Revenues $ 1,469.3 $ 1,145.7 $ 1,021.4
APCo
Years Ended December 31,
Description 2021 2020 2019
(in millions)
Retail Revenues
Residential Sales $ 1,379.7 $ 1,250.4 $ 1,272.3
Commercial Sales 556.3 517.0 562.2
Industrial Sales 584.8 553.3 594.5
Other Retail Sales 69.9 67.3 75.4
Total Retail Revenues 2,590.7 2,388.0 2,504.4
Wholesale Revenues
Off-system Sales 178.1 118.1 124.9
Transmission 75.2 71.0 57.0
Total Wholesale Revenues 253.3 189.1 181.9
Other Electric Revenues 51.5 34.0 32.3
Provision for Rate Refund - (0.2) (10.4)
Total Electric Generation, Transmission and Distribution Revenues 2,895.5 2,610.9 2,708.2
Sales to Affiliates 197.9 174.7 205.3
Other Revenues 11.8 10.6 11.2
Total Revenues $ 3,105.2 $ 2,796.2 $ 2,924.7
I&M
Years Ended December 31,
Description 2021 2020 2019
(in millions)
Retail Revenues
Residential Sales $ 811.4 $ 794.1 $ 730.9
Commercial Sales 511.0 499.4 494.9
Industrial Sales 561.2 547.5 551.4
Other Retail Sales 5.6 6.8 7.4
Total Retail Revenues 1,889.2 1,847.8 1,784.6
Wholesale Revenues
Off-system Sales 321.0 275.4 406.4
Transmission 29.0 31.0 19.3
Total Wholesale Revenues 350.0 306.4 425.7
Other Electric Revenues 35.8 11.3 14.4
Provision for Rate Refund (13.8) (0.2) (2.6)
Total Electric Generation, Transmission and Distribution Revenues 2,261.2 2,165.3 2,222.1
Sales to Affiliates 57.8 71.3 73.9
Other Revenues 7.7 5.2 10.7
Total Revenues $ 2,326.7 $ 2,241.8 $ 2,306.7
OPCo
Years Ended December 31,
Description 2021 2020 2019
(in millions)
Retail Revenues
Residential Sales $ 1,586.5 $ 1,552.6 $ 1,495.6
Commercial Sales 724.9 683.5 724.9
Industrial Sales 288.9 270.1 293.2
Other Retail Sales 12.6 13.1 12.9
Total Retail Revenues 2,612.9 2,519.3 2,526.6
Wholesale Revenues
Off-system Sales 100.8 60.6 93.0
Transmission 77.0 68.8 58.5
Total Wholesale Revenues 177.8 129.4 151.5
Other Electric Revenues 73.0 49.9 34.2
Provision for Rate Refund - - 47.2
Total Electricity, Transmission and Distribution Revenues 2,863.7 2,698.6 2,759.5
Sales to Affiliates 24.8 41.5 27.3
Other Revenues 10.6 9.0 10.8
Total Revenues $ 2,899.1 $ 2,749.1 $ 2,797.6
PSO
Years Ended December 31,
Description 2021 2020 2019
(in millions)
Retail Revenues
Residential Sales $ 651.2 $ 579.8 $ 636.1
Commercial Sales 378.3 320.4 377.3
Industrial Sales 273.9 221.2 296.5
Other Retail Sales 77.6 66.0 80.7
Total Retail Revenues 1,381.0 1,187.4 1,390.6
Wholesale Revenues
Off-system Sales 22.9 15.1 39.5
Transmission 39.2 35.3 31.9
Total Wholesale Revenues 62.1 50.4 71.4
Other Electric Revenues 22.2 10.4 9.6
Provision for Rate Refund - (2.1) (2.0)
Total Electric Generation, Transmission and Distribution Revenues 1,465.3 1,246.1 1,469.6
Sales to Affiliates 4.2 5.2 6.1
Other Revenues 4.9 14.8 6.1
Total Revenues $ 1,474.4 $ 1,266.1 $ 1,481.8
SWEPCo
Years Ended December 31,
Description 2021 2020 2019
(in millions)
Retail Revenues
Residential Sales $ 704.9 $ 637.4 $ 645.3
Commercial Sales 525.8 471.5 490.6
Industrial Sales 341.9 332.1 342.3
Other Retail Sales 10.0 9.1 9.1
Total Retail Revenues 1,582.6 1,450.1 1,487.3
Wholesale Revenues
Off-system Sales 386.6 162.0 194.7
Transmission 88.7 87.0 72.6
Total Wholesale Revenues 475.3 249.0 267.3
Other Electric Revenues 20.2 16.5 20.6
Provision for Rate Refund 10.8 (19.0) (30.6)
Total Electric Generation, Transmission and Distribution Revenues 2,088.9 1,696.6 1,744.6
Sales to Affiliates 41.0 39.0 4.9
Other Revenues 1.9 2.9 1.4
Total Revenues $ 2,131.8 $ 1,738.5 $ 1,750.9
FINANCING
General
Companies within the AEP System generally use short-term debt to finance working capital needs. Short-term debt may also be used to finance acquisitions, construction and redemption or repurchase of outstanding securities until such needs can be financed with long-term debt. In recent history, short-term funding needs have been provided for by cash on hand and AEP’s commercial paper program. Funds are made available to subsidiaries under the AEP corporate borrowing program. Certain public utility subsidiaries of AEP also sell accounts receivable to provide liquidity. See “Financial Condition” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2021 Annual Report for additional information.
AEP’s revolving credit agreement (which backstops the commercial paper program) includes covenants and events of default typical for this type of facility, including a maximum debt/capital test. In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of its 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 the credit agreement. As of December 31, 2021, AEP was in compliance with its debt covenants. With the exception of a voluntary bankruptcy or insolvency, any event of default has either or both a cure period or notice requirement before termination of the agreement. A voluntary bankruptcy or insolvency of AEP or one of its significant subsidiaries would be considered an immediate termination event. See “Financial Condition” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2021 Annual Report for additional information.
AEP’s subsidiaries have also utilized, and expect to continue to utilize, additional financing arrangements, such as securitization financings and leasing arrangements, including the leasing of coal transportation equipment and facilities.
ENVIRONMENTAL AND OTHER MATTERS
General
AEP subsidiaries are currently subject to regulation by federal, state and local authorities with regard to air and water-quality control and other environmental matters, and are subject to zoning and other regulation by local
authorities. The environmental issues that management believes are potentially material to the AEP System are outlined below.
Clean Water Act Requirements
Operations for AEP subsidiaries are subject to the CWA, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits and regulates systems that withdraw surface water for use in power plants. In 2014, the Federal EPA issued a final rule setting forth standards for water withdrawals at existing power plants that is intended to reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water. The standards affect all plants withdrawing more than two million gallons of cooling water per day. A schedule for compliance with the standard is established by the permit agency and incorporated in NPDES permits.
In November 2015, the Federal EPA issued a final rule revising ELG for electricity generating facilities. The rule established limits on FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater to be imposed in NPDES permits as soon as possible after November 2018 and no later than December 2023. The Federal EPA further revised the rule in August 2020 for FGD wastewater and bottom ash transport water extending the compliance date to December 2025 and establishing additional options.
In January 2020, the Federal EPA issued a final rule revising the scope of the “waters of the United States” subject to CWA regulation. In August 2021, this rule was vacated by a federal court and shortly thereafter, 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. See “Environmental Issues - Clean Water Act Regulations” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2021 Annual Report for additional information.
Coal Ash Regulation
AEP’s operations produce a number of different coal combustion by-products, including fly ash, bottom ash, gypsum and other materials. A rule by the Federal EPA regulates the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at coal-fired electric generating units. The rule requires certain standards for location, groundwater monitoring and dam stability to be met at landfills and certain surface impoundments at operating facilities. If existing disposal facilities cannot meet these standards, they will be required to close. 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 for seeking an extension of that date. AEP filed extension requests for seven facilities, but as of December 31, 2021, the Federal EPA had not acted upon any of those requests. See “Environmental Issues - Coal Combustion Residual (CCR) Rule” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2021 Annual Report for additional information.
Clean Air Act Requirements
The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control mobile and stationary sources of air emissions. The major CAA programs affecting AEP’s power plants are described below. The states implement and administer many of these programs and could impose additional or more stringent requirements.
The Acid Rain Program
The CAA includes a cap-and-trade emission reduction program for SO2 emissions from power plants and requirements for power plants to reduce NOx emissions through the use of available combustion controls, collectively called the Acid Rain Program. AEP continues to meet its obligations under the Acid Rain Program through the installation of controls, use of alternate fuels and participation in the emissions allowance markets.
National Ambient Air Quality Standards
The CAA requires the Federal EPA to review the available scientific data for criteria pollutants periodically and establish a concentration level in the ambient air for those substances that is adequate to protect the public health and welfare with an extra safety margin. The Federal EPA also can list additional pollutants and develop concentration levels for them. These concentration levels are known as NAAQS.
Each state identifies the areas within its boundaries that meet the NAAQS (attainment areas) and those that do not (non-attainment areas). Each state must develop a SIP to bring non-attainment areas into compliance with the NAAQS and maintain good air quality in attainment areas. All SIPs are submitted to the Federal EPA for approval. If a state fails to develop adequate plans, the Federal EPA develops and implements a plan. As the Federal EPA reviews the NAAQS and establishes new concentration levels, the attainment status of areas can change and states may be required to develop new SIPs. See “Environmental Issues - Clean Air Act Requirements” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2021 Annual Report for additional information.
Hazardous Air Pollutants (HAP)
The CAA also requires the Federal EPA to investigate HAP emissions from the electric utility sector and submit a report to Congress to determine whether those emissions should be regulated. In 2011, the Federal EPA issued a rule setting Maximum Achievable Control Technology standards for new and existing coal and oil-fired utility units and New Source Performance Standards for emissions from new and modified power plants. In 2014, the U.S. Supreme Court determined that the Federal EPA acted unreasonably in refusing to consider costs in determining if it was appropriate and necessary to regulate HAP emissions from electric generating units. The Federal EPA has engaged in additional rulemaking activity but the 2011 rule remains in effect.
Regional Haze
The CAA establishes visibility goals for certain federally designated areas, including national parks, and requires states to submit SIPs that will demonstrate reasonable progress toward preventing impairment of visibility in these protected areas. In 2005, the Federal EPA issued its Clean Air Visibility Rule, detailing how the CAA’s best available retrofit technology requirements will be applied to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants.
Climate Change
AEP has taken action to reduce and offset CO2 emissions from its generating fleet and expects CO2 emissions from its operations to continue to decline due to the retirement of coal-fired generation units, and actions taken to diversify the generation fleet and increase energy efficiency where there is regulatory support for such activities. In 2021, AEP announced revised intermediate and long-term CO2 emission reduction goals, based on the Company’s March 2021 climate impact analysis report. 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 51 million metric tons, a 70% reduction from AEP’s 2000 CO2 emissions. The Company continues to work toward these goals through its integrated resource planning processes, which take into account economics, customer demand, regulations, grid reliability and resiliency.
To date, the Federal EPA has twice taken action to regulate CO2 emissions from new and existing fossil fueled electric generating units under the existing provisions of the CAA. The Clean Power Plan was adopted in October 2015 but the U.S. Supreme Court issued a stay of its implementation, including all of the deadlines for submission of initial or final state plans. The Clean Power Plan was repealed by the Federal EPA in 2019 and replaced by the Affordable Clean Energy (ACE) Rule, which changed the Federal EPA’s approach to regulating CO2 emissions from existing coal-fired generating units. In January 2021, the ACE Rule was vacated by the U.S. Court of Appeals
for the District of Columbia Circuit (D.C. Circuit Court) and remanded to the Federal EPA for further proceedings. In October 2021, the U. S. Supreme Court granted certiorari and combined four separate petitions seeking review of the D.C. Circuit Court decision. Briefing is underway but management is unable to predict the outcome of that litigation. It is similarly too soon to predict how the Federal EPA will respond to the court’s remand. Management expects emissions to continue to decline over time as AEP diversifies generating sources and operates fewer coal units. The projected decline in coal-fired generation is due to a number of factors, including the ongoing cost of operating older units, the relative cost of coal and natural gas as fuel sources, increasing environmental regulations requiring significant capital investments and changing commodity market fundamentals.
Transforming AEP’s Generation Fleet
The electric utility industry is in the midst of an historic transformation, driven by changing customer needs, evolving public policies, stakeholder demands, demographics, competitive offerings, technologies and commodity prices. AEP is also transforming to be more agile and customer-focused as a valued provider of energy solutions. AEP’s long-term commitment to reduce CO2 emissions reflects the current direction of the company’s resource plans to meet those needs. AEP set new goals in 2021 to reduce carbon emissions by 80% by 2030 (from a 2000 baseline) and to achieve net zero carbon emissions by 2050. These goals are supported by a climate impact analysis report published in 2021. AEP’s exposure to carbon regulation has been greatly reduced over the last several years. From 2000 to 2021, AEP’s CO2 emissions declined 70%. In 2021, coal represented 42% of AEP’s generating capacity compared with 70% in 2005. Transforming AEP’s generation portfolio to include, where there is regulatory support, more renewable energy and focusing on the efficient use of energy, demand response, distributed resources and technology solutions to more efficiently manage the grid over time is part of this strategy.
The graph below summarizes AEP’s generation capacity by resource type for the years 1999, 2005 and 2021:
(a) Energy Efficiency/Demand Response represents avoided capacity rather than physical assets.
Renewable Sources of Energy
The states AEP serves, other than Kentucky, Oklahoma, West Virginia and Tennessee, have established mandatory or voluntary programs to increase the use of energy efficiency, alternative energy or renewable energy sources.
As of December 31, 2021, AEP’s regulated utilities had long-term contracts for 2,750 MWs of wind, 80 MWs of hydro, and 30 MWs of solar power delivering renewable energy to the companies’ customers. In addition, I&M owns four solar projects that make up I&M’s 15 MW Clean Energy Solar Pilot Project, and its 20 MW St. Joseph solar facility went into operation in 2021. Management actively manages AEP’s compliance position and is on pace to meet the relevant requirements or benchmarks in each applicable jurisdiction.
As of December 31, 2021, APCo has executed solar PPAs totaling 55 MWs either not eligible for or subject to regulatory pre-approval, of which 20 MWs are in operation. In 2021, APCo also executed solar PPAs for an additional 89 MWs, subject to regulatory approval including cost recovery. During the year, APCo also entered into agreements to purchase three solar facilities totaling 205 MWs and an agreement to purchase a 204 MW wind project, subject to regulatory approval including cost recovery. If approved, these projects are all expected to be online by late 2024 or early 2025.
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. The 199 MW Sundance wind facility was acquired and placed in service in April 2021 and the 287 MW Maverick wind facility was acquired and placed in service in September 2021. The 998 MW Traverse wind facility is targeted to be acquired and placed in service in the first quarter of 2022.
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. In addition to gradually reducing AEP’s reliance on coal-fueled generating units, the growth of renewables and natural gas helps AEP to maintain a diversity of generation resources.
The integrated resource plans submitted to state regulatory commissions by AEP’s regulated utility subsidiaries reflect AEP’s renewable strategy to balance reliability and cost with customers’ desire for clean energy in a carbon-constrained world. AEP has committed significant capital investments to modernize the electric grid and integrate these new resources. Transmission assets of the AEP System interconnect approximately 20,600 MWs of renewable energy resources. AEP’s transmission development initiatives are designed to facilitate the interconnection of additional renewable energy resources.
AEP Energy Supply, LLC is a holding company with several divisions, including AEP Renewables and AEP OnSite Partners.
AEP Renewables develops, owns and operates utility scale renewable projects backed with long-term contracts with creditworthy counterparties throughout the United States. AEP Renewables works directly with stakeholders to ensure that customers have clean, sustainable renewable energy to meet their environmental goals. As of December 31, 2021, AEP Renewables owned projects operating in 11 states, including approximately 1,435 MWs of installed wind capacity and 165 MWs of installed solar capacity. These figures include the 2020 acquisition of an additional 10% interest, or approximately 30 MWs, of Santa Rita East wind generation located in west Texas. In October 2019, AEP Renewables entered into an agreement to construct Flat Ridge 3, a 128 MW wind farm facility in Kansas, which was placed into service in December 2021. In February 2022, AEP management announced the beginning of a process to sell all or a portion of AEP Renewables’ competitive contracted renewables portfolio.
AEP OnSite Partners works directly with wholesale and large retail customers to provide tailored solutions to reduce their energy costs based upon market knowledge, innovative applications of technology and deal structuring capabilities. AEP OnSite Partners targets opportunities in distributed solar, combined heat and power,
energy storage, waste heat recovery, energy efficiency, peaking generation and other energy solutions that create value for customers. AEP OnSite Partners pursues and develops behind the meter projects with creditworthy customers. As of December 31, 2021, AEP OnSite Partners owned projects located in 22 states, including approximately 161 MWs of installed solar capacity, and approximately 27 MWs of solar projects under construction.
Competitive Renewable Generation Facilities
Size of
Energy Resource AEP Energy Supply, LLC Division Renewable
Energy Resource Location In-Service or
Under Construction
1,435 MW AEP Renewables Wind Eight states (a) In-service
20 MW AEP Renewables Solar California In-service
20 MW AEP Renewables Solar Utah In-service
125 MW AEP Renewables Solar Nevada In-service
161 MW AEP OnSite Partners Solar Seventeen states (b) In-service
27 MW AEP OnSite Partners Solar Two states (c) Under Construction
(a) Colorado, Hawaii, Indiana, Kansas, Michigan, Minnesota, Pennsylvania, and Texas.
(b) California, Colorado, Florida, Hawaii, Illinois, Iowa, Minnesota, Nebraska, New Hampshire, New Jersey, New Mexico, New York, Ohio, Rhode Island, Texas, Vermont and Wisconsin.
(c) Ohio and New Mexico.
End Use Energy Efficiency
Beginning in 2008, AEP ramped up efforts to reduce energy consumption and peak demand through the introduction of additional energy efficiency and demand response programs. These programs, commonly and collectively referred to as demand side management, were implemented in jurisdictions where appropriate cost recovery was available. Since that time, AEP's operating company’s programs have reduced annual consumption by over 9.6 million MWhs and peak demand by approximately 3,099 MWs. AEP estimates that its operating companies spent approximately $1.6 billion during that period to achieve these levels.
Energy efficiency and demand reduction programs have received regulatory support in most of the states AEP serves, and appropriate cost recovery will be essential for AEP operating companies to continue and expand these consumer offerings. Appropriate recovery of program costs, lost revenues, and an opportunity to earn a reasonable return ensures that energy efficiency programs are considered equally with supply side investments. As AEP continues to transition to a cleaner, more efficient energy future, energy efficiency and demand response programs will continue to play an important role in how the company serves its customers.
AEP believes its experience providing robust energy efficiency programs in several states positions the company to be a cost-effective provider of these programs as states develop their implementation plans.
Corporate Governance
In response to environmental issues and in connection with its assessment of AEP’s strategic plan, the Board of Directors continually reviews the risks posed by new environmental rules and requirements that could accelerate the retirement of coal-fired generation assets. The Board of Directors is informed of new environmental regulations and proposed environmental regulations or legislation that would significantly affect AEP. The Board’s Committee on Directors and Corporate Governance oversees AEP’s annual Corporate Accountability Report, which includes information about AEP’s environmental, social, governance and financial performance. AEP set CO2 emission reduction goals in 2018 after considering input from its annual corporate governance outreach effort with shareholders.
In February 2021, AEP announced new intermediate and long-term CO2 emission reduction goals. 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 has made significant
progress in reducing CO2 emissions from its power generation fleet and expects its emissions to continue to decline. Technological advances, including advanced energy storage, advanced nuclear reactors, hydrogen production and public policies are among the factors that will determine how quickly AEP can achieve net-zero emissions while continuing to provide reliable, affordable power for customers.
Other Environmental Issues and Matters
The Comprehensive Environmental Response, Compensation and Liability Act of 1980 imposes costs for environmental remediation upon owners and previous owners of sites, as well as transporters and generators of hazardous material disposed of at such sites. See “The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation” section of Note 6 included in the 2021 Annual Report for additional information.
Environmental Investments
Investments related to improving AEP System plants’ environmental performance and compliance with environmental quality standards during 2019, 2020 and 2021 and the current estimate for 2022 are shown below. These investments include both environmental as well as other related spending. Estimated construction 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 and the ability to access capital. In addition to the amounts set forth below, AEP expects to make substantial investments in future years in connection with the modification and addition at generation plants’ facilities for environmental quality controls. Such future investments are needed in order to comply with environmental standards that have been adopted and have deadlines for compliance after 2021 or have been proposed and may be adopted. Future investments could be significantly greater if emissions reduction requirements are accelerated or otherwise become more stringent or in response to rules governing the beneficial use and disposal of coal combustion by-products. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the AEP System. AEP typically recovers costs of complying with environmental standards from customers through rates in regulated jurisdictions. Failure to recover these costs could reduce future net income and cash flows and possibly harm AEP’s financial condition. See “Environmental Issues” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 6 - Commitments, Guarantees and Contingencies included in the 2021 Annual Report for additional information.
Historical and Projected Environmental Investments
2019 2020 2021 2022
Actual Actual Actual Estimate (b)
(in millions)
AEP (a) $ 167.1 $ 102.2 $ 94.3 $ 253.0
AEP Texas (0.2) - - -
APCo 23.8 21.3 60.0 193.1
I&M 56.4 31.8 7.2 4.5
SWEPCo 10.5 (3.6) 3.9 16.1
(a)Includes expenditures of the subsidiaries shown and other subsidiaries not shown. The figures reflect construction expenditures, not investments in subsidiary companies.
(b)Estimated amounts are exclusive of debt AFUDC.
Management continues to refine the cost estimates of complying with environmental standards and other impacts of the environmental proposals. The following cost estimates for the years 2022 through 2028 will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules. These 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. Management’s current ranges of estimates of new major environmental investments beginning in 2022, exclusive of debt AFUDC, are set forth below:
Projected (2022 - 2028)
Environmental Investment
Company Low High
(in millions)
AEP $ 325 $ 550
APCo 175 235
I&M 5 10
PSO 5 10
SWEPCo 30 90
HUMAN CAPITAL MANAGEMENT
Attracting, developing and retaining high-performing employees with the skills and experience needed to serve our customers efficiently and effectively is crucial to AEP’s growth and competitiveness and is central to our long-term strategy. AEP invests in employees and continues to build a high performance and inclusive culture that inspires leadership, encourages innovative thinking and welcomes everyone.
The following table shows AEP’s number of employees by subsidiary as of December 31, 2021:
Subsidiary Number of Employees
AEPSC 6,364
AEP Texas 1,575
APCo 1,617
I&M 1,978
OPCo 1,694
PSO 1,018
SWEPCo 1,369
Other 1,073
Total AEP 16,688
Of AEP’s 16,688 employees, less than 1% are Traditionalists (born before 1946), approximately 24% are Baby Boomers (born 1946-1964), approximately 37% are Generation X (born 1965-1980), approximately 36% are Millennials (born 1981-1996) and approximately 2% are Generation Z (born after 1996).
Safety
Achieving Zero Harm means every employee returns home at the end of their shift in the same condition as when they came to work. Zero Harm is what we value most and commit to wholeheartedly. It is hard work, as it requires full focus every moment of every day. We hold ourselves accountable and we are always striving to be better. AEP has put tools, training and processes in place to strengthen our safety-first culture and mindset. AEP’s focus is on learning from events and has proactive programs to prevent harm. One common industry safety metric utilized by AEP to track incidents is the Days Away/Restricted or Transferred (DART) rate. A DART event is an event that results in one or more lost days, one or more restricted days or results in an employee transferring to a different job within the company. The DART rate is a mathematical calculation (number of DART events multiplied by 200,000 work hours and divided by total YTD hours worked) that describes the number of recordable injuries per 100 full-time employees. In 2021, AEP’s employee DART Rate performance worsened to 0.430 compared to the three-year historical average of 0.375. The COVID-19 pandemic continues to present our teams with unprecedented distractions, both on the job and at home. Adjustments are being made to our proactive programs based on injury
trends and how behaviors impact work outcomes. New reinforcement materials will make sure our employees have the skills to identify and mitigate the most dangerous hazards.
Diversity, Equity and Inclusion
AEP is committed to cultivating a diverse and inclusive environment that supports the development and advancement of all. We foster an inclusive workplace that encourages diversity of thought, culture and background and actively work to eliminate unconscious biases. We believe our workforce should generally reﬂect the diversity of our customers and the communities we serve so that we may better understand how to tailor our services to meet their expectations. As of December 31, 2021, women comprised approximately 20% of AEP’s workforce while approximately 19% was represented by racially or ethnically diverse employees.
AEP has taken actions to denounce all forms of racism in the wake of the racial and social unrest across the country. To accelerate our diversity and inclusion strategy, in 2020 AEP initiated a “Seize the Moment: Let’s Keep the Momentum Going” action plan that included candid conversations about race, Town Hall webcasts and “Let’s Talk” discussions with the top 20 African American leaders at AEP. AEP Chief Executive Officer (CEO) Nicholas Akins joined more than 2,000 other CEOs as a signatory to the CEO Action for Diversity and Inclusion pledge, the largest CEO-driven business commitment to advancing diversity and inclusion within the workplace. Additionally, in 2021, the AEP Foundation launched a Delivering On the Dream: Social and Racial Justice grant program. The grants will play a pivotal role in addressing systemic racism by directing funds to support non-profits that are focused on outcomes that enhance social and racial justice. This new program will provide a total investment of up to $5 million, over five years, to help fund local and national organizations with operations and/or active programs within our footprint to embrace change and equity for neighbors of color, customers and employees. We also will encourage employees to make personal commitments as allies and advocates and support events that create greater collaboration within communities for equity and racial justice.
Culture
AEP believes in doing the right thing every time for our customers, each other and our future. AEP leaders at all levels are responsible for fostering an environment that supports a positive culture and for acting in a manner that positively models it. A high-performance culture forms the foundation for long-term success. An engaged, collaborative and empowered workforce is more likely to embrace a change mindset, drive continuous improvement, accept accountability, meet expectations, take ownership, and value personal growth. AEP is committed to driving our culture forward. Employees are given an opportunity to share their perspectives by participating in the Employee Culture Survey, administered by Gallup, Inc., that measures the progress we are making in improving our culture. In addition to engagement, the survey measures well-being and inclusiveness. In 2021, 89% of our organization participated in the survey and we continued to improve our grand mean score to remain in the top decile compared to Gallup’s overall company database. Additionally in 2021, AEP received the Gallup Exceptional Workplace Award for the second consecutive year. The award recognizes organizations with engaged workplace cultures. Company executives also have candid meetings with employees to discuss our challenges, opportunities, what is going well and what can be even better.
Employee Resource Groups
One of the best ways for AEP to demonstrate our commitment to a trusting and inclusive work environment is to empower employees to form and participate in Employee Resource Groups (ERG). The ERGs at AEP include Abled and Differently-Abled Partnering Together, the Black ERG, the Asian-American ERG, the Hispanic Origin Latin American ERG, the Military Veteran ERG, the Native American ERG, the Pride Partnership and the Women at Work ERG. Our ERGs reflect the diverse makeup of our workforce and enable us to gain valuable insight into the diverse communities we serve. They also help increase engagement across AEP by providing employees with a safe space to discuss work-related issues and to develop innovative solutions. ERGs play an active role in AEP’s diversity and inclusion efforts, including recruitment of new employees.
Training and Professional Development
At AEP, we are preparing our workforce for the future by providing opportunities to learn new skills and engaging higher education institutions to better prepare the next generation with the skills that we will need. AEP has training alliances with several community colleges, universities and vocational and technical schools across our service territory. We work with these institutions to develop academic programs that will prepare employees for upward mobility opportunities and to attract external job seekers interested in careers in our industry. AEP also provides a broad range of training and assistance that supports lifelong learning and transition development. This is especially important as we move closer toward a digital future that requires a more flexible, innovative and diverse workforce. AEP has robust processes to achieve this, including ongoing performance coaching, operational skills training, resources to support our commitment to environment, safety and health, job progression training, tuition assistance, and other forms of training that help employees improve their skills and become better leaders. In addition, in October 2021, AEP launched the Women in Linework (WiL) pilot program that will offer qualified participants a direct path into AEP’s linework apprenticeship program. The 14-month program is seeking to address the acute lack of women in lineworker careers and will provide a training regimen along with comprehensive support and development services. WiL will initially take place in OPCo’s Columbus district, with the potential for it to expand to other regions within AEP’s footprint.
In 2021, AEP employees completed more than 719,000 hours of training in programs for which we track participation. In addition, AEP invested more than $2 million in employee education, supporting approximately 1,000 employees through our tuition reimbursement program.
Compensation and Benefits
AEP recognizes the importance of our employees to our success and we offer physical, mental, financial and other health, wellness and assistance programs to our employees and their families to help them thrive at home and work. We ensure the pay we offer is competitive in the marketplace by using an overall market pricing process. In addition to competitive wages, nearly all AEP employees participate in an annual incentive program that rewards outstanding performance and achievement of business goals. Our incentive compensation provides financial rewards to those who contribute to business results and meet or exceed their personal performance goals, which fosters a high-performance culture. AEP also offers employees physical and mental health programs, including medical, dental and life insurance, along with a health and well-being program to help employees and their families stay healthy and feeling their best. Additionally, AEP’s retirement programs position our employees for financial stability in retirement.
Labor Relations
Nearly one fourth of AEP’s workforce is represented by labor unions. We value the relationships we have with our union represented employees and believe in a trusting, collaborative and respectful partnership. We continuously work to strengthen these relationships to ensure we have a culture that attracts and supports employees who can adapt to the rapid changes occurring in our company and industry. Our partnership with labor unions is critical to meeting the growing expectations of our customers and adapting to the challenges of rapidly changing technologies.
BUSINESS SEGMENTS
AEP’s Reportable Segments
AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments are as follows:
•Vertically Integrated Utilities
•Transmission and Distribution Utilities
•AEP Transmission Holdco
•Generation & Marketing
The remainder of AEP’s activities is presented as Corporate and Other, which is not considered a reportable segment. See Note 9 - Business Segments included in the 2021 Annual Report for additional information on AEP’s segments.
VERTICALLY INTEGRATED UTILITIES
GENERAL
AEP’s vertically integrated utility operations are engaged in the 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. AEPSC, as agent for AEP’s public utility subsidiaries, performs marketing, generation dispatch, fuel procurement and power-related risk management and trading activities on behalf of each of these subsidiaries.
ELECTRIC GENERATION
Facilities
As of December 31, 2021, AEP’s vertically integrated public utility subsidiaries owned or leased approximately 22,500 MWs of domestic generation. See Item 2 - Properties for more information regarding the generation capacity of vertically integrated public utility subsidiaries.
Fuel Supply
The following table shows the owned and leased generation sources by type (including wind purchase agreements), on an actual net generation (MWhs) basis, used by the Vertically Integrated Utilities:
2021 2020 2019
Coal and Lignite 50% 45% 54%
Nuclear 22% 24% 19%
Natural Gas 16% 18% 16%
Renewables 12% 13% 11%
A price increase/decrease in one or more fuel sources relative to other fuels, as well as the addition of renewable resources or retirement of traditional fossil fuel units, may result in the decreased/increased use of other fuels. AEP’s overall 2021 fossil fuel costs for the Vertically Integrated Utilities increased 68% on a dollar per
MMBtu basis from 2020 due to an increase in commodity price largely due to the impact of the February 2021 Severe Winter Weather Event.
Coal and Lignite
AEP’s Vertically Integrated Utilities procure coal and lignite under a combination of purchasing arrangements including long-term contracts, affiliate operations and spot agreements with various producers, marketers and coal trading firms. Coal consumption in 2021 increased approximately 26% from 2020 mainly due to higher gas prices and stronger power market prices.
Management believes that the Vertically Integrated Utilities will be able to secure and transport coal and lignite of adequate quality and quantities to operate their coal and lignite-fired units. Through subsidiaries, AEP owns, leases or controls 3,014 railcars, 343 barges, 5 towboats and a coal handling terminal with approximately 18 million tons of annual capacity to move and store coal for use in AEP generating facilities. AEP will be selling one boat and 74 barges will be coming off lease in the first quarter of 2022 and will not be extended.
Spot prices began 2021 at similar levels to 2020 but strengthened significantly in the back half of 2021 due to an increase in global and domestic demand. AEP’s strategy for purchasing coal includes layering in supplies over time. The price impact of this process is reflected in subsequent periods and can occasionally cause current spot market prices to be trending opposite to the price of coal delivered. The price paid for coal delivered in 2021 decreased approximately 5.9% from 2020 mainly due to the pricing of coal supply agreements entered into in previous years.
The following table shows the amount of coal and lignite delivered to the Vertically Integrated Utilities’ plants during the past three years and the average delivered price of coal and lignite purchased by the Vertically Integrated Utilities:
2021 2020 2019
Total coal and lignite delivered to the plants (in millions of tons) 18.2 19.4 30.4
Average cost per ton of coal and lignite delivered $ 50.76 $ 53.95 $ 45.85
The coal supplies at the Vertically Integrated Utilities plants vary from time to time depending on various factors, including, but not limited to, demand for electric power, unit outages, transportation infrastructure limitations, space limitations, plant coal consumption rates, availability of acceptable coals, labor issues and weather conditions, which may interrupt production or deliveries. As of December 31, 2021, the Vertically Integrated Utilities’ coal inventory was approximately 34 days of full load burn. While inventory targets vary by plant and are changed as necessary, the current coal inventory target for the Vertically Integrated Utilities is approximately 27 days of full load burn.
Natural Gas
The Vertically Integrated Utilities consumed approximately 108 billion cubic feet of natural gas during 2021 for generating power. This represents a decrease of 4.60% from 2020. Several of AEP’s natural gas-fired power plants are connected to at least two pipelines which allow greater access to competitive supplies and improve delivery reliability. A portfolio of term, seasonal, monthly and daily supply and transportation agreements provide natural gas requirements for each plant, as appropriate. AEP’s natural gas supply transactions are based on market prices.
The following table shows the amount of natural gas delivered to the Vertically Integrated Utilities’ plants during the past three years and the average delivered price of natural gas purchased by the Vertically Integrated Utilities. The increase in 2021 average delivered price is largely due to the impact of the February 2021 Severe Winter Weather Event.
2021 2020 2019
Total natural gas delivered to the plants (in billions cubic feet) 108.0 113.1 117.0
Average delivered price per MMBtu of purchased natural gas $ 8.92 $ 2.14 $ 2.64
Nuclear
I&M has made commitments to meet the current nuclear fuel requirements of the Cook Plant. I&M has made and will make purchases of uranium in various forms in the spot, short-term and mid-term markets. I&M also continues to finance its nuclear fuel through leasing.
For purposes of the storage of high-level radioactive waste in the form of SNF, I&M completed modifications to its SNF storage pool in the early 1990’s. I&M entered into an agreement to provide for onsite dry cask storage of SNF to permit normal operations to continue. I&M is scheduled to conduct further dry cask loading and storage projects on an ongoing periodic basis. The year of expiration of each NRC Operating License is 2034 for Unit 1 and 2037 for Unit 2.
Nuclear Waste and Decommissioning
As the owner of the Cook Plant, I&M has a significant future financial commitment to dispose of SNF and decommission and decontaminate the plant safely. The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program. The most recent decommissioning cost study was completed in 2021. The estimated cost of decommissioning and disposal of low-level radioactive waste for the Cook Plant was $2.2 billion in 2021 non-discounted dollars, with additional ongoing estimated costs of $7 million per year for post decommissioning storage of SNF and an eventual estimated cost of $33 million for the subsequent decommissioning of the spent fuel storage facility, also in 2021 non-discounted dollars. As of December 31, 2021 and 2020, the total decommissioning trust fund balance for the Cook Plant was approximately $3.5 billion and $3 billion, respectively. The balance of funds available to eventually decommission Cook Plant will differ based on contributions and investment returns. The ultimate cost of retiring the Cook Plant may be materially different from estimates and funding targets as a result of the:
•Escalation of various cost elements (including, but not limited to, general inflation and the cost of energy).
•Further development of regulatory requirements governing decommissioning.
•Technology available at the time of decommissioning differing significantly from that assumed in studies.
•Availability of nuclear waste disposal facilities.
•Availability of a United States Department of Energy facility for permanent storage of SNF.
Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant will not be significantly different than current projections. AEP will seek recovery from customers through regulated rates if actual decommissioning costs exceed projections. See the “Nuclear Contingencies” section of Note 6 - Commitments, Guarantees and Contingencies included in the 2021 Annual Report for additional information with respect to nuclear waste and decommissioning.
Low-Level Radioactive Waste
The Low-Level Waste Policy Act of 1980 mandates that the responsibility for the disposal of low-level radioactive waste rests with the individual states. Low-level radioactive waste consists largely of ordinary refuse and other items that have come in contact with radioactive materials. Michigan does not currently have a disposal site for such waste available. I&M cannot predict when such a site may be available. However, the states of Utah and Texas have licensed low-level radioactive waste disposal sites which currently accept low-level radioactive waste from Michigan waste generators. There is currently no set date limiting I&M’s access to either of these facilities. The Cook Plant has a facility onsite designed specifically for the storage of low-level radioactive waste. In the event that low-level radioactive waste disposal facility access becomes unavailable, it can be stored onsite at this facility.
Counterparty Risk Management
The Vertically Integrated Utilities segment also sells power and enters into related energy transactions with wholesale customers and other market participants. As a result, counterparties and exchanges may require cash or cash related instruments to be deposited on transactions as margin against open positions. As of December 31, 2021, counterparties posted approximately $10 million in cash, cash equivalents or letters of credit with AEPSC for the benefit of AEP’s public utility subsidiaries (while, as of that date, AEP’s public utility subsidiaries posted approximately $210 million with counterparties and exchanges). Since open trading contracts are valued based on market prices of various commodities, exposures change daily. See the “Quantitative and Qualitative Disclosures About Market Risk” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2021 Annual Report for additional information.
Certain Power Agreements
I&M
The UPA between AEGCo and I&M, dated March 31, 1982 (the I&M Power Agreement), provides for the sale by AEGCo to I&M of all the capacity (and the energy associated therewith) available to AEGCo at the Rockport Plant. Whether or not power is available from AEGCo, I&M is obligated to pay a demand charge for the right to receive such power (and an energy charge for any associated energy taken by I&M). The I&M Power Agreement will continue in effect until the debt obligations of AEGCo secured by the Rockport Plant have been satisfied and discharged (currently expected to be December 2028).
Pursuant to an assignment between I&M and KPCo, and a UPA between AEGCo and KPCo, AEGCo sells KPCo 30% of the capacity (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo has agreed to pay to AEGCo the amounts that I&M would have paid AEGCo under the terms of the UPA between AEGCo and I&M for such entitlement. The KPCo UPA expires in December 2022.
OVEC
AEP and several nonaffiliated utility companies jointly own OVEC. The aggregate equity participation of AEP in OVEC is 43.47%. Parent owns 39.17% and OPCo owns 4.3%. Under the Inter-Company Power Agreement (ICPA), which defines the rights of the owners and sets the power participation ratio of each, the sponsoring companies are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,400 MWs) in proportion to their respective power participation ratios. The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%. The ICPA terminates in June 2040. The proceeds from charges by OVEC to sponsoring companies under the ICPA based on their power participation ratios are designed to be sufficient for OVEC to meet its operating expenses and fixed costs. OVEC’s Board of Directors, as elected by AEP and nonaffiliated owners, has authorized environmental investments related to their ownership interests, with resulting expenses (including for related debt and interest thereon) included in charges under the ICPA. OVEC financed capital expenditures in excess of $1 billion in connection with flue gas desulfurization projects and the associated scrubber waste disposal
landfills at its two generation plants through debt issuances, including tax-advantaged debt issuances. Both OVEC generation plants are operating with the new environmental controls in-service. See Note 17 - Variable Interest Entities and Equity Method Investments for additional information.
ELECTRIC DELIVERY
General
Other than AEGCo, AEP’s vertically integrated public utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power. See Item 2 - Properties for more information regarding the transmission and distribution lines. Most of the transmission and distribution services are sold to retail customers of AEP’s vertically integrated public utility subsidiaries in their service territories. These sales are made at rates approved by the state utility commissions of the states in which they operate, and in some instances, approved by the FERC. See Item 1. Business - Vertically Integrated Utilities - Regulation - Rates. The FERC regulates and approves the rates for both wholesale transmission transactions and wholesale generation contracts. The use and the recovery of costs associated with the transmission assets of the AEP vertically integrated public utility subsidiaries are subject to the rules, principles, protocols and agreements in place with PJM and SPP, and as approved by the FERC. See Item 1. Business - Vertically Integrated Utilities - Regulation - FERC. As discussed below, some transmission services also are separately sold to nonaffiliated companies.
Other than AEGCo, AEP’s vertically integrated public utility subsidiaries hold franchises or other rights to provide electric service in various municipalities and regions in their service areas. In some cases, these franchises provide the utility with the exclusive right to provide electric service within a specific territory. These franchises have varying provisions and expiration dates. In general, the operating companies consider their franchises to be adequate for the conduct of their business. For a discussion of competition in the sale of power, see Item 1. Business - Vertically Integrated Utilities - Competition.
Transmission Agreement
APCo, I&M, KGPCo, KPCo and WPCo own and operate transmission facilities that are used to provide transmission service under the PJM OATT and are parties to the TA. OPCo, which is a subsidiary in AEP’s Transmission and Distribution Utilities segment that provides transmission service under the PJM OATT, is also a party to the TA. The TA defines how the parties to the agreement share the revenues associated with their transmission facilities and the costs of transmission service provided by PJM. The TA has been approved by the FERC.
Transmission Coordination Agreement and Open Access Transmission Tariff
PSO, SWEPCo and AEPSC are parties to the TCA. Under the TCA, a coordinating committee is charged with the responsibility of: (a) overseeing the coordinated planning of the transmission facilities of the parties to the agreement, including the performance of transmission planning studies, (b) the interaction of such subsidiaries with independent system operators and other regional bodies interested in transmission planning and (c) compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such tariff. Pursuant to the TCA, AEPSC has responsibility for monitoring the reliability of their transmission systems and administering the OATT on behalf of the other parties to the agreement. The TCA also provides for the allocation among the parties of revenues collected for transmission and ancillary services provided under the OATT. These allocations have been determined by the FERC-approved OATT for the SPP.
Regional Transmission Organizations
AEGCo, APCo, I&M, KGPCo, KPCo and WPCo are members of PJM, and PSO and SWEPCo are members of SPP (both FERC-approved RTOs). RTOs operate, plan and control utility transmission assets in a manner designed to
provide open access to such assets in a way that prevents discrimination between participants owning transmission assets and those that do not.
REGULATION
General
AEP’s vertically integrated public utility subsidiaries’ retail rates and certain other matters are subject to traditional cost-based regulation by the state utility commissions. AEP’s vertically integrated public utility subsidiaries are also subject to regulation by the FERC under the Federal Power Act with respect to wholesale power and transmission service transactions. I&M is subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant. AEP and its vertically integrated public utility subsidiaries are also subject to the regulatory provisions of, much of the Energy Policy Act of 2005, which is administered by the FERC.
Rates
Historically, state utility commissions have established electric service rates on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service. A utility’s cost-of-service generally reflects its operating expenses, including operation and maintenance expense, depreciation expense and taxes. State utility commissions periodically adjust rates pursuant to a review of: (a) a utility’s adjusted revenues and expenses during a defined test period and (b) such utility’s level of investment. Absent a legal limitation, such as a law limiting the frequency of rate changes or capping rates for a period of time, a state utility commission can review and change rates on its own initiative. Some states may initiate reviews at the request of a utility, customer, governmental or other representative of a group of customers. Such parties may, however, agree with one another not to request reviews of or changes to rates for a specified period of time.
Public utilities have traditionally financed capital investments until the new asset is placed in-service. Provided the asset was found to be a prudent investment, it was then added to rate base and entitled to a return through rate recovery. Given long lead times in construction, the high costs of plant and equipment and volatile capital markets, management actively pursues strategies to accelerate rate recognition of investments and cash flow. AEP representatives continue to engage state commissioners and legislators on alternative rate-making options to reduce regulatory lag and enhance certainty in the process. These options include pre-approvals, a return on construction work in progress, rider/trackers, formula rates and the inclusion of future test-year projections into rates.
The rates of AEP’s vertically integrated public utility subsidiaries are generally based on the cost of providing traditional bundled electric service (i.e., generation, transmission and distribution service). Historically, the state regulatory frameworks in the service area of the AEP vertically integrated public utility subsidiaries reflected specified fuel costs as part of bundled (or, more recently, unbundled) rates or incorporated fuel adjustment clauses in a utility’s rates and tariffs. Fuel adjustment clauses permit periodic adjustments to fuel cost recovery from customers and therefore provide protection against exposure to fuel cost changes.
The following state-by-state analysis summarizes the regulatory environment of certain major jurisdictions in which AEP’s vertically integrated public utility subsidiaries operate. Several public utility subsidiaries operate in more than one jurisdiction. See Note 4 - Rate Matters included in the 2021 Annual Report for more information regarding pending rate matters.
Indiana
I&M provides retail electric service in Indiana at bundled rates approved by the IURC, with rates set on a forecasted cost-of-service basis. Indiana provides for timely fuel and purchased power cost recovery through a fuel cost recovery mechanism.
Oklahoma
PSO provides retail electric service in Oklahoma at bundled rates approved by the OCC. PSO’s rates are set on a cost-of-service basis. Fuel and purchased energy costs are recovered or refunded through a fuel adjustment clause.
Virginia
APCo currently provides retail electric service in Virginia at unbundled generation and distribution rates approved by the Virginia SCC. Virginia generally allows for timely recovery of fuel costs through a fuel cost recovery mechanism. In addition to base rates and fuel cost recovery, APCo is permitted to recover a variety of costs through rate adjustment clauses including transmission services provided at OATT rates based on rates established by the FERC.
West Virginia
APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. West Virginia generally allows for timely recovery of fuel costs through the ENEC which trues-up to actual expenses. In addition to base rates and fuel cost recovery, APCo is permitted to recover a variety of costs through surcharges.
FERC
The FERC regulates rates for interstate power sales at wholesale, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. The FERC regulations require AEP’s vertically integrated public utility subsidiaries to provide open access transmission service at FERC-approved rates, and AEP has approved cost-based formula transmission rates on file at the FERC. The FERC also regulates unbundled transmission service to retail customers. In addition, the FERC regulates the sale of power for resale in interstate commerce by: (a) approving contracts for wholesale sales to municipal and cooperative utilities at cost-based rates and (b) granting authority to public utilities to sell power at wholesale at market-based rates upon a showing that the seller lacks the ability to improperly influence market prices. AEP’s vertically integrated public utility subsidiaries have market-based rate authority from the FERC, under which much of their wholesale marketing activity takes place. The FERC requires each public utility that owns or controls interstate transmission facilities, directly or through an RTO, to file an open access network and point-to-point transmission tariff that offers services comparable to the utility’s own uses of its transmission system. The FERC also requires all transmitting utilities, directly or through an RTO, to establish an Open Access Same-time Information System, which electronically posts transmission information such as available capacity and prices, and requires utilities to comply with Standards of Conduct that prohibit utilities’ transmission employees from providing non-public transmission information to the utility’s marketing employees. Additionally, the vertically integrated public utility subsidiaries are subject to reliability standards promulgated by the NERC, with the approval of the FERC.
The FERC oversees RTOs, entities created to operate, plan and control utility transmission assets. AEGCo, APCo, I&M, KGPCo, KPCo and WPCo are members of PJM. PSO and SWEPCo are members of SPP.
The FERC has jurisdiction over certain issuances of securities of most of AEP’s public utility subsidiaries, the acquisition of securities of utilities, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. In addition, both the FERC and state regulators are permitted to review the books and records of any company within a holding company system.
COMPETITION
Other than AEGCo, AEP’s vertically integrated public utility subsidiaries generate, transmit and distribute electricity to retail customers of AEP’s vertically integrated public utility subsidiaries in their service territories. These sales are made at rates approved by the state utility commissions of the states in which they operate, and in some instances, approved by the FERC, and are not subject to competition from other vertically integrated public utilities. Other than AEGCo, AEP’s vertically integrated public utility subsidiaries hold franchises or other rights that effectively grant the exclusive ability to provide electric service in various municipalities and regions in their service areas.
AEP’s vertically integrated public utility subsidiaries compete with self-generation and with distributors of other energy sources, such as natural gas, fuel oil, renewables and coal, within their service areas. The primary factors in such competition are price, reliability of service and the capability of customers to utilize alternative sources of energy other than electric power. With respect to competing generators and self-generation, the public utility subsidiaries of AEP believe that they currently maintain a competitive position.
Changes in regulatory policies and advances in newer technologies for batteries or energy storage, fuel cells, microturbines, wind turbines and photovoltaic solar cells are reducing costs of new technology to levels that are making them competitive with some central station electricity production. The costs of photovoltaic solar cells in particular have continued to become increasingly competitive. The ability to maintain relatively low cost, efficient and reliable operations and to provide cost-effective programs and services to customers are significant determinants of AEP’s competitiveness.
SEASONALITY
The consumption of electric power is generally seasonal. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. The pattern of this fluctuation may change due to the nature and location of AEP’s facilities and the terms of power sale contracts into which AEP enters. In addition, AEP has historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could diminish AEP’s results of operations. Conversely, unusually extreme weather conditions could increase AEP’s results of operations.
TRANSMISSION AND DISTRIBUTION UTILITIES
GENERAL
This segment consists of the transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo. OPCo is engaged in the transmission and distribution of electric power to approximately 1,515,000 retail customers in Ohio. OPCo purchases energy and capacity to serve standard service offer customers and provides transmission and distribution services for all connected load. AEP Texas is engaged in the transmission and distribution of electric power to approximately 1,082,000 retail customers through REPs in west, central and southern Texas.
AEP’s transmission and distribution utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power. See Item 2 - Properties, for more information regarding the transmission and distribution lines. Transmission and distribution services are sold to retail customers of AEP’s transmission and distribution utility subsidiaries in their service territories. These sales are made at rates approved by the PUCT for AEP Texas and by the PUCO and the FERC for OPCo. The FERC regulates and approves the rates for wholesale transmission transactions. As discussed below, some transmission services also are separately sold to nonaffiliated companies.
AEP’s transmission and distribution utility subsidiaries hold franchises or other rights to provide electric service in various municipalities and regions in their service areas. In some cases, these franchises provide the utility with the
exclusive right to provide electric service. These franchises have varying provisions and expiration dates. In general, the operating companies consider their franchises to be adequate for the conduct of their business.
The use and the recovery of costs associated with the transmission assets of the AEP transmission and distribution utility subsidiaries are subject to the rules, protocols and agreements in place with PJM and ERCOT, and as approved by the FERC. In addition to providing transmission services in connection with power sales in their service areas, AEP’s transmission and distribution utility subsidiaries also provide transmission services for nonaffiliated companies through RTOs.
Transmission Agreement
OPCo owns and operates transmission facilities that are used to provide transmission service under the PJM OATT; OPCo is a party to the TA with other utility subsidiary affiliates. The TA defines how the parties to the agreement share the revenues associated with their transmission facilities and the costs of transmission service provided by PJM. The TA has been approved by the FERC.
Regional Transmission Organizations
OPCo is a member of PJM, a FERC-approved RTO. RTOs operate, plan and control utility transmission assets to provide open access to such assets in a way that prevents discrimination between participants owning transmission assets and those that do not. AEP Texas is a member of ERCOT.
REGULATION
OPCo provides distribution and transmission services to retail customers within its service territory at cost-based rates approved by the PUCO or by the FERC. AEP Texas sets its rates through a combination of base rate cases and interim Transmission Cost of Services (TCOS) and Distribution Cost Recovery Factor (DCRF) filings. AEP Texas may file interim TCOS filings semi-annually and DCRF filings annually to update its rates to reflect changes in its net invested capital. Transmission and distribution rates are established on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service. The cost-of-service generally reflects operating expenses, including operation and maintenance expense, depreciation expense and taxes. Utility commissions periodically adjust rates pursuant to a review of: (a) a utility’s adjusted revenues and expenses during a defined test period and (b) such utility’s level of investment.
FERC
The FERC regulates rates for transmission of electric power, accounting and other matters. The FERC regulations require AEP to provide open access transmission service at FERC-approved rates, and it has approved cost-based formula transmission rates on file at the FERC. The FERC also regulates unbundled transmission service to retail customers. The FERC requires each public utility that owns or controls interstate transmission facilities to, directly or through an RTO, file an open access network and point-to-point transmission tariff that offers services comparable to the utility’s own uses of its transmission system. The FERC also requires all transmitting utilities, directly or through an RTO, to establish an Open Access Same-time Information System, which electronically posts transmission information such as available capacity and prices, and requires utilities to comply with Standards of Conduct that prohibit utilities’ transmission employees from providing non-public transmission information to the utility’s marketing employees. In addition, both the FERC and state regulators are permitted to review the books and records of any company within a holding company system. Additionally, the transmission and distribution utility subsidiaries are subject to reliability standards as set forth by the NERC, with the approval of the FERC.
SEASONALITY
The delivery of electric power is generally seasonal. In many parts of the country, demand for power peaks during the hot summer months. In other areas, power demand peaks during the winter months. The pattern of this fluctuation may change due to the nature and location of AEP’s transmission and distribution facilities. In addition, AEP transmission and distribution has historically delivered less power, and consequently earned less income, when weather conditions are milder. In Texas, where there is residential decoupling, unusually mild weather in the future could diminish AEP’s results of operations. Conversely, unusually extreme weather conditions could increase AEP’s results of operations.
AEP TRANSMISSION HOLDCO
GENERAL
AEPTHCo is a holding company for (a) AEPTCo, which is the direct holding company for the State Transcos and (b) AEP’s Transmission Joint Ventures.
AEPTCo
AEPTCo wholly owns the State Transcos which are independent of, but respectively overlay, the following AEP electric utility operating companies: APCo, I&M, KPCo, OPCo, PSO, SWEPCo and WPCo. The State Transcos develop, own, operate and maintain their respective transmission assets. Assets of the State Transcos interconnect to transmission facilities owned by the aforementioned operating companies and nonaffiliated transmission owners within the footprints of PJM, MISO and SPP. APTCo, IMTCo, KTCo, OHTCo and WVTCo are located within PJM. IMTCo also owns portions of the Greentown station assets located in MISO. OKTCo and SWTCo are located within SPP.
IMTCo, KTCo, OHTCo, OKTCo and WVTCo own and operate transmission assets in their respective jurisdictions. The Virginia SCC and WVPSC granted consent for APCo and APTCo to enter into a joint license agreement that will support APTCo investment in the state of Tennessee. SWTCo does not currently own or operate transmission assets.
The State Transcos are regulated for rate-making purposes exclusively by the FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. The State Transcos establish transmission rates each year through formula rate filings with the FERC. The rate filings calculate the revenue requirement needed to cover the costs of operation and debt service and to earn an allowed ROE. These rates are then included in an OATT for PJM, MISO and SPP.
The State Transcos own, operate, maintain and invest in transmission infrastructure in order to maintain and enhance system integrity and grid reliability, grid security, safety, reduce transmission constraints and facilitate interconnections of new generating resources and new wholesale customers, as well as enhance competitive wholesale electricity markets. A key part of AEP’s business is replacing and upgrading transmission facilities, assets and components of the existing AEP System as needed to maintain reliability.
The State Transcos provide the capability to build, replace and upgrade existing facilities. As of December 31, 2021, the State Transcos had $11.5 billion of transmission and other assets in-service with plans to construct approximately $3.5 billion of additional transmission assets, excluding CWIP, through 2024. Additional investment in transmission infrastructure is needed within PJM and SPP to maintain the required level of grid reliability, resiliency, security and efficiency and to address an aging transmission infrastructure. Additional transmission facilities will be needed based on changes in generating resources, such as wind or solar projects, generation additions or retirements and additional new customer interconnections. The State Transcos will continue their investment to enhance physical and cyber security of assets, and are also investing in improving the telecommunication network that supports the operation and control of the grid.
In October 2021, AEP entered into a Stock Purchase Agreement to sell KTCo to Liberty Utilities. Subject to satisfaction of closing conditions and receipt of regulatory approvals, the sale is expected to close in the second quarter of 2022. See “Disposition of KPCo and KTCo” section of Note 7 for additional information
AEPTHCO JOINT VENTURE INITIATIVES
AEP has established joint ventures with other electric utility companies for the purpose of developing, building and owning transmission assets that seek to improve reliability and market efficiency and provide transmission access to remote generation sources in North America (Transmission Joint Ventures).
The Transmission Joint Ventures currently include:
Joint Venture Name Location Projected or Actual Completion Date Owners
(Ownership %) Total Estimated/Actual Project Costs at Completion Approved Return on Equity
(in millions)
ETT Texas (a) Berkshire Hathaway $ 3,900.0 (a) 9.6 %
(ERCOT) Energy (50%)
AEP (50%)
Prairie Wind Kansas 2014 Evergy, Inc. (50%) 158.0 12.8 %
Berkshire Hathaway
Energy (25%)
AEP (25%)
Pioneer Indiana 2018 Duke Energy (50%) 191.0 10.52 % (b)
AEP (50%)
Transource Missouri 2016 Evergy, Inc. 310.5 11.1 % (c)
Missouri (13.5%) (d)
AEP (86.5%) (d)
Transource West 2019 Evergy, Inc. 84.0 10.5 %
West Virginia Virginia (13.5%) (d)
AEP (86.5%) (d)
Transource Maryland 2023 Evergy, Inc. 27.6 (e) 10.4 %
Maryland (13.5%) (d)
AEP (86.5%) (d)
Transource Pennsylvania 2023 Evergy, Inc. 243.6 (e) 10.4 %
Pennsylvania (13.5%) (d)
AEP (86.5%) (d)
Transource Oklahoma 2026 Evergy, Inc. 108.0 (f) 10.0 %
Oklahoma (13.5%(d)
AEP (86.5%) (d)
(a)ETT is undertaking multiple projects and the completion dates will vary for those projects. ETT’s investment in completed and active projects in ERCOT is expected to be $3.9 billion. Future projects will be evaluated on a case-by-case basis.
(b)In May 2020, Pioneer received FERC approval authorizing an ROE of 10.02% (10.52% inclusive of the RTO incentive adder of 0.5%).
(c)The ROE represents the weighted-average approved ROE based on the costs of two projects developed by Transource Missouri; the $64 million Iatan-Nashua project (10.3%) and the $247 million Sibley-Nebraska City project (11.3%).
(d)AEP owns 86.5% of Transource Missouri, Transource West Virginia, Transource Maryland, Transource Pennsylvania and Transource Oklahoma through its ownership interest in Transource Energy, LLC (Transource). Transource is a joint venture with AEPTHCo and Evergy, Inc. formed to pursue competitive transmission projects. AEPTHCo and Evergy, Inc. own 86.5% and 13.5% of Transource, respectively.
(e)See “Independence Energy Connection Project” section below for additional information.
(f)In 2016, Transource Kansas received approval from the FERC authorizing an ROE of 9.8% (10.3% inclusive of the RTO incentive adder of 0.5%) for future competitive transmission projects in SPP. In October 2020, Transource was awarded the Sooner-Wekiwa project by SPP and the project was assigned to Transource Kansas. In November 2020, Transource Kansas was renamed Transource Oklahoma. The project is expected to go in-service in 2026.
Transource Missouri, Transource West Virginia, Transource Maryland, Transource Pennsylvania and Transource Oklahoma are consolidated joint ventures by AEP. All other joint ventures in the table above are not consolidated by AEP. AEP’s joint ventures do not have employees. Business services for the joint ventures are provided by AEPSC and other AEP subsidiaries and the joint venture partners. In 2021, approximately 438 AEPSC employees and 256 operating company employees provided service to one or more joint ventures.
Independence Energy Connection Project
In 2016, PJM approved the Independence Energy Connection Project (IEC) and included it in its Regional Transmission Expansion Plan to alleviate congestion. Transource Energy owns the IEC, which is located in Maryland and Pennsylvania. In June 2020, the Maryland Public Service Commission approved a Certificate of Public Convenience and Necessity to construct the portion of the IEC in Maryland. In May 2021, the Pennsylvania Public Utility Commission (PA PUC) denied the IEC certificate for siting and construction of the portion in Pennsylvania. Transource Energy has appealed the PA PUC ruling in Pennsylvania state court and challenged the ruling before the United States District Court for the Middle District of Pennsylvania. The case before the state court is pending and the case before the United States District Court for the Middle District of Pennsylvania is currently suspended, pending the outcome of the case in the Pennsylvania state court.
In September 2021, PJM notified Transource Energy that the IEC was suspended to allow for the regulatory and related appeals process to proceed in an orderly manner without breaching milestone dates in the project agreement. PJM stated that the IEC has not been cancelled and remains necessary to alleviate congestion. As of December 31, 2021, AEP’s share of IEC capital expenditures was approximately $81 million. The FERC has previously granted abandonment benefits for this project, allowing the full recovery of prudently incurred costs if the project is cancelled for reasons outside the control of Transource Energy. If any of the IEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
REGULATION
The State Transcos and the Transmission Joint Ventures located outside of ERCOT establish transmission rates annually through forward-looking formula rate filings with the FERC pursuant to FERC-approved implementation protocols. The protocols include a transparent, formal review process to ensure the updated transmission rates are prudently-incurred and reasonably calculated. The IMTCo-owned Greentown station assets acquired from Duke Energy Indiana, LLC in December 2018 are located in MISO. IMTCo utilizes a historic cost recovery model to recover MISO assets.
The State Transcos’ and the Transmission Joint Ventures’ (where applicable) rates are included in the respective OATT for PJM and SPP. An OATT is the FERC rate schedule that provides the terms and conditions for transmission and related services on a transmission provider’s transmission system. The FERC requires transmission providers such as PJM and SPP to offer transmission service to all eligible customers (for example, load-serving entities, power marketers, generators and customers) on a non-discriminatory basis.
The FERC-approved formula rates establish the annual transmission revenue requirement (ATRR) and transmission service rates for transmission owners in annual rate base filings with the FERC. The formula rates establish rates for a one-year period based on the current projects in-service and proposed projects for a defined timeframe. The formula rates also include a true-up calculation for the previous year’s billings, allowing for over/under-recovery of the transmission owner’s ATRR. PJM and SPP pay the transmission owners their ATRR for use of their facilities and bill transmission customers taking service under the PJM and SPP OATTs, based on the terms and conditions in the respective OATT for the service taken. Additionally, the State Transcos are subject to reliability standards promulgated by the NERC, with the approval of the FERC.
Management continues to monitor the FERC’s 2019 Notice of Inquiry regarding base ROE policy, the FERC’s 2020 and 2021 supplemental Notice of Proposed Rulemaking (NOPR) regarding transmission incentives policy, and various other matters pending before the FERC with the potential to affect the transmission ROE methodology.
In April 2021, the FERC issued a supplemental 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 the annual rate base filings described above, the State Transcos in aggregate filed rate base totals of $8.4 billion, $7.0 billion and $5.9 billion for 2021, 2020 and 2019, respectively. The total filed transmission revenue requirements, including prior year over/under-recovery of revenue and associated carrying charges were $1.4 billion, $1.2 billion and $992 million for 2021, 2020 and 2019, respectively.
The rates of ETT, which is located in ERCOT, are determined by the PUCT. ETT sets its rates through a combination of base rate cases and interim Transmission Cost of Services (TCOS) filings. ETT may file interim TCOS filings semi-annually to update its rates to reflect changes in its net invested capital.
The Transmission Joint Ventures have approved ROEs ranging from 9.6% to 12.8% based on equity capital structures ranging from 40% to 60%.
GENERATION & MARKETING
GENERAL
The AEP Generation & Marketing segment subsidiaries consist of a wholesale energy trading and marketing business, a retail supply and energy management business and competitive generating assets.
AEP Energy Supply, LLC is a holding company with several divisions, including AEP Renewables and AEP OnSite Partners.
AEP Renewables develops, owns and operates utility scale renewable projects backed with long-term contracts with creditworthy counterparties throughout the United States. AEP Renewables works directly with stakeholders to ensure that customers have clean, sustainable renewable energy to meet their environmental goals. As of December 31, 2021, AEP Renewables owned projects operating in 11 states, including approximately 1,435 MWs of installed wind capacity and 165 MWs of installed solar capacity. In October 2019, AEP Renewables entered into an agreement to construct Flat Ridge 3, a wind farm in Kansas. The 128 MW facility was placed into service in December 2021. In November 2020, AEP Renewables signed a Purchase and Sale Agreement to acquire 75% of the Dry Lake Solar Project, a 100 MW solar facility in southern Nevada. This facility was placed into service in May 2021. In February 2022, AEP management announced the beginning of a process to sell all or a portion of AEP Renewables’ competitive contracted renewables portfolio.
AEP OnSite Partners works directly with wholesale and large retail customers to provide tailored solutions to reduce their energy costs based upon market knowledge, innovative applications of technology and deal structuring capabilities. AEP OnSite Partners targets opportunities in distributed solar, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other energy solutions that create value for customers. AEP OnSite Partners pursues and develops behind the meter projects with creditworthy customers. As of December 31, 2021, AEP OnSite Partners owned projects located in 22 states, including approximately 161 MWs of installed solar capacity, and approximately 27 MWs of solar projects under construction.
With respect to the wholesale energy trading and marketing business, AEP Generation & Marketing segment subsidiaries enter into short-term and long-term transactions to buy or sell capacity, energy and ancillary services in ERCOT, SPP, MISO and PJM. These subsidiaries sell power into the market and engage in power, natural gas and emissions allowances risk management and trading activities. These activities primarily involve the purchase-and-sale of electricity (and to a lesser extent, natural gas and emissions allowances) under forward contracts at fixed and variable prices. These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options. The majority of forward contracts are typically settled by entering into offsetting contracts. These transactions are executed with numerous counterparties or on exchanges.
With respect to the retail supply and energy management business, AEP Energy is a retail energy supplier that supplies electricity and/or natural gas to residential, commercial, and industrial customers. AEP Energy provides various energy solutions in Illinois, Pennsylvania, Delaware, Maryland, New Jersey, Ohio and Washington, D.C. AEP Energy had approximately 552,000 customer accounts as of December 31, 2021.
The primary fossil generation subsidiary in the Generation & Marketing segment is AGR. As of December 31, 2021, AGR owns the 595 MW Cardinal Plant which is operated by a nonaffiliated electric cooperative. Other subsidiaries in this segment own or have the right to receive power from additional generation assets. See Item 2 - Properties for more information regarding the generation assets of the Generation & Marketing segment. AGR is a competitive generation subsidiary.
REGULATION
AGR is a public utility under the Federal Power Act, and is subject to the FERC’s exclusive rate-making jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Under the Federal Power Act, the FERC has the authority to grant or deny market-based rates for sales of energy, capacity and
ancillary services to ensure that such sales are just and reasonable. The FERC granted AGR market-based rate authority in December 2013. The FERC’s jurisdiction over rate-making also includes the authority to suspend the market-based rates of AGR and set cost-based rates if the FERC subsequently determines that it can exercise market power, create barriers to entry or engage in abusive affiliate transactions. Periodically, AGR is required to file a market power update to show that it continues to meet the FERC’s standards with respect to generation market power and other criteria used to evaluate whether it continues to qualify for market-based rates. Other matters subject to the FERC jurisdiction include, but are not limited to, review of mergers, and dispositions of jurisdictional facilities and acquisitions of securities of another public utility or an existing operational generating facility.
Specific operations of AGR are also subject to the jurisdiction of various other federal, state, regional and local agencies, including federal and state environmental protection agencies. AGR is also regulated by the PUCT for transactions inside ERCOT. Additionally, AGR is subject to mandatory reliability standards promulgated by the NERC, with the approval of the FERC.
COMPETITION
The AEP Generation & Marketing segment subsidiaries face competition for the sale of available power, capacity and ancillary services. The principal factors of impact are electricity and fuel prices, new market entrants, construction or retirement of generating assets by others and technological advances in power generation. Because AGR’s remaining generation is coal-fired, lower relative natural gas prices will favor competitors that have a higher concentration of natural gas fueled generation. Other factors impacting competitiveness include environmental regulation, transmission congestion or transportation constraints at or near generation facilities, inoperability or inefficiencies, outages and deactivations and retirements at generation facilities.
Technology advancements, increased demand for clean energy, changing consumer behaviors, low-priced and abundant natural gas, and regulatory and public policy reforms are among the catalysts for transformation within the industry that impact competition for AEP’s Generation & Marketing segment. AGR also competes with self-generation and with distributors of other energy sources, such as natural gas, fuel oil, renewables and coal, within their service areas. The primary factors in such competition are price, unit availability and the capability of customers to utilize sources of energy other than electric power.
Changes in regulatory policies and advances in newer technologies for batteries or energy storage, fuel cells, microturbines, wind turbines and photovoltaic solar cells are reducing costs of new technology to levels that are making them competitive with some central station electricity production. The ability to maintain relatively low cost, efficient and reliable operations and to provide cost-effective programs and services to customers are significant determinants of AGR’s competitiveness. The costs of photovoltaic solar cells in particular have continued to become increasingly competitive.
This segment’s retail operations provide competitive electricity and natural gas in deregulated retail energy markets in six states and Washington, D.C. Each such retail choice jurisdiction establishes its own laws and regulations governing its competitive market, and public utility commission communications and utility default service pricing can affect customer participation in retail competition. Sustained low natural gas and power prices, low market volatility and maturing competitive environments can adversely affect this business.
This segment also engages in procuring and selling output from renewable generation sources under long-term contracts to creditworthy counterparties. New sources are not acquired without first securing a long-term placement of such power. Existing sources do not face competitive exposure. Competitive nonaffiliated suppliers of renewable or other generation could limit opportunities for future transactions for new sources and related output contracts.
SEASONALITY
The consumption of electric power is generally seasonal. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter months. The pattern of this fluctuation may change.
Fuel Supply
The following table shows the generation sources by type, on an actual net generation (MWhs) basis, used by the Generation & Marketing segment:
2021 2020 2019
Coal 38% 46% 64%
Renewables 62% 54% 36%
Coal and Consumables
AGR procures coal and consumables needed to burn the coal under a combination of purchasing arrangements including long-term and spot contracts with various producers and coal trading firms. As contracts expire, they are replaced, as needed, with contracts at market prices. Coal and consumable inventories remain adequate to meet generation requirements.
Management believes that AGR will be able to secure and transport coal and consumables of adequate quality and in adequate quantities to operate its coal-fired unit. AGR, through its contracts with third-party transporters, has the ability to adequately move and store coal and consumables for use in its generating facility. AGR plants consumed 1.2 million tons of coal in 2021.
The coal supplies at AGR’s plant vary from time to time depending on various factors, including, but not limited to, demand for electric power, unit outages, transportation infrastructure limitations, space limitations, plant coal consumption rates, coal quality, availability of acceptable coals, labor issues and weather conditions, which may interrupt production or deliveries. AGR aims to maintain the coal inventory of its managed plant in the range of 20 to 60 days of full load burn. As of December 31, 2021, the coal inventory of AGR was within the target range.
Counterparty Risk Management
Counterparties and exchanges may require cash or cash related instruments to be deposited on these transactions as margin against open positions. As of December 31, 2021, counterparties posted approximately $266 million in cash, cash equivalents or letters of credit with AEP for the benefit of AEP’s Generation & Marketing segment subsidiaries (while, as of that date, AEP’s Generation & Marketing segment subsidiaries posted approximately $113 million with counterparties and exchanges). Since open trading contracts are valued based on market prices of various commodities, exposures change daily. See the “Quantitative and Qualitative Disclosures About Market Risk” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2021 Annual Report for additional information.
Certain Power Agreements
As of December 31, 2021, the assets utilized in this segment included approximately 1,435 MWs of company-owned domestic wind power facilities and 148 MWs of domestic wind power from long-term purchase power agreements. Additional long term purchased power agreements have been entered into for 669 MWs of wind and 1,230 MWs of solar capacity which are all seeking permits or under construction. These agreements are all contingent on completion of construction which is expected by the end of 2024.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
The following persons are executive officers of AEP. Their ages are given as of February 24, 2022. The officers are appointed annually for a one-year term by the board of directors of AEP.
Nicholas K. Akins
Chairman of the Board, President and Chief Executive Officer
Age 61
Chairman of the Board since January 2014, President since January 2011 and Chief Executive Officer since November 2011.
Lisa M. Barton
Executive Vice President and Chief Operating Officer
Age 56
Chief Operating Officer since January 2021. Executive Vice President - Utilities from January 2019 to December 2020, Executive Vice President - Transmission from August 2011 to December 2018.
Paul Chodak, III
Executive Vice President - Generation
Age 58
Executive Vice President - Generation since January 2019. Executive Vice President - Utilities from January 2017 to December 2018. President and Chief Operating Officer of I&M from July 2010 to December 2016.
David M. Feinberg
Executive Vice President, General Counsel and Secretary
Age 52
Executive Vice President since January 2013. General Counsel and Secretary since January 2012.
Greg B. Hall
Executive Vice President - Energy Supply
Age 49
Executive Vice President - Energy Supply since July 2021. President and Chief Operating Officer of AEP Energy Supply LLC since July 2021. President of AEP Energy, Inc. since May 2017. President of AEP Energy Partners, Inc. since June 2007.
Charles R. Patton
Executive Vice President - External Affairs
Age 62
Executive Vice President - External Affairs since January 2017. President and Chief Operating Officer of APCo from June 2010 to December 2016.
Therace M. Risch
Executive Vice President and Chief Information & Technology Officer
Age 48
Executive Vice President since July 2021. Chief Information & Technology Officer since May 2020. Senior Vice President from April 2020 to July 2021.
Julia A. Sloat
Executive Vice President and Chief Financial Officer
Age 52
Executive Vice President and Chief Financial Officer since January 2021. Senior Vice President, Treasury & Risk and Treasurer from January 2019 to December 2020. President and Chief Operating Officer of OPCo from May 2016 to December 2018.
Charles E. Zebula
Executive Vice President - Portfolio Optimization
Age 61
Executive Vice President - Portfolio Optimization since July 2021. Executive Vice President - Energy Supply from January 2013 to July 2021.

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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS
GENERAL RISKS OF REGULATED OPERATIONS
AEP may not be able to recover the costs of substantial planned investment in capital improvements and additions. (Applies to all Registrants)
AEP’s business plan calls for extensive investment in capital improvements and additions, including the construction of additional transmission and renewable generation facilities, modernizing existing infrastructure, installation of environmental upgrades and retrofits as well as other initiatives. AEP’s public utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. If these regulatory commissions do not approve adjustments to the rates charged, affected AEP subsidiaries would not be able to recover the costs associated with their investments. This would cause financial results to be diminished.
Regulated electric revenues and earnings are dependent on federal and state regulation that may limit AEP’s ability to recover costs and other amounts. (Applies to all Registrants)
The rates customers pay to AEP regulated utility businesses are subject to approval by the FERC and the respective state utility commissions of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. In certain instances, AEP’s applicable regulated utility businesses may agree to negotiated settlements related to various rate matters that are subject to regulatory approval. AEP cannot predict the ultimate outcomes of any settlements or the actions by the FERC or the respective state commissions in establishing rates.
If regulated utility earnings exceed the returns established by the relevant commissions, retail electric rates may be subject to review and possible reduction by the commissions, which may decrease future earnings. Additionally, if regulatory bodies do not allow recovery of costs incurred in providing service on a timely basis, it could reduce future net income and cash flows and negatively impact financial condition. Similarly, if recovery or other rate relief authorized in the past is overturned or reversed on appeal, future earnings could be negatively impacted. Any regulatory action or litigation outcome that triggers a reversal of a regulatory asset or deferred cost generally results in an impairment to the balance sheet and a charge to the income statement of the company involved. See Note 4 - Rate Matters included in the 2021 Annual Report for additional information.
AEP’s transmission investment strategy and execution are dependent on federal and state regulatory policy. (Applies to all Registrants)
A significant portion of AEP’s earnings is derived from transmission investments and activities. FERC policy currently favors the expansion and updating of the transmission infrastructure within its jurisdiction. If the FERC were to adopt a different policy, if states were to limit or restrict such policies, or if transmission needs do not continue or develop as projected, AEP’s strategy of investing in transmission could be impacted. Management believes AEP’s experience with transmission facilities construction and operation gives AEP an advantage over other competitors in securing authorization to install, construct and operate new transmission lines and facilities. However, there can be no assurance that PJM, SPP, ERCOT or other RTOs will authorize new transmission projects or will award such projects to AEP.
Certain elements of AEP’s transmission formula rates have been challenged, which could result in lowered rates and/or refunds of amounts previously collected and thus have an adverse effect on AEP’s business, financial condition, results of operations and cash flows. (Applies to all Registrants other than AEP Texas)
AEP provides transmission service under rates regulated by the FERC. The FERC has approved the cost-based formula rate templates used by AEP to calculate its respective annual revenue requirements, but it has not expressly approved the amount of actual capital and operating expenditures to be used in the formula rates. All aspects of AEP’s rates accepted or approved by the FERC, including the formula rate templates, the rates of return on the
actual equity portion of its respective capital structures and the approved targeted capital structures, are subject to challenge by interested parties at the FERC, or by the FERC on its own initiative. In addition, interested parties may challenge the annual implementation and calculation by AEP of its projected rates and formula rate true-up pursuant to its approved formula rate templates under AEP’s formula rate implementation protocols. If a challenger can establish that any of these aspects are unjust, unreasonable, unduly discriminatory or preferential, then the FERC can make appropriate prospective adjustments to them and/or disallow any of AEP’s inclusion of those aspects in the rate setting formula.
Inquiries related to rates of return, as well as challenges to the formula rates of other utilities, are ongoing in other proceedings at the FERC. The results of these proceedings could potentially negatively impact AEP in any future challenges to AEP’s formula rates. If the FERC orders revenue reductions, including refunds, in any future cases related to its formula rates, it could reduce future net income and cash flows and impact financial condition.
End-use consumers and entities supplying electricity to end-use consumers may also attempt to influence government and/or regulators to change the rate setting methodologies that apply to AEP, particularly if rates for delivered electricity increase substantially.
AEP faces risks related to project siting, financing, construction, permitting, governmental approvals and the negotiation of project development agreements that may impede their development and operating activities. (Applies to all Registrants)
AEP owns, develops, constructs, manages and operates electric generation, transmission and distribution facilities. A key component of AEP's growth is its ability to construct and operate these facilities. As part of these operations AEP must periodically apply for licenses and permits from various local, state, federal and other regulatory authorities and abide by their respective conditions. Should AEP be unsuccessful in obtaining necessary licenses or permits on acceptable terms or resolving third-party challenges to such licenses or permits, should there be a delay in obtaining or renewing necessary licenses or permits or should regulatory authorities initiate any associated investigations or enforcement actions or impose related penalties or disallowances, it could reduce future net income and cash flows and impact financial condition. Any failure to negotiate successful project development agreements for new facilities with third-parties could have similar results.
Changes in technology and regulatory policies may lower the value of electric utility facilities and franchises. (Applies to all Registrants)
AEP primarily generates electricity at large central facilities and delivers that electricity to customers over its transmission and distribution facilities to customers usually situated within an exclusive franchise. This method results in economies of scale and generally lower costs than newer technologies such as fuel cells and microturbines, and distributed generation using either new or existing technology. Other technologies, such as light emitting diodes (LEDs), increase the efficiency of electricity and, as a result, lower the demand for it. Changes in regulatory policies and advances in batteries or energy storage, wind turbines and photovoltaic solar cells are reducing costs of new technology to levels that are making them competitive with some central station electricity production and delivery. These developments can challenge AEP’s competitive ability to maintain relatively low cost, efficient and reliable operations, to establish fair regulatory mechanisms and to provide cost-effective programs and services to customers. Further, in the event that alternative generation resources are mandated, subsidized or encouraged through legislation or regulation or otherwise are economically competitive and added to the available generation supply, such resources could displace a higher marginal cost generating units, which could reduce the price at which market participants sell their electricity.
AEP may not recover costs incurred to begin construction on projects that are canceled. (Applies to all Registrants)
AEP’s business plan for the construction of new projects involves a number of risks, including construction delays, non-performance by equipment and other third-party suppliers and increases in equipment and labor costs. To limit the risks of these construction projects, AEP’s subsidiaries enter into equipment purchase orders and construction contracts and incur engineering and design service costs in advance of receiving necessary regulatory approvals and/or siting or environmental permits. If any of these projects are canceled for any reason, including failure to receive necessary regulatory approvals and/or siting or environmental permits, significant cancellation penalties under the equipment purchase orders and construction contracts could occur. In addition, if any construction work or investments have been recorded as an asset, an impairment may need to be recorded in the event the project is canceled.
AEP is exposed to nuclear generation risk. (Applies to AEP and I&M)
I&M owns the Cook Plant, which consists of two nuclear generating units for a rated capacity of 2,296 MWs, or about 7% of the generating capacity in the AEP System. AEP and I&M are, therefore, subject to the risks of nuclear generation, which include the following:
•The potential harmful effects on the environment and human health due to an adverse incident/event resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials such as SNF.
•Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations.
•Uncertainties with respect to contingencies and assessment amounts triggered by a loss event (federal law requires owners of nuclear units to purchase the maximum available amount of nuclear liability insurance and potentially contribute to the coverage for losses of others).
•Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.
There can be no assurance that I&M’s preparations or risk mitigation measures will be adequate if these risks are triggered.
The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants. In addition, although management has no reason to anticipate a serious nuclear incident at the Cook Plant, if an incident did occur, it could harm results of operations or financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit. Moreover, a major incident at any nuclear facility in the U.S. could require AEP or I&M to make material contributory payments.
Costs associated with the operation (including fuel), maintenance and retirement of nuclear plants continue to be more significant and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements and safety standards, availability of nuclear waste disposal facilities and experience gained in the operation of nuclear facilities. Costs also may include replacement power, any unamortized investment at the end of the useful life of the Cook Plant (whether scheduled or premature), the carrying costs of that investment and retirement costs. The ability to obtain adequate and timely recovery of costs associated with the Cook Plant is not assured.
AEP subsidiaries are exposed to risks through participation in the market and transmission structures in various regional power markets that are beyond their control. (Applies to all Registrants)
Results are likely to be affected by differences in the market and transmission structures in various regional power markets. The rules governing the various RTOs, including SPP and PJM, may also change from time to time which could affect costs or revenues. Existing, new or changed rules of these RTOs could result in significant additional fees and increased costs to participate in those structures, including the cost of transmission facilities built by others due to changes in transmission rate design. In addition, these RTOs may assess costs resulting from improved transmission reliability, reduced transmission congestion and firm transmission rights. As members of these RTOs, AEP’s subsidiaries are subject to certain additional risks, including the allocation among existing members, of losses caused by unreimbursed defaults of other participants in these markets and resolution of complaint cases that may seek refunds of revenues previously earned by members of these markets.
AEP could be subject to higher costs and/or penalties related to mandatory reliability standards. (Applies to all Registrants)
Owners and operators of the bulk power transmission system are subject to mandatory reliability standards promulgated by the NERC and enforced by the FERC. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with new reliability standards may subject AEP to higher operating costs and/or increased capital expenditures. While management expects to recover costs and expenditures from customers through regulated rates, there can be no assurance that the applicable commissions will approve full recovery in a timely manner. If AEP were found not to be in compliance with the mandatory reliability standards, AEP could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates.
A substantial portion of the receivables of AEP Texas is concentrated in a small number of REPs, and any delay or default in payment could adversely affect its cash flows, financial condition and results of operations. (Applies to AEP and AEP Texas)
AEP Texas collects receivables from the distribution of electricity from REPs that supply the electricity it distributes to its customers. As of December 31, 2021, AEP Texas did business with approximately 123 REPs. Adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for these services or could cause them to delay such payments. AEP Texas depends on these REPs to remit payments on a timely basis. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. Applicable PUCT regulations significantly limit the extent to which AEP Texas can apply normal commercial terms or otherwise seek credit protection from firms desiring to provide retail electric service in its service territory, and AEP Texas thus remains at risk for payments related to services provided prior to the shift to another REP or the provider of last resort. In 2021, AEP Texas’ three largest REPs accounted for 43% of its operating revenue. Any delay or default in payment by REPs could adversely affect cash flows, financial condition and results of operations. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations, and claims might be made by creditors involving payments AEP Texas had received from such REP.
Ohio House Bill 6 (HB 6), which provides for beneficial cost recovery for OPCo and for plants owned by OVEC, has come under public scrutiny. (Applies to AEP and OPCo)
In 2019, Ohio adopted and implemented HB 6 which benefits OPCo by authorizing rate recovery for certain costs including renewable energy contracts, OVEC’s coal-fired generating units and energy efficiency measures. AEP and 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. The outcome of the U.S. Attorney’s Office investigation and its impact on HB 6 is not known. If certain provisions of HB 6 were to be eliminated, it is unclear whether new legislation addressing similar issues would be adopted. To the extent that OPCo is unable to recover the costs currently authorized by HB 6, it could reduce future net income and cash flows and impact financial condition. In addition, the impact of continued public scrutiny of HB 6 is not known, and may have an adverse impact on AEP and OPCo, including their relationship with regulatory and legislative authorities, customers and other stakeholders. AEP is a defendant in current litigation relating to HB6 and AEP or OPCo may be involved in future litigation.
RISKS RELATED TO MARKET, ECONOMIC OR FINANCIAL VOLATILITY AND OTHER RISKS
AEP’s financial condition and results of operations could continue to be adversely affected by the ongoing Coronavirus pandemic. (Applies to all Registrants)
The global 2019 novel coronavirus pandemic is an evolving situation that has caused and could continue to lead to extended disruption of economic activity in AEP’s markets. COVID-19 could negatively affect AEP’s ability to operate its generating and transmission and distribution assets, its ability to access capital markets and results of operations. AEP currently cannot estimate the potential impact to its financial position, results of operations and cash flows caused by COVID-19, which will depend on future developments and which are highly uncertain at this time. See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview for additional information on COVID-19.
AEP’s financial performance may be adversely affected if AEP is unable to successfully operate facilities or perform certain corporate functions. (Applies to all Registrants)
Performance is highly dependent on the successful operation of generation, transmission and/or distribution facilities. Operating these facilities involves many risks, including:
•Operator error and breakdown or failure of equipment or processes.
•Operating limitations that may be imposed by environmental or other regulatory requirements.
•Labor disputes.
•Compliance with mandatory reliability standards, including mandatory cyber security standards.
•Information technology failure that impairs AEP’s information technology infrastructure or disrupts normal business operations.
•Information technology failure that affects AEP’s ability to access customer information or causes loss of confidential or proprietary data that materially and adversely affects AEP’s reputation or exposes AEP to legal claims.
•Supply chain disruptions and inflation.
•Fuel or water supply interruptions caused by transportation constraints, adverse weather such as drought, non-performance by suppliers and other factors.
•Catastrophic events such as fires, earthquakes, explosions, hurricanes, tornados, ice storms, terrorism (including cyber-terrorism), floods or other similar occurrences.
•Fuel costs and related requirements triggered by financial stress in the coal industry.
Physical attacks or hostile cyber intrusions could severely impair operations, lead to the disclosure of confidential information and damage AEP’s reputation. (Applies to all Registrants)
AEP and its regulated utility businesses face physical security and cybersecurity risks as the owner-operators of generation, transmission and/or distribution facilities and as participants in commodities trading. AEP and its regulated utility businesses own assets deemed as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run these facilities are not completely isolated from external networks. Parties that wish to disrupt the U.S. bulk power system or AEP operations could view these computer systems, software or networks as targets for cyber-attack. In addition, the electric utility business requires the collection of sensitive customer data, as well as confidential employee and shareholder information, which is
subject to electronic theft or loss.
A security breach of AEP or its regulated utility businesses’ physical assets or information systems, interconnected entities in RTOs, or regulators could impact the operation of the generation fleet and/or reliability of the transmission and distribution system. AEP and its regulated utility businesses could be subject to financial harm associated with ransomware theft or inappropriate release of certain types of information, including sensitive customer, vendor, employee, trading or other confidential data. A successful cyber-attack on the systems that control generation, transmission, distribution or other assets could severely disrupt business operations, preventing service to customers or collection of revenues. The breach of certain business systems could affect the ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to AEP’s reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. AEP and its third-party vendors have been subject, and will likely continue to be subject, to attempts to gain unauthorized access to their technology systems and confidential data or to attempts to disrupt utility and related business operations. While there have been immaterial incidents of phishing, unauthorized access to technology systems, financial fraud, and disruption of remote access across the AEP System, there has been no material impact on business or operations from these attacks. However, the AEP cannot guarantee that security efforts will detect or prevent breaches, operational incidents, or other breakdowns of technology systems and network infrastructure and cannot provide any assurance that such incidents will not have a material adverse effect in the future.
The rate of taxes imposed on AEP could change. (Applies to all Registrants)
AEP is subject to income taxation at the federal level and by certain states and municipalities. In determining AEP’s income tax liability for these jurisdictions, management monitors changes to the applicable tax laws and related regulations. While management believes it is in compliance with current prevailing laws, one or more taxing jurisdictions could seek to impose incremental or new taxes on the company. In addition, the Biden administration has proposed and congressional leaders have considered significant changes in tax law and regulations that could result in additional federal income taxes being imposed on AEP. Any adverse developments in these laws or regulations, including legislative changes, judicial holdings or administrative interpretations, could have a material and adverse effect on financial condition and results of operations.
If AEP is unable to access capital markets or insurance markets on reasonable terms, it could reduce future net income and cash flows and negatively impact financial condition. (Applies to all Registrants)
AEP relies on access to capital markets as a significant source of liquidity for capital requirements not satisfied by operating cash flows or proceeds from the strategic sale of assets and investments, including subsidiaries such as the planned sale of KPCo and KTCo, and insurance markets to assist in managing its risk and liability profile. Volatility, increased interest rates and reduced liquidity in the financial markets could affect AEP’s ability to raise capital on reasonable terms to fund capital needs, including construction costs and refinancing maturing indebtedness. Certain sources of insurance and debt and equity capital have expressed increasing unwillingness to procure insurance for or to invest in companies, such as AEP, that rely on fossil fuels. Any planned sale of assets and investments, including subsidiaries, may not occur for any number of reasons beyond our control, including regulatory approval on terms that are acceptable. If sources of capital for AEP are reduced and/or expected sale proceeds do not become available, capital costs could increase materially. Restricted access to capital or insurance markets and/or increased borrowing costs or insurance premiums could reduce future net income and cash flows and negatively impact financial condition.
Shareholder activism could cause AEP to incur significant expense, hinder execution of AEP’s business strategy and impact AEP’s stock price. (Applies to all Registrants)
Shareholder activism, which can take many forms and arise in a variety of situations, could result in substantial costs and divert management’s and AEP’s board’s attention and resources from AEP’s business. Additionally, such
shareholder activism could give rise to perceived uncertainties as to AEP’s future, adversely affect AEP’s relationships with its employees, customers or service providers and make it more difficult to attract and retain qualified personnel. Also, AEP may be required to incur significant fees and other expenses related to activist shareholder matters, including for third-party advisors. AEP’s stock price could be subject to significant fluctuation or otherwise be adversely affected by the events, risks and uncertainties of any shareholder activism.
The announced phasing out of LIBOR may adversely affect the costs and availability of financing. (Applies to all Registrants)
A portion of the Registrants’ indebtedness bears interest at fluctuating interest rates, primarily based on the London interbank offered rate (“LIBOR”) for deposits of U.S. dollars. On November 30, 2020, the Federal Reserve and the Financial Conduct Authority in the United Kingdom announced that LIBOR would be phased out completely by June 20, 2023 and replaced by the Secured Overnight Financing Rate ("SOFR") and certain LIBOR maturities have already been phased out. However, because SOFR is a broad U.S. Treasury repo financing rate that represents overnight secured funding transactions, it differs fundamentally from U.S. dollar LIBOR and the SOFR market is not yet fully developed. In addition, the overall financial markets may be disrupted as a result of the phase-out or replacement of LIBOR. Uncertainty as to the nature of such phase-out and alternative reference rates or disruption in the financial market could cause interest rates to increase. If sources of capital for the Registrants are reduced, capital costs could increase materially. Restricted access to capital markets and/or increased borrowing costs could reduce future net income and cash flows and negatively impact financial condition and/or liquidity.
Downgrades in AEP’s credit ratings could negatively affect its ability to access capital. (Applies to all Registrants)
The credit ratings agencies periodically review AEP’s capital structure and the quality and stability of earnings and cash flows. Any negative ratings actions could constrain the capital available to AEP and could limit access to funding for operations. AEP’s business is capital intensive, and AEP is dependent upon the ability to access capital at rates and on terms management determines to be attractive. If AEP’s ability to access capital becomes significantly constrained, AEP’s interest costs will likely increase and could reduce future net income and cash flows and negatively impact financial condition.
AEP and AEPTCo have no income or cash flow apart from dividends paid or other payments due from their subsidiaries. (Applies to AEP and AEPTCo)
AEP and AEPTCo are holding companies and have no operations of their own. Their ability to meet their financial obligations associated with their indebtedness and to pay dividends is primarily dependent on the earnings and cash flows of their operating subsidiaries, primarily their regulated utilities, and the ability of their subsidiaries to pay dividends to, or repay loans from them. Their subsidiaries are separate and distinct legal entities that have no obligation (apart from loans from AEP or AEPTCo) to provide them with funds for their payment obligations, whether by dividends, distributions or other payments. Payments to AEP or AEPTCo by their subsidiaries are also contingent upon their earnings and business considerations. AEP and AEPTCo indebtedness and dividends are structurally subordinated to all subsidiary indebtedness.
AEP’s operating results may fluctuate on a seasonal or quarterly basis and with general economic and weather conditions. (Applies to all Registrants)
Electric power consumption is generally seasonal. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. As a result, overall operating results in the future may fluctuate substantially on a seasonal basis. In addition, AEP has historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could reduce future net income and cash flows and negatively impact financial condition. In addition, unusually extreme weather conditions could impact AEP’s results of operations in a manner that would not likely be sustainable.
Further, deteriorating economic conditions triggered by any cause, including international tariffs, generally result in reduced consumption by customers, particularly industrial customers who may curtail operations or cease production entirely, while an expanding economic environment generally results in increased revenues. As a result, prevailing economic conditions may reduce future net income and cash flows and negatively impact financial condition.
Volatility in the securities markets, interest rates, and other factors could substantially increase defined benefit pension and other postretirement plan costs and the costs of nuclear decommissioning. (Applies to all Registrants and to AEP and I&M with respect to the costs of nuclear decommissioning)
The costs of providing pension and other postretirement benefit plans are dependent on a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plan, changes in actuarial assumptions, future government regulation, changes in life expectancy and the frequency and amount of AEP’s required or voluntary contributions made to the plans. Changes in actuarial assumptions and differences between the assumptions and actual values, as well as a significant decline in the value of investments that fund the pension and other postretirement plans, if not offset or mitigated by a decline in plan liabilities, could increase pension and other postretirement expense, and AEP could be required from time to time to fund the pension plan with significant amounts of cash. Such cash funding obligations could have a material impact on liquidity by reducing cash flows and could negatively affect results of operations.
Additionally, I&M holds a significant amount of assets in its nuclear decommissioning trusts to satisfy obligations to decommission its nuclear plant. The rate of return on assets held in those trusts can significantly impact both the costs of decommissioning and the funding requirements for the trusts.
Supply chain disruptions and inflation could negatively impact our operations and corporate strategy. (Applies to all Registrants)
AEP’s operations and business plans depend on the global supply chain to procure the equipment, materials and other resources necessary to build and provide services in a safe and reliable manner. The delivery of components, materials, equipment and other resources that are critical to our business operations and corporate strategy has been restricted by the current domestic and global supply chain upheaval. This has resulted in the shortage of critical items. These disruptions and shortages could adversely impact both our business operations and corporate strategy. The constraints in the supply chain could restrict the availability and delay the construction, maintenance or repair of items that are needed to support normal operations or are required to execute on our corporate strategy for continued capital investment in utility equipment. These disruptions and constraints could reduce future net income and cash flows and possibly harm AEP’s financial condition.
Supply chain disruptions have contributed to higher prices of components, materials, equipment and other needed commodities and these inflationary increases may continue in the future. While inflation in the United States has been relatively low in recent years, during 2021, the economy in the United States encountered a material level of inflation. The impact of COVID-19 continues to increase uncertainty in the outlook of near-term economic activity, including whether inflation will continue and at what rate. AEP typically recovers increases in capital expenses from customers through rates in regulated jurisdictions. Failure to recover increased capital costs could reduce future net income and cash flows and possibly harm AEP’s financial condition. Increases in inflation raises our costs for labor, materials and services, and failure to secure these on reasonable terms may adversely impact our financial condition.
AEP’s results of operations and cash flows may be negatively affected by a lack of growth or slower growth in the number of customers, or decline in customer demand. (Applies to all Registrants)
Growth in customer accounts and growth of customer usage each directly influence demand for electricity and the need for additional power generation and delivery facilities. Customer growth and customer usage are affected by a number of factors outside the control of AEP, such as mandated energy efficiency measures, demand-side
management goals, distributed generation resources and economic and demographic conditions, such as population changes, job and income growth, housing starts, new business formation and the overall level of economic activity, including changes due to public health considerations.
Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to further reduce energy consumption. Additionally, technological advances or other improvements in or applications of technology could lead to declines in per capita energy consumption. Some or all of these factors, could impact the demand for electricity.
Failure to attract and retain an appropriately qualified workforce could harm results of operations. (Applies to all Registrants)
Certain events, such as an aging workforce without appropriate replacements, employee reaction to comply with potential COVID-19 vaccination or testing mandates, mismatch of skillset or complement to future needs, or unavailability of contract resources may lead to operating challenges and increased costs. The challenges include potential higher rates of existing employee departures, lack of resources, loss of knowledge and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs, safety costs and costs of compliance with potential COVID-19 vaccination or testing mandates, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate the business. If AEP is unable to successfully attract and retain an appropriately qualified workforce, future net income and cash flows may be reduced.
Changes in the price of commodities, the cost of procuring fuel, emission allowances for criteria pollutants and the costs of transport may increase AEP’s cost of producing power, impacting financial performance. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)
AEP is exposed to changes in the price and availability of fuel (including the cost to procure coal and gas) and the price and availability to transport fuel. AEP has existing contracts of varying durations for the supply of fuel, but as these contracts end or if they are not honored, AEP may not be able to purchase fuel on terms as favorable as the current contracts. The inability to procure fuel at costs that are economical could cause AEP to retire generating capacity prior to the end of its useful life, and while AEP typically recovers expenditures for undepreciated plant balances, there can be no assurance in the future that AEP will recover such costs. Similarly, AEP is exposed to changes in the price and availability of emission allowances. AEP uses emission allowances based on the amount of fuel used and reductions achieved through emission controls and other measures. Based on current environmental programs remaining in effect, AEP has sufficient emission allowances to cover the majority of the projected needs for the next two years and beyond. Additional costs may be incurred either to acquire additional allowances or to achieve further reductions in emissions. If AEP needs to obtain allowances, those purchases may not be on as favorable terms as those under the current environmental programs. AEP’s risks relative to the price and availability to transport coal include the volatility of the price of diesel which is the primary fuel used in transporting coal by barge.
Prices for coal, natural gas and emission allowances have shown material swings in the past. Changes in the cost of fuel, emission allowances or natural gas and changes in the relationship between such costs and the market prices of power could reduce future net income and cash flows and negatively impact financial condition.
In addition, actual power prices and fuel costs will differ from those assumed in financial projections used to value trading and marketing transactions, and those differences may be material. As a result, as those transactions are marked-to-market, they may impact future results of operations and cash flows and impact financial condition.
AEP is subject to physical and financial risks associated with climate change. (Applies to all Registrants)
Climate change creates physical and financial risk. Physical risks from climate change may include an increase in sea level and changes in weather conditions, such as changes in precipitation and extreme weather events, such as fires. Customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes.
Increased energy use due to weather changes may require AEP to invest in additional generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may affect financial condition through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions. Weather conditions outside of the AEP service territory could also have an impact on revenues. AEP buys and sells electricity depending upon system needs and market opportunities. Extreme weather conditions creating high energy demand on AEP’s own and/or other systems may raise electricity prices as AEP buys short-term energy to serve AEP’s own system, which would increase the cost of energy AEP provides to customers.
Severe weather and weather-related events impact AEP’s service territories, primarily when thunderstorms, tornadoes, hurricanes, fires, floods and snow or ice storms occur. To the extent the frequency and intensity of extreme weather events and storms increase, AEP’s cost of providing service will increase, including the costs and the availability of procuring insurance related to such impacts, and these costs may not be recoverable. Changes in precipitation resulting in droughts, water shortages or floods could adversely affect operations, principally the fossil fuel generating units. A negative impact to water supplies due to long-term drought conditions or severe flooding could adversely impact AEP’s ability to provide electricity to customers, as well as increase the price they pay for energy. AEP may not recover all costs related to mitigating these physical and financial risks.
To the extent climate change impacts a region’s economic health, it may also impact revenues. AEP’s financial performance is tied to the health of the regional economies AEP serves. The price of energy, as a factor in a region’s cost of living as well as an important input into the cost of goods and services, has an impact on the economic health of the communities within the AEP System.
Management cannot predict the outcome of the legal proceedings relating to AEP’s business activities. (Applies to all Registrants)
AEP is involved in legal proceedings, claims and litigation arising out of its business operations, the most significant of which are summarized in Note 6 - Commitments, Guarantees and Contingencies included in the 2021 Annual Report. Adverse outcomes in these proceedings could require significant expenditures that could reduce future net income and cash flows and negatively impact financial condition.
Disruptions at power generation facilities owned by third-parties could interrupt the sales of transmission and distribution services. (Applies to AEP and AEP Texas)
AEP Texas transmits and distributes electric power that the REPs obtain from power generation facilities owned by third-parties. If power generation is disrupted or if power generation capacity is inadequate, sales of transmission and distribution services may be diminished or interrupted, and results of operations, financial condition and cash flows could be adversely affected.
Management is unable to predict the course, results or impact, if any, of current or future litigation or investigations relating to the extreme winter weather in Texas in February 2021. (Applies to AEP and AEP Texas)
As a result of the February 2021 severe winter weather in Texas which caused a shortage of electric generation, ERCOT instructed AEP Texas and other Texas electric utilities to initiate power outages to avoid a sustained large-scale outage and prevent long-term damage to the electric system. At its peak, approximately 468,000 (44%) AEP Texas customers were without power.
AEP Texas and other AEP entities are named in approximately 100 lawsuits generally alleging the failure to exercise reasonable care in maintaining and updating their generation, transmission and distribution facilities in order to prevent cold weather failures and other related negligence. The complaints seek monetary damages among other forms of relief. In February 2021, AEP Texas received a Civil Investigative Demand from the Office of the Attorney General of Texas requesting, among other data, information about its communications to and from ERCOT, PUCT, retail electric providers, utilities, or power generation companies, concerning power outages related to the February 2021 winter storm. The company responded to the Civil Investigative Demand in March 2021. Management is unable to predict the course or outcome of these or any future litigation or investigations or their impact, if any, on future results of operations, financial condition and cash flows.
Hazards associated with high-voltage electricity transmission may result in suspension of AEP’s operations or the imposition of civil or criminal penalties. (Applies to all Registrants)
AEP operations are subject to the usual hazards associated with high-voltage electricity transmission, including explosions, fires, inclement weather, natural disasters, mechanical failure, unscheduled downtime, equipment interruptions, remediation, chemical spills, discharges or releases of toxic or hazardous substances or gases and other environmental risks. The hazards can cause personal injury and loss of life, severe damage to or destruction of property and equipment and environmental damage, and may result in suspension of operations and the imposition of civil or criminal penalties. AEP maintains property and casualty insurance, but AEP is not fully insured against all potential hazards incident to AEP’s business, such as damage to poles, towers and lines or losses caused by outages.
AEPTCo depends on its affiliates in the AEP System for a substantial portion of its revenues. (Applies to AEPTCo)
AEPTCo’s principal transmission service customers are its affiliates in the AEP System. Management expects that these affiliates will continue to be AEPTCo’s principal transmission service customers for the foreseeable future. For the year ended December 31, 2021, its affiliates were responsible for approximately 79% of the consolidated transmission revenues of AEPTCo.
Most of the real property rights on which the assets of AEPTCo are situated result from affiliate license agreements and are dependent on the terms of the underlying easements and other rights of its affiliates. (Applies to AEPTCo)
AEPTCo does not hold title to the majority of real property on which its electric transmission assets are located. Instead, under the provisions of certain affiliate contracts, it is permitted to occupy and maintain its facilities upon real property held by the respective AEP System utility affiliate that overlay its operations. The ability of AEPTCo to continue to occupy such real property is dependent upon the terms of such affiliate contracts and upon the underlying real property rights of these utility affiliates, which may be encumbered by easements, mineral rights and other similar encumbrances that may affect the use of such real property. AEP can give no assurance that (a) the relevant AEP System utility affiliates will continue to be affiliates of AEPTCo, (b) suitable replacement arrangements can be obtained in the event that the relevant AEP System utility affiliates are not its affiliates and (c) the underlying easements and other rights are sufficient to permit AEPTCo to operate its assets in a manner free from interruption.
Compliance with legislative and regulatory requirements may lead to increased costs and result in penalties. (Applies to all Registrants)
Business activities of electric utilities and related companies are heavily regulated, primarily through national and state laws and regulations of general applicability, including laws and regulations related to working conditions, health and safety, equal employment opportunity, employee benefit and other labor and employment matters, laws and regulations related to competition and antitrust matters. Many agencies employ mandatory civil penalty structures for regulatory violations. Registrants are subject to the jurisdiction of many federal and state agencies, including the FERC, NERC, Commodities Futures Trading Commission, Federal EPA, NRC, Occupational Safety and Health Administration, the SEC and the United States Department of Justice which may impose significant civil and criminal penalties to enforce compliance requirements relative to AEP’s business, which could have a material adverse effect on financial operating results including earnings, cash flow and liquidity.
The impact of new laws, regulations and policies and the related interpretations, as well as changes in enforcement practices or regulatory scrutiny generally cannot be predicted, and changes in applicable laws, regulations and policies and the related interpretations and enforcement practices may require extensive system and operational changes, be difficult to implement, increase AEP’s operating costs, require significant capital expenditures, or adversely impact the cost or attractiveness of the products or services AEP offers, or result in adverse publicity and harm AEP’s reputation.
RISKS RELATED TO OWNING AND OPERATING GENERATION ASSETS AND SELLING POWER
Costs of compliance with existing and evolving environmental laws are significant. (Applies to all Registrants except AEPTCo)
Operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and health and safety. A majority of the electricity generated by the AEP System is produced by the combustion of fossil fuels. Emissions of nitrogen and sulfur oxides, mercury and particulates and the discharge and disposal of solid waste (including coal-combustion residuals or CCR) resulting from fossil fueled generation plants are subject to increased regulations, controls and mitigation expenses. Compliance with these legal requirements (including any new and more stringent application of existing CCR regulations) requires AEP to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees, disposal, remediation and permits at AEP facilities and could cause AEP to retire generating capacity prior to the end of its estimated useful life. Costs of compliance with environmental statutes and regulations could reduce future net income and negatively impact financial condition, especially if emission limits, CCR waste discharge and/or discharge disposal obligations are tightened, more extensive operating and/or permitting requirements are imposed or additional substances or facilities become regulated. Although AEP typically recovers expenditures for pollution control technologies, replacement generation, undepreciated plant balances and associated operating costs from customers, there can be no assurance in the future that AEP will recover the remaining costs associated with such plants. Failure to recover these costs could reduce future net income and cash flows and possibly harm financial condition.
Regulation of CO2 emissions could materially increase costs to AEP and its customers or cause some electric generating units to be uneconomical to operate or maintain. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)
To date, federal court decisions have blocked Federal EPA’s attempts to regulate CO2 emissions from existing utility units. While there are no federal CO2 regulations in effect at present, the current administration has announced addressing climate change as a policy priority. Costs of compliance with the environmental regulation of CO2 emissions, if any, could reduce future net income and negatively impact financial condition and/or could cause AEP to retire generating capacity prior to the end of its estimated useful life. Although AEP typically recovers environmental expenditures, there can be no assurance in the future that AEP can recover such costs which could reduce future net income and cash flows and possibly harm financial condition.
Courts adjudicating nuisance and other similar claims in the future may order AEP to pay damages or to limit or reduce emissions. (Applies to all Registrants except AEP Texas and AEPTCo)
In the past, there have been several cases seeking damages based on allegations of federal and state common law nuisance in which AEP, among others, were defendants. In general, the actions allege that emissions from the defendants’ power plants constitute a public nuisance. The plaintiffs in these actions generally seek recovery of damages and other relief. If future actions are resolved against AEP, substantial modifications or retirement of AEP’s existing coal-fired power plants could be required, and AEP might be required to purchase power from third-parties to fulfill AEP’s commitments to supply power to AEP customers. This could have a material impact on revenues. In addition, AEP could be required to invest significantly in additional emission control equipment, accelerate the timing of capital expenditures, pay damages or penalties and/or halt operations. Unless recovered, those costs could reduce future net income and cash flows and harm financial condition. Moreover, results of operations and financial position could be reduced due to the timing of recovery of these investments and the expense of ongoing litigation.
Commodity trading and marketing activities are subject to inherent risks which can be reduced and controlled but not eliminated. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)
AEP routinely has open trading positions in the market, within guidelines set by AEP, resulting from the management of AEP’s trading portfolio. To the extent open trading positions exist, fluctuating commodity prices can improve or diminish financial results and financial position.
AEP’s power trading activities also expose AEP to risks of commodity price movements. To the extent that AEP’s power trading does not hedge the price risk associated with the generation it owns, or controls, AEP would be exposed to the risk of rising and falling spot market prices.
In connection with these trading activities, AEP routinely enters into financial contracts, including futures and options, OTC options, financially-settled swaps and other derivative contracts. These activities expose AEP to risks from price movements. If the values of the financial contracts change in a manner AEP does not anticipate, it could harm financial position or reduce the financial contribution of trading operations.
Parties with whom AEP has contracts may fail to perform their obligations, which could harm AEP’s results of operations. (Applies to all Registrants)
AEP sells power from its generation facilities into the spot market and other competitive power markets on a contractual basis. AEP also enters into contracts to purchase and sell electricity, natural gas, emission allowances, renewable energy credits and coal as part of its power marketing and energy trading operations. AEP is exposed to the risk that counterparties that owe AEP money or the delivery of a commodity, including power, could breach their obligations. Should the counterparties to these arrangements fail to perform, AEP may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices that may exceed AEP’s contractual prices, which would cause financial results to be diminished and AEP might incur losses. Although estimates take into account the expected probability of default by a counterparty, actual exposure to a default by a counterparty may be greater than the estimates predict.
AEP relies on electric transmission facilities that AEP does not own or control. If these facilities do not provide AEP with adequate transmission capacity, AEP may not be able to deliver wholesale electric power to the purchasers of AEP’s power. (Applies to all Registrants)
AEP depends on transmission facilities owned and operated by other nonaffiliated power companies to deliver the power AEP sells at wholesale. This dependence exposes AEP to a variety of risks. If transmission is disrupted, or transmission capacity is inadequate, AEP may not be able to sell and deliver AEP wholesale power. If a region’s power transmission infrastructure is inadequate, AEP’s recovery of wholesale costs and profits may be limited. If
restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure.
The FERC has issued electric transmission initiatives that require electric transmission services to be offered unbundled from commodity sales. Although these initiatives are designed to encourage wholesale market transactions, access to transmission systems may not be available if transmission capacity is insufficient because of physical constraints or because it is contractually unavailable. Management also cannot predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets.
OVEC may require additional liquidity and other capital support. (Applies to AEP, APCo, I&M and OPCo)
AEP and several nonaffiliated utility companies own OVEC. The Inter-Company Power Agreement (ICPA) defines the rights and obligations and sets the power participation ratio of the parties to it. Under the ICPA, parties are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,400 MWs) in proportion to their respective power participation ratios. The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%. If a party fails to make payments owed by it under the ICPA, OVEC may not have sufficient funds to honor its payment obligations, including its ongoing operating expenses as well as its indebtedness. As of December 31, 2021, OVEC has outstanding indebtedness of approximately $1.1 billion, of which APCo, I&M, and OPCo are collectively responsible for $492 million through the ICPA. Although they are not an obligor or guarantor, APCo, I&M, and OPCo are responsible for their respective ratio of OVEC’s outstanding debt through the ICPA and if OVEC’s indebtedness is accelerated for any reason, there is risk that APCo, I&M and/or OPCo may be required to pay some or all of such accelerated indebtedness in amounts equal to their aggregate power participation ratio of 43.47%.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

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ITEM 2. PROPERTIES
ITEM 2. PROPERTIES
GENERATION FACILITIES
As of December 31, 2021, the AEP System owned (or leased where indicated) generation plants, with locations and net maximum power capabilities (winter rating), are shown in the following tables:
Vertically Integrated Utilities Segment
AEGCo
Plant Name Units State Fuel Type Net Maximum
Capacity (MWs) Year Plant
or First Unit Commissioned
Rockport, Units 1 and 2 - 50% of each (a) 2 IN Steam - Coal 1,310 1984
(a)Rockport Plant, Unit 2 is leased. In April 2021, AEGCo and I&M executed an agreement to purchase 100% of the interests in Rockport Plant, Unit 2 effective at the end of the lease term in December 2022.
APCo
Plant Name Units State Fuel Type Net Maximum
Capacity (MWs) Year Plant
or First Unit Commissioned
Buck 3 VA Hydro 11 1912
Byllesby 4 VA Hydro 19 1912
Claytor 4 VA Hydro 76 1939
Leesville 2 VA Hydro 50 1964
London 3 WV Hydro 14 1935
Marmet 3 WV Hydro 14 1935
Niagara 2 VA Hydro 1 1906
Winfield 3 WV Hydro 15 1938
Ceredo 6 WV Natural Gas 516 2001
Dresden 3 OH Natural Gas 665 2012
Smith Mountain 5 VA Pumped Storage 585 1965
Amos 3 WV Steam - Coal 2,930 1971
Mountaineer 1 WV Steam - Coal 1,320 1980
Clinch River 2 VA Steam - Natural Gas 465 1958
Total MWs 6,681
I&M
Plant Name Units State Fuel Type Net Maximum
Capacity (MWs) Year Plant
or First Unit Commissioned
Berrien Springs 12 MI Hydro 7 1908
Buchanan 10 MI Hydro 3 1919
Constantine 4 MI Hydro 1 1921
Elkhart 3 IN Hydro 3 1913
Mottville 4 MI Hydro 2 1923
Twin Branch Hydro 8 IN Hydro 4 1904
Deer Creek Solar Farm NA IN Solar 3 2016
Olive Solar Farm NA IN Solar 5 2016
St. Joseph NA IN Solar 20 2021
Twin Branch Solar Farm NA IN Solar 3 2016
Watervliet NA MI Solar 5 2016
Rockport (Units 1 and 2, 50% of each) (a)
2 IN Steam - Coal 1,310 1984
Cook 2 MI Steam - Nuclear 2,296 1975
Total MWs 3,662
(a)Rockport Plant, Unit 2 is leased. In April 2021, AEGCo and I&M executed an agreement to purchase 100% of the interests in Rockport Plant, Unit 2 effective at the end of the lease term in December 2022.
NA Not applicable.
The following table provides operating information related to the Cook Plant:
Cook Plant
Unit 1 Unit 2
Year Placed in Operation 1975 1978
Year of Expiration of NRC License 2034 2037
Nominal Net Electrical Rating in MWs 1,084 1,212
Annual Capacity Utilization
2021 96.0 % 84.2 %
2020 87.2 % 94.2 %
2019 77.3 % 84.3 %
KPCo
Plant Name Units State Fuel Type Net Maximum
Capacity (MWs) Year Plant
or First Unit Commissioned
Mitchell (a)(b) 2 WV Steam - Coal 780 1971
Big Sandy 1 KY Steam - Natural Gas 295 1963
Total MWs 1,075
(a)KPCo owns a 50% interest in the Mitchell Plant units. WPCo owns the remaining 50%. Figures presented reflect only the portion owned by KPCo.
(b)In November 2021, KPCo made filings with KPSC, WVPSC and FERC to approve a new proposed Mitchell Plant Operations and Maintenance Agreement and Mitchell Plant Ownership Agreement between KPCo and WPCo pursuant to which WPCo will replace KPCo as the operator of Mitchell Plant. See “Dispositions of KPCo and KTCo” section of Note 7 included in the 2021 Annual Report for additional information.
PSO
Plant Name Units State Fuel Type Net Maximum
Capacity (MWs) Year Plant
or First Unit Commissioned
Comanche 3 OK Natural Gas 248 1973
Northeastern, Unit 1 1 OK Natural Gas 470 1961
Riverside, Units 3 and 4 2 OK Natural Gas 160 2008
Southwestern, Units 4 and 5 2 OK Natural Gas 168 2008
Weleetka 2 OK Natural Gas 100 1975
Northeastern, Unit 3 1 OK Steam - Coal 465 1979
Northeastern, Unit 2 1 OK Steam - Natural Gas 434 1961
Riverside, Units 1 and 2 2 OK Steam - Natural Gas 896 1974
Southwestern, Units 1, 2 and 3 3 OK Steam - Natural Gas 446 1952
Tulsa 2 OK Steam - Natural Gas 322 1956
Maverick (a) NA OK Wind 131 2021
Sundance (a) NA OK Wind 91 2021
Total MWs 3,931
(a)SWEPCo owns a 54.5% interest and PSO owns the remaining 45.5% interest in Sundance and Maverick.
NA Not applicable.
SWEPCo
Plant Name Units State Fuel Type Net Maximum
Capacity (MWs) Year Plant
or First Unit Commissioned
Mattison 4 AR Natural Gas 314 2007
Stall 3 LA Natural Gas 534 2010
Flint Creek (a) 1 AR Steam - Coal 258 1978
Turk (a) 1 AR Steam - Coal 477 2012
Welsh (b) 2 TX Steam - Coal 1,053 1977
Pirkey (a)(c) 1 TX Steam - Lignite 580 1985
Arsenal Hill 1 LA Steam - Natural Gas 110 1960
Knox Lee 1 TX Steam - Natural Gas 344 1950
Lieberman 3 LA Steam - Natural Gas 217 1947
Wilkes 3 TX Steam - Natural Gas 889 1964
Maverick (d) NA OK Wind 156 2021
Sundance (d) NA OK Wind 108 2021
Total MWs 5,040
(a)Jointly-owned with nonaffiliated entities. Figures presented reflect only the portion owned by SWEPCo. The Arkansas jurisdictional portion of SWEPCo’s interest in Turk Plant is not in rate base.
(b)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028.
(c)In November 2020, management announced plans to retire the plant in 2023.
(d)SWEPCo owns a 54.5% interest and PSO owns the remaining 45.5% interest in Sundance and Maverick.
NA Not applicable.
WPCo
Plant Name Units State Fuel Type Net Maximum
Capacity (MWs) Year Plant
or First Unit Commissioned
Mitchell (a)(b) 2 WV Steam - Coal 780 1971
(a)WPCo owns 50% in the Mitchell Plant units. KPCo owns the remaining 50%. Figures presented reflect only the portion owned by WPCo.
(b)In November 2021, KPCo made filings with KPSC, WVPSC and FERC to approve a new proposed Mitchell Plant Operations and Maintenance Agreement and Mitchell Plant Ownership Agreement between KPCo and WPCo pursuant to which WPCo will replace KPCo as the operator of Mitchell Plant. See “Dispositions of KPCo and KTCo” section of Note 7 included in the 2021 Annual Report for additional information.
Generation & Marketing Segment
AGR
Plant Name Units State Fuel Type Net Maximum
Capacity (MWs) Year Plant
or First Unit Commissioned
Cardinal 1 OH Steam - Coal 595 1967
Renewable Power
Size of Energy Resource AEP Energy Supply, LLC Division Renewable
Energy Resource Location In-Service or
Under Construction
1,435 MW AEP Renewables Wind Eight states (a) In-service
20 MW AEP Renewables Solar California In-service
20 MW AEP Renewables Solar Utah In-service
125 MW AEP Renewables Solar Nevada In-service
161 MW AEP OnSite Partners Solar Seventeen states (b) In-service
27 MW AEP OnSite Partners Solar Two states (c) Under Construction
(a) Colorado, Hawaii, Indiana, Kansas, Michigan, Minnesota, Pennsylvania and Texas.
(b) California, Colorado, Florida, Hawaii, Illinois, Iowa, Minnesota, Nebraska, New Hampshire, New Jersey, New Mexico, New York, Ohio, Rhode Island, Texas, Vermont and Wisconsin.
(c) Ohio and New Mexico.
TRANSMISSION AND DISTRIBUTION FACILITIES
The following tables set forth the total overhead circuit miles of transmission and distribution lines of the AEP System and its operating companies.
Vertically Integrated Utilities Segment
Total Overhead Circuit Miles of Transmission and Distribution Lines
APCo 51,714
I&M 20,943
KGPCo 1,408
KPCo 11,166
PSO 18,145
SWEPCo 26,162
WPCo 1,730
Total Circuit Miles 131,268
Transmission and Distribution Utilities Segment
Total Overhead Circuit Miles of Transmission and Distribution Lines
OPCo 44,703
AEP Texas 46,353
Total Circuit Miles 91,056
AEP Transmission Holdco Segment
The following table sets forth the total overhead circuit miles of transmission lines of certain wholly-owned and joint venture-owned entities:
Total Overhead Circuit Miles of Transmission Lines
ETT 1,883
IMTCo 990
OHTCo 1,026
OKTCo 1,015
WVTCo 261
Pioneer 43
Prairie Wind Transmission 216
Transource Missouri 167
Transource West Virginia 27
Total Circuit Miles 5,628
TITLE TO PROPERTY
The AEP System’s generating facilities are generally located on lands owned in fee simple. The greater portion of the transmission and distribution lines of the AEP System has been constructed over lands of private owners pursuant to easements or along public highways and streets pursuant to appropriate statutory authority. The rights of AEP’s public utility subsidiaries in the realty on which their facilities are located are considered adequate for use in the conduct of their business. Minor defects and irregularities customarily found in title to properties of like size and character may exist, but such defects and irregularities do not materially impair the use of the properties. AEP’s public utility subsidiaries generally have the right of eminent domain which permits them, if necessary, to acquire, perfect or secure titles to or easements on privately held lands used or to be used in their utility operations.
SYSTEM TRANSMISSION LINES AND FACILITY SITING
Laws in the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Tennessee, Texas, Virginia and West Virginia require prior approval of sites of generating facilities and/or routes of high-voltage transmission lines. AEP has experienced delays and additional costs in constructing facilities as a result of proceedings conducted pursuant to such statutes and in proceedings in which AEP’s operating companies have sought to acquire rights-of-way through condemnation. These proceedings may result in additional delays and costs in future years.
CONSTRUCTION PROGRAM
With input from its state utility commissions, the AEP System continuously assesses the adequacy of its transmission, distribution, generation and other facilities to plan and provide for the reliable supply of electric power and energy to its customers. In this assessment process, assumptions are continually being reviewed as new information becomes available and assessments and plans are modified, as appropriate. AEP forecasts approximately $7.6 billion of construction expenditures for 2022. Estimated construction 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. See the “Budgeted Capital Expenditures” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2021 Annual Report for additional information.
POTENTIAL UNINSURED LOSSES
Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including liabilities relating to damage to AEP’s generation plants and costs of replacement power. Unless allowed to be recovered through rates, future losses or liabilities which are not completely insured could reduce net income and impact the financial conditions of AEP and other AEP System companies. For risks related to owning a nuclear generating unit, see the “Nuclear Contingencies” section of Note 6 - Commitments, Guarantees and Contingencies included in the 2021 Annual Report for additional information.

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS
For a discussion of material legal proceedings, see Note 6 - Commitments, Guarantees and Contingencies included in the 2021 Annual Report for additional information.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURE
The Federal Mine Safety and Health Act of 1977 (Mine Act) imposes stringent health and safety standards on various mining operations. The Mine Act and its related regulations affect numerous aspects of mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans and other matters. SWEPCo, through its ownership of DHLC, a wholly-owned lignite mining subsidiary of SWEPCo, is subject to the provisions of the Mine Act.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. Exhibit 95 “Mine Safety Disclosure Exhibit” contains the notices of violation and proposed assessments received by DHLC under the Mine Act for the quarter ended December 31, 2021.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
AEP
In addition to the AEP Common Stock Information section below, the remaining information required by this item is incorporated herein by reference to the material under the “Dividend Policy and Restrictions” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2021 Annual Report.
During the quarter ended December 31, 2021, neither AEP nor its publicly-traded subsidiaries purchased equity securities that are registered by AEP or its publicly-traded subsidiaries pursuant to Section 12 of the Exchange Act.
AEP Texas, APCo, I&M, OPCo, PSO and SWEPCo
The common stock of these companies is held solely by AEP. For more information see the “Dividend Restrictions” section of Note 14 - Financing Activities included in the 2021 Annual Report.
AEPTCo
AEP owns the entire interest in AEPTCo through its wholly-owned subsidiary AEP Transmission Holdco.
AEP COMMON STOCK INFORMATION
AEP common stock is principally traded using the trading symbol “AEP” on the NASDAQ Stock Market. As of December 31, 2021, AEP had 53,124 registered shareholders. The performance graph below compares the cumulative total return among AEP, the S&P 500 Index and the S&P Electric Utilities (SP833) Index over a five year period. The performance graph assumes an initial investment of $100 on December 31, 2016 and that all dividends were reinvested.
Source: S&P Dow Jones Indices LLC. Data as of December 31, 2021. Past performance is no guarantee of future results. Chart provided for illustrative purposes.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. RESERVED

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
AEP
The information required by this item is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2021 Annual Report. Year-to-year comparisons between 2020 and 2019 have been omitted from this Form 10-K but may be found in "Management's Discussion and Analysis of Financial Condition" in Part II, Item 7 of our Form 10-K for the fiscal year ended December 31, 2020, which specific discussion is incorporated herein by reference.
AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo
Omitted pursuant to Instruction I(2)(a). Management’s narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2021 Annual Report.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo
The information required by this item is incorporated herein by reference to the material under the “Quantitative and Qualitative Disclosures About Market Risk” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2021 Annual Report.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
2021 Annual Reports
American Electric Power Company, Inc. and Subsidiary Companies
AEP Texas Inc. and Subsidiaries
AEP Transmission Company, LLC and Subsidiaries
Appalachian Power Company and Subsidiaries
Indiana Michigan Power Company and Subsidiaries
Ohio Power Company and Subsidiaries
Public Service Company of Oklahoma
Southwestern Electric Power Company Consolidated
Audited Financial Statements and
Management’s Discussion and Analysis of Financial Condition and Results of Operations
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF ANNUAL REPORTS
Page
Number
American Electric Power Company, Inc. and Subsidiary Companies:
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Report of Independent Registered Public Accounting Firm (PCAOB ID 238)
Management’s Report on Internal Control Over Financial Reporting 129
Consolidated Financial Statements
AEP Texas Inc. and Subsidiaries:
Management’s Narrative Discussion and Analysis of Results of Operations 137
Report of Independent Registered Public Accounting Firm (PCAOB ID 238)
Management’s Report on Internal Control Over Financial Reporting 142
Consolidated Financial Statements 143
AEP Transmission Company, LLC and Subsidiaries:
Management’s Narrative Discussion and Analysis of Results of Operations 150
Report of Independent Registered Public Accounting Firm (PCAOB ID 238)
Management’s Report on Internal Control Over Financial Reporting 154
Consolidated Financial Statements 155
Appalachian Power Company and Subsidiaries:
Management’s Narrative Discussion and Analysis of Results of Operations
Report of Independent Registered Public Accounting Firm (PCAOB ID 238)
Management’s Report on Internal Control Over Financial Reporting 166
Consolidated Financial Statements
Indiana Michigan Power Company and Subsidiaries:
Management’s Narrative Discussion and Analysis of Results of Operations
Report of Independent Registered Public Accounting Firm (PCAOB ID 238)
Management’s Report on Internal Control Over Financial Reporting 179
Consolidated Financial Statements
Ohio Power Company and Subsidiaries:
Management’s Narrative Discussion and Analysis of Results of Operations
Report of Independent Registered Public Accounting Firm (PCAOB ID 238)
Management’s Report on Internal Control Over Financial Reporting 193
Consolidated Financial Statements
Public Service Company of Oklahoma:
Management’s Narrative Discussion and Analysis of Results of Operations
Report of Independent Registered Public Accounting Firm (PCAOB ID 238)
Management’s Report on Internal Control Over Financial Reporting 206
Financial Statements
Southwestern Electric Power Company Consolidated:
Management’s Narrative Discussion and Analysis of Results of Operations
Report of Independent Registered Public Accounting Firm (PCAOB ID 238)
Management’s Report on Internal Control Over Financial Reporting 219
Consolidated Financial Statements
Index of Notes to Financial Statements of Registrants
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
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.
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.
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.
•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.
•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.
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.
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
Approved Revenue Approved New Rates
Company Jurisdiction Requirement Increase (Decrease) ROE Effective
(in millions)
KPCo Kentucky $ 52.7 (a) 9.3% January 2021
OPCo Ohio (68.1) (b) 9.7% December 2021
SWEPCo Texas 39.4 (c) 9.25% March 2021
PSO Oklahoma 50.7 9.4% February 2022 (d)
I&M Indiana 61.4 (e) 9.7% February 2022
(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
Requested Revenue Commission Staff/
Filing Requirement Requested Intervenor Range of
Company Jurisdiction Date Increase ROE Recommended ROE
(in millions)
SWEPCo Louisiana December 2020 $ 94.7 10.35% 9.1%-9.8% (a)
SWEPCo Arkansas July 2021 80.9 10.35% 8.75%-9.3%
KGPCo Tennessee November 2021 6.9 10.2% (b)
(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.
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.
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.
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
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
Year Range
(in millions)
2023 $ 39.0 - $ 69.0
2024 19.0 - 49.0
2025 5.0 - 25.0
2026 5.0 - 25.0
2027 5.0 - 25.0
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.
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.
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.
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.
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.
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.
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:
Company Plant Name Generating
Capacity Net Book Value (a) Projected
Retirement Date
(in MWs) (in millions)
AEGCo Rockport Plant, Unit 1 655 $ 232.5 2028
APCo Amos 2,930 2,103.9 2040
APCo Mountaineer 1,320 968.5 2040
I&M Rockport Plant, Unit 1 655 510.4 (b) 2028
KPCo Mitchell Plant 780 586.1 2040
SWEPCo Flint Creek Plant 258 265.6 2038
WPCo Mitchell Plant 780 588.3 2040
(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.
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:
Company Plant Name and Unit Generating
Capacity Net Investment (a) Accelerated Depreciation Regulatory Asset Projected
Retirement Date
(in MWs) (in millions)
SWEPCo Pirkey Power Plant 580 $ 120.0 $ 87.0 2023 (b)
SWEPCo Welsh Plants, Units 1 & 3 1,053 475.2 45.9 2028 (c)(d)
(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.
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.
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.
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:
Company Plant Net
Investment (a) Accelerated Depreciation Regulatory Asset Actual/Projected
Retirement
Date Current Authorized
Recovery
Period Annual Depreciation (b)
(in millions) (in millions)
PSO Northeastern Plant, Unit 3 $ 167.2 $ 128.1 2026 (c) $ 14.9
SWEPCo Dolet Hills Power Station
- 72.3 2021 (d) -
SWEPCo Pirkey Power Plant 120.0 87.0 2023 (e) 13.5
SWEPCo Welsh Plant, Units 1 and 3 475.2 45.9 2028 (f) (g) 36.4
SWEPCo Welsh Plant, Unit 2 - 35.2 2016 (h) -
(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.
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.
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:
Years Ended December 31,
2021 2020 2019
(in millions)
Vertically Integrated Utilities $ 1,113.6 $ 1,061.6 $ 982.0
Transmission and Distribution Utilities 543.4 496.4 451.0
AEP Transmission Holdco 677.8 504.8 516.3
Generation & Marketing 217.5 226.9 112.8
Corporate and Other (64.2) (89.6) (141.0)
Earnings Attributable to AEP Common Shareholders $ 2,488.1 $ 2,200.1 $ 1,921.1
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.
VERTICALLY INTEGRATED UTILITIES
(a)Other AEP Segments excludes Corporate and Other which is not considered a reportable segment.
Years Ended December 31,
Vertically Integrated Utilities 2021 2020 2019
(in millions)
Revenues $ 9,998.5 $ 8,879.4 $ 9,367.1
Fuel and Purchased Electricity 3,144.2 2,544.9 3,103.1
Gross Margin 6,854.3 6,334.5 6,264.0
Other Operation and Maintenance 3,043.1 2,754.3 2,934.4
Asset Impairments and Other Related Charges 11.6 - 92.9
Depreciation and Amortization 1,747.6 1,600.5 1,447.0
Taxes Other Than Income Taxes 497.3 472.6 460.9
Operating Income 1,554.7 1,507.1 1,328.8
Other Income 13.5 2.4 6.1
Allowance for Equity Funds Used During Construction 40.2 42.2 50.7
Non-Service Cost Components of Net Periodic Benefit Cost 67.9 67.9 67.6
Interest Expense (574.2) (565.0) (568.3)
Income Before Income Tax Benefit and Equity Earnings 1,102.1 1,054.6 884.9
Income Tax Benefit (11.2) (7.0) (97.7)
Equity Earnings of Unconsolidated Subsidiary 3.4 2.9 3.0
Net Income 1,116.7 1,064.5 985.6
Net Income Attributable to Noncontrolling Interests 3.1 2.9 3.6
Earnings Attributable to AEP Common Shareholders $ 1,113.6 $ 1,061.6 $ 982.0
Summary of KWh Energy Sales for Vertically Integrated Utilities
Years Ended December 31,
2021 2020 2019
(in millions of KWhs)
Retail:
Residential 32,149 31,526 32,359
Commercial 22,833 22,225 23,839
Industrial 33,181 32,860 35,252
Miscellaneous 2,214 2,185 2,302
Total Retail 90,377 88,796 93,752
Wholesale (a) 19,025 16,987 20,090
Total KWhs 109,402 105,783 113,842
(a)Includes Off-system Sales, municipalities and cooperatives, unit power and other wholesale customers.
Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues. In general, degree day changes in the eastern region have a larger effect on revenues than changes in the western region due to the relative size of the two regions and the number of customers within each region.
Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities
Years Ended December 31,
2021 2020 2019
(in degree days)
Eastern Region
Actual - Heating (a) 2,438 2,295 2,617
Normal - Heating (b) 2,720 2,727 2,732
Actual - Cooling (c) 1,268 1,222 1,369
Normal - Cooling (b) 1,110 1,104 1,092
Western Region
Actual - Heating (a) 1,241 1,160 1,512
Normal - Heating (b) 1,461 1,464 1,473
Actual - Cooling (c) 2,370 2,117 2,328
Normal - Cooling (b) 2,246 2,253 2,240
(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.
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)
Year Ended December 31, 2020 $ 1,061.6
Changes in Gross Margin:
Retail Margins 470.4
Margins from Off-system Sales 25.2
Transmission Revenues 30.6
Other Revenues (6.4)
Total Change in Gross Margin 519.8
Changes in Expenses and Other:
Other Operation and Maintenance (288.8)
Asset Impairments and Other Related Charges (11.6)
Depreciation and Amortization (147.1)
Taxes Other Than Income Taxes (24.7)
Other Income 11.1
Allowance for Equity Funds Used During Construction (2.0)
Interest Expense (9.2)
Total Change in Expenses and Other (472.3)
Income Tax Benefit 4.2
Equity Earnings of Unconsolidated Subsidiary 0.5
Net Income Attributable to Noncontrolling Interests (0.2)
Year Ended December 31, 2021 $ 1,113.6
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.
•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.
•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.
TRANSMISSION AND DISTRIBUTION UTILITIES
(a)Other AEP Segments excludes Corporate and Other which is not considered a reportable segment.
Years Ended December 31,
Transmission and Distribution Utilities 2021 2020 2019
(in millions)
Revenues $ 4,492.9 $ 4,345.9 $ 4,482.5
Purchased Electricity 729.9 682.7 794.3
Amortization of Generation Deferrals - - 65.3
Gross Margin 3,763.0 3,663.2 3,622.9
Other Operation and Maintenance 1,573.9 1,575.4 1,628.1
Asset Impairments and Other Related Charges - - 32.5
Depreciation and Amortization 690.3 751.1 789.5
Taxes Other Than Income Taxes 640.9 586.7 575.0
Operating Income 857.9 750.0 597.8
Interest and Investment Income 1.4 2.4 6.6
Carrying Costs Income 1.2 1.6 1.0
Allowance for Equity Funds Used During Construction 32.3 31.9 33.4
Non-Service Cost Components of Net Periodic Benefit Cost 29.0 29.4 30.3
Interest Expense (300.9) (289.2) (243.3)
Income Before Income Tax Expense (Benefit) 620.9 526.1 425.8
Income Tax Expense (Benefit) 77.5 29.7 (25.2)
Net Income 543.4 496.4 451.0
Net Income Attributable to Noncontrolling Interests - - -
Earnings Attributable to AEP Common Shareholders $ 543.4 $ 496.4 $ 451.0
Summary of KWh Energy Sales for Transmission and Distribution Utilities
Years Ended December 31,
2021 2020 2019
(in millions of KWhs)
Retail:
Residential 26,830 26,518 26,407
Commercial 25,514 23,998 25,018
Industrial 23,919 22,432 23,289
Miscellaneous 737 749 779
Total Retail (a) 77,000 73,697 75,493
Wholesale (b) 2,018 1,859 2,335
Total KWhs 79,018 75,556 77,828
(a)Represents energy delivered to distribution customers.
(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold into PJM.
Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues. In general, degree day changes in the eastern region have a larger effect on revenues than changes in the western region due to the relative size of the two regions and the number of customers within each region.
Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities
Years Ended December 31,
2021 2020 2019
(in degree days)
Eastern Region
Actual - Heating (a) 2,815 2,743 3,071
Normal - Heating (b) 3,190 3,202 3,208
Actual - Cooling (c) 1,222 1,140 1,224
Normal - Cooling (b) 1,016 1,006 992
Western Region
Actual - Heating (a) 341 189 301
Normal - Heating (b) 310 313 322
Actual - Cooling (d) 2,653 2,846 2,989
Normal - Cooling (b) 2,712 2,711 2,699
(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.
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)
Year Ended December 31, 2020 $ 496.4
Changes in Gross Margin:
Retail Margins 197.8
Margins from Off-system Sales (95.3)
Transmission Revenues 89.9
Other Revenues (92.6)
Total Change in Gross Margin 99.8
Changes in Expenses and Other:
Other Operation and Maintenance 1.5
Depreciation and Amortization 60.8
Taxes Other Than Income Taxes (54.2)
Interest and Investment Income (1.0)
Carrying Costs Income (0.4)
Allowance for Equity Funds Used During Construction 0.4
Non-Service Cost Components of Net Periodic Benefit Cost (0.4)
Interest Expense (11.7)
Total Change in Expenses and Other (5.0)
Income Tax Expense (47.8)
Year Ended December 31, 2021 $ 543.4
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.
•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.
•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.
AEP TRANSMISSION HOLDCO
(a)Other AEP Segments excludes Corporate and Other which is not considered a reportable segment.
Years Ended December 31,
AEP Transmission Holdco 2021 2020 2019
(in millions)
Transmission Revenues $ 1,526.2 $ 1,198.8 $ 1,073.2
Other Operation and Maintenance 132.3 119.0 119.0
Depreciation and Amortization 306.0 257.6 183.4
Taxes Other Than Income Taxes 245.0 211.0 174.4
Operating Income 842.9 611.2 596.4
Interest and Investment Income 0.7 2.9 3.4
Allowance for Equity Funds Used During Construction 67.2 74.0 84.3
Non-Service Cost Components of Net Periodic Benefit Cost 2.1 2.0 2.7
Interest Expense (146.3) (133.2) (103.3)
Income Before Income Tax Expense and Equity Earnings 766.6 556.9 583.5
Income Tax Expense 159.6 130.8 136.2
Equity Earnings of Unconsolidated Subsidiary 75.0 82.4 72.8
Net Income 682.0 508.5 520.1
Net Income Attributable to Noncontrolling Interests 4.2 3.7 3.8
Earnings Attributable to AEP Common Shareholders $ 677.8 $ 504.8 $ 516.3
Summary of Investment in Transmission Assets for AEP Transmission Holdco
December 31,
2021 2020 2019
(in millions)
Plant in Service $ 11,718.0 $ 10,327.5 $ 8,812.2
Construction Work in Progress 1,495.0 1,499.7 1,521.8
Accumulated Depreciation and Amortization 801.8 595.7 418.9
Total Transmission Property, Net $ 12,411.2 $ 11,231.5 $ 9,915.1
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)
Year Ended December 31, 2020 $ 504.8
Changes in Transmission Revenues:
Transmission Revenues 327.4
Total Change in Transmission Revenues 327.4
Changes in Expenses and Other:
Other Operation and Maintenance (13.3)
Depreciation and Amortization (48.4)
Taxes Other Than Income Taxes (34.0)
Interest and Investment Income (2.2)
Allowance for Equity Funds Used During Construction (6.8)
Non-Service Cost Components of Net Periodic Pension Cost 0.1
Interest Expense (13.1)
Total Change in Expenses and Other (117.7)
Income Tax Expense (28.8)
Equity Earnings of Unconsolidated Subsidiary (7.4)
Net Income Attributable to Noncontrolling Interests (0.5)
Year Ended December 31, 2021 $ 677.8
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.
GENERATION & MARKETING
(a)Other AEP Segments excludes Corporate and Other which is not considered a reportable segment.
Years Ended December 31,
Generation & Marketing 2021 2020 2019
(in millions)
Revenues $ 2,163.7 $ 1,725.6 $ 1,857.6
Fuel, Purchased Electricity and Other 1,806.8 1,403.6 1,456.2
Gross Margin 356.9 322.0 401.4
Other Operation and Maintenance 97.5 124.9 223.8
Asset Impairments and Other Related Charges - - 31.0
Depreciation and Amortization 80.9 72.8 69.5
Taxes Other Than Income Taxes 10.5 13.2 15.6
Operating Income 168.0 111.1 61.5
Interest and Investment Income 4.2 3.2 7.7
Non-Service Cost Components of Net Periodic Benefit Cost 15.4 15.4 14.9
Interest Expense (15.6) (24.0) (30.0)
Income Before Income Tax Benefit and Equity Earnings (Loss) 172.0 105.7 54.1
Income Tax Benefit (48.8) (108.0) (53.8)
Equity Earnings (Loss) of Unconsolidated Subsidiaries (10.6) 3.2 (3.8)
Net Income 210.2 216.9 104.1
Net Loss Attributable to Noncontrolling Interests (7.3) (10.0) (8.7)
Earnings Attributable to AEP Common Shareholders $ 217.5 $ 226.9 $ 112.8
Summary of MWhs Generated for Generation & Marketing
Years Ended December 31,
2021 2020 2019
(in millions of MWhs)
Fuel Type:
Coal 3 4 6
Renewables 4 3 2
Total MWhs 7 7 8
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)
Year Ended December 31, 2020 $ 226.9
Changes in Gross Margin:
Merchant Generation (11.9)
Renewable Generation 8.6
Retail, Trading and Marketing 38.2
Total Change in Gross Margin 34.9
Changes in Expenses and Other:
Other Operation and Maintenance 27.4
Depreciation and Amortization (8.1)
Taxes Other Than Income Taxes 2.7
Interest and Investment Income 1.0
Interest Expense 8.4
Total Change in Expenses and Other 31.4
Income Tax Benefit (59.2)
Equity Earnings of Unconsolidated Subsidiaries (13.8)
Net Loss Attributable to Noncontrolling Interests (2.7)
Year Ended December 31, 2021 $ 217.5
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.
•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.
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.
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.
LIQUIDITY AND CAPITAL RESOURCES
Debt and Equity Capitalization
December 31,
2021 2020
(dollars in millions)
Long-term Debt, including amounts due within one year
$ 33,454.5 57.0 % $ 31,072.5 57.2 %
Short-term Debt 2,614.0 4.4 2,479.3 4.6
Total Debt 36,068.5 61.4 33,551.8 61.8
AEP Common Equity 22,433.2 38.2 20,550.9 37.8
Noncontrolling Interests 247.0 0.4 223.6 0.4
Total Debt and Equity Capitalization $ 58,748.7 100.0 % $ 54,326.3 100.0 %
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:
Amount Maturity
(in millions)
Commercial Paper Backup:
Revolving Credit Facility
$ 4,000.0 March 2026
Revolving Credit Facility
1,000.0 March 2023
364-Day Term Loan 500.0 March 2022 (a)
Cash and Cash Equivalents 403.4
Total Liquidity Sources 5,903.4
Less: AEP Commercial Paper Outstanding 1,364.0
364-Day Term Loan 500.0
Net Available Liquidity $ 4,039.4
(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%.
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
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.
Years Ended December 31,
2021 2020 2019
(in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period $ 438.3 $ 432.6 $ 444.1
Net Cash Flows from Operating Activities 3,839.9 3,832.9 4,270.1
Net Cash Flows Used for Investing Activities (6,433.9) (6,233.9) (7,144.5)
Net Cash Flows from Financing Activities 2,607.1 2,406.7 2,862.9
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash 13.1 5.7 (11.5)
Cash, Cash Equivalents and Restricted Cash at End of Period $ 451.4 $ 438.3 $ 432.6
Operating Activities
Years Ended December 31,
2021 2020 2019
(in millions)
Net Income $ 2,488.1 $ 2,196.7 $ 1,919.8
Non-Cash Adjustments to Net Income (a) 3,032.0 2,946.3 2,685.7
Mark-to-Market of Risk Management Contracts 112.3 66.5 (29.2)
Pension Contributions to Qualified Plan Trust - (110.3) -
Property Taxes (68.0) (43.3) (73.8)
Deferred Fuel Over/Under Recovery, Net (1,647.9) (31.8) 85.2
Change in Regulatory Assets (238.9) (337.9) 49.5
Change in Other Noncurrent Assets (132.7) (142.5) (112.8)
Change in Other Noncurrent Liabilities 206.4 (54.5) (116.1)
Change in Certain Components of Working Capital 88.6 (656.3) (138.2)
Net Cash Flows from Operating Activities $ 3,839.9 $ 3,832.9 $ 4,270.1
(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.
Investing Activities
Years Ended December 31,
2021 2020 2019
(in millions)
Construction Expenditures $ (5,659.6) $ (6,246.3) $ (6,051.4)
Acquisitions of Nuclear Fuel (104.5) (69.7) (92.3)
Acquisition of Sempra Renewables LLC and Santa Rita East, Net of Cash and Restricted Cash Acquired - - (918.4)
Acquisition of the Dry Lake Solar Project (114.4) - -
Acquisition of the North Central Wind Energy Facilities (652.8) - -
Other 97.4 82.1 (82.4)
Net Cash Flows Used for Investing Activities $ (6,433.9) $ (6,233.9) $ (7,144.5)
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
Years Ended December 31,
2021 2020 2019
(in millions)
Issuance of Common Stock $ 600.5 $ 155.0 $ 65.3
Issuance/Retirement of Debt, Net 3,631.7 3,927.3 4,244.1
Dividends Paid on Common Stock (1,519.5) (1,424.9) (1,350.0)
Redemption of Noncontrolling Interests - (100.2) -
Other (105.6) (150.5) (96.5)
Net Cash Flows from Financing Activities $ 2,607.1 $ 2,406.7 $ 2,862.9
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.
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.
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:
2022 Budgeted Capital Expenditures
Segment Environmental Generation Renewables Transmission Distribution Other (a) Total
(in millions)
Vertically Integrated Utilities $ 251.7 $ 438.7 $ 1,287.7 $ 669.9 $ 1,112.1 $ 374.0 $ 4,134.1 (b)
Transmission and Distribution Utilities - - - 835.1 900.4 205.5 1,941.0
AEP Transmission Holdco - - - 1,343.9 - 60.9 1,404.8 (b)
Generation & Marketing 1.3 64.3 42.1 - - 13.8 121.5
Corporate and Other - - - - - 37.5 37.5
Total $ 253.0 $ 503.0 $ 1,329.8 $ 2,848.9 $ 2,012.5 $ 691.7 $ 7,638.9
(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.
The table below represents estimated capital investments by business segment for the years 2023 to 2026:
Segment 2023 2024 2025 2026
Vertically Integrated Utilities $ 3,585.5 $ 4,926.5 $ 4,536.4 $ 4,277.8
Transmission and Distribution Utilities 2,037.8 2,165.1 2,126.6 1,936.9
AEP Transmission Holdco 1,317.8 1,209.5 1,119.6 1,086.4
Generation & Marketing 86.7 69.2 39.2 38.5
Corporate and Other 36.0 32.6 19.1 19.1
Total $ 7,063.8 $ 8,402.9 $ 7,840.9 $ 7,358.7
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:
2022 Budgeted Capital Expenditures
Company Environmental Generation Renewables Transmission Distribution Other (a) Total
(in millions)
AEP Texas $ - $ - $ - $ 599.9 $ 462.3 $ 91.3 $ 1,153.5
AEPTCo - - - 1,259.2 - 18.2 1,277.4
APCo 193.1 102.0 12.8 274.1 364.6 146.5 1,093.1
I&M 4.5 167.3 - 64.7 271.3 100.5 608.3
OPCo - - - 235.2 438.1 114.2 787.5
PSO 0.1 20.5 588.2 82.6 248.7 51.7 991.8
SWEPCo 16.1 53.9 686.7 222.0 171.1 62.5 1,212.3
(a) Amount primarily consists of facilities, software and telecommunications.
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
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.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING STANDARDS
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect reported amounts and related disclosures, including amounts related to legal matters and contingencies. Management considers an accounting estimate to be critical if:
•It requires assumptions to be made that were uncertain at the time the estimate was made; and
•Changes in the estimate or different estimates that could have been selected could have a material effect on net income or financial condition.
Management discusses the development and selection of critical accounting estimates as presented below with the Audit Committee of AEP’s Board of Directors and the Audit Committee reviews the disclosures relating to them.
Management believes that the current assumptions and other considerations used to estimate amounts reflected in the financial statements are appropriate. However, actual results can differ significantly from those estimates.
The sections that follow present information about critical accounting estimates, as well as the effects of hypothetical changes in the material assumptions used to develop each estimate.
Regulatory Accounting
Nature of Estimates Required
The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated.
The Registrants recognize regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) for the economic effects of regulation. Specifically, the timing of expense and income recognition is matched with regulated revenues. Liabilities are also recorded for refunds, or probable refunds, to customers that have not been made.
Assumptions and Approach Used
When incurred costs are probable of recovery through regulated rates, regulatory assets are recorded on the balance sheets. Management reviews the probability of recovery at each balance sheet date and whenever new events occur. Similarly, regulatory liabilities are recorded when a determination is made that a refund is probable or when ordered by a commission. Examples of new events that affect probability include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs as well as the return of revenues, rate of return earned on invested capital and timing and amount of assets to be recovered through regulated rates. If recovery of a regulatory asset is no longer probable, that regulatory asset is written-off as a charge against earnings. A write-off of regulatory assets or establishment of a regulatory liability may also reduce future cash flows since there will be no recovery through regulated rates.
Effect if Different Assumptions Used
A change in the above assumptions may result in a material impact on net income. See Note 5 - Effects of Regulation for additional information related to regulatory assets and regulatory liabilities.
Revenue Recognition - Unbilled Revenues
Nature of Estimates Required
AEP recognizes revenues from customers as the performance obligations of delivering energy to customers are satisfied. The determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue accrual is recorded. This estimate is reversed in the following month and actual revenue is recorded based on meter readings. PSO and SWEPCo do not include the fuel portion in unbilled revenue in accordance with the applicable state commission regulatory treatment in Arkansas, Louisiana, Oklahoma and Texas.
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.
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.
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.
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:
Years Ended December 31,
Net Periodic Cost (Credit) 2021 2020 2019
(in millions)
Pension Plans $ 138.2 $ 108.6 $ 61.5
OPEB (122.0) (109.7) (80.7)
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:
Pension Plans OPEB
Assumed/ Assumed/
2022 Expected 2022 Expected
Target Long-Term Target Long-Term
Asset Rate of Asset Rate of
Allocation Return Allocation Return
Equity 25 % 7.42 % 59 % 6.96 %
Fixed Income 59 3.89 40 3.59
Other Investments 15 7.96 - -
Cash and Cash Equivalents 1 1.60 1 1.60
Total 100 % 100 %
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.
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.
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:
Pension Plans OPEB
+0.5% -0.5% +0.5% -0.5%
(in millions)
Effect on December 31, 2021 Benefit Obligations
Discount Rate $ (259.7) $ 285.7 $ (53.9) $ 59.5
Compensation Increase Rate 31.6 (29.2) NA NA
Cash Balance Crediting Rate 77.6 (72.4) NA NA
Health Care Cost Trend Rate NA NA 9.4 (7.5)
Effect on 2021 Periodic Cost
Discount Rate $ (13.6) $ 14.9 $ 3.2 $ (3.1)
Compensation Increase Rate 7.9 (7.2) NA NA
Cash Balance Crediting Rate 15.2 (14.2) NA NA
Health Care Cost Trend Rate NA NA 0.7 (0.2)
Expected Return on Plan Assets (24.2) 24.2 (9.6) 9.6
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.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market Risks
The Vertically Integrated Utilities segment is exposed to certain market risks as a major power producer and through transactions in power, coal, natural gas and marketing contracts. These risks include commodity price risks which may be subject to capacity risk, credit risk as well as interest rate risk. These risks represent the risk of loss that may impact this segment due to changes in the underlying market prices or rates.
The Transmission and Distribution Utilities segment is exposed to energy procurement risk and interest rate risk.
The Generation & Marketing segment conducts marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. This segment is exposed to certain market risks as a marketer of wholesale and retail electricity. These risks include commodity price risks which may be subject to capacity risk, credit risk as well as interest rate risk. These risks represent the risk of loss that may impact this segment due to changes in the underlying market prices or rates. In addition, the Generation & Marketing segment is also exposed to certain market risks as a power producer and through transactions in wholesale electricity, natural gas and marketing contracts.
Management employs risk management contracts including physical forward and financial forward purchase-and-sale contracts. Management engages in risk management of power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. As a result, AEP is subject to price risk. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Financial Officer, Chief Operating Officer, Executive Vice President of Generation, Senior Vice President of Grid Solutions, Senior Vice President of Treasury and Risk and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Financial Officer, Senior Vice President of Treasury and Risk and Chief Risk Officer in addition to Energy Supply’s President and Senior Vice President. When commercial activities exceed predetermined limits, positions are modified to reduce the risk to be within the limits unless specifically approved by the respective committee.
The effects of COVID-19 continue to be monitored, and while markets have shown improvement, credit risks remain as counterparties encounter business and supply chain disruptions.
Due to multiple defaults of market participants, ERCOT had a large outstanding unpaid balance associated with the February 2021 winter storm. A certain portion of this balance has been securitized and disbursed to impacted market participants. Financial costs associated with securitization are allocated to load serving entities through their qualified scheduling entities and in that role AEPEP is exposed, but not materially. If the market rules were to change on how socialized losses are allocated this could affect AEPEP’s exposure. Regardless of the approach of how socialized losses are allocated there are potential downstream impacts that could push counterparties into financial distress and or bankruptcy, affecting AEPEP, AEP Texas and ETT.
The following table summarizes the reasons for changes in total MTM value as compared to December 31, 2020:
MTM Risk Management Contract Net Assets (Liabilities)
Year Ended December 31, 2021
Vertically
Integrated
Utilities Transmission
and
Distribution
Utilities Generation
&
Marketing Total
(in millions)
Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2020 $ 41.2 $ (109.5) $ 168.1 $ 99.8
(Gain)/Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period (42.0) 8.0 (12.9) (46.9)
Fair Value of New Contracts at Inception When Entered During the Period (a) - - 2.1 2.1
Changes in Fair Value Due to Market Fluctuations During the Period (b) - - 118.6 118.6
Changes in Fair Value Allocated to Regulated Jurisdictions (c) 66.6 10.1 - 76.7
MTM Risk Management Contract Net Assets Held for Sale Related to KPCo (d) (6.0) - - (6.0)
Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2021 $ 59.8 $ (91.4) $ 275.9 244.3
Commodity Cash Flow Hedge Contracts 207.5
Fair Value Hedge Contracts (36.9)
Collateral Deposits (259.2)
Total MTM Derivative Contract Net Assets as of December 31, 2021 $ 155.7
(a)Reflects fair value on primarily long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location and delivery term. A significant portion of the total volumetric position has been economically hedged.
(b)Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable.
(d)MTM risk management contract net assets relating to KPCo are classified as Assets Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
See Note 10 - Derivatives and Hedging and Note 11 - Fair Value Measurements for additional information related to risk management contracts. The following tables and discussion provide information on credit risk and market volatility risk.
Credit Risk
Credit risk is mitigated in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.
AEP has risk management contracts (includes non-derivative contracts) with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, exposures change daily. As of December 31, 2021, credit exposure net of collateral to sub investment grade counterparties was approximately 0.8%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting
loss). As of December 31, 2021, the following table approximates AEP’s counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:
Counterparty Credit Quality Exposure
Before
Credit
Collateral Credit
Collateral Net
Exposure Number of
Counterparties
>10% of
Net Exposure Net Exposure
of
Counterparties
>10%
(in millions, except number of counterparties)
Investment Grade $ 447.1 $ 56.4 $ 390.7 2 $ 147.6
No External Ratings:
Internal Investment Grade
81.2 - 81.2 3 63.6
Internal Noninvestment Grade
6.4 2.6 3.8 3 2.7
Total as of December 31, 2021 $ 534.7 $ 59.0 $ 475.7
All exposure in the table above relates to AEPSC and AEPEP as AEPSC is agent for and transacts on behalf of certain AEP subsidiaries, including the Registrant Subsidiaries and AEPEP is agent for and transacts on behalf of other AEP subsidiaries.
In addition, AEP is exposed to credit risk related to participation in RTOs. For each of the RTOs in which AEP participates, this risk is generally determined based on the proportionate share of member gross activity over a specified period of time.
Value at Risk (VaR) Associated with Risk Management Contracts
Management uses a risk measurement model, which calculates VaR, to measure AEP’s commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, as of December 31, 2021, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition.
Management calculates the VaR for both a trading and non-trading portfolio. The trading portfolio consists primarily of contracts related to energy trading and marketing activities. The non-trading portfolio consists primarily of economic hedges of generation and retail supply activities.
The following tables show the end, high, average and low market risk as measured by VaR for the periods indicated:
VaR Model
Trading Portfolio
Twelve Months Ended Twelve Months Ended
December 31, 2021 December 31, 2020
End High Average Low End High Average Low
(in millions) (in millions)
$ 0.4 $ 3.6 $ 0.4 $ 0.1 $ 0.1 $ 0.3 $ 0.1 $ -
VaR Model
Non-Trading Portfolio
Twelve Months Ended Twelve Months Ended
December 31, 2021 December 31, 2020
End High Average Low End High Average Low
(in millions) (in millions)
$ 8.3 $ 14.9 $ 3.7 $ 0.7 $ 2.2 $ 2.9 $ 1.0 $ 0.1
Management back-tests VaR results against performance due to actual price movements. Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.
As the VaR calculation captures recent price movements, management also performs regular stress testing of the trading portfolio to understand AEP’s exposure to extreme price movements. A historical-based method is employed whereby the current trading portfolio is subjected to actual, observed price movements from the last several years in order to ascertain which historical price movements translated into the largest potential MTM loss. Management then researches the underlying positions, price movements and market events that created the most significant exposure and reports the findings to the Risk Executive Committee, Regulated Risk Committee or Competitive Risk Committee as appropriate.
Interest Rate Risk
AEP is exposed to interest rate market fluctuations in the normal course of business operations. AEP has outstanding short and long-term debt which is subject to a variable rate. AEP manages interest rate risk by limiting variable-rate exposures to a percentage of total debt, by entering into interest rate derivative instruments and by monitoring the effects of market changes in interest rates. For the 12 months ended December 31, 2021, 2020 and 2019, a 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pretax interest expense annually by $33 million, $32 million and $24 million, respectively.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
American Electric Power Company, Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of American Electric Power Company, Inc. and its subsidiaries (the “Company”) as of December 31, 2021 and 2020, and the related consolidated statements of income, of comprehensive income (loss), of changes in equity and of cash flows for each of the three years in the period ended December 31, 2021, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Accounting for the Effects of Cost-Based Regulation
As described in Notes 1 and 5 to the consolidated financial statements, the Company’s consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. As of December 31, 2021, there were $4.8 billion of deferred costs included in regulatory assets, $1.0 billion of which were pending final regulatory approval, and $8.7 billion of regulatory liabilities awaiting potential refund or future rate reduction, $0.3 billion of which were pending final regulatory determination. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation.
The principal considerations for our determination that performing procedures relating to the accounting for the effects of cost-based regulation is a critical audit matter are the significant judgment by management in the ongoing evaluation of the recovery of regulatory assets and refund of regulatory liabilities, and in applying guidance contained in rate orders and other relevant evidence; this in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence related to the probability of recovery of regulatory assets and refund of regulatory liabilities.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s evaluation of new events, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management’s assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities, involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, application of relevant regulatory precedents, and other relevant evidence.
Valuation of Level 3 Risk Management Commodity Contracts
As described in Notes 1, 10 and 11 to the consolidated financial statements, the Company employs risk management commodity contracts including physical and financial forward purchase and sale contracts and, to a lesser extent, over-the-counter swaps and options to accomplish its risk management strategies. Certain over-the-counter and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. As disclosed by management, the fair value of these risk management commodity contracts 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 including forward market price assumptions. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. Management utilized such unobservable pricing inputs to value its Level 3 risk management commodity contract assets and liabilities, which totaled $245.5 million and $148.2 million, as of December 31, 2021, respectively.
The principal considerations for our determination that performing procedures relating to the valuation of Level 3 risk management commodity contracts is a critical audit matter are the significant judgment by management when developing the fair value of the commodity contracts; this in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence relating to the forward market price assumptions used in management’s valuation models. In addition, the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s valuation of the risk management commodity contracts, including controls over the assumptions used to value the Level 3 risk management commodity contracts. These procedures also included, among others, testing management’s process for developing the fair value of the Level 3 risk management commodity contracts, evaluating the appropriateness of the valuation models, evaluating the reasonableness of the forward market price assumptions, and testing the data used by management in the valuation models. Professionals with specialized skill and knowledge were used to assist in evaluating the reasonableness of the forward market price assumptions.
/s/ PricewaterhouseCoopers LLP
Columbus, Ohio
February 24, 2022
We have served as the Company's auditor since 2017.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of American Electric Power Company, Inc. and Subsidiary Companies (AEP) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. AEP’s internal control is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of AEP’s internal control over financial reporting as of December 31, 2021. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). Based on management’s assessment, management concluded AEP’s internal control over financial reporting was effective as of December 31, 2021.
PricewaterhouseCoopers LLP, AEP’s independent registered public accounting firm has issued an audit report on the effectiveness of AEP’s internal control over financial reporting as of December 31, 2021. The Report of Independent Registered Public Accounting Firm appears on the previous page.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2021, 2020 and 2019
(in millions, except per-share and share amounts)
Years Ended December 31,
2021 2020 2019
REVENUES
Vertically Integrated Utilities $ 9,852.2 $ 8,753.2 $ 9,245.7
Transmission and Distribution Utilities 4,464.1 4,238.7 4,319.0
Generation & Marketing 2,108.3 1,621.0 1,721.8
Other Revenues 367.4 305.6 274.9
TOTAL REVENUES 16,792.0 14,918.5 15,561.4
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 5,466.3 4,369.7 5,106.1
Other Operation 2,547.7 2,572.4 2,743.7
Maintenance 1,121.8 1,010.4 1,213.9
Asset Impairments and Other Related Charges 11.6 - 156.4
Depreciation and Amortization 2,825.7 2,682.8 2,514.5
Taxes Other Than Income Taxes 1,407.6 1,295.5 1,234.5
TOTAL EXPENSES 13,380.7 11,930.8 12,969.1
OPERATING INCOME 3,411.3 2,987.7 2,592.3
Other Income (Expense):
Other Income 41.4 57.0 26.6
Allowance for Equity Funds Used During Construction 139.7 148.1 168.4
Non-Service Cost Components of Net Periodic Benefit Cost 118.6 119.0 120.0
Interest Expense (1,199.1) (1,165.7) (1,072.5)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS 2,511.9 2,146.1 1,834.8
Income Tax Expense (Benefit) 115.5 40.5 (12.9)
Equity Earnings of Unconsolidated Subsidiaries 91.7 91.1 72.1
NET INCOME 2,488.1 2,196.7 1,919.8
Net Income (Loss) Attributable to Noncontrolling Interests - (3.4) (1.3)
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $ 2,488.1 $ 2,200.1 $ 1,921.1
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING
500,522,177 495,718,223 493,694,345
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
$ 4.97 $ 4.44 $ 3.89
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING 501,784,032 497,226,867 495,306,238
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
$ 4.96 $ 4.42 $ 3.88
See Notes to Financial Statements of Registrants beginning on page 226.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Years Ended December 31,
2021 2020 2019
Net Income $ 2,488.1 $ 2,196.7 $ 1,919.8
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $66.6, $1.8 and $(21.1) in 2021, 2020 and 2019, Respectively
250.5 6.9 (79.4)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(2.2), $(1.9) and $(1.5) in 2021, 2020 and 2019, Respectively
(8.1) (7.0) (5.6)
Pension and OPEB Funded Status, Net of Tax of $7.3, $16.7 and $15.3 in 2021, 2020 and 2019, Respectively
27.5 62.7 57.7
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) 269.9 62.6 (27.3)
TOTAL COMPREHENSIVE INCOME 2,758.0 2,259.3 1,892.5
Total Comprehensive Loss Attributable To Noncontrolling Interests - (3.4) (1.3)
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $ 2,758.0 $ 2,262.7 $ 1,893.8
See Notes to Financial Statements of Registrants beginning on page 226.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
AEP Common Shareholders
Common Stock Accumulated
Other
Comprehensive
Income (Loss)
Shares Amount Paid-in
Capital Retained
Earnings Noncontrolling
Interests Total
TOTAL EQUITY - DECEMBER 31, 2018 513.5 $ 3,337.4 $ 6,486.1 $ 9,325.3 $ (120.4) $ 31.0 $ 19,059.4
Issuance of Common Stock 0.9 6.0 59.3 65.3
Common Stock Dividends (1,345.5) (a) (4.5) (1,350.0)
Other Changes in Equity (9.8) (b) 2.2 (7.6)
Acquisition of Sempra Renewables LLC 134.8 134.8
Acquisition of Santa Rita East 118.8 118.8
Net Income (Loss) 1,921.1 (1.3) 1,919.8
Other Comprehensive Loss (27.3) (27.3)
TOTAL EQUITY - DECEMBER 31, 2019 514.4 3,343.4 6,535.6 9,900.9 (147.7) 281.0 19,913.2
Issuance of Common Stock 2.4 15.9 139.1 155.0
Common Stock Dividends (1,415.0) (a) (9.9) (1,424.9)
Other Changes in Equity (85.8) (c) (0.4) (86.2)
ASU 2016-13 Adoption 1.8 1.8
Acquisition of Incremental Interest in Santa Rita East (43.7) (43.7)
Net Income (Loss) 2,200.1 (3.4) 2,196.7
Other Comprehensive Income 62.6 62.6
TOTAL EQUITY - DECEMBER 31, 2020 516.8 3,359.3 6,588.9 10,687.8 (85.1) 223.6 20,774.5
Issuance of Common Stock 7.6 49.4 551.1 600.5
Common Stock Dividends (1,507.7) (a) (11.8) (1,519.5)
Other Changes in Equity 32.6 (1.1) 16.3 47.8
Acquisition of Dry Lake Solar Project 18.9 18.9
Net Income 2,488.1 - 2,488.1
Other Comprehensive Income 269.9 269.9
TOTAL EQUITY - DECEMBER 31, 2021 524.4 $ 3,408.7 $ 7,172.6 $ 11,667.1 $ 184.8 $ 247.0 $ 22,680.2
(a) Cash dividends declared per AEP common share were $3.00, $2.84 and $2.71 for the years ended December 31, 2021, 2020 and 2019, respectively.
(b) Includes $(62) million related to a forward equity purchase contract associated with the issuance of Equity Units. See “Equity Units” section of Note 14 for additional information.
(c) Includes $(121) million related to a forward equity purchase contract associated with the issuance of Equity Units. See “Equity Units” section of Note 14 for additional information.
See Notes to Financial Statements of Registrants beginning on page 226.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2021 and 2020
(in millions)
December 31,
2021 2020
CURRENT ASSETS
Cash and Cash Equivalents $ 403.4 $ 392.7
Restricted Cash
(December 31, 2021 and 2020 Amounts Include $48 and $45.6, Respectively, Related to Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Santa Rita East)
48.0 45.6
Other Temporary Investments
(December 31, 2021 and 2020 Amounts Include $214.8 and $194.6, Respectively, Related to EIS and Transource Energy)
220.4 200.8
Accounts Receivable:
Customers 720.9 613.6
Accrued Unbilled Revenues 204.4 248.7
Pledged Accounts Receivable - AEP Credit 1,038.0 1,018.4
Miscellaneous 33.9 33.1
Allowance for Uncollectible Accounts (55.6) (71.1)
Total Accounts Receivable 1,941.6 1,842.7
Fuel 307.9 629.4
Materials and Supplies 681.3 680.6
Risk Management Assets 194.4 94.7
Accrued Tax Benefits 121.5 185.3
Regulatory Asset for Under-Recovered Fuel Costs 647.8 90.7
Margin Deposits 193.4 62.0
Assets Held for Sale 2,919.7 -
Prepayments and Other Current Assets 129.8 127.0
TOTAL CURRENT ASSETS 7,809.2 4,351.5
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation 23,088.1 23,133.9
Transmission 29,911.1 27,886.7
Distribution 24,440.0 23,972.1
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 5,682.9 5,294.6
Construction Work in Progress 3,684.3 4,025.7
Total Property, Plant and Equipment 86,806.4 84,313.0
Accumulated Depreciation and Amortization 20,805.1 20,411.4
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET 66,001.3 63,901.6
OTHER NONCURRENT ASSETS
Regulatory Assets 4,142.3 3,527.0
Securitized Assets 552.8 657.0
Spent Nuclear Fuel and Decommissioning Trusts 3,867.0 3,306.7
Goodwill 52.5 52.5
Long-term Risk Management Assets 267.0 242.2
Operating Lease Assets 578.3 866.4
Deferred Charges and Other Noncurrent Assets 4,398.3 3,852.3
TOTAL OTHER NONCURRENT ASSETS 13,858.2 12,504.1
TOTAL ASSETS $ 87,668.7 $ 80,757.2
See Notes to Financial Statements of Registrants beginning on page 226.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
December 31, 2021 and 2020
(dollars in millions)
December 31,
2021 2020
CURRENT LIABILITIES
Accounts Payable $ 2,054.6 $ 1,709.7
Short-term Debt:
Securitized Debt for Receivables - AEP Credit 750.0 592.0
Other Short-term Debt 1,864.0 1,887.3
Total Short-term Debt 2,614.0 2,479.3
Long-term Debt Due Within One Year
(December 31, 2021 and 2020 Amounts Include $190.5 and $198.3, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)
2,153.8 2,086.1
Risk Management Liabilities 75.4 78.8
Customer Deposits 321.6 335.6
Accrued Taxes 1,586.4 1,476.4
Accrued Interest 273.2 267.6
Obligations Under Operating Leases 97.6 241.3
Liabilities Held for Sale 1,880.9 -
Other Current Liabilities 1,369.2 1,251.9
TOTAL CURRENT LIABILITIES 12,426.7 9,926.7
NONCURRENT LIABILITIES
Long-term Debt
(December 31, 2021 and 2020 Amounts Include $840.5 and $950.1, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)
31,300.7 28,986.4
Long-term Risk Management Liabilities 230.3 232.8
Deferred Income Taxes 8,202.5 8,240.9
Regulatory Liabilities and Deferred Investment Tax Credits 8,686.3 8,378.7
Asset Retirement Obligations 2,676.2 2,469.2
Employee Benefits and Pension Obligations 328.4 336.4
Obligations Under Operating Leases 492.8 638.4
Deferred Credits and Other Noncurrent Liabilities 601.3 728.0
TOTAL NONCURRENT LIABILITIES 52,518.5 50,010.8
TOTAL LIABILITIES 64,945.2 59,937.5
Rate Matters (Note 4)
Commitments and Contingencies (Note 6)
MEZZANINE EQUITY
Contingently Redeemable Performance Share Awards 43.3 45.2
TOTAL MEZZANINE EQUITY 43.3 45.2
EQUITY
Common Stock - Par Value - $6.50 Per Share:
2021 2020
Shares Authorized 600,000,000 600,000,000
Shares Issued 524,416,175 516,808,354
(20,204,160 Shares were Held in Treasury as of December 31, 2021 and 2020, Respectively)
3,408.7 3,359.3
Paid-in Capital 7,172.6 6,588.9
Retained Earnings 11,667.1 10,687.8
Accumulated Other Comprehensive Income (Loss) 184.8 (85.1)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY 22,433.2 20,550.9
Noncontrolling Interests 247.0 223.6
TOTAL EQUITY 22,680.2 20,774.5
TOTAL LIABILITIES, MEZZANINE EQUITY AND EQUITY $ 87,668.7 $ 80,757.2
See Notes to Financial Statements of Registrants beginning on page 226.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Years Ended December 31,
2021 2020 2019
OPERATING ACTIVITIES
Net Income $ 2,488.1 $ 2,196.7 $ 1,919.8
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 2,825.7 2,682.8 2,514.5
Rockport Plant, Unit 2 Lease Amortization 135.4 136.5 136.5
Deferred Income Taxes 107.6 196.1 (17.8)
Asset Impairments and Other Related Charges 11.6 - 156.4
Allowance for Equity Funds Used During Construction (139.7) (148.1) (168.4)
Mark-to-Market of Risk Management Contracts 112.3 66.5 (29.2)
Amortization of Nuclear Fuel 85.3 87.5 89.1
Pension and Postemployment Benefit Reserves 6.1 (8.5) (24.6)
Pension Contributions to Qualified Plan Trust - (110.3) -
Property Taxes (68.0) (43.3) (73.8)
Deferred Fuel Over/Under-Recovery, Net (1,647.9) (31.8) 85.2
Change in Regulatory Assets (238.9) (337.9) 49.5
Change in Other Noncurrent Assets (132.7) (142.5) (112.8)
Change in Other Noncurrent Liabilities 206.4 (54.5) (116.1)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net (119.7) (129.3) 247.8
Fuel, Materials and Supplies 300.2 (142.9) (248.2)
Accounts Payable 200.6 (35.3) 5.8
Accrued Taxes, Net 218.7 20.1 138.9
Rockport Plant, Unit 2 Operating Lease Payments (147.7) (147.7) (147.7)
Other Current Assets (151.3) 34.3 70.7
Other Current Liabilities (212.2) (255.5) (205.5)
Net Cash Flows from Operating Activities 3,839.9 3,832.9 4,270.1
INVESTING ACTIVITIES
Construction Expenditures (5,659.6) (6,246.3) (6,051.4)
Purchases of Investment Securities (1,955.1) (1,678.8) (1,576.0)
Sales of Investment Securities 1,901.4 1,644.3 1,494.2
Acquisitions of Nuclear Fuel (104.5) (69.7) (92.3)
Acquisition of Sempra Renewables LLC and Santa Rita East, Net of Cash and Restricted Cash Acquired - - (918.4)
Acquisition of the Dry Lake Solar Project (114.4) - -
Acquisition of the North Central Wind Energy Facilities (652.8) - -
Other Investing Activities 151.1 116.6 (0.6)
Net Cash Flows Used for Investing Activities (6,433.9) (6,233.9) (7,144.5)
FINANCING ACTIVITIES
Issuance of Common Stock, Net 600.5 155.0 65.3
Issuance of Long-term Debt 6,486.3 5,626.1 4,536.6
Issuance of Short-term Debt with Original Maturities greater than 90 Days 1,393.3 1,396.5 -
Change in Short-term Debt with Original Maturities less than 90 Day, Net (487.3) (448.4) 928.3
Retirement of Long-term Debt (2,989.3) (1,339.8) (1,220.8)
Redemption of Short-term Debt with Original Maturities greater than 90 Days (771.3) (1,307.1) -
Principal Payments for Finance Lease Obligations (64.0) (61.7) (70.7)
Dividends Paid on Common Stock (1,519.5) (1,424.9) (1,350.0)
Redemption of Noncontrolling Interests - (100.2) -
Other Financing Activities (41.6) (88.8) (25.8)
Net Cash Flows from Financing Activities 2,607.1 2,406.7 2,862.9
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash 13.1 5.7 (11.5)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period 438.3 432.6 444.1
Cash, Cash Equivalents and Restricted Cash at End of Period $ 451.4 $ 438.3 $ 432.6
See Notes to Financial Statements of Registrants beginning on page 226.
AEP TEXAS INC.
AND SUBSIDIARIES
AEP TEXAS INC. AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
KWh Sales/Degree Days
Summary of KWh Energy Sales
Years Ended December 31,
2021 2020 2019
(in millions of KWhs)
Retail:
Residential 12,284 12,163 11,996
Commercial 10,477 10,065 10,419
Industrial 9,598 9,085 8,882
Miscellaneous 625 636 665
Total Retail 32,984 31,949 31,962
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.
Summary of Heating and Cooling Degree Days
Years Ended December 31,
2021 2020 2019
(in degree days)
Actual - Heating (a) 341 189 301
Normal - Heating (b) 310 313 322
Actual - Cooling (c) 2,653 2,846 2,989
Normal - Cooling (b) 2,712 2,711 2,699
(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 70 degree temperature base.
2021 Compared to 2020
AEP Texas Inc. and Subsidiaries
Reconciliation of Year Ended December 31, 2020 to Year Ended December 31, 2021
Net Income
(in millions)
Year Ended December 31, 2020 $ 241.0
Changes in Gross Margin:
Retail Margins 82.4
Margins from Off-system Sales (73.8)
Transmission Revenues 98.0
Other Revenues (118.0)
Total Change in Gross Margin (11.4)
Changes in Expenses and Other:
Other Operation and Maintenance (6.3)
Depreciation and Amortization 142.8
Taxes Other Than Income Taxes (18.7)
Interest Income (0.6)
Allowance for Equity Funds Used During Construction 2.1
Non-Service Cost Components of Net Periodic Benefit Cost (0.1)
Interest Expense (4.7)
Total Change in Expenses and Other 114.5
Income Tax Expense (54.3)
Year Ended December 31, 2021 $ 289.8
The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals were as follows:
•Retail Margins increased $82 million primarily due to the following:
•A $44 million increase from interim rate increases driven by increased distribution investment.
•A $21 million increase due to prior year refunds of Excess ADIT and excess federal income taxes collected as a result of Tax Reform. This increase was partially offset in Income Tax Expense below.
•A $13 million increase from interim rate increases driven by increased transmission investment.
•A $7 million increase in weather-related usage primarily due to an 80% increase in heating degree days.
•Margins from Off-system Sales decreased $74 million primarily due to the retirement of the Oklaunion Power Station in September 2020. This decrease was partially offset in Depreciation and Amortization expenses below.
•Transmission Revenues increased $98 million primarily due to the following:
•An $80 million increase from interim rate increases driven by increased transmission investment.
•A $14 million increase 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 $118 million primarily due to securitization revenues driven by the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset below in Depreciation and Amortization expenses and in Interest Expense.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $6 million primarily due to the following:
•A $17 million increase due to the prior year revision of the Oklaunion Power Station ARO. This increase was offset in Margins from Off-System Sales above.
This increase was partially offset by:
•A $12 million decrease primarily due to the retirement of Oklaunion Power Station in September 2020.
•Depreciation and Amortization expenses decreased $143 million primarily due to the following:
•A $107 million decrease in securitization amortizations 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.
•A $55 million decrease in depreciation expense due to the retirement of the Oklaunion Power Station in September 2020. This decrease was partially offset above in Margins from Off-system Sales and Other Operation and Maintenance expenses.
These decreases were partially offset by:
•A $15 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
•Taxes Other Than Income Taxes increased $19 million primarily due to higher property taxes as a result of increased distribution and transmission investment.
•Interest Expense increased $5 million primarily due to higher long-term debt balances.
•Income Tax Expense increased $54 million primarily due to a decrease in amortization of Excess ADIT and an increase in pretax book income. The decrease in amortization of Excess ADIT was partially offset above in Retail Margins.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
AEP Texas Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of AEP Texas Inc. and its subsidiaries (the “Company”) as of December 31, 2021 and 2020, and the related consolidated statements of income, of comprehensive income (loss), of changes in common shareholder's equity and of cash flows for each of the three years in the period ended December 31, 2021, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Cost-Based Regulation
As described in Notes 1 and 5 to the consolidated financial statements, the Company’s consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. As of December 31, 2021, there were $275.2 million of deferred costs included in regulatory assets, $41.2 million of which were pending final regulatory approval, and $1.2 billion of regulatory liabilities awaiting potential refund or future rate reduction, $13.0 million of which are pending final regulatory determination. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation.
The principal considerations for our determination that performing procedures relating to the accounting for the effects of cost-based regulation is a critical audit matter are the significant judgment by management in the ongoing evaluation of the recovery of regulatory assets and refund of regulatory liabilities, and in applying guidance contained in rate orders and other relevant evidence; this in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence related to the probability of recovery of regulatory assets and refund of regulatory liabilities.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s evaluation of new events, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management’s assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, application of relevant regulatory precedents, and other relevant evidence.
/s/ PricewaterhouseCoopers LLP
Columbus, Ohio
February 24, 2022
We have served as the Company's auditor since 2017.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of AEP Texas Inc. and Subsidiaries (AEP Texas) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. AEP Texas’ internal control is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of AEP Texas’ internal control over financial reporting as of December 31, 2021. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). Based on management’s assessment, management concluded AEP Texas’ internal control over financial reporting was effective as of December 31, 2021.
This annual report does not include an audit report from PricewaterhouseCoopers LLP, AEP Texas’ registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit AEP Texas to provide only management’s report in this annual report.
AEP TEXAS INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Years Ended December 31,
2021 2020 2019
REVENUES
Electric Transmission and Distribution $ 1,586.4 $ 1,524.9 $ 1,545.9
Sales to AEP Affiliates 3.9 90.8 160.5
Other Revenues 3.5 3.2 2.9
TOTAL REVENUES 1,593.8 1,618.9 1,709.3
EXPENSES
Fuel and Other Consumables Used for Electric Generation - 13.7 31.1
Other Operation 489.5 488.9 492.0
Maintenance 86.2 80.5 158.8
Asset Impairments and Other Related Charges - - 32.5
Depreciation and Amortization 387.0 529.8 622.3
Taxes Other Than Income Taxes 155.1 136.4 140.6
TOTAL EXPENSES 1,117.8 1,249.3 1,477.3
OPERATING INCOME 476.0 369.6 232.0
Other Income (Expense):
Interest Income 0.8 1.4 3.4
Allowance for Equity Funds Used During Construction 21.5 19.4 15.2
Non-Service Cost Components of Net Periodic Benefit Cost 11.1 11.2 11.3
Interest Expense (176.5) (171.8) (137.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 332.9 229.8 124.7
Income Tax Expense (Benefit) 43.1 (11.2) (53.6)
NET INCOME $ 289.8 $ 241.0 $ 178.3
The common stock of AEP Texas is wholly-owned by Parent.
See Notes to Financial Statements of Registrants beginning on page 226.
AEP TEXAS INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Years Ended December 31,
2021 2020 2019
Net Income $ 289.8 $ 241.0 $ 178.3
OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.3, $0.3 and $0.3 in 2021, 2020 and 2019, Respectively
1.0 1.1 1.0
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0, $0 and $0 in 2021, 2020 and 2019, Respectively
0.2 0.2 0.2
Pension and OPEB Funded Status, Net of Tax of $0.3, $0.7 and $0.3 in 2021, 2020 and 2019, Respectively
1.2 2.6 1.1
TOTAL OTHER COMPREHENSIVE INCOME 2.4 3.9 2.3
TOTAL COMPREHENSIVE INCOME $ 292.2 $ 244.9 $ 180.6
See Notes to Financial Statements of Registrants beginning on page 226.
AEP TEXAS INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Paid-in
Capital Retained
Earnings Accumulated
Other
Comprehensive
Income (Loss) Total
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2018 $ 1,257.9 $ 1,337.7 $ (15.1) $ 2,580.5
Capital Contribution from Parent 200.0 200.0
Net Income 178.3 178.3
Other Comprehensive Income 2.3 2.3
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2019 1,457.9 1,516.0 (12.8) 2,961.1
Net Income 241.0 241.0
Other Comprehensive Income 3.9 3.9
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2020 1,457.9 1,757.0 (8.9) 3,206.0
Capital Contribution from Parent 96.0 96.0
Net Income 289.8 289.8
Other Comprehensive Income 2.4 2.4
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2021 $ 1,553.9 $ 2,046.8 $ (6.5) $ 3,594.2
See Notes to Financial Statements of Registrants beginning on page 226.
AEP TEXAS INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2021 and 2020
(in millions)
December 31,
2021 2020
CURRENT ASSETS
Cash and Cash Equivalents $ 0.1 $ 0.1
Restricted Cash
(December 31, 2021 and 2020 Amounts Include $30.4 and $28.7, Respectively, Related to Transition Funding and Restoration Funding)
30.4 28.7
Advances to Affiliates 6.9 7.1
Accounts Receivable:
Customers 123.4 112.8
Affiliated Companies 7.9 5.1
Accrued Unbilled Revenues 77.9 65.8
Allowance for Uncollectible Accounts (4.0) (0.1)
Total Accounts Receivable 205.2 183.6
Materials and Supplies 73.9 70.0
Accrued Tax Benefits 24.8 16.8
Prepayments and Other Current Assets 5.9 4.6
TOTAL CURRENT ASSETS 347.2 310.9
PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission 5,849.9 5,279.6
Distribution 4,917.2 4,580.8
Other Property, Plant and Equipment 961.1 868.4
Construction Work in Progress 551.3 614.1
Total Property, Plant and Equipment 12,279.5 11,342.9
Accumulated Depreciation and Amortization 1,644.1 1,529.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET 10,635.4 9,813.6
OTHER NONCURRENT ASSETS
Regulatory Assets 275.2 266.8
Securitized Assets
(December 31, 2021 and 2020 Amounts Include $367.6 and $446.8, Respectively, Related to Transition Funding and Restoration Funding)
367.6 446.8
Deferred Charges and Other Noncurrent Assets 211.3 192.1
TOTAL OTHER NONCURRENT ASSETS 854.1 905.7
TOTAL ASSETS $ 11,836.7 $ 11,030.2
See Notes to Financial Statements of Registrants beginning on page 226.
AEP TEXAS INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
December 31, 2021 and 2020
(in millions)
December 31,
2021 2020
CURRENT LIABILITIES
Advances from Affiliates $ 26.9 $ 67.1
Accounts Payable:
General 306.3 231.7
Affiliated Companies 32.5 44.0
Long-term Debt Due Within One Year - Nonaffiliated
(December 31, 2021 and 2020 Amounts Include $91 and $88.7, Respectively, Related to Transition Funding and Restoration Funding)
716.0 88.7
Accrued Taxes 93.3 78.3
Accrued Interest
(December 31, 2021 and 2020 Amounts Include $2.3 and $2.5, Respectively, Related to Transition Funding and Restoration Funding)
44.7 43.9
Obligations Under Operating Leases 14.0 14.5
Other Current Liabilities 78.0 108.6
TOTAL CURRENT LIABILITIES 1,311.7 676.8
NONCURRENT LIABILITIES
Long-term Debt - Nonaffiliated
(December 31, 2021 and 2020 Amounts Include $313.7 and $403.9, Respectively, Related to Transition Funding and Restoration Funding)
4,464.8 4,731.7
Deferred Income Taxes 1,088.9 1,016.7
Regulatory Liabilities and Deferred Investment Tax Credits 1,242.0 1,270.8
Obligations Under Operating Leases 61.3 71.0
Deferred Credits and Other Noncurrent Liabilities 73.8 57.2
TOTAL NONCURRENT LIABILITIES 6,930.8 7,147.4
TOTAL LIABILITIES 8,242.5 7,824.2
Rate Matters (Note 4)
Commitments and Contingencies (Note 6)
COMMON SHAREHOLDER’S EQUITY
Paid-in Capital 1,553.9 1,457.9
Retained Earnings 2,046.8 1,757.0
Accumulated Other Comprehensive Income (Loss) (6.5) (8.9)
TOTAL COMMON SHAREHOLDER’S EQUITY 3,594.2 3,206.0
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY $ 11,836.7 $ 11,030.2
See Notes to Financial Statements of Registrants beginning on page 226.
AEP TEXAS INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Years Ended December 31,
2021 2020 2019
OPERATING ACTIVITIES
Net Income $ 289.8 $ 241.0 $ 178.3
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 387.0 529.8 622.3
Deferred Income Taxes 43.0 (15.2) (23.5)
Asset Impairments and Other Related Charges - - 32.5
Allowance for Equity Funds Used During Construction (21.5) (19.4) (15.2)
Mark-to-Market of Risk Management Contracts - - (0.2)
Pension Contributions to Qualified Plan Trust - (11.3) -
Change in Other Noncurrent Assets (78.2) (74.0) 9.3
Change in Other Noncurrent Liabilities 26.4 (24.7) 11.3
Changes in Certain Components of Working Capital:
Accounts Receivable, Net (21.6) 9.8 3.5
Fuel, Materials and Supplies (3.9) (7.4) (1.0)
Accounts Payable 8.9 30.2 7.5
Accrued Taxes, Net 7.0 42.7 (11.8)
Other Current Assets (0.9) 0.8 (0.4)
Other Current Liabilities (39.4) (88.1) 10.8
Net Cash Flows from Operating Activities 596.6 614.2 823.4
INVESTING ACTIVITIES
Construction Expenditures (1,033.3) (1,295.0) (1,275.1)
Change in Advances to Affiliates, Net 0.2 200.1 (199.2)
Other Investing Activities 32.3 29.5 2.1
Net Cash Flows Used for Investing Activities (1,000.8) (1,065.4) (1,472.2)
FINANCING ACTIVITIES
Capital Contribution from Parent 96.0 - 200.0
Issuance of Long-term Debt - Nonaffiliated 444.2 652.7 1,070.4
Change in Advances from Affiliates, Net (40.2) 67.1 (216.0)
Retirement of Long-term Debt - Nonaffiliated (88.7) (392.1) (401.8)
Principal Payments for Finance Lease Obligations (6.7) (6.3) (5.1)
Other Financing Activities 1.3 0.8 (0.7)
Net Cash Flows from Financing Activities 405.9 322.2 646.8
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash 1.7 (129.0) (2.0)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period 28.8 157.8 159.8
Cash, Cash Equivalents and Restricted Cash at End of Period $ 30.5 $ 28.8 $ 157.8
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts $ 168.9 $ 153.2 $ 148.6
Net Cash Paid (Received) for Income Taxes 5.7 (42.9) (11.0)
Noncash Acquisitions Under Finance Leases 4.4 5.6 11.4
Construction Expenditures Included in Current Liabilities as of December 31, 230.0 177.8 225.5
See Notes to Financial Statements of Registrants beginning on page 226.
AEP TRANSMISSION COMPANY, LLC
AND SUBSIDIARIES
AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
Summary of Investment in Transmission Assets for AEPTCo
As of December 31,
2021 2020 2019
(in millions)
Plant In Service $ 11,313.7 $ 9,923.0 $ 8,407.5
CWIP 1,394.8 1,422.6 1,485.7
Accumulated Depreciation 772.8 572.8 402.3
Total Transmission Property, Net $ 11,935.7 $ 10,772.8 $ 9,490.9
2021 Compared to 2020
AEP Transmission Company, LLC and Subsidiaries
Reconciliation of Year Ended December 31, 2020 to Year Ended December 31, 2021
Net Income
(in millions)
Year Ended December 31, 2020 $ 423.4
Changes in Transmission Revenues:
Transmission Revenues 323.6
Total Change in Transmission Revenues 323.6
Changes in Expenses and Other:
Other Operation and Maintenance (13.9)
Depreciation and Amortization (48.3)
Taxes Other Than Income Taxes (33.6)
Interest Income - Affiliated (1.9)
Allowance for Equity Funds Used During Construction (6.8)
Interest Expense (13.4)
Total Change in Expenses and Other (117.9)
Income Tax Expense (37.4)
Year Ended December 31, 2021 $ 591.7
The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and nonaffiliates were as follows:
•Transmission Revenues increased $324 million primarily due to the following:
•A $260 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 $14 million increase as a result of the nonaffiliated annual transmission formula rate true-up.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $14 million primarily due to:
•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 $37 million primarily due to an increase in pretax book income.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Member of
AEP Transmission Company, LLC
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of AEP Transmission Company, LLC and its subsidiaries (the “Company”) as of December 31, 2021 and 2020, and the related consolidated statements of income, of changes in member's equity and of cash flows for each of the three years in the period ended December 31, 2021, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Cost-Based Regulation
As described in Notes 1 and 5 to the consolidated financial statements, the Company’s consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. As of December 31, 2021, there were $8.5 million of deferred costs included in regulatory assets and $664.1 million of regulatory liabilities awaiting potential refund or future rate reduction, $8.7 million of which are pending final regulatory determination. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation.
The principal considerations for our determination that performing procedures relating to the accounting for the effects of cost-based regulation is a critical audit matter are the significant judgment by management in the ongoing evaluation of the recovery of regulatory assets and refund of regulatory liabilities, and in applying guidance contained in rate orders and other relevant evidence; this in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence related to the probability of recovery of regulatory assets and refund of regulatory liabilities.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s evaluation of new events, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management’s assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, application of relevant regulatory precedents, and other relevant evidence.
/s/ PricewaterhouseCoopers LLP
Columbus, Ohio
February 24, 2022
We have served as the Company's auditor since 2017.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of AEP Transmission Company, LLC and Subsidiaries (AEPTCo) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. AEPTCo’s internal control is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of AEPTCo’s internal control over financial reporting as of December 31, 2021. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). Based on management’s assessment, management concluded AEPTCo’s internal control over financial reporting was effective as of December 31, 2021.
This annual report does not include an audit report from PricewaterhouseCoopers LLP, AEPTCo’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit AEPTCo to provide only management’s report in this annual report.
AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Years Ended December 31,
2021 2020 2019
REVENUES
Transmission Revenues $ 315.1 $ 248.8 $ 214.6
Sales to AEP Affiliates 1,153.9 896.3 806.7
Other Revenues 0.3 0.6 0.1
TOTAL REVENUES 1,469.3 1,145.7 1,021.4
EXPENSES
Other Operation 105.5 99.8 93.9
Maintenance 18.4 10.2 15.4
Depreciation and Amortization 297.3 249.0 176.0
Taxes Other Than Income Taxes 238.8 205.2 168.9
TOTAL EXPENSES 660.0 564.2 454.2
OPERATING INCOME 809.3 581.5 567.2
Other Income (Expense):
Interest Income - Affiliated 0.5 2.4 3.0
Allowance for Equity Funds Used During Construction 67.2 74.0 84.3
Interest Expense (141.2) (127.8) (97.4)
INCOME BEFORE INCOME TAX EXPENSE 735.8 530.1 557.1
Income Tax Expense 144.1 106.7 117.4
NET INCOME $ 591.7 $ 423.4 $ 439.7
AEPTCo is wholly-owned by AEP Transmission Holdco.
See Notes to Financial Statements of Registrants beginning on page 226.
AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Paid-in
Capital Retained
Earnings Total Member’s Equity
TOTAL MEMBER'S EQUITY - DECEMBER 31, 2018 $ 2,480.6 $ 1,089.2 $ 3,569.8
Net Income 439.7 439.7
TOTAL MEMBER'S EQUITY - DECEMBER 31, 2019 2,480.6 1,528.9 4,009.5
Capital Contribution from Member 335.0 335.0
Capital Distribution of Radial Assets to Member (50.0) (50.0)
Dividends Paid to Member (5.0) (5.0)
Net Income 423.4 423.4
TOTAL MEMBER'S EQUITY - DECEMBER 31, 2020 2,765.6 1,947.3 4,712.9
Capital Contribution from Member 184.0 184.0
Dividends Paid to Member (112.5) (112.5)
Net Income 591.7 591.7
TOTAL MEMBER'S EQUITY - DECEMBER 31, 2021 $ 2,949.6 $ 2,426.5 $ 5,376.1
See Notes to Financial Statements of Registrants beginning on page 226.
AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2021 and 2020
(in millions)
December 31,
2021 2020
CURRENT ASSETS
Advances to Affiliates $ 27.2 $ 109.1
Accounts Receivable:
Customers 22.5 22.9
Affiliated Companies 96.1 81.2
Total Accounts Receivable 118.6 104.1
Materials and Supplies 9.3 8.5
Accrued Tax Benefits 5.6 9.9
Assets Held for Sale 167.9 -
Prepayments and Other Current Assets 2.7 4.2
TOTAL CURRENT ASSETS 331.3 235.8
TRANSMISSION PROPERTY
Transmission Property 10,886.3 9,593.5
Other Property, Plant and Equipment 427.4 329.5
Construction Work in Progress 1,394.8 1,422.6
Total Transmission Property 12,708.5 11,345.6
Accumulated Depreciation and Amortization 772.8 572.8
TOTAL TRANSMISSION PROPERTY - NET
11,935.7 10,772.8
OTHER NONCURRENT ASSETS
Regulatory Assets 8.5 15.1
Deferred Property Taxes 245.7 220.1
Deferred Charges and Other Noncurrent Assets 3.2 2.2
TOTAL OTHER NONCURRENT ASSETS 257.4 237.4
TOTAL ASSETS $ 12,524.4 $ 11,246.0
See Notes to Financial Statements of Registrants beginning on page 226.
AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND MEMBER’S EQUITY
December 31, 2021 and 2020
December 31,
2021 2020
(in millions)
CURRENT LIABILITIES
Advances from Affiliates $ 124.0 $ 156.7
Accounts Payable:
General 460.1 380.4
Affiliated Companies 69.9 97.3
Long-term Debt Due Within One Year - Nonaffiliated 104.0 50.0
Accrued Taxes 479.0 418.1
Accrued Interest 28.4 23.9
Obligations Under Operating Leases 0.9 1.2
Liabilities Held for Sale 27.6 -
Other Current Liabilities 3.0 9.9
TOTAL CURRENT LIABILITIES 1,296.9 1,137.5
NONCURRENT LIABILITIES
Long-term Debt - Nonaffiliated 4,239.9 3,898.5
Deferred Income Taxes 962.9 906.9
Regulatory Liabilities 644.1 581.8
Obligations Under Operating Leases 1.3 0.4
Deferred Credits and Other Noncurrent Liabilities 3.2 8.0
TOTAL NONCURRENT LIABILITIES 5,851.4 5,395.6
TOTAL LIABILITIES 7,148.3 6,533.1
Rate Matters (Note 4)
Commitments and Contingencies (Note 6)
MEMBER’S EQUITY
Paid-in Capital 2,949.6 2,765.6
Retained Earnings 2,426.5 1,947.3
TOTAL MEMBER’S EQUITY 5,376.1 4,712.9
TOTAL LIABILITIES AND MEMBER’S EQUITY $ 12,524.4 $ 11,246.0
See Notes to Financial Statements of Registrants beginning on page 226.
AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Years Ended December 31,
2021 2020 2019
OPERATING ACTIVITIES
Net Income $ 591.7 $ 423.4 $ 439.7
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 297.3 249.0 176.0
Deferred Income Taxes 68.5 81.6 91.3
Allowance for Equity Funds Used During Construction (67.2) (74.0) (84.3)
Property Taxes (25.6) (26.6) (35.6)
Change in Other Noncurrent Assets 7.5 (8.2) 9.6
Change in Other Noncurrent Liabilities 3.7 8.3 (8.1)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net (16.0) (19.0) (5.4)
Materials and Supplies (0.8) 5.3 5.2
Accounts Payable (2.2) 77.8 37.6
Accrued Taxes, Net 67.2 62.7 90.8
Accrued Interest 4.8 4.7 3.3
Other Current Assets 1.2 0.7 (0.3)
Other Current Liabilities (4.4) (14.5) (11.2)
Net Cash Flows from Operating Activities 925.7 771.2 708.6
INVESTING ACTIVITIES
Construction Expenditures (1,424.8) (1,615.9) (1,410.1)
Change in Advances to Affiliates, Net 81.9 (23.7) 11.5
Acquisitions of Assets (17.9) (6.0) (9.4)
Other Investing Activities 1.8 5.2 4.8
Net Cash Flows Used for Investing Activities (1,359.0) (1,640.4) (1,403.2)
FINANCING ACTIVITIES
Capital Contributions from Member 184.0 335.0 -
Issuance of Long-term Debt - Nonaffiliated 443.7 519.5 688.0
Change in Advances from Affiliates, Net (31.9) 19.7 91.6
Retirement of Long-term Debt - Nonaffiliated (50.0) - (85.0)
Dividends Paid to Member (112.5) (5.0) -
Net Cash Flows from Financing Activities 433.3 869.2 694.6
Net Change in Cash and Cash Equivalents - - -
Cash and Cash Equivalents at Beginning of Period - - -
Cash and Cash Equivalents at End of Period $ - $ - $ -
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts $ 132.9 $ 119.7 $ 90.6
Net Cash Paid for Income Taxes 65.7 22.9 1.5
Construction Expenditures Included in Current Liabilities as of December 31, 358.7 311.9 472.7
Noncash Distribution of Radial Assets to Member - (50.0) -
See Notes to Financial Statements of Registrants beginning on page 226.
APPALACHIAN POWER COMPANY
AND SUBSIDIARIES
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
KWh Sales/Degree Days
Summary of KWh Energy Sales
Years Ended December 31,
2021 2020 2019
(in millions of KWhs)
Retail:
Residential 11,207 10,916 11,253
Commercial 5,949 5,887 6,365
Industrial 8,879 8,873 9,546
Miscellaneous 810 794 857
Total Retail 26,845 26,470 28,021
Wholesale 4,285 3,281 3,085
Total KWhs 31,130 29,751 31,106
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.
Summary of Heating and Cooling Degree Days
Years Ended December 31,
2021 2020 2019
(in degree days)
Actual - Heating (a) 1,969 1,764 2,057
Normal - Heating (b) 2,210 2,216 2,224
Actual - Cooling (c) 1,389 1,379 1,597
Normal - Cooling (b) 1,242 1,236 1,221
(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.
2021 Compared to 2020
Appalachian Power Company and Subsidiaries
Reconciliation of Year Ended December 31, 2020 to Year Ended December 31, 2021
Net Income
(in millions)
Year Ended December 31, 2020 $ 369.7
Changes in Gross Margin:
Retail Margins 179.9
Margins from Off-system Sales 3.9
Transmission Revenues 18.4
Other Revenues 0.5
Total Change in Gross Margin 202.7
Changes in Expenses and Other:
Other Operation and Maintenance (118.2)
Re-Establishment of Regulatory Asset - Coal Fired Generation (49.0)
Depreciation and Amortization (38.7)
Taxes Other Than Income Taxes (4.0)
Interest Income (0.6)
Allowance for Equity Funds Used During Construction 1.0
Non-Service Cost Components of Net Periodic Benefit Cost 0.2
Interest Expense 3.6
Total Change in Expenses and Other (205.7)
Income Tax Expense (17.8)
Year Ended December 31, 2021 $ 348.9
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 $180 million primarily due to the following:
•A $99 million increase due to rider revenues in Virginia and West Virginia, which includes the WV modified rate base cost surcharge, effective September 2021. 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 $24 million increase in weather-related usage primarily driven by a 12% increase in heating degree days.
•A $19 million increase due to lower customer refunds related to Tax Reform. This increase was partially offset in Income Tax Expense below.
•A $14 million increase in weather-normalized margins primarily in the residential and commercial classes.
These increases were partially offset by:
•An $18 million decrease in deferred fuel primarily due to the timing of recoverable expenses. This decrease was offset in other expense items below.
•Margins from Off-system Sales increased $4 million due to stronger market prices for energy in RTOs which caused an increase in sales volume and margins.
•Transmission Revenues increased $18 million primarily due to continued investment in transmission assets. This increase was partially offset in Depreciation and Amortization expenses below.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $118 million primarily due to the following:
•A $64 million increase in recoverable PJM transmission expenses. This increase was partially offset in Retail Margins above.
•A $41 million increase in vegetation management services. This increase was partially offset in Retail Margins above.
•A $24 million increase in transmission formula rate true-up activity. This increase was partially offset in Retail Margins above.
These increases were partially offset by:
•A $9 million decrease in employee-related expenses.
•An $8 million decrease in accretion expense primarily due to the deferral of incremental Glen Lyn ash pond ARO expense.
•Re-Establishment of Regulatory Asset - Coal Fired Generation decreased $49 million due to the 2017-2019 Virginia triennial review which authorized regulatory recovery of previously retired coal-fired generation assets.
•Depreciation and Amortization expenses increased $39 million primarily due to an increase in depreciation rates in Virginia and a higher depreciable base. This increase was partially offset in Retail Margins and Transmission Revenues above.
•Taxes Other Than Income Taxes increased $4 million primarily due to an increase in West Virginia business and occupational taxes.
•Interest Expense decreased $4 million primarily due to lower short-term debt balances.
•Income Tax Expense increased $18 million primarily due to a decrease in amortization of Excess ADIT and parent company loss benefit. The decrease in amortization of Excess ADIT was partially offset in Retail Margin above.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Appalachian Power Company
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Appalachian Power Company and its subsidiaries (the “Company”) as of December 31, 2021 and 2020, and the related consolidated statements of income, of comprehensive income (loss), of changes in common shareholder's equity and of cash flows for each of the three years in the period ended December 31, 2021, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Cost-Based Regulation
As described in Notes 1 and 5 to the consolidated financial statements, the Company’s consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. As of December 31, 2021, there were $958.9 million of deferred costs included in regulatory assets, $105.1 million of which were pending final regulatory approval, and $1.2 billion of regulatory liabilities awaiting potential refund or future rate reduction, $4.5 million of which are pending final regulatory determination. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation.
The principal considerations for our determination that performing procedures relating to the accounting for the effects of cost-based regulation is a critical audit matter are the significant judgment by management in the ongoing evaluation of the recovery of regulatory assets and refund of regulatory liabilities, and in applying guidance contained in rate orders and other relevant evidence; this in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence related to the probability of recovery of regulatory assets and refund of regulatory liabilities.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s evaluation of new events, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management’s assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, application of relevant regulatory precedents, and other relevant evidence.
/s/ PricewaterhouseCoopers LLP
Columbus, Ohio
February 24, 2022
We have served as the Company's auditor since 2017.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Appalachian Power Company and Subsidiaries (APCo) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. APCo’s internal control is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of APCo’s internal control over financial reporting as of December 31, 2021. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). Based on management’s assessment, management concluded APCo’s internal control over financial reporting was effective as of December 31, 2021.
This annual report does not include an audit report from PricewaterhouseCoopers LLP, APCo’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit APCo to provide only management’s report in this annual report.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Years Ended December 31,
2021 2020 2019
REVENUES
Electric Generation, Transmission and Distribution $ 2,895.5 $ 2,610.9 $ 2,708.2
Sales to AEP Affiliates 197.9 174.7 205.3
Other Revenues 11.8 10.6 11.2
TOTAL REVENUES 3,105.2 2,796.2 2,924.7
EXPENSES
Fuel and Other Consumables Used for Electric Generation 440.3 513.3 607.5
Purchased Electricity for Resale 539.6 360.3 391.0
Other Operation 610.0 530.5 567.6
Maintenance 265.5 226.8 255.4
Asset Impairments and Other Related Charges - Coal Fired Generation - - 92.9
Re-Establishment of Regulatory Asset - Coal Fired Generation - (49.0) -
Depreciation and Amortization 546.2 507.5 466.8
Taxes Other Than Income Taxes 154.2 150.2 146.2
TOTAL EXPENSES 2,555.8 2,239.6 2,527.4
OPERATING INCOME 549.4 556.6 397.3
Other Income (Expense):
Interest Income 1.0 1.6 2.4
Allowance for Equity Funds Used During Construction 15.6 14.6 16.6
Non-Service Cost Components of Net Periodic Benefit Cost 19.0 18.8 17.0
Interest Expense (214.0) (217.6) (205.0)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 371.0 374.0 228.3
Income Tax Expense (Benefit) 22.1 4.3 (78.0)
NET INCOME $ 348.9 $ 369.7 $ 306.3
The common stock of APCo is wholly-owned by Parent.
See Notes to Financial Statements of Registrants beginning on page 226.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Years Ended December 31,
2021 2020 2019
Net Income $ 348.9 $ 369.7 $ 306.3
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $2.2, $(0.5) and $(0.2) in 2021, 2020 and 2019, Respectively
8.3 (1.7) (0.9)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(1.1), $(1.0) and $(0.7) in 2021, 2020 and 2019, Respectively
(4.2) (3.8) (2.5)
Pension and OPEB Funded Status, Net of Tax of $3.5, $2.0 and $3.6 in 2021, 2020 and 2019, Respectively
13.1 7.7 13.4
TOTAL OTHER COMPREHENSIVE INCOME 17.2 2.2 10.0
TOTAL COMPREHENSIVE INCOME $ 366.1 $ 371.9 $ 316.3
See Notes to Financial Statements of Registrants beginning on page 226.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Common
Stock Paid-in
Capital Retained
Earnings Accumulated
Other
Comprehensive
Income (Loss) Total
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2018 $ 260.4 $ 1,828.7 $ 1,922.0 $ (5.0) $ 4,006.1
Common Stock Dividends (150.0) (150.0)
Net Income 306.3 306.3
Other Comprehensive Income 10.0 10.0
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2019 260.4 1,828.7 2,078.3 5.0 4,172.4
Common Stock Dividends (200.0) (200.0)
Net Income 369.7 369.7
Other Comprehensive Income 2.2 2.2
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2020 260.4 1,828.7 2,248.0 7.2 4,344.3
Common Stock Dividends (62.5) (62.5)
Net Income 348.9 348.9
Other Comprehensive Income 17.2 17.2
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2021 $ 260.4 $ 1,828.7 $ 2,534.4 $ 24.4 $ 4,647.9
See Notes to Financial Statements of Registrants beginning on page 226.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2021 and 2020
(in millions)
December 31,
2021 2020
CURRENT ASSETS
Cash and Cash Equivalents $ 2.5 $ 5.8
Restricted Cash for Securitized Funding 17.6 16.9
Advances to Affiliates 20.8 21.4
Accounts Receivable:
Customers 158.5 142.8
Affiliated Companies 129.9 64.3
Accrued Unbilled Revenues 54.0 80.1
Miscellaneous 0.2 0.3
Allowance for Uncollectible Accounts (1.6) (3.1)
Total Accounts Receivable 341.0 284.4
Fuel 67.1 193.6
Materials and Supplies 109.8 99.6
Risk Management Assets 42.0 22.4
Regulatory Asset for Under-Recovered Fuel Costs 201.3 5.3
Margin Deposits 71.8 1.8
Prepayments and Other Current Assets 51.4 22.9
TOTAL CURRENT ASSETS 925.3 674.1
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation 6,683.9 6,633.7
Transmission 4,322.4 3,900.5
Distribution 4,683.3 4,464.3
Other Property, Plant and Equipment 696.6 627.2
Construction Work in Progress 469.9 484.6
Total Property, Plant and Equipment 16,856.1 16,110.3
Accumulated Depreciation and Amortization 5,051.8 4,716.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET 11,804.3 11,394.1
OTHER NONCURRENT ASSETS
Regulatory Assets 757.6 686.3
Securitized Assets 185.1 210.1
Employee Benefits and Pension Assets 220.5 150.1
Operating Lease Assets 66.9 78.8
Deferred Charges and Other Noncurrent Assets 129.2 121.7
TOTAL OTHER NONCURRENT ASSETS 1,359.3 1,247.0
TOTAL ASSETS $ 14,088.9 $ 13,315.2
See Notes to Financial Statements of Registrants beginning on page 226.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
December 31, 2021 and 2020
December 31,
2021 2020
(in millions)
CURRENT LIABILITIES
Advances from Affiliates $ 199.3 $ 18.6
Accounts Payable:
General 262.2 212.0
Affiliated Companies 118.6 97.1
Long-term Debt Due Within One Year - Nonaffiliated 480.7 518.3
Customer Deposits 73.9 77.8
Accrued Taxes 119.7 109.9
Obligations Under Operating Leases 15.1 14.9
Other Current Liabilities 146.4 169.1
TOTAL CURRENT LIABILITIES 1,415.9 1,217.7
NONCURRENT LIABILITIES
Long-term Debt - Nonaffiliated 4,458.2 4,315.8
Deferred Income Taxes 1,804.7 1,749.9
Regulatory Liabilities and Deferred Investment Tax Credits 1,238.8 1,224.7
Asset Retirement Obligations 394.9 304.8
Employee Benefits and Pension Obligations 41.5 44.0
Obligations Under Operating Leases 52.4 64.4
Deferred Credits and Other Noncurrent Liabilities 34.6 49.6
TOTAL NONCURRENT LIABILITIES 8,025.1 7,753.2
TOTAL LIABILITIES 9,441.0 8,970.9
Rate Matters (Note 4)
Commitments and Contingencies (Note 6)
COMMON SHAREHOLDER’S EQUITY
Common Stock - No Par Value:
Authorized -30,000,000 Shares
Outstanding - 13,499,500 Shares
260.4 260.4
Paid-in Capital 1,828.7 1,828.7
Retained Earnings 2,534.4 2,248.0
Accumulated Other Comprehensive Income (Loss) 24.4 7.2
TOTAL COMMON SHAREHOLDER’S EQUITY 4,647.9 4,344.3
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $ 14,088.9 $ 13,315.2
See Notes to Financial Statements of Registrants beginning on page 226.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Years Ended December 31,
2021 2020 2019
OPERATING ACTIVITIES
Net Income $ 348.9 $ 369.7 $ 306.3
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 546.2 507.5 466.8
Deferred Income Taxes 15.0 (26.2) (126.2)
Asset Impairments and Other Related Charges - Coal Fired Generation - - 92.9
Allowance for Equity Funds Used During Construction (15.6) (14.6) (16.6)
Mark-to-Market of Risk Management Contracts (22.3) 18.8 19.9
Pension Contributions to Qualified Plan Trust - (7.0) -
Deferred Fuel Over/Under-Recovery, Net (196.0) 37.2 57.1
Re-Establishment of Regulatory Asset - Coal Fired Generation - (49.0) -
Change in Other Noncurrent Assets (68.8) (40.4) (38.2)
Change in Other Noncurrent Liabilities 35.6 11.2 (40.3)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net (53.3) (30.2) 35.7
Fuel, Materials and Supplies 116.1 (38.2) (93.4)
Margin Deposits (70.0) 2.8 8.1
Accounts Payable 36.8 (48.1) 37.7
Accrued Taxes, Net (16.2) 31.3 (10.2)
Other Current Assets (2.4) 15.5 7.3
Other Current Liabilities (42.3) (28.3) (45.5)
Net Cash Flows from Operating Activities 611.7 712.0 661.4
INVESTING ACTIVITIES
Construction Expenditures (841.6) (767.4) (862.6)
Change in Advances to Affiliates, Net 0.6 0.7 0.9
Other Investing Activities 14.5 8.8 24.3
Net Cash Flows Used for Investing Activities (826.5) (757.9) (837.4)
FINANCING ACTIVITIES
Issuance of Long-term Debt - Nonaffiliated 494.0 606.9 478.2
Change in Advances from Affiliates, Net 180.7 (218.1) 31.1
Retirement of Long-term Debt - Nonaffiliated (393.0) (140.3) (180.5)
Principal Payments for Finance Lease Obligations (7.7) (7.4) (6.7)
Dividends Paid on Common Stock (62.5) (200.0) (150.0)
Other Financing Activities 0.7 0.7 0.9
Net Cash Flows from Financing Activities 212.2 41.8 173.0
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding (2.6) (4.1) (3.0)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period 22.7 26.8 29.8
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period $ 20.1 $ 22.7 $ 26.8
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts $ 207.5 $ 207.1 $ 190.7
Net Cash Paid for Income Taxes 32.8 - 63.0
Noncash Acquisitions Under Finance Leases 1.7 7.2 8.8
Construction Expenditures Included in Current Liabilities as of December 31, 139.1 105.6 149.7
See Notes to Financial Statements of Registrants beginning on page 226.
INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
KWh Sales/Degree Days
Summary of KWh Energy Sales
Years Ended December 31,
2021 2020 2019
(in millions of KWhs)
Retail:
Residential 5,463 5,464 5,409
Commercial 4,600 4,475 4,685
Industrial 7,373 7,225 7,589
Miscellaneous 58 67 69
Total Retail 17,494 17,231 17,752
Wholesale 6,618 7,135 8,268
Total KWhs 24,112 24,366 26,020
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.
Summary of Heating and Cooling Degree Days
Years Ended December 31,
2021 2020 2019
(in degree days)
Actual - Heating (a)
3,396 3,352 3,782
Normal - Heating (b)
3,730 3,742 3,740
Actual - Cooling (c)
1,055 928 940
Normal - Cooling (b)
861 854 849
(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.
2021 Compared to 2020
Indiana Michigan Power Company and Subsidiaries
Reconciliation of Year Ended December 31, 2020 to Year Ended December 31, 2021
Net Income
(in millions)
Year Ended December 31, 2020 $ 284.8
Changes in Gross Margin:
Retail Margins 48.9
Margins from Off-system Sales 0.5
Transmission Revenues (5.1)
Other Revenues 0.8
Total Change in Gross Margin 45.1
Changes in Expenses and Other:
Other Operation and Maintenance (12.0)
Depreciation and Amortization (34.4)
Taxes Other Than Income Taxes (3.7)
Other Income 1.7
Non-Service Cost Components of Net Periodic Benefit Cost (0.3)
Interest Expense (4.5)
Total Change in Expenses and Other (53.2)
Income Tax Benefit 3.1
Year Ended December 31, 2021 $ 279.8
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 $49 million primarily due to the following:
•A $48 million increase in rider revenues. This increase was partially offset in other expense items below.
•A $30 million increase in Indiana and Michigan base rate revenues. This increase was partially offset in expense items below.
•A $19 million increase due to the annual wholesale formula rate true-up. This increase was partially offset in expense items below.
•A $16 million increase in weather-related usage primarily due to a 14% increase in cooling degree days.
•A $6 million decrease in fuel related expenses due to timing of recovery related to wholesale contracts.
These increases were partially offset by:
•A $49 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.
•Transmission Revenues decreased $5 million primarily due to the transmission formula rate true-up activity.
Expenses and Other and Income Tax Benefit changed between years as follows:
•Other Operation and Maintenance expenses increased $12 million primarily due to the following:
•A $27 million increase in transmission expenses primarily due to a $17 million increase in transmission formula rate true-up activity and a $7 million increase in vegetation management expenses.
•A $25 million increase in recoverable PJM transmission expenses. This increase was partially offset in Retail Margins above.
•An $8 million increase in distribution expenses primarily due to an increase in vegetation management expenses.
•A $4 million increase due to a decreased Nuclear Electric Insurance Limited distribution in 2021.
These increases were partially offset by:
•A $28 million decrease in Indiana jurisdictional Demand Side Management expenses. This decrease was offset in Retail Margins above.
•A $23 million decrease in employee-related expenses.
•Depreciation and Amortization expenses increased $34 million primarily due to a higher depreciable base and an increase in depreciation rates. This increase was partially offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $4 million primarily due to property taxes driven by an increase in utility plant and higher tax rates.
•Interest Expense increased $5 million primarily due to higher long-term debt balances.
•Income Tax Benefit increased $3 million primarily due to a decrease in pretax book income and state tax expense.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Indiana Michigan Power Company
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Indiana Michigan Power Company and its subsidiaries (the “Company”) as of December 31, 2021 and 2020, and the related consolidated statements of income, of comprehensive income (loss), of changes in common shareholder's equity and of cash flows for each of the three years in the period ended December 31, 2021, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Cost-Based Regulation
As described in Notes 1 and 5 to the consolidated financial statements, the Company’s consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. As of December 31, 2021, there were $417.3 million of deferred costs included in regulatory assets, $3.7 million of which were pending final regulatory approval, and $2.4 billion of regulatory liabilities awaiting potential refund or future rate reduction. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation.
The principal considerations for our determination that performing procedures relating to the accounting for the effects of cost-based regulation is a critical audit matter are the significant judgment by management in the ongoing evaluation of the recovery of regulatory assets and refund of regulatory liabilities, and in applying guidance contained in rate orders and other relevant evidence; this in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence related to the probability of recovery of regulatory assets and refund of regulatory liabilities.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s evaluation of new events, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management’s assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, application of relevant regulatory precedents, and other relevant evidence.
/s/ PricewaterhouseCoopers LLP
Columbus, Ohio
February 24, 2022
We have served as the Company's auditor since 2017.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Indiana Michigan Power Company and Subsidiaries (I&M) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. I&M’s internal control is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of I&M’s internal control over financial reporting as of December 31, 2021. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). Based on management’s assessment, management concluded I&M’s internal control over financial reporting was effective as of December 31, 2021.
This annual report does not include an audit report from PricewaterhouseCoopers LLP, I&M’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit I&M to provide only management’s report in this annual report.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Years Ended December 31,
2021 2020 2019
REVENUES
Electric Generation, Transmission and Distribution $ 2,261.2 $ 2,165.3 $ 2,222.1
Sales to AEP Affiliates 3.8 10.5 10.5
Other Revenues - Affiliated 54.0 60.8 63.4
Other Revenues - Nonaffiliated 7.7 5.2 10.7
TOTAL REVENUES 2,326.7 2,241.8 2,306.7
EXPENSES
Fuel and Other Consumables Used for Electric Generation 162.1 162.0 190.6
Purchased Electricity for Resale 176.8 182.2 232.3
Purchased Electricity from AEP Affiliates 217.9 172.8 214.9
Other Operation 645.2 650.0 641.2
Maintenance 210.0 193.2 231.2
Depreciation and Amortization 446.0 411.6 350.6
Taxes Other Than Income Taxes 110.8 107.1 105.1
TOTAL EXPENSES 1,968.8 1,878.9 1,965.9
OPERATING INCOME 357.9 362.9 340.8
Other Income (Expense):
Other Income 11.7 10.0 18.2
Non-Service Cost Components of Net Periodic Benefit Cost 16.4 16.7 17.7
Interest Expense (116.8) (112.3) (117.9)
INCOME BEFORE INCOME TAX BENEFIT 269.2 277.3 258.8
Income Tax Benefit (10.6) (7.5) (10.6)
NET INCOME $ 279.8 $ 284.8 $ 269.4
The common stock of I&M is wholly-owned by Parent.
See Notes to Financial Statements of Registrants beginning on page 226.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Years Ended December 31,
2021 2020 2019
Net Income $ 279.8 $ 284.8 $ 269.4
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.4, $0.4 and $0.4 in 2021, 2020 and 2019, Respectively
1.6 1.6 1.6
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0, $0 and $0 in 2021, 2020 and 2019, Respectively
(0.1) (0.1) (0.2)
Pension and OPEB Funded Status, Net of Tax of $1.1, $0.8 and $0.2 in 2021, 2020 and 2019, Respectively
4.2 3.1 0.8
TOTAL OTHER COMPREHENSIVE INCOME 5.7 4.6 2.2
TOTAL COMPREHENSIVE INCOME $ 285.5 $ 289.4 $ 271.6
See Notes to Financial Statements of Registrants beginning on page 226.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Common
Stock Paid-in
Capital Retained Earnings Accumulated
Other
Comprehensive
Income (Loss) Total
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2018
$ 56.6 $ 980.9 $ 1,329.1 $ (13.8) $ 2,352.8
Common Stock Dividends (80.0) (80.0)
Net Income 269.4 269.4
Other Comprehensive Income 2.2 2.2
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2019
56.6 980.9 1,518.5 (11.6) 2,544.4
Common Stock Dividends (85.0) (85.0)
ASU 2016-13 Adoption 0.4 0.4
Net Income 284.8 284.8
Other Comprehensive Income 4.6 4.6
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2020
56.6 980.9 1,718.7 (7.0) 2,749.2
Common Stock Dividends (250.0) (250.0)
Net Income 279.8 279.8
Other Comprehensive Income 5.7 5.7
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2021
$ 56.6 $ 980.9 $ 1,748.5 $ (1.3) $ 2,784.7
See Notes to Financial Statements of Registrants beginning on page 226.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2021 and 2020
(in millions)
December 31,
2021 2020
CURRENT ASSETS
Cash and Cash Equivalents $ 1.3 $ 3.3
Advances to Affiliates 21.5 13.3
Accounts Receivable:
Customers 40.6 44.0
Affiliated Companies 78.2 51.3
Miscellaneous 2.5 2.0
Allowance for Uncollectible Accounts (0.1) (0.3)
Total Accounts Receivable 121.2 97.0
Fuel 56.8 86.0
Materials and Supplies 175.2 175.8
Risk Management Assets 3.3 3.6
Accrued Tax Benefits 12.7 10.3
Regulatory Asset for Under-Recovered Fuel Costs 6.4 5.4
Prepayments and Other Current Assets 41.0 24.1
TOTAL CURRENT ASSETS 439.4 418.8
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation 5,531.8 5,264.7
Transmission 1,783.1 1,696.4
Distribution 2,800.1 2,594.6
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 792.9 686.7
Construction Work in Progress 302.8 362.4
Total Property, Plant and Equipment 11,210.7 10,604.8
Accumulated Depreciation, Depletion and Amortization 3,899.8 3,552.5
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET 7,310.9 7,052.3
OTHER NONCURRENT ASSETS
Regulatory Assets 410.9 404.8
Spent Nuclear Fuel and Decommissioning Trusts 3,867.0 3,306.7
Operating Lease Assets 63.5 218.1
Deferred Charges and Other Noncurrent Assets 316.5 237.6
TOTAL OTHER NONCURRENT ASSETS 4,657.9 4,167.2
TOTAL ASSETS $ 12,408.2 $ 11,638.3
See Notes to Financial Statements of Registrants beginning on page 226.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
December 31, 2021 and 2020
(dollars in millions)
December 31,
2021 2020
CURRENT LIABILITIES
Advances from Affiliates $ 93.3 $ 103.0
Accounts Payable:
General 174.4 153.2
Affiliated Companies 94.9 80.5
Long-term Debt Due Within One Year - Nonaffiliated
(December 31, 2021 and 2020 Amounts Include $65.0 and $75.7 Respectively, Related to DCC Fuel)
67.0 369.6
Risk Management Liabilities 5.0 0.1
Customer Deposits 45.2 41.7
Accrued Taxes 106.5 102.5
Accrued Interest 37.0 35.6
Obligations Under Finance Leases 130.5 6.4
Obligations Under Operating Leases 15.5 85.6
Regulatory Liability for Over-Recovered Fuel Costs 1.5 20.8
Other Current Liabilities 123.2 105.5
TOTAL CURRENT LIABILITIES 894.0 1,104.5
NONCURRENT LIABILITIES
Long-term Debt - Nonaffiliated 3,128.0 2,660.3
Deferred Income Taxes 1,100.2 1,064.4
Regulatory Liabilities and Deferred Investment Tax Credits 2,447.9 2,041.9
Asset Retirement Obligations 1,946.2 1,812.9
Obligations Under Operating Leases 48.9 135.9
Deferred Credits and Other Noncurrent Liabilities 58.3 69.2
TOTAL NONCURRENT LIABILITIES 8,729.5 7,784.6
TOTAL LIABILITIES 9,623.5 8,889.1
Rate Matters (Note 4)
Commitments and Contingencies (Note 6)
COMMON SHAREHOLDER’S EQUITY
Common Stock - No Par Value:
Authorized - 2,500,000 Shares
Outstanding - 1,400,000 Shares
56.6 56.6
Paid-in Capital 980.9 980.9
Retained Earnings 1,748.5 1,718.7
Accumulated Other Comprehensive Income (Loss) (1.3) (7.0)
TOTAL COMMON SHAREHOLDER’S EQUITY 2,784.7 2,749.2
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY $ 12,408.2 $ 11,638.3
See Notes to Financial Statements of Registrants beginning on page 226.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Years Ended December 31,
2021 2020 2019
OPERATING ACTIVITIES
Net Income $ 279.8 $ 284.8 $ 269.4
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 446.0 411.6 350.6
Rockport Plant, Unit 2 Operating Lease Amortization 62.4 69.2 69.2
Deferred Income Taxes (38.0) (16.2) (52.7)
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net 7.5 24.4 (26.4)
Allowance for Equity Funds Used During Construction (12.8) (11.5) (19.4)
Mark-to-Market of Risk Management Contracts 5.2 5.9 (0.6)
Amortization of Nuclear Fuel 85.3 87.5 89.1
Pension Contributions to Qualified Plan Trust - (6.4) -
Deferred Fuel Over/Under-Recovery, Net (20.2) 12.4 (24.3)
Change in Other Noncurrent Assets (54.1) 6.1 8.3
Change in Other Noncurrent Liabilities 7.5 45.0 33.7
Changes in Certain Components of Working Capital:
Accounts Receivable, Net (22.3) 14.5 35.4
Fuel, Materials and Supplies 30.1 (34.7) (22.4)
Accounts Payable 42.3 (10.8) 3.6
Accrued Taxes, Net 1.6 (20.2) 48.3
Rockport Plant, Unit 2 Operating Lease Payments (73.9) (73.9) (73.9)
Other Current Assets (15.2) 14.3 11.2
Other Current Liabilities 2.5 (25.7) (13.9)
Net Cash Flows from Operating Activities 733.7 776.3 685.2
INVESTING ACTIVITIES
Construction Expenditures (500.9) (544.7) (585.9)
Change in Advances to Affiliates, Net (8.2) (0.1) (0.5)
Purchases of Investment Securities (1,928.2) (1,637.2) (1,531.0)
Sales of Investment Securities 1,886.4 1,593.4 1,473.0
Acquisitions of Nuclear Fuel (104.5) (69.7) (92.3)
Other Investing Activities 22.3 9.4 16.6
Net Cash Flows Used for Investing Activities (633.1) (648.9) (720.1)
FINANCING ACTIVITIES
Issuance of Long-term Debt - Nonaffiliated 546.7 69.5 123.3
Change in Advances from Affiliates, Net (9.7) (11.4) 113.3
Retirement of Long-term Debt - Nonaffiliated (383.5) (93.2) (117.1)
Principal Payments for Finance Lease Obligations (6.8) (6.5) (5.7)
Dividends Paid on Common Stock (250.0) (85.0) (80.0)
Other Financing Activities 0.7 0.5 0.7
Net Cash Flows from (Used for) Financing Activities (102.6) (126.1) 34.5
Net Increase (Decrease) in Cash and Cash Equivalents (2.0) 1.3 (0.4)
Cash and Cash Equivalents at Beginning of Period 3.3 2.0 2.4
Cash and Cash Equivalents at End of Period $ 1.3 $ 3.3 $ 2.0
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts $ 110.9 $ 107.6 $ 111.9
Net Cash Paid for Income Taxes 29.3 42.1 3.4
Noncash Acquisitions Under Finance Leases 132.3 3.0 11.9
Construction Expenditures Included in Current Liabilities as of December 31, 87.8 62.8 86.0
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31, - 33.4 0.1
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage 1.7 2.6 0.3
See Notes to Financial Statements of Registrants beginning on page 226.
OHIO POWER COMPANY AND SUBSIDIARIES
OHIO POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
KWh Sales/Degree Days
Summary of KWh Energy Sales
Years Ended December 31,
2021 2020 2019
(in millions of KWhs)
Retail:
Residential 14,547 14,355 14,411
Commercial 15,036 13,933 14,599
Industrial 14,321 13,347 14,407
Miscellaneous 112 113 114
Total Retail (a) 44,016 41,748 43,531
Wholesale (b) 2,018 1,859 2,335
Total KWhs 46,034 43,607 45,866
(a)Represents energy delivered to distribution customers.
(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold into PJM.
Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.
Summary of Heating and Cooling Degree Days
Years Ended December 31,
2021 2020 2019
(in degree days)
Actual - Heating (a)
2,815 2,743 3,071
Normal - Heating (b)
3,190 3,202 3,208
Actual - Cooling (c)
1,222 1,140 1,224
Normal - Cooling (b)
1,016 1,006 992
(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.
2021 Compared to 2020
Ohio Power Company and Subsidiaries
Reconciliation of Year Ended December 31, 2020 to Year Ended December 31, 2021
Net Income
(in millions)
Year Ended December 31, 2020 $ 271.4
Changes in Gross Margin:
Retail Margins 115.3
Margins from Off-system Sales (43.6)
Transmission Revenues (8.1)
Other Revenues 25.4
Total Change in Gross Margin 89.0
Changes in Expenses and Other:
Other Operation and Maintenance (45.3)
Depreciation and Amortization (26.7)
Taxes Other Than Income Taxes (35.5)
Interest Income (0.4)
Carrying Costs Income (0.4)
Allowance for Equity Funds Used During Construction (1.7)
Non-Service Cost Components of Net Periodic Benefit Cost (0.4)
Interest Expense (7.2)
Total Change in Expenses and Other (117.6)
Income Tax Expense 10.8
Year Ended December 31, 2021 $ 253.6
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity were as follows:
•Retail Margins increased $115 million primarily due to the following:
•A $164 million net increase in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below.
•A $91 million increase related to various rider revenues. This increase was partially offset in Margins from Off-system Sales, Other Revenues and other expense items below.
•A $15 million increase in weather-normalized margins primarily from the residential class.
These increases were partially offset by:
•An $87 million decrease due to the ending of Energy Efficiency and Peak Demand Reduction Rider 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). This decrease was offset in Other Operations and Maintenance expenses below.
•A $14 million decrease in weather-related usage primarily due to the end of decoupling and mild December weather.
•Margins from Off-system Sales decreased $44 million primarily due to the following:
•A $67 million decrease in deferrals of OVEC costs. This decrease was offset in Retail Margins above and Other Revenues below.
This decrease was partially offset by:
•A $24 million increase in off-system sales at OVEC due to higher market prices and volume. This increase was offset in Retail Margins above and Other Revenues below.
•Transmission Revenues decreased $8 million primarily due to an increase in affiliated transmission expenses netted against revenues.
•Other Revenues increased $25 million primarily due to the following:
•A $17 million increase in third-party Legacy Generation Resource Rider revenues related to the recovery of OVEC costs. This increase was offset in Retail Margins and Margins from Off-system Sales above.
•A $3 million increase in miscellaneous revenues primarily due to an increase in reconnection fees.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $45 million primarily due to the following:
•A $152 million net increase in transmission expenses, primarily 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 above.
•A $20 million increase in recoverable distribution expenses primarily related to vegetation management. This increase was offset in Retail Margins above.
•A $9 million increase in distribution maintenance expenses related to the annual major storm reserve true-up. This increase was offset in Retail Margins above.
These increases were partially offset by:
•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/Peak Demand Reduction expenses. This decrease was partially offset in Retail Margins above.
•A $23 million decrease in factored customer accounts receivable expenses primarily due to lower bad debt expenses and a current year favorable adjustment to the allowance for doubtful accounts.
•A $13 million decrease in employee-related expenses.
•Depreciation and Amortization expenses increased $27 million primarily due to the following:
•A $13 million increase in amortization of capitalized software.
•A $6 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
•A $5 million increase in recoverable smart grid depreciable expenses. This increase was offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $36 million primarily due to the following:
•A $30 million increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
•A $5 million increase in excise taxes driven by increased metered KWh usage in 2021. This increase was offset in Retail Margins above.
•Interest Expense increased $7 million primarily due to higher long-term debt balances.
•Income Tax Expense decreased $11 million primarily due to the following:
•An $8 million decrease due to 2020 tax return to provision adjustments.
•A $6 million decrease due to a decrease in pretax book income.
•A $5 million increase in amortization of Excess ADIT partially offset in Retail Margins above.
These decreases were partially offset by:
•A $9 million increase in tax expense due to an out of period adjustment related to deferred taxes.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Ohio Power Company
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Ohio Power Company and its subsidiaries (the “Company”) as of December 31, 2021 and 2020, and the related consolidated statements of income, of comprehensive income (loss), of changes in common shareholder's equity and of cash flows for each of the three years in the period ended December 31, 2021, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Accounting for the Effects of Cost-Based Regulation
As described in Notes 1 and 5 to the consolidated financial statements, the Company’s consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. As of December 31, 2021, there were $293.0 million of deferred costs included in regulatory assets, $3.8 million of which were pending final regulatory approval, and $1.0 billion of regulatory liabilities awaiting potential refund or future rate reduction, $0.2 million of which were pending final regulatory determination. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation.
The principal considerations for our determination that performing procedures relating to the accounting for the effects of cost-based regulation is a critical audit matter are the significant judgment by management in the ongoing evaluation of the recovery of regulatory assets and refund of regulatory liabilities, and in applying guidance contained in rate orders and other relevant evidence; this in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence related to the probability of recovery of regulatory assets and refund of regulatory liabilities.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s evaluation of new events, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management’s assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, application of relevant regulatory precedents, and other relevant evidence.
Valuation of Level 3 Risk Management Commodity Contracts
As described in Notes 1, 10 and 11 to the consolidated financial statements, the Company employs risk management commodity contracts including physical and financial forward purchase and sale contracts and, to a lesser extent, over-the-counter swaps and options to accomplish its risk management strategies. Certain over-the-counter and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. As disclosed by management, the fair value of these risk management commodity contracts 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 including forward market price assumptions. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. Management utilized such unobservable pricing inputs to value its Level 3 risk management commodity contract liabilities, which totaled $92.5 million, as of December 31, 2021.
The principal considerations for our determination that performing procedures relating to the valuation of Level 3 risk management commodity contracts is a critical audit matter are the significant judgment by management when developing the fair value of the commodity contracts; this in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence relating to the forward market price assumptions used in management’s valuation models. In addition, the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s valuation of the risk management commodity contracts, including controls over the assumptions used to value the Level 3 risk management commodity contracts. These procedures also included, among others, testing management’s process for developing the fair value of the Level 3 risk management commodity contracts, evaluating the appropriateness of the valuation models, evaluating the reasonableness of the forward market price assumptions, and testing the data used by management in the valuation models. Professionals with specialized skill and knowledge were used to assist in evaluating the reasonableness of the forward market price assumptions.
/s/ PricewaterhouseCoopers LLP
Columbus, Ohio
February 24, 2022
We have served as the Company's auditor since 2017.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Ohio Power Company and Subsidiaries (OPCo) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. OPCo’s internal control is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of OPCo’s internal control over financial reporting as of December 31, 2021. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). Based on management’s assessment, management concluded OPCo’s internal control over financial reporting was effective as of December 31, 2021.
This annual report does not include an audit report from PricewaterhouseCoopers LLP, OPCo’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit OPCo to provide only management’s report in this annual report.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Years Ended December 31,
2021 2020 2019
REVENUES
Electricity, Transmission and Distribution $ 2,863.7 $ 2,698.6 $ 2,759.5
Sales to AEP Affiliates 24.8 41.5 27.3
Other Revenues 10.6 9.0 10.8
TOTAL REVENUES 2,899.1 2,749.1 2,797.6
EXPENSES
Purchased Electricity for Resale 678.0 549.2 607.3
Purchased Electricity from AEP Affiliates 51.9 119.7 156.0
Amortization of Generation Deferrals - - 65.3
Other Operation 836.8 822.6 742.6
Maintenance 158.2 127.1 150.1
Depreciation and Amortization 303.3 276.6 240.9
Taxes Other Than Income Taxes 485.7 450.2 434.2
TOTAL EXPENSES 2,513.9 2,345.4 2,396.4
OPERATING INCOME 385.2 403.7 401.2
Other Income (Expense):
Interest Income 0.6 1.0 3.2
Carrying Costs Income 1.2 1.6 1.0
Allowance for Equity Funds Used During Construction 10.8 12.5 18.2
Non-Service Cost Components of Net Periodic Benefit Cost 14.6 15.0 14.6
Interest Expense (124.4) (117.2) (106.2)
INCOME BEFORE INCOME TAX EXPENSE 288.0 316.6 332.0
Income Tax Expense 34.4 45.2 34.9
NET INCOME $ 253.6 $ 271.4 $ 297.1
The common stock of OPCo is wholly-owned by Parent.
See Notes to Financial Statements of Registrants beginning on page 226.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Years Ended December 31,
2021 2020 2019
Net Income $ 253.6 $ 271.4 $ 297.1
OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0, $0 and $(0.3) in 2021, 2020 and 2019, Respectively
- - (1.0)
TOTAL COMPREHENSIVE INCOME $ 253.6 $ 271.4 $ 296.1
See Notes to Financial Statements of Registrants beginning on page 226.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Common
Stock Paid-in
Capital Retained Earnings Accumulated
Other
Comprehensive
Income (Loss) Total
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2018
$ 321.2 $ 838.8 $ 1,136.4 $ 1.0 $ 2,297.4
Common Stock Dividends (85.0) (85.0)
Net Income 297.1 297.1
Other Comprehensive Loss (1.0) (1.0)
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2019
321.2 838.8 1,348.5 - 2,508.5
Common Stock Dividends (87.5) (87.5)
ASU 2016-13 Adoption 0.3 0.3
Net Income 271.4 271.4
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2020
321.2 838.8 1,532.7 - 2,692.7
Common Stock Dividends (100.0) (100.0)
Net Income 253.6 253.6
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2021
$ 321.2 $ 838.8 $ 1,686.3 $ - $ 2,846.3
See Notes to Financial Statements of Registrants beginning on page 226.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2021 and 2020
(in millions)
December 31,
2021 2020
CURRENT ASSETS
Cash and Cash Equivalents $ 3.0 $ 7.4
Advances to Affiliates 42.0 -
Accounts Receivable:
Customers 71.6 50.0
Affiliated Companies 71.8 65.1
Accrued Unbilled Revenues 1.3 14.8
Miscellaneous 5.9 3.9
Allowance for Uncollectible Accounts (0.6) (0.6)
Total Accounts Receivable 150.0 133.2
Materials and Supplies 74.1 66.9
Renewable Energy Credits 30.5 29.5
Prepayments and Other Current Assets 27.9 19.3
TOTAL CURRENT ASSETS 327.5 256.3
PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission 2,992.8 2,831.9
Distribution 6,070.6 5,708.3
Other Property, Plant and Equipment 992.9 899.6
Construction Work in Progress 365.0 362.3
Total Property, Plant and Equipment 10,421.3 9,802.1
Accumulated Depreciation and Amortization 2,458.3 2,350.0
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET 7,963.0 7,452.1
OTHER NONCURRENT ASSETS
Regulatory Assets 293.0 385.8
Operating Lease Assets 81.2 92.0
Deferred Charges and Other Noncurrent Assets 601.1 524.2
TOTAL OTHER NONCURRENT ASSETS 975.3 1,002.0
TOTAL ASSETS $ 9,265.8 $ 8,710.4
See Notes to Financial Statements of Registrants beginning on page 226.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
December 31, 2021 and 2020
(dollars in millions)
December 31,
2021 2020
CURRENT LIABILITIES
Advances from Affiliates $ - $ 259.2
Accounts Payable:
General 213.5 181.0
Affiliated Companies 125.4 118.4
Long-term Debt Due Within One Year - Nonaffiliated 0.1 500.1
Risk Management Liabilities 6.7 8.7
Customer Deposits 66.4 55.1
Accrued Taxes 702.4 631.0
Obligations Under Operating Leases 13.1 13.1
Other Current Liabilities 118.1 139.6
TOTAL CURRENT LIABILITIES 1,245.7 1,906.2
NONCURRENT LIABILITIES
Long-term Debt - Nonaffiliated 2,968.4 1,930.1
Long-term Risk Management Liabilities 85.8 101.6
Deferred Income Taxes 1,000.9 955.1
Regulatory Liabilities and Deferred Investment Tax Credits 1,020.9 1,005.2
Obligations Under Operating Leases 68.6 79.5
Deferred Credits and Other Noncurrent Liabilities 29.2 40.0
TOTAL NONCURRENT LIABILITIES 5,173.8 4,111.5
TOTAL LIABILITIES 6,419.5 6,017.7
Rate Matters (Note 4)
Commitments and Contingencies (Note 6)
COMMON SHAREHOLDER'S EQUITY
Common Stock - No Par Value:
Authorized - 40,000,000 Shares
Outstanding - 27,952,473 Shares
321.2 321.2
Paid-in Capital 838.8 838.8
Retained Earnings 1,686.3 1,532.7
TOTAL COMMON SHAREHOLDER’S EQUITY 2,846.3 2,692.7
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY $ 9,265.8 $ 8,710.4
See Notes to Financial Statements of Registrants beginning on page 226.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Years Ended December 31,
2021 2020 2019
OPERATING ACTIVITIES
Net Income $ 253.6 $ 271.4 $ 297.1
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 303.3 276.6 240.9
Amortization of Generation Deferrals - - 65.3
Deferred Income Taxes 30.7 77.2 43.8
Allowance for Equity Funds Used During Construction (10.8) (12.5) (18.2)
Mark-to-Market of Risk Management Contracts (17.8) 6.7 4.0
Property Taxes (35.3) (16.6) (33.7)
Refund of Global Settlement - - (16.5)
Reversal of Regulatory Provision - - (56.2)
Change in Regulatory Assets 38.3 (69.4) (20.1)
Change in Other Noncurrent Assets (40.7) (49.4) (35.3)
Change in Other Noncurrent Liabilities 6.9 (66.4) (93.2)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net (11.8) 4.2 75.0
Materials and Supplies (2.5) (23.9) (16.4)
Accounts Payable 19.1 10.3 0.4
Accrued Taxes, Net 78.2 43.3 38.7
Other Current Assets (15.7) 1.9 0.8
Other Current Liabilities (19.9) (42.5) (55.2)
Net Cash Flows from Operating Activities 575.6 410.9 421.2
INVESTING ACTIVITIES
Construction Expenditures (732.8) (813.2) (799.2)
Change in Advances to Affiliates, Net (42.0) - -
Other Investing Activities 21.5 22.2 55.1
Net Cash Flows Used for Investing Activities (753.3) (791.0) (744.1)
FINANCING ACTIVITIES
Issuance of Long-term Debt - Nonaffiliated 1,037.1 347.0 444.3
Change in Advances from Affiliates, Net (259.2) 128.2 16.9
Retirement of Long-term Debt - Nonaffiliated (500.1) (0.1) (80.3)
Principal Payments for Finance Lease Obligations (4.9) (4.7) (3.5)
Dividends Paid on Common Stock (100.0) (87.5) (85.0)
Other Financing Activities 0.4 0.9 1.7
Net Cash Flows from Financing Activities 173.3 383.8 294.1
Net Increase (Decrease) in Cash and Cash Equivalents (4.4) 3.7 (28.8)
Cash and Cash Equivalents at Beginning of Period 7.4 3.7 32.5
Cash and Cash Equivalents at End of Period $ 3.0 $ 7.4 $ 3.7
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts $ 119.5 $ 111.2 $ 100.6
Net Cash Paid (Received) for Income Taxes (7.9) (26.9) 7.3
Noncash Acquisitions Under Finance Leases 2.5 6.1 11.3
Construction Expenditures Included in Current Liabilities as of December 31, 97.1 76.7 125.9
See Notes to Financial Statements of Registrants beginning on page 226.
PUBLIC SERVICE COMPANY OF OKLAHOMA
PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
KWh Sales/Degree Days
Summary of KWh Energy Sales
Years Ended December 31,
2021 2020 2019
(in millions of KWhs)
Retail:
Residential 6,243 6,117 6,273
Commercial 4,911 4,673 4,958
Industrial 5,830 5,713 6,156
Miscellaneous 1,222 1,199 1,246
Total Retail 18,206 17,702 18,633
Wholesale 669 345 714
Total KWhs 18,875 18,047 19,347
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.
Summary of Heating and Cooling Degree Days
Years Ended December 31,
2021 2020 2019
(in degree days)
Actual - Heating (a)
1,499 1,454 1,846
Normal - Heating (b)
1,742 1,744 1,751
Actual - Cooling (c)
2,198 2,069 2,265
Normal - Cooling (b)
2,165 2,174 2,160
(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.
2021 Compared to 2020
Public Service Company of Oklahoma
Reconciliation of Year Ended December 31, 2020 to Year Ended December 31, 2021
Net Income
(in millions)
Year Ended December 31, 2020 $ 123.0
Changes in Gross Margin:
Retail Margins (a) 74.1
Margins from Off-system Sales (1.0)
Transmission Revenues 6.2
Other Revenues (11.8)
Total Change in Gross Margin 67.5
Changes in Expenses and Other:
Other Operation and Maintenance (25.3)
Depreciation and Amortization (23.1)
Taxes Other Than Income Taxes (2.1)
Interest Income 4.2
Allowance for Funds Used During Construction (1.6)
Interest Expense (2.6)
Total Change in Expenses and Other (50.5)
Income Tax Expense 1.1
Year Ended December 31, 2021 $ 141.1
(a)Includes firm wholesale sales to municipals and cooperatives.
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 $74 million primarily due to the following:
•A $51 million increase in revenue from rate riders. This increase was partially offset in other expense items below.
•A $10 million increase in weather-normalized margins primarily in the commercial and residential classes.
•A $10 million increase due to reduced customer refunds related to Tax Reform. This increase was partially offset in Income Tax Expense below.
•A $7 million increase due to new base rates implemented in November 2021.
•A $4 million increase in weather-related usage due to a 6% increase in cooling degree days and 3% increase in heating degree days.
These increases were partially offset by:
•A $7 million increase in fuel expense due to NCWF PTC benefits provided to customers. This increase in fuel expense was partially offset in Income Tax Expense below.
•Transmission Revenues increased $6 million primarily due to the following:
•A $3 million increase in the annual transmission formula rate true-up.
•A $3 million increase due to increased load and transmission investment.
•Other Revenues decreased $12 million primarily due to lower business development revenue. This decrease was partially offset in Other Operation and Maintenance expenses below.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $25 million primarily due to the following:
•A $28 million increase in transmission expense primarily due to a $22 million increase in recoverable SPP transmission expense and a $5 million increase in formula rate true-up activity. This increase was partially offset in Retail Margins above.
•An $11 million increase in administrative and general expenses primarily due to a prior year insurance settlement, an increase in rate case expenses and an increase in employee-related expenses.
•A $3 million increase due to the prior year capitalization of previously expensed NCWF costs.
These increases were partially offset by:
•A $9 million decrease in business development expenses. This decrease was partially offset in Other Revenues above.
•A $9 million decrease in steam generation expenses at various plants.
•Depreciation and Amortization expenses increased $23 million primarily due to a higher depreciable base and the timing of refunds to customers under rate rider mechanisms.
•Interest Income increased $4 million primarily related to carrying charges on regulatory assets resulting from the February 2021 severe winter weather event.
•Income Tax Expense decreased $1 million primarily due to an increase in PTC, partially offset by an increase in pretax book income and 2020 tax return to provision adjustments.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Public Service Company of Oklahoma
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Public Service Company of Oklahoma (the “Company”) as of December 31, 2021 and 2020, and the related statements of income, of comprehensive income (loss), of changes in common shareholder's equity and of cash flows for each of the three years in the period ended December 31, 2021, including the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Cost-Based Regulation
As described in Notes 1 and 5 to the financial statements, the Company’s financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. As of December 31, 2021, there were $1.2 billion of deferred costs included in regulatory assets, $14.2 million of which were pending final regulatory approval, and $835.3 million of regulatory liabilities awaiting potential refund or future rate reduction, $56.2 million of which are pending final regulatory determination. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation.
The principal considerations for our determination that performing procedures relating to the accounting for the effects of cost-based regulation is a critical audit matter are the significant judgment by management in the ongoing evaluation of the recovery of regulatory assets and refund of regulatory liabilities, and in applying guidance contained in rate orders and other relevant evidence; this in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence related to the probability of recovery of regulatory assets and refund of regulatory liabilities.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. These procedures included testing the effectiveness of controls relating to management’s evaluation of new events, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management’s assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, application of relevant regulatory precedents, and other relevant evidence.
/s/ PricewaterhouseCoopers LLP
Columbus, Ohio
February 24, 2022
We have served as the Company's auditor since 2017.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Public Service Company of Oklahoma (PSO) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. PSO’s internal control is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of PSO’s internal control over financial reporting as of December 31, 2021. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). Based on management’s assessment, management concluded PSO’s internal control over financial reporting was effective as of December 31, 2021.
This annual report does not include an audit report from PricewaterhouseCoopers LLP, PSO’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit PSO to provide only management’s report in this annual report.
PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF INCOME
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Years Ended December 31,
2021 2020 2019
REVENUES
Electric Generation, Transmission and Distribution $ 1,465.3 $ 1,246.1 $ 1,469.6
Sales to AEP Affiliates 4.2 5.2 6.1
Other Revenues 4.9 14.8 6.1
TOTAL REVENUES 1,474.4 1,266.1 1,481.8
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 584.3 443.5 654.0
Other Operation 353.8 327.3 315.0
Maintenance 97.2 98.4 100.7
Depreciation and Amortization 196.6 173.5 169.5
Taxes Other Than Income Taxes 49.6 47.5 43.3
TOTAL EXPENSES 1,281.5 1,090.2 1,282.5
OPERATING INCOME 192.9 175.9 199.3
Other Income (Expense):
Interest Income 4.3 0.1 1.2
Allowance for Equity Funds Used During Construction 2.4 4.0 2.7
Non-Service Cost Components of Net Periodic Benefit Cost 8.5 8.5 8.4
Interest Expense (62.9) (60.3) (66.5)
INCOME BEFORE INCOME TAX EXPENSE 145.2 128.2 145.1
Income Tax Expense 4.1 5.2 7.5
NET INCOME $ 141.1 $ 123.0 $ 137.6
The common stock of PSO is wholly-owned by Parent.
See Notes to Financial Statements of Registrants beginning on page 226.
PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Years Ended December 31,
2021 2020 2019
Net Income $ 141.1 $ 123.0 $ 137.6
OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0, $(0.3) and $(0.3) in 2021, 2020 and 2019, Respectively
(0.1) (1.0) (1.0)
TOTAL COMPREHENSIVE INCOME $ 141.0 $ 122.0 $ 136.6
See Notes to Financial Statements of Registrants beginning on page 226.
PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Common
Stock Paid-in
Capital Retained Earnings Accumulated
Other
Comprehensive
Income (Loss) Total
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2018 $ 157.2 $ 364.0 $ 724.7 $ 2.1 $ 1,248.0
Common Stock Dividends (11.3) (11.3)
Net Income 137.6 137.6
Other Comprehensive Loss (1.0) (1.0)
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2019 157.2 364.0 851.0 1.1 1,373.3
Capital Contribution of Radial Assets from Parent 50.0 50.0
ASU 2016-13 Adoption 0.3 0.3
Net Income 123.0 123.0
Other Comprehensive Loss (1.0) (1.0)
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2020 157.2 414.0 974.3 0.1 1,545.6
Capital Contribution from Parent 625.0 625.0
Common Stock Dividends (20.0) (20.0)
Net Income 141.1 141.1
Other Comprehensive Loss (0.1) (0.1)
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2021 $ 157.2 $ 1,039.0 $ 1,095.4 $ - $ 2,291.6
See Notes to Financial Statements of Registrants beginning on page 226.
PUBLIC SERVICE COMPANY OF OKLAHOMA
BALANCE SHEETS
ASSETS
December 31, 2021 and 2020
(in millions)
December 31,
2021 2020
CURRENT ASSETS
Cash and Cash Equivalents $ 1.3 $ 2.6
Accounts Receivable:
Customers 41.5 30.8
Affiliated Companies 35.0 15.6
Miscellaneous 0.6 2.0
Total Accounts Receivable 77.1 48.4
Fuel 14.5 17.9
Materials and Supplies 56.2 54.0
Risk Management Assets 12.1 10.3
Accrued Tax Benefits 17.6 10.9
Regulatory Asset for Under-Recovered Fuel Costs 194.6 30.1
Prepayments and Other Current Assets 13.4 7.1
TOTAL CURRENT ASSETS 386.8 181.3
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation 1,802.4 1,480.7
Transmission 1,107.7 1,069.9
Distribution 3,004.9 2,853.0
Other Property, Plant and Equipment 437.0 393.3
Construction Work in Progress 156.0 128.7
Total Property, Plant and Equipment 6,508.0 5,925.6
Accumulated Depreciation and Amortization 1,705.2 1,605.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET
4,802.8 4,320.0
OTHER NONCURRENT ASSETS
Regulatory Assets 1,037.4 375.0
Employee Benefits and Pension Assets 95.2 65.8
Operating Lease Assets 68.9 42.6
Deferred Charges and Other Noncurrent Assets 7.9 6.0
TOTAL OTHER NONCURRENT ASSETS 1,209.4 489.4
TOTAL ASSETS $ 6,399.0 $ 4,990.7
See Notes to Financial Statements of Registrants beginning on page 226.
PUBLIC SERVICE COMPANY OF OKLAHOMA
BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
December 31, 2021 and 2020
December 31,
2021 2020
(in millions)
CURRENT LIABILITIES
Advances from Affiliates $ 72.3 $ 155.4
Accounts Payable:
General 157.4 107.0
Affiliated Companies 51.0 43.4
Long-term Debt Due Within One Year - Nonaffiliated 125.5 0.5
Risk Management Liabilities 3.7 -
Customer Deposits 56.2 54.8
Accrued Taxes 27.0 26.8
Obligations Under Operating Leases 6.9 6.5
Other Current Liabilities 62.7 84.2
TOTAL CURRENT LIABILITIES 562.7 478.6
NONCURRENT LIABILITIES
Long-term Debt - Nonaffiliated 1,788.0 1,373.3
Deferred Income Taxes 782.3 688.5
Regulatory Liabilities and Deferred Investment Tax Credits 835.3 802.2
Asset Retirement Obligations 57.5 45.7
Obligations Under Operating Leases 62.2 36.2
Deferred Credits and Other Noncurrent Liabilities 19.4 20.6
TOTAL NONCURRENT LIABILITIES 3,544.7 2,966.5
TOTAL LIABILITIES 4,107.4 3,445.1
Rate Matters (Note 4)
Commitments and Contingencies (Note 6)
COMMON SHAREHOLDER’S EQUITY
Common Stock - Par Value - $15 Per Share:
Authorized - 11,000,000 Shares
Issued - 10,482,000 Shares
Outstanding - 9,013,000 Shares
157.2 157.2
Paid-in Capital 1,039.0 414.0
Retained Earnings 1,095.4 974.3
Accumulated Other Comprehensive Income (Loss) - 0.1
TOTAL COMMON SHAREHOLDER’S EQUITY 2,291.6 1,545.6
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $ 6,399.0 $ 4,990.7
See Notes to Financial Statements of Registrants beginning on page 226.
PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Years Ended December 31,
2021 2020 2019
OPERATING ACTIVITIES
Net Income $ 141.1 $ 123.0 $ 137.6
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization 196.6 173.5 169.5
Deferred Income Taxes 113.9 17.0 (18.2)
Allowance for Equity Funds Used During Construction (2.4) (4.0) (2.7)
Mark-to-Market of Risk Management Contracts 1.9 5.5 (6.4)
Deferred Fuel Over/Under-Recovery, Net (843.8) (94.0) 43.8
Change in Other Noncurrent Assets (18.3) (17.9) 5.7
Change in Other Noncurrent Liabilities 4.4 1.6 (7.3)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net (28.7) 1.4 15.4
Fuel, Materials and Supplies 1.4 (14.1) (1.9)
Accounts Payable 34.2 (29.5) 7.0
Accrued Taxes, Net (6.5) 3.6 3.9
Other Current Assets (6.3) 4.6 (0.7)
Other Current Liabilities (20.8) (13.7) 4.6
Net Cash Flows from (Used for) Operating Activities (433.3) 157.0 350.3
INVESTING ACTIVITIES
Construction Expenditures (332.1) (337.9) (291.9)
Change in Advances to Affiliates, Net - 38.8 (38.8)
Acquisition of the North Central Wind Energy Facilities (297.0) - -
Other Investing Activities 2.4 4.0 2.6
Net Cash Flows Used for Investing Activities (626.7) (295.1) (328.1)
FINANCING ACTIVITIES
Capital Contribution from Parent 625.0 - -
Issuance of Long-term Debt - Nonaffiliated 1,290.0 - 349.5
Change in Advances from Affiliates, Net (83.1) 155.4 (105.5)
Retirement of Long-term Debt - Nonaffiliated (750.5) (13.2) (250.5)
Principal Payments for Finance Lease Obligations (3.2) (3.5) (3.1)
Dividends Paid on Common Stock (20.0) - (11.3)
Other Financing Activities 0.5 0.5 (1.8)
Net Cash Flows from (Used for) Financing Activities 1,058.7 139.2 (22.7)
Net Increase (Decrease) in Cash and Cash Equivalents (1.3) 1.1 (0.5)
Cash and Cash Equivalents at Beginning of Period 2.6 1.5 2.0
Cash and Cash Equivalents at End of Period $ 1.3 $ 2.6 $ 1.5
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts $ 57.0 $ 59.1 $ 61.1
Net Cash Paid (Received) for Income Taxes (102.9) (11.8) 22.4
Noncash Acquisitions Under Finance Leases 3.6 3.2 5.3
Construction Expenditures Included in Current Liabilities as of December 31, 56.8 35.5 46.0
Noncash Contribution of Radial Assets from Parent - 50.0 -
See Notes to Financial Statements of Registrants beginning on page 226.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
KWh Sales/Degree Days
Summary of KWh Energy Sales
Years Ended December 31,
2021 2020 2019
(in millions of KWhs)
Retail:
Residential 6,205 5,988 6,303
Commercial 5,489 5,296 5,776
Industrial 4,682 4,891 5,337
Miscellaneous 77 79 80
Total Retail 16,453 16,254 17,496
Wholesale 6,704 5,838 6,791
Total KWhs 23,157 22,092 24,287
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.
Summary of Heating and Cooling Degree Days
Years Ended December 31,
2021 2020 2019
(in degree days)
Actual - Heating (a)
981 862 1,174
Normal - Heating (b)
1,177 1,181 1,191
Actual - Cooling (c)
2,543 2,165 2,392
Normal - Cooling (b)
2,328 2,333 2,321
(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.
2021 Compared to 2020
Reconciliation of Year Ended December 31, 2020 to Year Ended December 31, 2021
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
Year Ended December 31, 2020 $ 180.8
Changes in Gross Margin:
Retail Margins (a) 95.9
Margins from Off-system Sales 20.8
Transmission Revenues 8.2
Other Revenues 1.9
Total Change in Gross Margin 126.8
Changes in Expenses and Other:
Other Operation and Maintenance (29.0)
Asset Impairments and Other Related Charges (11.6)
Depreciation and Amortization (22.3)
Taxes Other Than Income Taxes (14.9)
Interest Income 7.1
Allowance for Equity Funds Used During Construction (0.7)
Non-Service Cost Components of Net Periodic Benefit Cost (0.1)
Interest Expense (7.4)
Total Change in Expenses and Other (78.9)
Income Tax Expense 10.0
Equity Earnings of Unconsolidated Subsidiary 0.5
Net Income Attributable to Noncontrolling Interest (0.2)
Year Ended December 31, 2021 $ 239.0
(a)Includes firm wholesale sales to municipals and cooperatives.
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 $96 million primarily due to the following:
•A $47 million increase 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 $31 million increase in weather-related usage primarily due to an 18% increase in cooling degree days and a 14% increase in heating degree days.
•A $16 million increase in recoverable fuel costs primarily due to timing of recovery.
•An $11 million increase in weather-normalized municipal and cooperative revenues primarily due to the February 2021 severe winter weather event.
•A $10 million increase due to the prior year fuel cost disallowance in the 2020 Texas Fuel Reconciliation.
•A $9 million increase in municipal and cooperative revenues due to the annual generation formula rate true-up.
These increases were partially offset by:
•A $28 million decrease in weather-normalized margins primarily in the residential and industrial classes.
•Margins from Off-system Sales increased $21 million primarily due to increased Turk Plant merchant sales as a result of the February 2021 severe winter weather event.
•Transmission Revenues increased $8 million primarily due to the following:
•A $15 million increase due to an increase in load and transmission investment.
This increase was partially offset by:
•A $6 million decrease in the annual transmission formula rate true-up.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $29 million primarily due to the following:
•A $24 million increase in transmission expenses primarily due to a $15 million increase in transmission services expense resulting from increased load and a $10 million increase in transmission formula rate true-up activity.
•A $13 million increase in administrative and general expenses primarily due to a prior year insurance settlement.
These increases were partially offset by:
•A $6 million decrease in expenses at various generation plants.
•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.
•Depreciation and Amortization expenses increased $22 million primarily due to a higher depreciable base and an increase in Texas depreciation rates recorded in December 2021 as a result of an order received in the 2020 Texas Base Rate Case. This increase was partially offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $15 million primarily due to increased property taxes resulting from the expiration of the Louisiana Industrial Tax Exemption related to Stall Plant.
•Interest Income increased $7 million primarily related to carrying charges on regulatory assets resulting from the February 2021 severe winter weather event.
•Interest Expense increased $7 million primarily due to higher long-term debt balances resulting from the February 2021 severe winter weather event.
•Income Tax Expense decreased $10 million primarily due to the following:
•A $12 million decrease in state tax expense primarily due to tax deductions related to increased purchase power costs that are flowed-through.
•A $9 million increase in amortization of Excess ADIT, partially offset in Retail Margins above.
•A $7 million increase in PTC.
These decreases were partially offset by:
•A $10 million increase due to an increase in pretax book income.
•A $6 million decrease in parent company loss benefit.
•A $3 million increase in state deferred taxes due to legislative changes in Arkansas and Louisiana.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Southwestern Electric Power Company
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Southwestern Electric Power Company and its subsidiaries (the “Company”) as of December 31, 2021 and 2020, and the related consolidated statements of income, of comprehensive income (loss), of changes in equity and of cash flows for each of the three years in the period ended December 31, 2021, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Cost-Based Regulation
As described in Notes 1 and 5 to the consolidated financial statements, the Company’s consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. As of December 31, 2021, there were $1.1 billion of deferred costs included in regulatory assets, $817.9 million of which were pending final regulatory approval, and $806.9 million of regulatory liabilities awaiting potential refund or future rate reduction. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation.
The principal considerations for our determination that performing procedures relating to the accounting for the effects of cost-based regulation is a critical audit matter are the significant judgment by management in the ongoing evaluation of the recovery of regulatory assets and refund of regulatory liabilities, and in applying guidance contained in rate orders and other relevant evidence; this in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence related to the probability of recovery of regulatory assets and refund of regulatory liabilities.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s evaluation of new events, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management’s assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, application of relevant regulatory precedents, and other relevant evidence.
/s/ PricewaterhouseCoopers LLP
Columbus, Ohio
February 24, 2022
We have served as the Company's auditor since 2017.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Southwestern Electric Power Company Consolidated (SWEPCo) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. SWEPCo’s internal control is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of SWEPCo’s internal control over financial reporting as of December 31, 2021. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). Based on management’s assessment, management concluded SWEPCo’s internal control over financial reporting was effective as of December 31, 2021.
This annual report does not include an audit report from PricewaterhouseCoopers LLP, SWEPCo’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit SWEPCo to provide only management’s report in this annual report.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Years Ended December 31,
2021 2020 2019
REVENUES
Electric Generation, Transmission and Distribution $ 2,088.9 $ 1,696.6 $ 1,744.6
Sales to AEP Affiliates 41.4 41.0 36.9
Provision for Refund - Affiliated (0.4) (2.0) (32.0)
Other Revenues 1.9 2.9 1.4
TOTAL REVENUES 2,131.8 1,738.5 1,750.9
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 871.0 604.5 652.3
Other Operation 360.3 338.3 348.0
Maintenance 136.7 129.7 145.6
Asset Impairments and Other Related Charges 11.6 - -
Depreciation and Amortization 295.0 272.7 249.1
Taxes Other Than Income Taxes 117.7 102.8 100.2
TOTAL EXPENSES 1,792.3 1,448.0 1,495.2
OPERATING INCOME 339.5 290.5 255.7
Other Income (Expense):
Interest Income 9.2 2.1 2.6
Allowance for Equity Funds Used During Construction 7.0 7.7 6.8
Non-Service Cost Components of Net Periodic Benefit Cost 8.3 8.4 8.5
Interest Expense (125.9) (118.5) (119.1)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS 238.1 190.2 154.5
Income Tax Expense (Benefit) (0.6) 9.4 (4.7)
Equity Earnings of Unconsolidated Subsidiary 3.4 2.9 3.0
NET INCOME 242.1 183.7 162.2
Net Income Attributable to Noncontrolling Interest 3.1 2.9 3.6
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER $ 239.0 $ 180.8 $ 158.6
The common stock of SWEPCo is wholly-owned by Parent.
See Notes to Financial Statements of Registrants beginning on page 226.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Years Ended December 31,
2021 2020 2019
Net Income $ 242.1 $ 183.7 $ 162.2
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.4, $0.4 and $0.4 in 2021, 2020 and 2019, Respectively
1.5 1.5 1.5
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.4), $(0.4) and $(0.3) in 2021, 2020 and 2019, Respectively
(1.6) (1.5) (1.1)
Pension and OPEB Funded Status, Net of Tax of $1.3, $0.9 and $1 in 2021, 2020 and 2019, Respectively
4.9 3.2 3.7
TOTAL OTHER COMPREHENSIVE INCOME 4.8 3.2 4.1
TOTAL COMPREHENSIVE INCOME 246.9 186.9 166.3
Total Comprehensive Income Attributable to Noncontrolling Interest 3.1 2.9 3.6
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER
$ 243.8 $ 184.0 $ 162.7
See Notes to Financial Statements of Registrants beginning on page 226.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
SWEPCo Common Shareholder
Common
Stock Paid-in
Capital Retained
Earnings Accumulated
Other
Comprehensive
Income (Loss) Noncontrolling
Interest Total
TOTAL EQUITY - DECEMBER 31, 2018 $ 135.7 $ 676.6 $ 1,508.4 $ (5.4) $ 0.3 $ 2,315.6
Common Stock Dividends (37.5) (37.5)
Common Stock Dividends - Nonaffiliated (3.3) (3.3)
Net Income 158.6 3.6 162.2
Other Comprehensive Income 4.1 4.1
TOTAL EQUITY - DECEMBER 31, 2019 135.7 676.6 1,629.5 (1.3) 0.6 2,441.1
Reverse Common Stock Split (a) (135.6) 135.6 -
Common Stock Dividends - Nonaffiliated (1.9) (1.9)
ASU 2016-03 Adoption 1.6 1.6
Net Income 180.8 2.9 183.7
Other Comprehensive Income 3.2 3.2
TOTAL EQUITY - DECEMBER 31, 2020 0.1 812.2 1,811.9 1.9 1.6 2,627.7
Capital Contribution from Parent 280.0 280.0
Common Stock Dividends - Nonaffiliated (4.8) (4.8)
Net Income 239.0 3.1 242.1
Other Comprehensive Income 4.8 4.8
TOTAL EQUITY - DECEMBER 31, 2021 $ 0.1 $ 1,092.2 $ 2,050.9 $ 6.7 $ (0.1) $ 3,149.8
(a) In August 2020, SWEPCo executed a reverse stock split with each 2,048 shares of common stock issued and outstanding being combined into one share of common stock. The common stock of SWEPCo is wholly-owned by Parent.
See Notes to Financial Statements of Registrants beginning on page 226.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2021 and 2020
(in millions)
December 31,
2021 2020
CURRENT ASSETS
Cash and Cash Equivalents
(December 31, 2021 and 2020 Amounts Include $49.9 and $10.1, Respectively, Related to Sabine)
$ 51.2 $ 13.2
Advances to Affiliates 155.9 2.1
Accounts Receivable:
Customers 35.8 27.1
Affiliated Companies 38.3 25.1
Miscellaneous 12.3 12.7
Total Accounts Receivable 86.4 64.9
Fuel
(December 31, 2021 and 2020 Amounts Include $13.1 and $35.2, Respectively, Related to Sabine)
82.2 191.1
Materials and Supplies
(December 31, 2021 and 2020 Amounts Include $12 and $23.3, Respectively, Related to Sabine)
81.9 95.8
Risk Management Assets 9.8 3.2
Accrued Tax Benefits 17.8 29.9
Regulatory Asset for Under-Recovered Fuel Costs 143.9 2.6
Prepayments and Other Current Assets 39.4 25.2
TOTAL CURRENT ASSETS 668.5 428.0
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation 4,734.5 4,681.4
Transmission 2,316.9 2,165.7
Distribution 2,514.3 2,382.5
Other Property, Plant and Equipment
(December 31, 2021 and 2020 Amounts Include $219.9 and $223.7, Respectively, Related to Sabine)
764.0 788.8
Construction Work in Progress 240.7 228.3
Total Property, Plant and Equipment 10,570.4 10,246.7
Accumulated Depreciation and Amortization
(December 31, 2021 and 2020 Amounts Include $168.1 and $126.5, Respectively, Related to Sabine)
3,170.3 3,158.5
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET 7,400.1 7,088.2
OTHER NONCURRENT ASSETS
Regulatory Assets 1,005.3 403.1
Deferred Charges and Other Noncurrent Assets 251.8 234.8
TOTAL OTHER NONCURRENT ASSETS 1,257.1 637.9
TOTAL ASSETS $ 9,325.7 $ 8,154.1
See Notes to Financial Statements of Registrants beginning on page 226.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
December 31, 2021 and 2020
December 31,
2021 2020
(in millions)
CURRENT LIABILITIES
Advances from Affiliates $ - $ 124.6
Accounts Payable:
General 163.6 135.9
Affiliated Companies 61.4 43.0
Short-term Debt - Nonaffiliated - 35.0
Long-term Debt Due Within One Year - Nonaffiliated 6.2 106.2
Risk Management Liabilities 2.1 0.7
Customer Deposits 62.4 61.3
Accrued Taxes 44.3 41.0
Accrued Interest 36.0 34.6
Obligations Under Operating Leases 8.1 7.9
Other Current Liabilities 154.6 173.4
TOTAL CURRENT LIABILITIES 538.7 763.6
NONCURRENT LIABILITIES
Long-term Debt - Nonaffiliated 3,389.0 2,530.2
Deferred Income Taxes 1,087.6 1,017.6
Regulatory Liabilities and Deferred Investment Tax Credits 806.9 863.4
Asset Retirement Obligations 192.7 193.7
Employee Benefits and Pension Obligations 20.3 18.6
Obligations Under Operating Leases 77.7 44.1
Deferred Credits and Other Noncurrent Liabilities 63.0 95.2
TOTAL NONCURRENT LIABILITIES 5,637.2 4,762.8
TOTAL LIABILITIES 6,175.9 5,526.4
Rate Matters (Notes 4)
Commitments and Contingencies (Note 6)
EQUITY
Common Stock - Par Value - $18 Per Share:
Authorized - 3,680 Shares
Outstanding - 3,680 Shares
0.1 0.1
Paid-in Capital 1,092.2 812.2
Retained Earnings 2,050.9 1,811.9
Accumulated Other Comprehensive Income (Loss) 6.7 1.9
TOTAL COMMON SHAREHOLDER’S EQUITY 3,149.9 2,626.1
Noncontrolling Interest (0.1) 1.6
TOTAL EQUITY 3,149.8 2,627.7
TOTAL LIABILITIES AND EQUITY $ 9,325.7 $ 8,154.1
See Notes to Financial Statements of Registrants beginning on page 226.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Years Ended December 31,
2021 2020 2019
OPERATING ACTIVITIES
Net Income $ 242.1 $ 183.7 $ 162.2
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 295.0 272.7 249.1
Deferred Income Taxes 16.6 32.4 (11.0)
Asset Impairments and Other Related Charges 11.6 - -
Allowance for Equity Funds Used During Construction (7.0) (7.7) (6.8)
Mark-to-Market of Risk Management Contracts (7.3) (0.1) 0.8
Pension Contributions to Qualified Plan Trust - (8.9) -
Deferred Fuel Over/Under-Recovery, Net (546.4) 26.3 16.5
Change in Regulatory Assets (95.6) (108.4) 3.5
Change in Other Noncurrent Assets 41.9 16.1 2.7
Change in Other Noncurrent Liabilities (1.1) 25.2 2.7
Changes in Certain Components of Working Capital:
Accounts Receivable, Net (21.5) 7.3 -
Fuel, Materials and Supplies 126.5 (46.4) (46.1)
Accounts Payable 22.0 11.1 (28.4)
Accrued Taxes, Net 15.4 (23.1) (3.2)
Other Current Assets (3.6) (2.8) (8.9)
Other Current Liabilities 8.2 (21.1) 6.7
Net Cash Flows from Operating Activities 96.8 356.3 339.8
INVESTING ACTIVITIES
Construction Expenditures (414.6) (402.7) (412.7)
Change in Advances to Affiliates, Net (153.8) - 81.3
Acquisition of the North Central Wind Energy Facilities (355.8) - -
Other Investing Activities 3.5 10.1 1.2
Net Cash Flows Used for Investing Activities (920.7) (392.6) (330.2)
FINANCING ACTIVITIES
Capital Contribution from Parent 280.0 - -
Issuance of Long-term Debt - Nonaffiliated 1,137.6 - -
Change in Short-term Debt - Nonaffiliated (35.0) 16.7 18.3
Change in Advances from Affiliates, Net (124.6) 64.7 59.9
Retirement of Long-term Debt - Nonaffiliated (381.2) (21.2) (59.7)
Principal Payments for Finance Lease Obligations (10.9) (10.9) (11.0)
Dividends Paid on Common Stock - - (37.5)
Dividends Paid on Common Stock - Nonaffiliated (4.8) (1.9) (3.3)
Other Financing Activities 0.8 0.5 0.8
Net Cash Flows from (Used for) Financing Activities 861.9 47.9 (32.5)
Net Increase (Decrease) in Cash and Cash Equivalents 38.0 11.6 (22.9)
Cash and Cash Equivalents at Beginning of Period 13.2 1.6 24.5
Cash and Cash Equivalents at End of Period $ 51.2 $ 13.2 $ 1.6
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts $ 116.5 $ 110.7 $ 111.1
Net Cash Paid (Received) for Income Taxes (28.8) 4.3 8.6
Noncash Acquisitions Under Finance Leases 4.8 8.9 7.4
Construction Expenditures Included in Current Liabilities as of December 31, 69.0 46.0 69.1
See Notes to Financial Statements of Registrants beginning on page 226.
INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANTS
The notes to financial statements are a combined presentation for the Registrants. The following list indicates Registrants to which the notes apply. Specific disclosures within each note apply to all Registrants unless indicated otherwise.
Note Registrant Page
Number
Organization and Summary of Significant Accounting Policies
AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
New Accounting Standards AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Comprehensive Income AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo
Rate Matters AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Effects of Regulation AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Commitments, Guarantees and Contingencies AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Acquisitions, Assets and Liabilities Held for Sale, Dispositions and Impairments AEP, AEP Texas, AEPTCo, APCo, PSO, SWEPCo 289
Benefit Plans AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo
Business Segments AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Derivatives and Hedging AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo
Fair Value Measurements AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Income Taxes AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Leases AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Financing Activities AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Stock-based Compensation AEP
Related Party Transactions AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Variable Interest Entities and Equity Method Investments
AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Property, Plant and Equipment AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Revenue from Contracts with Customers AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Goodwill AEP
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The disclosures in this note apply to all Registrants unless indicated otherwise.
ORGANIZATION
The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions.
AEP provides competitive electric and gas supply for residential, commercial and industrial customers in deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier.
The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, AEP operates competitive wind and solar farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through Sabine, conducts lignite mining operations to fuel the Pirkey Plant.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Rates and Service Regulation
AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over certain issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system.
The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued-up to actual costs annually.
The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers continue to pay for certain legacy deferred generation-related costs through PUCO approved riders. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by REPs. AEP has one active REP in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind assets, the power from which is marketed and sold in ERCOT. Power from the Oklaunion Power Station was also marketed and sold by these nonregulated subsidiaries in ERCOT prior to its retirement in 2020.
The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. Retail transmission rates are based on formula rates included in the PJM OATT that are cost-based and are unbundled in Ohio for OPCo, in Virginia for APCo and in Michigan for I&M. AEP Texas’ retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEPTCo’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based.
In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis.
In addition, the FERC regulates the SIA, Operating Agreement, TA and TCA, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. The FERC also regulates the PCA. See Note 16 - Related Party Transactions for additional information.
Principles of Consolidation
AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for AEP Texas include the Registrant Subsidiary, its wholly-owned subsidiaries, Transition Funding (consolidated VIEs) and Restoration Funding (a consolidated VIE). The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a consolidated VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (consolidated VIEs). The consolidated statements of cash flows for OPCo include the Registrant Subsidiary and Ohio Phase-in Recovery Funding (a consolidated VIE) for the year ended December 31, 2019. In July 2019, the Ohio Phase-in Recovery Funding securitization bonds matured. The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a consolidated VIE). Intercompany items are eliminated in consolidation.
The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings or losses is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income.
AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included on the income statements and the assets and liabilities are reflected on the balance sheets. See Note 17 - Variable Interest Entities and Equity Method Investments and Note 18 - Property, Plant and Equipment for additional information. In October 2020, AEP Texas, PSO and a nonaffiliated joint-owner executed an Environmental Liability and Property Transfer and Asset Purchase Agreement with a nonaffiliated third-party related to the Oklaunion Power Station site. See Note 7 - Acquisitions, Dispositions and Impairments for additional information.
Accounting for the Effects of Cost-Based Regulation
The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.
Use of Estimates
The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.
Cash and Cash Equivalents
Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.
Restricted Cash (Applies to AEP, AEP Texas and APCo)
Restricted Cash primarily includes funds held by trustees for the payment of securitization bonds.
Reconciliation of Cash, Cash Equivalents and Restricted Cash
The following tables provide a reconciliation of Cash, Cash Equivalents and Restricted Cash reported within the balance sheets that sum to the total of the same amounts shown on the statement of cash flows:
December 31, 2021
AEP AEP Texas APCo
(in millions)
Cash and Cash Equivalents $ 403.4 $ 0.1 $ 2.5
Restricted Cash 48.0 30.4 17.6
Total Cash, Cash Equivalents and Restricted Cash $ 451.4 $ 30.5 $ 20.1
December 31, 2020
AEP AEP Texas APCo
(in millions)
Cash and Cash Equivalents $ 392.7 $ 0.1 $ 5.8
Restricted Cash 45.6 28.7 16.9
Total Cash, Cash Equivalents and Restricted Cash $ 438.3 $ 28.8 $ 22.7
Other Temporary Investments (Applies to AEP)
Other Temporary Investments primarily include marketable securities and investments by its protected cell of EIS. These securities have readily determinable fair values and are carried at fair value with changes in fair value recognized in net income. The cost of securities sold is based on the specific identification or weighted-average cost method. See “Fair Value Measurements of Other Temporary Investments” section of Note 11 for additional information.
Inventory
Fossil fuel inventories are carried at average cost with the exception of AGR, which carries these inventories at the lower of average cost or net realizable value. Materials and supplies inventories are carried at average cost.
Accounts Receivable
Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities.
Revenue is recognized over time as the performance obligations of delivering energy to customers are satisfied. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing.
AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables they acquire from affiliated utility subsidiaries. See “Securitized Accounts Receivable - AEP Credit” section of Note 14 for additional information.
Allowance for Uncollectible Accounts
Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. The assessment is performed separately by each participating AEP subsidiary, which inherently contemplates any differences in geographical risk characteristics for the allowance. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. KPCo terminated selling accounts receivable to AEP Credit in the first quarter of 2022, based on the pending sale to Liberty. As a result of the termination, in the first quarter of 2022, KPCo will record an allowance for uncollectible accounts on its balance sheet for those receivables no longer sold to AEP Credit. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable, unless specifically identified. In addition to these processes, management contemplates available current information, as well as any reasonable and supportable forecast information, to determine if allowances for uncollectible accounts should be further adjusted in accordance with the accounting guidance for “Credit Losses.” Management’s assessments contemplate expected losses over the life of the accounts receivable.
Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries)
APCo, I&M, OPCo, PSO and SWEPCo do not have any significant customers that comprise 10% or more of their operating revenues. AEP Texas had significant transactions with REPs which on a combined basis account for the following percentages of Total Revenues for the years ended December 31 and Accounts Receivable - Customers as of December 31:
Significant Customers of AEP Texas:
Reliant Energy, Direct Energy and TXU Energy (a) 2021 2020 2019
Percentage of Total Revenues 43 % 46 % 48 %
Percentage of Accounts Receivable - Customers 41 % 40 % 43 %
(a)In January 2021, NRG Energy, parent company of Reliant Energy, completed a deal to purchase Direct Energy from Centrica.
AEPTCo had significant transactions with AEP Subsidiaries which on a combined basis account for the following percentages of Total Revenues for the years ended December 31 and Total Accounts Receivable as of December 31:
Significant Customers of AEPTCo:
AEP Subsidiaries 2021 2020 2019
Percentage of Total Revenues 79 % 78 % 79 %
Percentage of Total Accounts Receivable 81 % 78 % 78 %
The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuous basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements.
Renewable Energy Credits (Applies to all Registrants except AEP Texas and AEPTCo)
In regulated jurisdictions, the Registrants record renewable energy credits (RECs) at cost. For AEP’s competitive generation business, management records RECs at the lower of cost or net realizable value. The Registrants follow the inventory model for these RECs. RECs expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. RECs with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of RECs are reported in the Operating Activities section of the statements of cash flows. RECs that are consumed to meet applicable state renewable portfolio standards are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of RECs affects the determination of deferred fuel and REC costs.
Property, Plant and Equipment
Regulated
Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs accrued are typically recorded as regulatory liabilities when the revenue received for removal costs accrued exceeds actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. A regulatory asset balance will occur if actual removal costs incurred exceed accumulated removal costs accrued.
The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses.
Nuclear fuel, including nuclear fuel in the fabrication phase, is included in Other Property, Plant and Equipment on the balance sheets.
Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in-service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed or is not probable, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. 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, as opposed to 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, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.
Nonregulated
Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense.
Allowance for Funds Used During Construction and Interest Capitalization
For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense on the statements of income. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”
Valuation of Nonderivative Financial Instruments
The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments.
Fair Value Measurements of Assets and Liabilities (Applies to all Registrants except AEPTCo)
The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.
For commercial activities, exchange-traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange-traded derivatives where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative
instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket-based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility.
AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes.
Assets in the benefits and nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Investments classified as Other are valued using Net Asset Value as a practical expedient. Items classified as Other are primarily cash equivalent funds, common collective trusts, commingled funds, structured products, private equity, real estate, infrastructure and alternative credit investments. These investments do not have a readily determinable fair value or they contain redemption restrictions which may include the right to suspend redemptions under certain circumstances. Redemption restrictions may also prevent certain investments from being redeemed at the reporting date for the underlying value.
Deferred Fuel Costs (Applies to all Registrants except AEP Texas and AEPTCo)
The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily using the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a commission-approved plan to delay refunds or recoveries beyond a one year period. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. The Registrants share the majority of their Off-system Sales margins to customers either through an active FAC or other rate mechanisms. Where the FAC or Off-system Sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings.
Revenue Recognition
Regulatory Accounting
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. Regulatory assets (deferred expenses or alternative revenues recognized in accordance with the guidance for “Regulated Operations”) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching revenue with its passage to customers in cost-based regulated rates.
When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are reviewed for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is derecognized as a charge against income.
Retail and Wholesale Supply and Delivery of Electricity
The Registrants recognize revenues from customers for retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize such revenues on the statements of income as the performance obligations of delivering energy to customers are satisfied. Recognized revenues include both billed and unbilled amounts. In accordance with the applicable state commission’s regulatory treatment, PSO and SWEPCo do not include the fuel portion in unbilled revenue, but rather recognize such revenues when billed to customers.
Wholesale transmission revenue is based on FERC-approved formula rate filings made for each calendar year using estimated costs. Revenues initially recognized per the annual rate filing are compared to actual costs, resulting in the subsequent recognition of an over or under-recovered amount, with interest, that is refunded or recovered, respectively, in a future year’s rates. These annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for “Regulated Operations”, and are recognized by the Registrants in the second quarter of each calendar year following the filing of annual FERC reports. Any portion of the true-ups applicable to an affiliated company is recorded as Accounts Receivable - Affiliated Companies or Accounts Payable - Affiliated Companies on the balance sheets. Any portion of the true-ups applicable to third-parties is recorded as Regulatory Assets or Regulatory Liabilities on the balance sheets. See Note 19 - Revenue from Contracts with Customers for additional information.
Gross versus Net Presentation of Certain Electricity Supply and Delivery Activities
Most of the power produced at the generation plants is sold to PJM or SPP. The Registrants also purchase power from PJM and SPP to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income. With the exception of certain dedicated load bilateral power supply contracts, the transactions of AEP’s nonregulated subsidiaries are reported as gross purchases or sales.
Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income. Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s facts and circumstances. Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on the statements of income. All other non-trading derivative purchases are recorded net in revenues.
In general, the Registrants record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated. In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).
Energy Marketing and Risk Management Activities (Applies to all Registrants except AEPTCo)
The Registrants engage in power, capacity and, to a lesser extent, natural gas marketing as major power producers and participants in electricity and natural gas markets. The Registrants also engage in power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity risk management activities focused on markets where the AEP System owns assets and on adjacent markets. These activities include the purchase-and-sale of energy under forward contracts at fixed and variable prices. These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options. Certain energy marketing and risk management transactions are with RTOs.
The Registrants recognize revenues from marketing and risk management transactions that are not derivatives as the performance obligation of delivering the commodity is satisfied. Expenses from marketing and risk management transactions that are not derivatives are also recognized upon delivery of the commodity.
The Registrants use MTM accounting for marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or elected normal under the normal purchase normal sale election. Unrealized MTM gains and losses are included on the balance sheets as Risk Management Assets or Liabilities, as appropriate, and on the statements of income in Total Revenues. Realized gains and losses on marketing and risk management transactions are included in revenues or expenses based on the transaction’s facts and circumstances. However, in regulated jurisdictions subject to cost-based regulation, unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).
Certain qualifying marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge). In the event the Registrants designate a cash flow hedge, the cash flow hedge’s gain or loss is initially recorded as a component of AOCI. When the forecasted transaction is realized and affects net income, the Registrants subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their statements of income. See “Accounting for Cash Flow Hedging Strategies” section of Note 10 for additional information.
Levelization of Nuclear Refueling Outage Costs (Applies to AEP and I&M)
In accordance with regulatory orders, I&M defers incremental operation and maintenance costs associated with periodic refueling outages at its Cook Plant and amortizes the costs over approximately 18 months, beginning with the month following the start of each unit’s refueling outage and lasting until the end of the month in which the same unit’s next scheduled refueling outage begins.
Maintenance
The Registrants expense maintenance costs as incurred. If it becomes probable that the Registrants will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues. In certain regulated jurisdictions, the Registrants defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.
Income Taxes and Investment and Production Tax Credits
The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled.
When the flow-through method of accounting for temporary differences is required by a regulator to be reflected in regulated revenues (that is, when deferred taxes are not included in the cost-of-service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense.
AEP and subsidiaries apply the deferral methodology for the recognition of ITCs. Deferred ITCs are amortized to income tax expense over the life of the asset that generated the credit. Amortization of deferred ITCs begins when the asset is placed in-service, except where regulatory commissions reflect ITCs in the rate-making process, then amortization begins when the cash tax benefit is recognized. Alternatively, PTCs reduce income tax expense as they are earned. PTCs are earned when electricity is produced.
The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense on the statements of income.
Excise Taxes (Applies to all Registrants except AEPTCo)
As agents for some state and local governments, the Registrants collect from customers certain excise taxes levied by those state or local governments on customers. The Registrants do not record these taxes as revenue or expense.
Debt
Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates. Operations not subject to cost-based rate regulation report gains and losses on the reacquisition of debt in Interest Expense on the statements of income upon reacquisition.
Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations. The net amortization expense is included in Interest Expense on the statements of income.
Goodwill (Applies to AEP)
When the Registrants acquire a business, as defined by the accounting guidance for “Business Combinations,” management recognizes all acquired assets and liabilities at their fair value. To the extent that consideration exceeds the net fair value of the identified assets and liabilities, goodwill is recognized on the balance sheets. Goodwill is not amortized. Management tests acquired goodwill at the reporting unit level for impairment at least annually at its estimated fair value. Fair value is the amount at which an asset or liability 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, management estimates fair value using various internal and external valuation methods.
Pension and OPEB Plans (Applies to all Registrants except AEPTCo)
AEP sponsors a qualified pension plan and two unfunded non-qualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a non-qualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. The Registrant Subsidiaries account for their participation in the AEP sponsored pension and OPEB plans using multiple-employer accounting. See Note 8 - Benefit Plans for additional information including significant accounting policies associated with the plans.
Investments Held in Trust for Future Liabilities (Applies to all Registrants except AEPTCo)
AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and SNF disposal. All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations. The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance.
Benefit Plans
All benefit plan assets are invested in accordance with each plan’s investment policy. The investment policy outlines the investment objectives, strategies and target asset allocations by plan.
The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns. Strategies used include:
•Maintaining a long-term investment horizon.
•Diversifying assets to help control volatility of returns at acceptable levels.
•Managing fees, transaction costs and tax liabilities to maximize investment earnings.
•Using active management of investments where appropriate risk/return opportunities exist.
•Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks.
•Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification.
The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities. The current target asset allocations are as follows:
Pension Plan Assets Target
Equity 25 %
Fixed Income 59 %
Other Investments 15 %
Cash and Cash Equivalents 1 %
OPEB Plans Assets Target
Equity 59 %
Fixed Income 40 %
Cash and Cash Equivalents 1 %
The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies or certain commingled funds). However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law.
For equity investments, the concentration limits are generally as follows:
•No security in excess of 5% of all equities.
•Cash equivalents must be less than 10% of an investment manager’s equity portfolio.
•No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager’s equity portfolio.
•No securities may be bought or sold on margin or other use of leverage.
For fixed income investments, each investment manager’s portfolio is compared to investment grade, diversified long and intermediate benchmark indices.
A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation. Real estate properties are illiquid, difficult to value and not actively traded. The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties. To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification. Real estate holdings include core, value-added and opportunistic classifications.
A portion of the pension assets is invested in private equity. Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance. Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded. The pension plan uses limited partnerships to invest across the private equity investment spectrum. The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise. The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investments.
AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses. AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral. All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested. The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security. The securities lending program’s objective is to provide modest incremental income with a limited increase in risk. As of December 31, 2021 and 2020, the fair value of securities on loan as part of the program was $137 million and $177 million, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned as of December 31, 2021 and 2020.
Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts. The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust. Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid. Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities. With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds. A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges. The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities.
Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal. The underlying holdings in the cash
funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities. The cash funds are valued each business day and provide daily liquidity.
Nuclear Trust Funds (Applies to AEP and I&M)
Nuclear decommissioning and SNF trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and SNF disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include:
•Acceptable investments (rated investment grade or above when purchased).
•Maximum percentage invested in a specific type of investment.
•Prohibition of investment in obligations of AEP, I&M or their affiliates.
•Withdrawals permitted only for payment of decommissioning costs and trust expenses.
I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by an external investment manager that must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.
I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies debt securities in the trust funds as available-for-sale due to their long-term purpose.
Other-than-temporary impairments for investments in debt securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains, unrealized losses and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. See the “Nuclear Contingencies” section of Note 6 for additional discussion of nuclear matters. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts.
Comprehensive Income (Loss) (Applies to all Registrants except AEPTCo)
Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).
Stock-Based Compensation Plans
As of December 31, 2021, AEP had performance shares and restricted stock units outstanding under the American Electric Power System 2015 Long-Term Incentive Plan (2015 LTIP). Upon vesting, all outstanding performance shares and restricted stock units settle in AEP common stock. Performance units awarded prior to 2017 and restricted stock units granted after January 1, 2013 and prior to January 1, 2017 that vested to executive officers were settled in cash. During 2019, all of the remaining performance units and restricted stock units that settle in
cash were settled. The impact of AEP’s stock-based compensation plans are insignificant to the financial statements of the Registrant Subsidiaries.
AEP maintains a variety of tax qualified and non-qualified deferred compensation plans for employees and non-employee directors that include, among other options, an investment in or an investment return equivalent to that of AEP common stock. This includes AEP career shares maintained under the American Electric Power System Stock Ownership Requirement Plan (SORP), which facilitates executives in meeting minimum stock ownership requirements assigned to them by the Human Resources Committee of the Board of Directors. AEP career shares are derived from vested performance shares granted to employees under the 2015 LTIP and previous long-term incentive plans. AEP career shares accrue additional dividend shares in an amount equal to dividends paid on AEP common shares at the closing market price on the dividend payments date. All AEP career shares are settled in shares of AEP common stock after the executive’s service with AEP ends.
Performance shares awarded after January 1, 2017 are classified as temporary equity in the Mezzanine Equity section of the balance sheets until the awards vest. Upon vesting, the performance shares are classified as permanent equity. These awards may be settled in cash upon an employee’s qualifying termination due to a change in control. Because such event is not solely within the control of the company, these awards are classified outside of permanent equity until the awards vest.
AEP compensates their non-employee directors, in part, with stock units under the American Electric Power Company, Inc. Stock Unit Accumulation Plan for Non-Employee Directors. These stock units were payable in cash to directors after their service ends. Effective in June 2022, these stock units become payable in AEP common stock rather than cash.
Management measures and recognizes compensation expense for all share-based payment awards to employees and directors based on estimated fair values. For share-based payment awards with service only vesting conditions, management recognizes compensation expense on a straight-line basis. Stock-based compensation expense recognized on the statements of income for the years ended December 31, 2021, 2020 and 2019 is based on the number of outstanding awards at the end of each period without a reduction for estimated forfeitures. AEP accounts for forfeitures in the period in which they occur.
For the years ended December 31, 2021, 2020 and 2019, compensation cost is included in Net Income for the performance shares, career shares, restricted stock units and the non-employee director stock units. Compensation cost may also be capitalized. See Note 15 - Stock-based Compensation for additional information.
Equity Investment in Unconsolidated Entities (Applies to AEP and SWEPCo)
The equity method of accounting is used for equity investments where either AEP or SWEPCo exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings or losses is included in Equity Earnings (Loss) of Unconsolidated Subsidiaries on the statements of income. AEP and SWEPCo regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature.
AEP has various significant equity method investments, which include ETT, DHLC and five wind farms acquired in the purchase of Sempra Renewables LLC. See Note 17 - Variable Interest Entities and Equity Method Investments for additional information.
Earnings Per Share (EPS) (Applies to AEP)
Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted-average outstanding common shares, assuming conversion of all potentially dilutive stock awards.
The following table presents AEP’s basic and diluted EPS calculations included on the statements of income:
Years Ended December 31,
2021 2020 2019
(in millions, except per-share data)
$/share $/share $/share
Earnings Attributable to AEP Common Shareholders
$ 2,488.1 $ 2,200.1 $ 1,921.1
Weighted-Average Number of Basic AEP Common Shares Outstanding 500.5 $ 4.97 495.7 $ 4.44 493.7 $ 3.89
Weighted-Average Dilutive Effect of Stock-Based Awards 1.3 (0.01) 1.5 (0.02) 1.6 (0.01)
Weighted-Average Number of Diluted AEP Common Shares Outstanding 501.8 $ 4.96 497.2 $ 4.42 495.3 $ 3.88
Equity Units are potentially dilutive securities but were excluded from the calculation of diluted EPS for the years ended December 31, 2021, 2020 and 2019, as the dilutive stock price thresholds were not met. See Note 14 - Financing Activities for additional information related to Equity Units.
There were no antidilutive shares outstanding as of December 31, 2021 and 2019. There were 128 thousand antidilutive shares outstanding as of December 31, 2020.
Supplementary Income Statement Information
The following tables provide the components of Depreciation and Amortization for the years ended December 31, 2021, 2020 and 2019:
Depreciation and Amortization AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Depreciation and Amortization of Property, Plant and Equipment
$ 2,717.1 $ 327.2 $ 297.3 $ 547.0 $ 424.9 $ 301.1 $ 185.9 $ 292.9
Amortization of Certain Securitized Assets
64.2 64.2 - - - - - -
Amortization of Regulatory Assets and Liabilities
44.4 (4.4) - (0.8) 21.1 2.2 10.7 2.1
Total Depreciation and Amortization
$ 2,825.7 $ 387.0 $ 297.3 $ 546.2 $ 446.0 $ 303.3 $ 196.6 $ 295.0
Depreciation and Amortization AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Depreciation and Amortization of Property, Plant and Equipment
$ 2,487.5 $ 364.2 $ 249.0 $ 507.8 $ 393.3 $ 275.0 $ 171.9 $ 271.2
Amortization of Certain Securitized Assets
171.3 171.3 - - - - - -
Amortization of Regulatory Assets and Liabilities
24.0 (5.7) - (0.3) 18.3 1.6 1.6 1.5
Total Depreciation and Amortization
$ 2,682.8 $ 529.8 $ 249.0 $ 507.5 $ 411.6 $ 276.6 $ 173.5 $ 272.7
Depreciation and Amortization AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Depreciation and Amortization of Property, Plant and Equipment
$ 2,203.7 $ 365.9 $ 176.0 $ 466.5 $ 330.6 $ 229.4 $ 162.5 $ 247.9
Amortization of Certain Securitized Assets
280.7 258.7 - - - 22.0 - -
Amortization of Regulatory Assets and Liabilities
30.1 (2.3) - 0.3 20.0 (10.5) 7.0 1.2
Total Depreciation and Amortization
$ 2,514.5 $ 622.3 $ 176.0 $ 466.8 $ 350.6 $ 240.9 $ 169.5 $ 249.1
Supplementary Cash Flow Information (Applies to AEP)
Years Ended December 31,
Cash Flow Information 2021 2020 2019
(in millions)
Cash Paid (Received) for:
Interest, Net of Capitalized Amounts $ 1,137.2 $ 1,029.1 $ 1,022.5
Income Taxes 13.2 (49.1) 6.1
Noncash Investing and Financing Activities:
Acquisitions Under Finance Leases 287.6 44.2 87.5
Construction Expenditures Included in Current Liabilities as of December 31,
1,180.4 975.4 1,341.1
Construction Expenditures Included in Noncurrent Liabilities as of December 31,
- 5.5 -
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,
- 33.4 0.1
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage
1.7 2.6 0.3
Noncash Contribution of Assets to Cedar Creek Project (9.3) - -
Noncontrolling Interest Assumed - Dry Lake Solar Project 35.3 - -
Noncontrolling Interest Assumed with Sempra Renewables LLC and Santa Rita East Acquisition
- - 253.4
Liabilities Assumed with Sempra Renewable LLC and Santa Rita East Acquisition
- - 32.4
Forward Equity Purchase Contracts Included in Current and Noncurrent Liabilities as of December 31, - 110.6 47.3
2. NEW ACCOUNTING STANDARDS
The disclosures in this note apply to all Registrants unless indicated otherwise.
During the FASB’s standard-setting process and upon issuance of final standards, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. There are no new standards expected to have a material impact on the Registrants’ financial statements.
3. COMPREHENSIVE INCOME
The disclosures in this note apply to all Registrants except for AEPTCo. AEPTCo does not have any components of other comprehensive income for any period presented in the financial statements.
Presentation of Comprehensive Income
The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the years ended December 31, 2021, 2020 and 2019. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 8 - Benefit Plans for additional information.
AEP
Cash Flow Hedges Pension and OPEB
For the Year Ended December 31, 2021 Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total
(in millions)
Balance in AOCI as of December 31, 2020 $ (60.6) $ (47.5) $ 123.7 $ (100.7) $ (85.1)
Change in Fair Value Recognized in AOCI 488.2 21.1 (a) - 27.5 536.8
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b)
0.7 - - - 0.7
Purchased Electricity for Resale (b)
(334.8) - - - (334.8)
Interest Expense (b)
- 6.5 - - 6.5
Amortization of Prior Service Cost (Credit)
- - (19.4) - (19.4)
Amortization of Actuarial (Gains) Losses
- - 9.1 - 9.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit
(334.1) 6.5 (10.3) - (337.9)
Income Tax (Expense) Benefit
(70.2) 1.4 (2.2) - (71.0)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
(263.9) 5.1 (8.1) - (266.9)
Net Current Period Other Comprehensive Income (Loss)
224.3 26.2 (8.1) 27.5 269.9
Balance in AOCI as of December 31, 2021 $ 163.7 $ (21.3) $ 115.6 $ (73.2) $ 184.8
AEP
Cash Flow Hedges Pension and OPEB
For the Year Ended December 31, 2020 Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total
(in millions)
Balance in AOCI as of December 31, 2019 $ (103.5) $ (11.5) $ 130.7 $ (163.4) $ (147.7)
Change in Fair Value Recognized in AOCI (89.2) (39.9) (a) - 62.7 (66.4)
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b)
(0.4) - - - (0.4)
Purchased Electricity for Resale (b)
167.6 - - - 167.6
Interest Expense (b)
- 4.9 - - 4.9
Amortization of Prior Service Cost (Credit)
- - (19.2) - (19.2)
Amortization of Actuarial (Gains) Losses
- - 10.3 - 10.3
Reclassifications from AOCI, before Income Tax (Expense) Benefit
167.2 4.9 (8.9) - 163.2
Income Tax (Expense) Benefit
35.1 1.0 (1.9) - 34.2
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
132.1 3.9 (7.0) - 129.0
Net Current Period Other Comprehensive Income (Loss)
42.9 (36.0) (7.0) 62.7 62.6
Balance in AOCI as of December 31, 2020 $ (60.6) $ (47.5) $ 123.7 $ (100.7) $ (85.1)
Cash Flow Hedges Pension and OPEB
For the Year Ended December 31, 2019 Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total
(in millions)
Balance in AOCI as of December 31, 2018 $ (23.0) $ (12.6) $ 136.3 $ (221.1) $ (120.4)
Change in Fair Value Recognized in AOCI (127.2) (0.2) (a) - 57.7 (69.7)
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b)
(0.2) - - - (0.2)
Purchased Electricity for Resale (b)
59.5 - - - 59.5
Interest Expense (b)
- 1.5 - - 1.5
Amortization of Prior Service Cost (Credit)
- - (19.2) - (19.2)
Amortization of Actuarial (Gains) Losses
- - 12.1 - 12.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit
59.3 1.5 (7.1) - 53.7
Income Tax (Expense) Benefit
12.6 0.2 (1.5) - 11.3
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
46.7 1.3 (5.6) - 42.4
Net Current Period Other Comprehensive Income (Loss)
(80.5) 1.1 (5.6) 57.7 (27.3)
Balance in AOCI as of December 31, 2019 $ (103.5) $ (11.5) $ 130.7 $ (163.4) $ (147.7)
AEP Texas
Pension and OPEB
Amortization Changes in
Cash Flow Hedge - of Deferred Funded
For the Year Ended December 31, 2021 Interest Rate Costs Status Total
(in millions)
Balance in AOCI as of December 31, 2020 $ (2.3) $ 5.1 $ (11.7) $ (8.9)
Change in Fair Value Recognized in AOCI
0.1 - 1.2 1.3
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)
1.2 - - 1.2
Amortization of Prior Service Cost (Credit)
- (0.1) - (0.1)
Amortization of Actuarial (Gains) Losses
- 0.3 - 0.3
Reclassifications from AOCI, before Income Tax (Expense) Benefit
1.2 0.2 - 1.4
Income Tax (Expense) Benefit
0.3 - - 0.3
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
0.9 0.2 - 1.1
Net Current Period Other Comprehensive Income (Loss) 1.0 0.2 1.2 2.4
Balance in AOCI as of December 31, 2021 $ (1.3) $ 5.3 $ (10.5) $ (6.5)
Pension and OPEB
Amortization Changes in
Cash Flow Hedge - of Deferred Funded
For the Year Ended December 31, 2020 Interest Rate Costs Status Total
(in millions)
Balance in AOCI as of December 31, 2019 $ (3.4) $ 4.9 $ (14.3) $ (12.8)
Change in Fair Value Recognized in AOCI
0.1 - 2.6 2.7
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)
1.3 - - 1.3
Amortization of Prior Service Cost (Credit)
- (0.1) - (0.1)
Amortization of Actuarial (Gains) Losses
- 0.3 - 0.3
Reclassifications from AOCI, before Income Tax (Expense) Benefit
1.3 0.2 - 1.5
Income Tax (Expense) Benefit
0.3 - - 0.3
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
1.0 0.2 - 1.2
Net Current Period Other Comprehensive Income (Loss) 1.1 0.2 2.6 3.9
Balance in AOCI as of December 31, 2020 $ (2.3) $ 5.1 $ (11.7) $ (8.9)
Pension and OPEB
Amortization Changes in
Cash Flow Hedge - of Deferred Funded
For the Year Ended December 31, 2019 Interest Rate Costs Status Total
(in millions)
Balance in AOCI as of December 31, 2018 $ (4.4) $ 4.7 $ (15.4) $ (15.1)
Change in Fair Value Recognized in AOCI
- - 1.1 1.1
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)
1.3 - - 1.3
Amortization of Prior Service Cost (Credit)
- (0.1) - (0.1)
Amortization of Actuarial (Gains) Losses
- 0.3 - 0.3
Reclassifications from AOCI, before Income Tax (Expense) Benefit
1.3 0.2 - 1.5
Income Tax (Expense) Benefit
0.3 - - 0.3
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
1.0 0.2 - 1.2
Net Current Period Other Comprehensive Income (Loss) 1.0 0.2 1.1 2.3
Balance in AOCI as of December 31, 2019 $ (3.4) $ 4.9 $ (14.3) $ (12.8)
APCo
Pension and OPEB
Amortization Changes in
Cash Flow Hedge - of Deferred Funded
For the Year Ended December 31, 2021 Interest Rate Costs Status Total
(in millions)
Balance in AOCI as of December 31, 2020 $ (0.8) $ 5.4 $ 2.6 $ 7.2
Change in Fair Value Recognized in AOCI
9.2 - 13.1 22.3
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)
(1.1) - - (1.1)
Amortization of Prior Service Cost (Credit)
- (5.3) - (5.3)
Reclassifications from AOCI, before Income Tax (Expense) Benefit
(1.1) (5.3) - (6.4)
Income Tax (Expense) Benefit
(0.2) (1.1) - (1.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
(0.9) (4.2) - (5.1)
Net Current Period Other Comprehensive Income (Loss) 8.3 (4.2) 13.1 17.2
Balance in AOCI as of December 31, 2021 $ 7.5 $ 1.2 $ 15.7 $ 24.4
Pension and OPEB
Amortization Changes in
Cash Flow Hedges - of Deferred Funded
For the Year Ended December 31, 2020 Interest Rate Costs Status Total
(in millions)
Balance in AOCI as of December 31, 2019 $ 0.9 $ 9.2 $ (5.1) $ 5.0
Change in Fair Value Recognized in AOCI
(0.7) - 7.7 7.0
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)
(1.3) - - (1.3)
Amortization of Prior Service Cost (Credit)
- (5.3) - (5.3)
Amortization of Actuarial (Gains) Losses
- 0.5 - 0.5
Reclassifications from AOCI, before Income Tax (Expense) Benefit
(1.3) (4.8) - (6.1)
Income Tax (Expense) Benefit
(0.3) (1.0) - (1.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
(1.0) (3.8) - (4.8)
Net Current Period Other Comprehensive Income (Loss) (1.7) (3.8) 7.7 2.2
Balance in AOCI as of December 31, 2020 $ (0.8) $ 5.4 $ 2.6 $ 7.2
Pension and OPEB
Amortization Changes in
Cash Flow Hedges of Deferred Funded
For the Year Ended December 31, 2019 Interest Rate Costs Status Total
(in millions)
Balance in AOCI as of December 31, 2018 $ 1.8 $ 11.7 $ (18.5) $ (5.0)
Change in Fair Value Recognized in AOCI
- - 13.4 13.4
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)
(1.1) - - (1.1)
Amortization of Prior Service Cost (Credit)
- (5.3) - (5.3)
Amortization of Actuarial (Gains) Losses
- 2.1 - 2.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit
(1.1) (3.2) - (4.3)
Income Tax (Expense) Benefit
(0.2) (0.7) - (0.9)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
(0.9) (2.5) - (3.4)
Net Current Period Other Comprehensive Income (Loss) (0.9) (2.5) 13.4 10.0
Balance in AOCI as of December 31, 2019 $ 0.9 $ 9.2 $ (5.1) $ 5.0
I&M
Pension and OPEB
Amortization Changes in
Cash Flow Hedge - of Deferred Funded
For the Year Ended December 31, 2021 Interest Rate Costs Status Total
(in millions)
Balance in AOCI as of December 31, 2020 $ (8.3) $ 4.8 $ (3.5) $ (7.0)
Change in Fair Value Recognized in AOCI
- - 4.2 4.2
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)
2.0 - - 2.0
Amortization of Prior Service Cost (Credit)
- (0.8) - (0.8)
Amortization of Actuarial (Gains) Losses
- 0.7 - 0.7
Reclassifications from AOCI, before Income Tax (Expense) Benefit
2.0 (0.1) - 1.9
Income Tax (Expense) Benefit
0.4 - - 0.4
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
1.6 (0.1) - 1.5
Net Current Period Other Comprehensive Income (Loss) 1.6 (0.1) 4.2 5.7
Balance in AOCI as of December 31, 2021 $ (6.7) $ 4.7 $ 0.7 $ (1.3)
Pension and OPEB
Amortization Changes in
Cash Flow Hedge - of Deferred Funded
For the Year Ended December 31, 2020 Interest Rate Costs Status Total
(in millions)
Balance in AOCI as of December 31, 2019 $ (9.9) $ 4.9 $ (6.6) $ (11.6)
Change in Fair Value Recognized in AOCI
- - 3.1 3.1
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)
2.0 - - 2.0
Amortization of Prior Service Cost (Credit)
- (0.8) - (0.8)
Amortization of Actuarial (Gains) Losses
- 0.7 - 0.7
Reclassifications from AOCI, before Income Tax (Expense) Benefit
2.0 (0.1) - 1.9
Income Tax (Expense) Benefit
0.4 - - 0.4
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
1.6 (0.1) - 1.5
Net Current Period Other Comprehensive Income (Loss) 1.6 (0.1) 3.1 4.6
Balance in AOCI as of December 31, 2020 $ (8.3) $ 4.8 $ (3.5) $ (7.0)
Pension and OPEB
Amortization Changes in
Cash Flow Hedge - of Deferred Funded
For the Year Ended December 31, 2019 Interest Rate Costs Status Total
(in millions)
Balance in AOCI as of December 31, 2018 $ (11.5) $ 5.1 $ (7.4) $ (13.8)
Change in Fair Value Recognized in AOCI
- - 0.8 0.8
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)
2.0 - - 2.0
Amortization of Prior Service Cost (Credit)
- (0.8) - (0.8)
Amortization of Actuarial (Gains) Losses
- 0.6 - 0.6
Reclassifications from AOCI, before Income Tax (Expense) Benefit
2.0 (0.2) - 1.8
Income Tax (Expense) Benefit
0.4 - - 0.4
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
1.6 (0.2) - 1.4
Net Current Period Other Comprehensive Income (Loss) 1.6 (0.2) 0.8 2.2
Balance in AOCI as of December 31, 2019 $ (9.9) $ 4.9 $ (6.6) $ (11.6)
OPCo
Cash Flow Hedge -
For the Year Ended December 31, 2021 Interest Rate
(in millions)
Balance in AOCI as of December 31, 2020 $ -
Change in Fair Value Recognized in AOCI
-
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)
-
Reclassifications from AOCI, before Income Tax (Expense) Benefit
-
Income Tax (Expense) Benefit
-
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
-
Net Current Period Other Comprehensive Income (Loss) -
Balance in AOCI as of December 31, 2021 $ -
Cash Flow Hedge -
For the Year Ended December 31, 2020 Interest Rate
(in millions)
Balance in AOCI as of December 31, 2019 $ -
Change in Fair Value Recognized in AOCI
-
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)
-
Reclassifications from AOCI, before Income Tax (Expense) Benefit
-
Income Tax (Expense) Benefit
-
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
-
Net Current Period Other Comprehensive Income (Loss) -
Balance in AOCI as of December 31, 2020 $ -
Cash Flow Hedge -
For the Year Ended December 31, 2019 Interest Rate
(in millions)
Balance in AOCI as of December 31, 2018 $ 1.0
Change in Fair Value Recognized in AOCI
-
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)
(1.3)
Reclassifications from AOCI, before Income Tax (Expense) Benefit
(1.3)
Income Tax (Expense) Benefit
(0.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
(1.0)
Net Current Period Other Comprehensive Income (Loss) (1.0)
Balance in AOCI as of December 31, 2019 $ -
PSO
Cash Flow Hedge -
For the Year Ended December 31, 2021 Interest Rate
(in millions)
Balance in AOCI as of December 31, 2020 $ 0.1
Change in Fair Value Recognized in AOCI
-
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)
(0.1)
Reclassifications from AOCI, before Income Tax (Expense) Benefit
(0.1)
Income Tax (Expense) Benefit
-
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
(0.1)
Net Current Period Other Comprehensive Income (Loss) (0.1)
Balance in AOCI as of December 31, 2021 $ -
Cash Flow Hedge -
For the Year Ended December 31, 2020 Interest Rate
(in millions)
Balance in AOCI as of December 31, 2019 $ 1.1
Change in Fair Value Recognized in AOCI
-
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)
(1.3)
Reclassifications from AOCI, before Income Tax (Expense) Benefit
(1.3)
Income Tax (Expense) Benefit
(0.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
(1.0)
Net Current Period Other Comprehensive Income (Loss) (1.0)
Balance in AOCI as of December 31, 2020 $ 0.1
Cash Flow Hedge -
For the Year Ended December 31, 2019 Interest Rate
(in millions)
Balance in AOCI as of December 31, 2018 $ 2.1
Change in Fair Value Recognized in AOCI
-
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)
(1.3)
Reclassifications from AOCI, before Income Tax (Expense) Benefit
(1.3)
Income Tax (Expense) Benefit
(0.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
(1.0)
Net Current Period Other Comprehensive Income (Loss) (1.0)
Balance in AOCI as of December 31, 2019 $ 1.1
SWEPCo
Pension and OPEB
Amortization Changes in
Cash Flow Hedge - of Deferred Funded
For the Year Ended December 31, 2021 Interest Rate Costs Status Total
(in millions)
Balance in AOCI as of December 31, 2020 $ (0.3) $ (2.8) $ 5.0 $ 1.9
Change in Fair Value Recognized in AOCI
- - 4.9 4.9
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)
1.9 - - 1.9
Amortization of Prior Service Cost (Credit)
- (2.0) - (2.0)
Amortization of Actuarial (Gains) Losses
- - - -
Reclassifications from AOCI, before Income Tax (Expense) Benefit
1.9 (2.0) - (0.1)
Income Tax (Expense) Benefit
0.4 (0.4) - -
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
1.5 (1.6) - (0.1)
Net Current Period Other Comprehensive Income (Loss) 1.5 (1.6) 4.9 4.8
Balance in AOCI as of December 31, 2021 $ 1.2 $ (4.4) $ 9.9 $ 6.7
Pension and OPEB
Amortization Changes in
Cash Flow Hedge - of Deferred Funded
For the Year Ended December 31, 2020 Interest Rate Costs Status Total
(in millions)
Balance in AOCI as of December 31, 2019 $ (1.8) $ (1.3) $ 1.8 $ (1.3)
Change in Fair Value Recognized in AOCI
- - 3.2 3.2
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)
1.9 - - 1.9
Amortization of Prior Service Cost (Credit)
- (2.0) - (2.0)
Amortization of Actuarial (Gains) Losses
- 0.1 - 0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit
1.9 (1.9) - -
Income Tax (Expense) Benefit
0.4 (0.4) - -
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
1.5 (1.5) - -
Net Current Period Other Comprehensive Income (Loss) 1.5 (1.5) 3.2 3.2
Balance in AOCI as of December 31, 2020 $ (0.3) $ (2.8) $ 5.0 $ 1.9
Pension and OPEB
Amortization Changes in
Cash Flow Hedge - of Deferred Funded
For the Year Ended December 31, 2019 Interest Rate Costs Status Total
(in millions)
Balance in AOCI as of December 31, 2018 $ (3.3) $ (0.2) $ (1.9) $ (5.4)
Change in Fair Value Recognized in AOCI
- - 3.7 3.7
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)
1.9 - - 1.9
Amortization of Prior Service Cost (Credit)
- (2.0) - (2.0)
Amortization of Actuarial (Gains) Losses
- 0.6 - 0.6
Reclassifications from AOCI, before Income Tax (Expense) Benefit
1.9 (1.4) - 0.5
Income Tax (Expense) Benefit
0.4 (0.3) - 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
1.5 (1.1) - 0.4
Net Current Period Other Comprehensive Income (Loss) 1.5 (1.1) 3.7 4.1
Balance in AOCI as of December 31, 2019 $ (1.8) $ (1.3) $ 1.8 $ (1.3)
(a)The change in fair value includes $(7) million, $6 million and $4 million related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC for the years ended December 31, 2021, 2020 and 2019, respectively. See “Sempra Renewables LLC” section of Note 17 for additional information.
(b)Amounts reclassified to the referenced line item on the statements of income.
4. RATE MATTERS
The disclosures in this note apply to all Registrants unless indicated otherwise.
The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrants’ recent significant rate orders and pending rate filings are addressed in this note.
AEP Texas Rate Matters (Applies to AEP and AEP Texas)
AEP Texas Interim Transmission and Distribution Rates
Through December 31, 2021, AEP Texas’ cumulative revenues from interim base rate increases that are subject to review is approximately $298 million. A base rate review could result in a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. AEP Texas is required to file for a comprehensive rate review no later than April 5, 2024.
APCo and WPCo Rate Matters (Applies to AEP and APCo)
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, an intervenor filed its assignments of error with the Virginia Supreme Court related to the appeal of the November 2020 order in which it stated the Virginia SCC erred: (a) in determining that Virginia law did not apply to its determination to permit amortization for recovery of costs associated with retired coal-fired generation assets, (b) in establishing a new regulatory asset for a cost incurred outside of the triennial review period due to its failure to apply a threshold earnings test before approving deferred cost recovery and (c) in misapplying the requirement that APCo bear the burden of demonstrating that power purchases made by APCo from its affiliate, OVEC, were priced at the lower of OVEC’s cost or the market price for nonaffiliated power.
In March 2021, APCo filed its assignments of error with the Virginia Supreme Court related to its appeal of the November 2020 order in which it stated the Virginia SCC erred: (a) in finding that costs associated with asset impairments related to early retirement determinations made by APCo for certain generation facilities should not be attributed to the test periods under review and deemed fully recovered in the period recorded, (b) in finding that it was permitted to evaluate the reasonableness of APCo’s decision to record, per books for financial reporting purposes, asset impairments related to early retirement determinations for certain generation facilities, (c) as a result of the errors described in (a) and (b), in denying APCo an increase in rates, (d) in failing to review and make any findings regarding whether APCo’s rates would allow it to earn a fair rate of return going forward, (e) in denying APCo an increase in base rates by failing to ensure that APCo has an opportunity to recover its costs and earn a fair rate of return, thereby resulting in a taking of private property for public use without just compensation and (f) in retroactively adjusting APCo’s depreciation expense for purposes of calculating APCo’s earnings for the 2017-2019 triennial period.
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.
CCR/ELG Compliance Plan Filings
In December 2020, APCo submitted filings with the Virginia SCC and WVPSC requesting approvals necessary to implement CCR/ELG compliance plans at 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.
ETT Rate Matters (Applies to AEP)
ETT Interim Transmission Rates
AEP has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next base rate proceeding. Through December 31, 2021, AEP’s share of ETT’s cumulative revenues that are subject to review is approximately $1.4 billion. A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. ETT is required to file for a comprehensive rate review no later than February 1, 2023, during which the $1.4 billion of cumulative revenues above will be subject to review.
I&M Rate Matters (Applies to AEP and I&M)
2021 Indiana Base Rate Case
In July 2021, I&M filed a request with the IURC for a $104 million annual increase in Indiana rates, inclusive of base rates and riders, based upon a proposed 10% ROE. I&M proposed a phased-in annual increase in rates of $73 million effective in May 2022 with the remaining $31 million annual increase in rates to be effective January 2023. The proposed annual increase includes $7 million related to an annual increase in depreciation expense, driven by increased depreciation rates and proposed investments. The request also includes a new AMI rider for proposed meter projects.
In November 2021, I&M and intervenors filed an unopposed joint settlement agreement with the IURC. After adjustments to remove the impact of Rockport Plant, Unit 2, the agreement includes a $61 million annual revenue increase based on a 9.7% ROE. The primary differences between I&M’s requested annual rate increase and the agreed upon settlement increase are primarily due to: (a) changes to the capital structure of I&M, (b) decreased depreciation rates and (c) certain changes to I&M’s proposed rate base. Rockport Plant, Unit 2 costs will be recovered through riders until the lease expiration in December 2022. Adjustments to remove Rockport Plant, Unit 2 costs from base rates are consistent with the IURC’s order approving I&M’s proposed purchase of Rockport Plant, Unit 2. See “Rockport Plant Litigation” section of Note 6 for additional information. In February 2022, the IURC issued an order approving the joint settlement agreement with no modifications. The IURC’s order resulted in a phased-in increase in Indiana rates with a $3 million annual increase effective February 2022 and the remaining $58 million annual increase effective in January 2023.
KPCo Rate Matters (Applies to AEP)
CCR/ELG Compliance Plan Filings
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, KPCo’s share of the Mitchell Plant’s ELG investment balance in CWIP was $3 million. 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.
OPCo Rate Matters (Applies to AEP and OPCo)
2020 Ohio Base Rate Case
In June 2020, OPCo filed a request with the PUCO for a $42 million annual increase in base rates based upon a proposed 10.15% ROE net of existing riders.
In March 2021, OPCo, the PUCO staff and various intervenors filed a joint stipulation and settlement agreement with the PUCO. The agreement includes a $68 million annual decrease in base rates based on an ROE of 9.7%. The difference between OPCo’s requested annual base rate increase and the agreed upon decrease is primarily due to a reduction in the requested ROE, the removal of proposed future energy efficiency costs and a decrease in vegetation management expenses moved to recovery in riders. Additionally, the agreement includes: (a) an
increased fixed monthly residential customer charge, (b) the discontinuation of rate decoupling and (c) the continuation of the DIR with annual revenue caps of $57 million in 2021, $91 million in 2022, $116 million in 2023 and $51 million for the first five months of 2024. Annual revenue caps for the DIR can be increased if OPCo achieves certain reliability standards. In November 2021, the PUCO approved the joint stipulation and settlement agreement and rates went into effect in December 2021.
OVEC Cost Recovery Audits
In December 2021, as part of OVEC cost recovery audits pending before the PUCO, intervenors filed positions claiming that costs incurred by OPCo during the 2018-2019 audit period were imprudent and should be disallowed. Management disagrees with these claims and is unable to predict the impact, if any, these disputes may have on future results of operations, financial condition and cash flows. See "OVEC" section of Note 17 for additional information on AEP and OPCo’s investment in OVEC.
PSO Rate Matters (Applies to AEP and PSO)
2021 Oklahoma Base Rate Case
In April 2021, PSO filed a request with the OCC for a $172 million net annual increase in Oklahoma base rates based upon a 10% ROE. The proposed net annual increase includes: (a) a $57 million annual depreciation expense increase, of which $45 million is related to the accelerated depreciation recovery of the Oklaunion Power Station and Northeastern Plant, Unit 3 through 2026 and (b) $31 million related to increased SPP expenses. PSO also requested the continuation of its SPP Transmission Tariff that tracks transmission costs as well as continuation and expansion of its Distribution and Safety Reliability Rider to recover projects in its proposed grid transformation and revitalization plan, which includes $100 million annual capital spend over a 5 year period. In August 2021, PSO updated its request for a net annual revenue increase to appropriately reflect certain cost reductions and annualized rider revenues transitioning into base rates. PSO’s updated request filed with the OCC is for a $128 million net annual increase in Oklahoma base rates based upon a 10% ROE.
In September 2021, PSO, OCC staff and certain intervenors filed a contested joint stipulation and settlement agreement with the OCC that included a net annual revenue increase of $51 million based upon a 9.4% ROE. The agreement also included: (a) recovery of, with a debt return on, the Oklaunion Power Station regulatory asset through 2046 and continued recovery of Northeastern Plant, Unit 3 through 2040, (b) updated depreciation rates for plant in service, excluding coal production plant, (c) approval to defer a weighted average cost of capital carrying charge on PSO’s deferred tax asset associated with net operating loss on a stand-alone tax basis beginning in November 2021 and, contingent upon receipt of a supportive private letter ruling from the IRS, approval to collect the deferral through a rider over a 20-month period, (d) modification of the SPP transmission tariff to reduce the scope of tracked transmission expense and (e) modification of the Distribution Reliability and Safety Rider to limit recovery to previously approved projects not in service as of June 2021. PSO implemented an interim annual base rate increase of $51 million starting with the November 2021 billing cycle. In December 2021, the OCC approved the joint stipulation and settlement agreement without modifications. Effective February 2022, interim rates were terminated and updated rates and tariffs went into effect in accordance with the final order.
February 2021 Severe Winter Weather Impacts in SPP
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. For the time period of February 9, 2021, to February 20, 2021, PSO’s natural gas expenses and purchases of electricity still to be recovered from customers are $679 million as of December 31, 2021.
In April 2021, the OCC approved a waiver for PSO allowing the deferral of the extraordinary fuel and purchases of electricity, including a carrying charge at an interim rate of 0.75%, over a longer time period than what the FAC traditionally allows. 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.
SWEPCo Rate Matters (Applies to AEP and SWEPCo)
2012 Texas Base Rate Case
In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs.
Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, SWEPCo reversed $114 million of a previously recorded regulatory disallowance in 2013. 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. No parties filed a motion for rehearing with the Texas Supreme Court. 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.
2016 Texas Base Rate Case
In 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% ROE. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a ROE of 9.6%, effective May 2017. The final order also included: (a) approval to recover the Texas jurisdictional share of environmental investments placed in- service, as of June 30, 2016, at various plants, including Welsh Plant, Units 1 and 3, (b) approval of recovery of, but no return on, the Texas jurisdictional share of the net book value of Welsh Plant, Unit 2, (c) approval of $2 million in additional vegetation management expenses and (d) the rejection of SWEPCo’s proposed transmission cost recovery mechanism.
As a result of the final order, in 2017 SWEPCo: (a) recorded an impairment charge of $19 million, which included $7 million associated with the lack of return on Welsh Plant, Unit 2 and $12 million related to other disallowed plant investments, (b) recognized $32 million of additional revenues, for the period of May 2017 through December 2017, that was surcharged to customers in 2018 and (c) recognized an additional $7 million of expenses consisting primarily of depreciation expense and vegetation management expense, offset by the deferral of rate case expense. SWEPCo implemented new rates in February 2018 billings. The $32 million of additional 2017 revenues was collected during 2018. In March 2018, the PUCT clarified and corrected portions of the final order, without changing the overall decision or amounts of the rate change. The order has been appealed by various intervenors. The appeal will move forward following the conclusion of the 2012 Texas Base Rate Case. If certain parts of the PUCT order are overturned, it could reduce future net income and cash flows and impact financial condition.
2020 Texas Base Rate Case
In October 2020, SWEPCo filed a request with the PUCT for a $105 million annual increase in Texas base rates based upon a proposed 10.35% ROE. The request would move transmission and distribution interim revenues recovered through riders into base rates. Eliminating these riders would result in a net annual requested base rate increase of $90 million primarily due to increased investments. The proposed net annual increase: (a) includes $5 million related to vegetation management to maintain and improve the reliability of SWEPCo’s Texas jurisdictional distribution system, (b) requests a $10 million annual depreciation increase and (c) seeks $2 million annually to establish a storm catastrophe reserve. In addition, SWEPCo also requested recovery of the Texas jurisdictional share of the Dolet Hills Power Station of $45 million which was retired in December 2021. SWEPCo subsequently filed a request with the PUCT lowering the requested annual increase in Texas base rates to $100 million which would result in an $85 million net annual base rate increase after moving the proposed riders to rate base.
In January 2022, the PUCT issued a final order approving an annual revenue increase of $39 million based upon a 9.25% ROE. The order also includes: (a) rates implemented retroactively back to March 18, 2021, (b) $5 million of the proposed increase related to vegetation management, (c) $2 million annually to establish a storm catastrophe reserve (d) the creation of a rider that would recover the Dolet Hills Power Station as if it were in rate base until its retirement at the end of 2021 and starting in 2022 the remaining net book value would be recovered as a regulatory asset through 2046. As a result of the final order, SWEPCo recorded a disallowance of $12 million associated with the lack of return on the Dolet Hills Power Station. In February 2022, SWEPCo filed a motion for rehearing with the PUCT challenging several errors in the order, which include challenges of the approved ROE, the denial of a reasonable return or carrying costs on the Dolet Hills Power Station and the calculation of the Texas jurisdictional share of the storm catastrophe reserve.
2020 Louisiana Base Rate Case
In December 2020, SWEPCo filed a request with the LPSC for a $134 million annual increase in Louisiana base rates based upon a proposed 10.35% ROE. SWEPCo subsequently revised the requested annual increase to $114 million to reflect removing hurricane storm restoration costs from the base case filing. The hurricane costs have been requested in a separate storm filing. See “2021 Louisiana Storm Cost Filing” below for more information. The base case filing would extend the formula rate plan for five years and includes modifications to the formula rate plan to allow for forward-looking transmission costs, reflects the impact of net operating losses associated with the acceleration of certain tax benefits and incorporates future federal corporate income tax changes. The proposed net annual increase requests a $32 million annual depreciation increase to recover Louisiana’s share of the Dolet Hills Power Station, Pirkey Power Plant and Welsh Plant, all of which are expected to be retired early.
In July 2021, the LPSC staff filed testimony supporting a $6 million annual increase in base rates based upon a ROE of 9.1% while other intervenors recommended a ROE ranging from 9.35% to 9.8%. The primary differences between SWEPCo’s requested annual increase in base rates and the LPSC staff’s recommendation include: (a) a reduction in depreciation expense, (b) recovery of Dolet Hills Power Station and Pirkey Power Plant in a separate rider mechanism, (c) the rejection of SWEPCo’s proposed adjustment to include a stand-alone net operating loss carryforward deferred tax asset in rate base and (d) a reduction in the proposed ROE.
In September 2021, SWEPCo filed rebuttal testimony supporting a revised requested annual increase in base rates of $95 million. The primary differences in the rebuttal testimony from the previous revised request of $114 million are modifications to the proposed recovery of the Dolet Hills Power Station and revisions to various proposed amortizations. LPSC staff and intervenor responses to SWEPCo’s rebuttal testimony were filed in October 2021. The procedural schedule for the case is on hold due to ongoing settlement discussions.
If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
2021 Arkansas Base Rate Case
In July 2021, SWEPCo filed a request with the APSC for an $85 million annual increase in Arkansas base rates based upon a proposed 10.35% ROE with a capital structure of 48.7% debt and 51.3% common equity. The proposed annual increase includes: (a) a $41 million revenue requirement for the North Central Wind Facilities, (b) a $14 million annual depreciation increase primarily due to recovery of the Dolet Hills Power Station through 2026 and Pirkey Plant and Welsh Plant, Units 1 and 3 through 2037 and (c) a $6 million increase due to SPP costs. SWEPCo requested that rates become effective in June 2022.
APSC staff filed testimony supporting a $47 million annual increase in base rates based upon a ROE of 9.3% while other intervenors recommended a ROE ranging from 8.75% to 9.25%. The primary differences between SWEPCo’s requested annual increase in base rates and the APSC staff’s recommendation include: (a) recovery of the Dolet Hills Power Station through 2046 with no debt or equity return, (b) a reduction in the proposed ROE with a capital structure of 55.5% debt and 44.5% common equity and (c) lower depreciation rates. The APSC staff also recommended future generating facility retirements be treated similar to the Dolet Hills Power Station recommendation of recovery with no debt or equity return. Also, an intervenor recommended no debt or equity return on the Pirkey Power Plant after its retirement, which is currently expected to be in 2023. SWEPCo filed rebuttal testimony in January 2022 revising the requested annual increase in Arkansas base rates to $81 million with rates to be effective in June 2022. A hearing will be held at the APSC in March 2022. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
2021 Louisiana Storm Cost Filing
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.
February 2021 Severe Winter Weather Impacts in SPP
As discussed in the “PSO Rate Matters” section above, severe winter weather had a significant impact in SPP, resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system. For the time period of February 9, 2021, to February 20, 2021, SWEPCo’s natural gas expenses and purchases of electricity still to be recovered from customers are $430 million as of December 31, 2021, of which $103 million, $148 million and $179 million is related to the Arkansas, Louisiana and Texas jurisdictions, respectively.
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.
FERC Rate Matters
FERC SPP Transmission Formula Rate Challenge (Applies to AEP, AEPTCo, PSO and SWEPCo)
In May 2021, certain joint customers submitted a formal challenge at the FERC related to the 2020 Annual Update of the 2019 SPP Transmission Formula Rates of the AEP transmission owning subsidiaries within SPP. Management has reviewed the formal challenge and responses were filed with the FERC in 2021. If the FERC orders revenue refunds or reductions, it could reduce future net income and cash flows and impact financial condition.
Independence Energy Connection Project (Applies to AEP)
In 2016, PJM approved the Independence Energy Connection Project (IEC) and included it in its Regional Transmission Expansion Plan to alleviate congestion. Transource Energy owns the IEC, which is located in Maryland and Pennsylvania. In June 2020, the Maryland Public Service Commission approved a Certificate of Public Convenience and Necessity to construct the portion of the IEC in Maryland. In May 2021, the Pennsylvania Public Utility Commission (PA PUC) denied the IEC certificate for siting and construction of the portion in Pennsylvania. Transource Energy has appealed the PA PUC ruling in Pennsylvania state court and challenged the ruling before the United States District Court for the Middle District of Pennsylvania. The case before the state court is pending and the case before the United States District Court for the Middle District of Pennsylvania is currently suspended, pending the outcome of the case in the Pennsylvania state court.
In September 2021, PJM notified Transource Energy that the IEC was suspended to allow for the regulatory and related appeals process to proceed in an orderly manner without breaching milestone dates in the project agreement. PJM stated that the IEC has not been cancelled and remains necessary to alleviate congestion. As of December 31, 2021, AEP’s share of IEC capital expenditures was approximately $81 million. The FERC has previously granted abandonment benefits for this project, allowing the full recovery of prudently incurred costs if the project is cancelled for reasons outside the control of Transource Energy. If any of the IEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
5. EFFECTS OF REGULATION
The disclosures in this note apply to all Registrants unless indicated otherwise.
Coal-Fired Generation Plants (Applies to AEP, PSO and SWEPCo)
Compliance with extensive environmental regulations requires significant capital investment in environmental monitoring, installation of pollution control equipment, emission fees, disposal costs and permits. Management continuously evaluates cost estimates of complying with these regulations which has resulted in, and in the future may result in, a decision to retire coal-fired generating facilities earlier than their currently estimated useful lives.
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 and cash flows and impact financial condition.
Regulated Generating Units that have been Retired
PSO
The Oklaunion Power Station was retired in September 2020 and sold to a nonaffiliated third-party in October 2020. As part of the 2021 Oklahoma Base Rate Case, PSO received approval from the OCC to recover the Oklaunion Power Station as a regulatory asset through 2046. See “2021 Oklahoma Base Rate Case” section of Note 4 for additional information.
SWEPCo
In April 2016, Welsh Plant, Unit 2 was retired. As part of the 2016 Texas Base Rate Case, the PUCT authorized recovery of SWEPCo’s Texas jurisdictional share of Welsh Plant, Unit 2, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $7 million in 2017. See “2016 Texas Base Rate Case” section of Note 4 for additional information. As part of the 2019 Arkansas Base Rate Case, SWEPCo received approval from the APSC to recover the Arkansas jurisdictional share of Welsh Plant, Unit 2. In December 2020, SWEPCo filed a request with the LPSC to recover the Louisiana jurisdictional share of Welsh Plant, Unit 2. See “2020 Louisiana Base Rate Case” section of Note 4 for additional information. As of December 31, 2021, SWEPCo has a regulatory asset for plant retirement costs pending approval recorded on its balance sheet of $35 million related to the Louisiana jurisdictional share of Welsh Plant, Unit 2.
In December 2021, the Dolet Hills Power Station was retired. As part of the 2020 Texas Base Rate Case, the PUCT authorized recovery of SWEPCo’s Texas jurisdictional share of the Dolet Hills Power Station, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $12 million in December 2021. SWEPCo has also requested recovery of the Dolet Hills Power Station in the Arkansas and Louisiana jurisdictions through base rate cases. See “2020 Texas Base Rate Case”, “2020 Louisiana Base Rate Case” and “2021 Arkansas Base Rate Case” sections of Note 4 for additional information. The Dolet Hills Power Station is currently being recovered through 2026 in the Louisiana jurisdiction and through 2046 in the Arkansas and Texas jurisdictions. As of December 31, 2021, SWEPCo has a regulatory asset for the Dolet Hills Power Station pending approval recorded on its balance sheet of $72 million related to the Arkansas and Louisiana jurisdictional shares.
Regulated Generating Units to be Retired
PSO
In 2014, PSO received final approval from the Federal EPA to close Northeastern Plant, Unit 3, in 2026. The plant was originally scheduled to close in 2040. As a result of the early retirement date, PSO revised the useful life of Northeastern Plant, Unit 3, to the projected retirement date of 2026 and the incremental depreciation is being deferred as a regulatory asset. As part of the 2021 Oklahoma Base Rate Case, PSO will continue to recover Northeastern Plant, Unit 3 through 2040. See “2021 Oklahoma Base Rate Case” section of Note 4 for additional information.
SWEPCo
In November 2020, management announced plans to retire Pirkey Power Plant in 2023 and that it will cease using coal at the Welsh Plant in 2028. As a result of the announcement, SWEPCo began recording a regulatory asset for accelerated depreciation.
The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of December 31, 2021, of generating facilities planned for early retirement:
Plant Net Book Value Accelerated Depreciation Regulatory Asset Cost of Removal
Regulatory Liability Projected
Retirement Date Current Authorized
Recovery Period Annual
Depreciation (a)
(dollars in millions)
Northeastern Plant, Unit 3 $ 167.2 $ 128.1 $ 20.0 (b) 2026 (c) $ 14.9
Pirkey Power Plant 120.0 87.0 39.3 2023 (d) 13.5
Welsh Plant, Units 1 and 3 475.2 45.9 58.4 (e) 2028 (f) 36.4
(a)Represents the amount of annual depreciation that has been collected from customers over the prior 12-month period.
(b)Includes Northeastern Plant, Unit 4, which was retired in 2016. Removal of Northeastern Plant, Unit 4, will be performed with Northeastern Plant, Unit 3, after retirement.
(c)Northeastern Plant, Unit 3 is currently being recovered through 2040.
(d)Pirkey Power Plant is currently being recovered through 2025 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.
(e)Includes Welsh Plant, Unit 2, which was retired in 2016. Removal of Welsh Plant, Unit 2, will be performed with Welsh Plant, Units 1 and 3, after retirement.
(f)Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.
Dolet Hills Power Station and Related Fuel Operations (Applies to AEP and SWEPCo)
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.
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” below 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 (Applies to AEP and SWEPCo)
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.
2020 Texas Fuel Reconciliation (Applies to AEP and SWEPCo)
In June 2020, SWEPCo filed a fuel reconciliation with the PUCT for its retail operations in Texas for the reconciliation period of March 1, 2017 to December 31, 2019. The fuel reconciliation included total fuel costs of $1.7 billion ($616 million of which is related to the Texas jurisdiction). In January 2021, various parties filed testimony recommending fuel cost disallowances totaling $125 million relating to the Texas jurisdiction. Also in January 2021, SWEPCo filed rebuttal testimony disputing the recommended disallowances. In February 2021, SWEPCo and various parties reached a settlement in principle which resulted in a $10 million reduction in recoverable fuel costs for the reconciliation period, which was recognized in SWEPCo’s 2020 financial statements. In November 2021, the settlement was approved by the PUCT.
Regulatory Assets and Liabilities
Regulatory assets and liabilities are comprised of the following items:
AEP
December 31, Remaining Recovery Period
2021 (a) 2020
Current Regulatory Assets (in millions)
Under-recovered Fuel Costs - earns a return $ 409.4 $ 41.4 1 year
Under-recovered Fuel Costs - does not earn a return 175.7 49.3 1 year
Unrecovered Winter Storm Fuel Costs - earns a return (b) 62.7 - 1 year
Total Current Regulatory Assets $ 647.8 $ 90.7
Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:
Regulatory Assets Currently Earning a Return
Unrecovered Winter Storm Fuel Costs $ 367.5 $ -
Pirkey Power Plant Accelerated Depreciation 87.0 12.2
Dolet Hills Power Station Accelerated Depreciation 72.3 71.2
Welsh Plant, Units 1 and 3 Accelerated Depreciation 45.9 3.6
Plant Retirement Costs - Unrecovered Plant, Louisiana 35.2 35.2
Dolet Hills Power Station Fuel Costs - Louisiana 30.9 -
Kentucky Deferred Purchased Power Expenses - 41.3
Oklaunion Power Station Accelerated Depreciation - 34.4
Other Regulatory Assets Pending Final Regulatory Approval 9.2 22.8
Total Regulatory Assets Currently Earning a Return 648.0 220.7
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs 256.9 134.2
Plant Retirement Costs - Asset Retirement Obligation Costs 25.9 25.9
COVID-19 11.2 24.9
Other Regulatory Assets Pending Final Regulatory Approval 43.9 36.5
Total Regulatory Assets Currently Not Earning a Return 337.9 221.5
Total Regulatory Assets Pending Final Regulatory Approval 985.9 442.2
Regulatory assets approved for recovery:
Regulatory Assets Currently Earning a Return
Unrecovered Winter Storm Fuel Costs 679.3 - (c)
Plant Retirement Costs - Unrecovered Plant (d) 522.2 713.1 25 years
Rockport Plant Dry Sorbent Injection System and Selective Catalytic Reduction 66.6 34.4 7 years
Meter Replacement Costs 44.9 55.5 6 years
Ohio Distribution Decoupling 41.6 46.6 2 years
Environmental Control Projects 36.2 38.6 19 years
Cook Plant Uprate Project 27.7 30.2 12 years
Storm-Related Costs 17.4 11.5 3 years
Plant Retirement Costs - Asset Retirement Obligation Costs - 107.1
Other Regulatory Assets Approved for Recovery 99.2 94.4 various
Total Regulatory Assets Currently Earning a Return 1,535.1 1,131.4
Regulatory Assets Currently Not Earning a Return
Pension and OPEB Funded Status 677.0 1,088.6 12 years
Plant Retirement Costs - Asset Retirement Obligation Costs 293.2 212.7 21 years
Unamortized Loss on Reacquired Debt 111.2 120.0 27 years
Unrealized Loss on Forward Commitments 100.8 111.3 11 years
Plant Retirement Costs - Unrecovered Plant, Texas 51.9 16.1 25 years
Peak Demand Reduction/Energy Efficiency 40.8 27.0 5 years
Virginia Transmission Rate Adjustment Clause 37.2 18.8 2 years
Cook Plant Nuclear Refueling Outage Levelization 32.0 39.5 3 years
Texas Transmission Cost Recovery Factor 30.6 4.6 2 years
Vegetation Management 29.3 67.8 4 years
Postemployment Benefits 29.1 29.1 3 years
PJM/SPP Annual Formula Rate True-up 17.6 33.0 2 years
Fuel and Purchased Power Adjustment Rider 12.1 24.0 2 years
OVEC Purchased Power - 27.4
Other Regulatory Assets Approved for Recovery 158.5 133.5 various
Total Regulatory Assets Currently Not Earning a Return 1,621.3 1,953.4
Total Regulatory Assets Approved for Recovery 3,156.4 3,084.8
Total Noncurrent Regulatory Assets $ 4,142.3 $ 3,527.0
(a)2021 amounts exclude $485 million of regulatory assets classified as Assets Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
(b)Unrecovered Winter Storm Fuel Costs are pending final regulatory approval as of December 31, 2021. The current asset balance represents amounts expected to be recovered in the Arkansas and Louisiana jurisdictions over the next 12 months. See “February 2021 Severe Winter Weather Impacts in SPP” section of SWEPCo Rate Matters in Note 4 for additional information.
(c)In February 2022, the OCC approved PSO’s securitization of the Unrecovered Winter Storm Fuel Costs. The timing of securitization is to be determined. See ”February 2021 Severe Winter Weather Impacts in SPP” section of PSO Rate Matters in Note 4 for additional information.
(d)Northeastern Plant, Unit 3 is approved for recovery through 2040, but expected to retire in 2026. PSO records a regulatory asset for accelerated depreciation. See “Regulated Generating Units to be Retired” section above for additional information.
AEP
December 31, Remaining
2021 (a) 2020 Refund Period
Current Regulatory Liabilities (in millions)
Over-recovered Fuel Costs - pays a return $ - $ 27.6
Over-recovered Fuel Costs - does not pay a return 1.5 25.0 1 year
Total Current Regulatory Liabilities $ 1.5 $ 52.6
Noncurrent Regulatory Liabilities and
Deferred Investment Tax Credits
Regulatory liabilities pending final regulatory determination:
Regulatory Liabilities Currently Paying a Return
Other Regulatory Liabilities Pending Final Regulatory Determination $ - $ 2.5
Total Regulatory Liabilities Currently Paying a Return - 2.5
Regulatory Liabilities Currently Not Paying a Return
Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 1.5
Total Regulatory Liabilities Currently Not Paying a Return 0.2 1.5
Income Tax Related Regulatory Liabilities (b)
Excess ADIT Associated with Certain Depreciable Property - 291.6
Excess ADIT that is Not Subject to Rate Normalization Requirements (c) (d) 262.2 193.3
Total Income Tax Related Regulatory Liabilities 262.2 484.9
Total Regulatory Liabilities Pending Final Regulatory Determination 262.4 488.9
Regulatory liabilities approved for payment:
Regulatory Liabilities Currently Paying a Return
Asset Removal Costs 3,172.1 3,061.9 (e)
Deferred Investment Tax Credits 2.1 4.1 32 years
Other Regulatory Liabilities Approved for Payment 33.1 25.2 various
Total Regulatory Liabilities Currently Paying a Return 3,207.3 3,091.2
Regulatory Liabilities Currently Not Paying a Return
Excess Nuclear Decommissioning Funding 1,939.7 1,476.6 (f)
Deferred Investment Tax Credits 248.5 216.7 35 years
Spent Nuclear Fuel 49.5 43.1 (f)
PJM Transmission Enhancement Refund 42.9 56.2 4 years
2017-2019 Virginia Triennial Revenue Provision 41.6 44.2 27 years
Unrealized Gain on Forward Commitments 37.2 11.7 3 years
Peak Demand Reduction/Energy Efficiency 28.6 26.3 2 years
Transition and Restoration Charges - Texas 26.3 48.2 8 years
Other Regulatory Liabilities Approved for Payment 90.9 82.9 various
Total Regulatory Liabilities Currently Not Paying a Return 2,505.2 2,005.9
Income Tax Related Regulatory Liabilities (b)
Excess ADIT Associated with Certain Depreciable Property 3,556.7 3,485.7 (g)
Excess ADIT that is Not Subject to Rate Normalization Requirements 386.5 714.9 7 years
Income Taxes Subject to Flow Through (1,231.8) (1,407.9) 52 years
Total Income Tax Related Regulatory Liabilities 2,711.4 2,792.7
Total Regulatory Liabilities Approved for Payment 8,423.9 7,889.8
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 8,686.3 $ 8,378.7
(a)2021 amounts exclude $148 million of regulatory liabilities classified as Liabilities Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
(b)Predominately pays a return due to the inclusion of Excess ADIT in rate base.
(c)2021 and 2020 amounts include approximately $173 million and $173 million, respectively, related to AEP Transmission Holdco’s investment in ETT and Transource Energy. AEP Transmission Holdco expects to amortize the balance commensurate with the return of Excess ADIT to ETT and Transource Energy’s customers.
(d)2021 amount includes $70 million for Excess ADIT as a result of changes in various state income tax rates. See the “Federal and State Tax Legislation” section of Note 12 for additional information.
(e)Relieved as removal costs are incurred.
(f)Relieved when plant is decommissioned.
(g)Refunded using ARAM.
AEP Texas
December 31, Remaining
Recovery
Period
Regulatory Assets: 2021 2020
(in millions)
Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:
Regulatory Assets Currently Earning a Return
Advanced Metering System $ - $ 16.3
Total Regulatory Assets Currently Earning a Return - 16.3
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs 22.4 0.8
Vegetation Management Program 5.2 3.8
Texas Retail Electric Provider Bad Debt Expense 4.1 -
COVID-19 2.1 10.5
Other Regulatory Assets Pending Final Regulatory Approval 7.4 1.5
Total Regulatory Assets Currently Not Earning a Return 41.2 16.6
Total Regulatory Assets Pending Final Regulatory Approval 41.2 32.9
Regulatory assets approved for recovery:
Regulatory Assets Currently Earning a Return
Meter Replacement Costs 22.7 29.3 5 years
Advanced Metering System 10.6 - 1 year
Other Regulatory Assets Approved for Recovery 2.1 - various
Total Regulatory Assets Currently Earning a Return 35.4 29.3
Regulatory Assets Currently Not Earning a Return
Pension and OPEB Funded Status 119.0 145.0 12 years
Texas Transmission Cost Recovery Factor 30.6 4.6 2 years
Vegetation Management Program 17.4 22.4 4 years
Peak Demand Reduction/Energy Efficiency 14.5 7.7 2 years
Storm-Related Costs 12.8 17.1 3 years
Other Regulatory Assets Approved for Recovery 4.3 7.8 various
Total Regulatory Assets Currently Not Earning a Return 198.6 204.6
Total Regulatory Assets Approved for Recovery 234.0 233.9
Total Noncurrent Regulatory Assets $ 275.2 $ 266.8
AEP Texas
December 31, Remaining
Refund
Period
Regulatory Liabilities: 2021 2020
(in millions)
Noncurrent Regulatory Liabilities and
Deferred Investment Tax Credits
Regulatory liabilities pending final regulatory determination:
Regulatory Liabilities Currently Paying a Return
Other Regulatory Liabilities Pending Final Regulatory Determination $ - $ 2.5
Total Regulatory Liabilities Currently Paying a Return - 2.5
Income Tax Related Regulatory Liabilities (a)
Excess ADIT that is Not Subject to Rate Normalization Requirements 13.0 (8.2)
Total Income Tax Related Regulatory Liabilities 13.0 (8.2)
Total Regulatory Liabilities Pending Final Regulatory Determination 13.0 (5.7)
Regulatory liabilities approved for payment:
Regulatory Liabilities Currently Paying a Return
Asset Removal Costs 744.7 718.3 (b)
Other Regulatory Liabilities Approved for Payment 4.8 5.3 various
Total Regulatory Liabilities Currently Paying a Return 749.5 723.6
Regulatory Liabilities Currently Not Paying a Return
Transition and Restoration Charges 26.3 48.2 8 years
Deferred Investment Tax Credits 6.8 8.5 12 years
Other Regulatory Liabilities Approved for Payment 1.1 1.2 various
Total Regulatory Liabilities Currently Not Paying a Return 34.2 57.9
Income Tax Related Regulatory Liabilities (a)
Excess ADIT Associated with Certain Depreciable Property 498.8 506.0 (c)
Excess ADIT that is Not Subject to Rate Normalization Requirements - 41.7
Income Taxes Subject to Flow Through (53.5) (52.7) 35 years
Total Income Tax Related Regulatory Liabilities 445.3 495.0
Total Regulatory Liabilities Approved for Payment 1,229.0 1,276.5
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,242.0 $ 1,270.8
(a)Predominately pays a return due to the inclusion of Excess ADIT in rate base.
(b)Relieved as removal costs are incurred.
(c)Refunded using ARAM.
AEPTCo
December 31, Remaining
Recovery
Period
Regulatory Assets: 2021 2020
(in millions)
Noncurrent Regulatory Assets
Regulatory assets approved for recovery:
Regulatory Assets Currently Not Earning a Return
PJM/SPP Annual Formula Rate True-up $ 8.5 $ 15.1 2 years
Total Regulatory Assets Approved for Recovery 8.5 15.1
Total Noncurrent Regulatory Assets $ 8.5 $ 15.1
AEPTCo
December 31, Remaining
Refund
Period
Regulatory Liabilities: 2021 (a) 2020
(in millions)
Noncurrent Regulatory Liabilities
Regulatory liabilities pending final regulatory determination:
Income Tax Related Regulatory Liabilities (b)
Excess ADIT that is Not Subject to Rate Normalization Requirements (c) $ 8.7 $ -
Total Regulatory Liabilities Pending Final Regulatory Determination 8.7 -
Regulatory liabilities approved for payment:
Regulatory Liabilities Currently Paying a Return
Asset Removal Costs 271.4 198.6 (d)
Total Regulatory Liabilities Currently Paying a Return 271.4 198.6
Income Tax Related Regulatory Liabilities (b)
Excess ADIT Associated with Certain Depreciable Property 522.6 531.5 (e)
Excess ADIT that is Not Subject to Rate Normalization Requirements (26.2) (30.6) 7 years
Income Taxes Subject to Flow Through (132.4) (117.7) 36 years
Total Income Tax Related Regulatory Liabilities 364.0 383.2
Total Regulatory Liabilities Approved for Payment 635.4 581.8
Total Noncurrent Regulatory Liabilities $ 644.1 $ 581.8
(a)2021 amounts exclude $8 million of regulatory liabilities classified as Liabilities Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
(b)Predominately pays a return due to the inclusion of Excess ADIT in rate base.
(c)Amount represents regulatory liabilities for Excess ADIT as a result of changes in various state income tax rates. See the “Federal and State Tax Legislation” section of Note 12 for additional information.
(d)Relieved as removal costs are incurred.
(e)Refunded using ARAM.
APCo
December 31, Remaining
Recovery
Period
Regulatory Assets: 2021 2020
(in millions)
Current Regulatory Assets
Under-recovered Fuel Costs - earns a return $ 127.2 $ 3.3 1 year
Under-recovered Fuel Costs - does not earn a return 74.1 2.0 1 year
Total Current Regulatory Assets $ 201.3 $ 5.3
Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:
Regulatory Assets Currently Earning a Return
COVID-19 - Virginia $ 6.8 $ 3.7
Total Regulatory Assets Currently Earning a Return 6.8 3.7
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs 68.8 3.4
Plant Retirement Costs - Asset Retirement Obligation Costs 25.9 25.9
Environmental Expense Deferral - Virginia - 9.3
Other Regulatory Assets Pending Final Regulatory Approval 3.6 1.5
Total Regulatory Assets Currently Not Earning a Return 98.3 40.1
Total Regulatory Assets Pending Final Regulatory Approval 105.1 43.8
Regulatory assets approved for recovery:
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant 110.0 122.4 22 years
Other Regulatory Assets Approved for Recovery 0.4 1.0 various
Total Regulatory Assets Currently Earning a Return 110.4 123.4
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs - Asset Retirement Obligation Costs 293.1 202.7 15 years
Unamortized Loss on Reacquired Debt 78.2 82.1 24 years
Pension and OPEB Funded Status 62.7 114.4 12 years
Virginia Transmission Rate Adjustment Clause 37.2 18.8 2 years
Peak Demand Reduction/Energy Efficiency 17.8 16.8 5 years
Environmental Compliance Costs 13.7 - 2 years
Postemployment Benefits 13.3 13.5 3 years
Vegetation Management Program - West Virginia 11.9 45.4 2 years
PJM Annual Formula Rate True-up 3.5 12.7 2 years
Other Regulatory Assets Approved for Recovery 10.7 12.7 various
Total Regulatory Assets Currently Not Earning a Return 542.1 519.1
Total Regulatory Assets Approved for Recovery 652.5 642.5
Total Noncurrent Regulatory Assets $ 757.6 $ 686.3
APCo
December 31, Remaining
Refund
Period
Regulatory Liabilities: 2021 2020
(in millions)
Noncurrent Regulatory Liabilities and
Deferred Investment Tax Credits
Regulatory liabilities pending final regulatory determination:
Income Tax Related Regulatory Liabilities (a)
Excess ADIT that is Not Subject to Rate Normalization Requirements (b) $ 4.5 $ -
Total Regulatory Liabilities Pending Final Regulatory Determination 4.5 -
Regulatory liabilities approved for payment:
Regulatory Liabilities Currently Paying a Return
Asset Removal Costs 703.3 678.9 (c)
Deferred Investment Tax Credits 0.3 0.3 32 years
Total Regulatory Liabilities Currently Paying a Return 703.6 679.2
Regulatory Liabilities Currently Not Paying a Return
2017-2019 Virginia Triennial Revenue Provision 41.6 44.2 27 years
Unrealized Gain on Forward Commitments 28.2 5.5 3 years
PJM Transmission Enhancement Refund 13.0 16.3 4 years
Other Regulatory Liabilities Approved for Payment 15.0 6.8 various
Total Regulatory Liabilities Currently Not Paying a Return 97.8 72.8
Income Tax Related Regulatory Liabilities (a)
Excess ADIT Associated with Certain Depreciable Property 663.6 690.0 (d)
Excess ADIT that is Not Subject to Rate Normalization Requirements 83.6 139.1 7 years
Income Taxes Subject to Flow Through (314.3) (356.4) 23 years
Total Income Tax Related Regulatory Liabilities 432.9 472.7
Total Regulatory Liabilities Approved for Payment 1,234.3 1,224.7
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
$ 1,238.8 $ 1,224.7
(a)Predominately pays a return due to the inclusion of Excess ADIT in rate base.
(b)Amount represents regulatory liabilities for Excess ADIT as a result of a change in the state income tax apportionment formula in West Virginia. See the “Federal and State Tax Legislation” section of Note 12 for additional information.
(c)Relieved as removal costs are incurred.
(d)Refunded using ARAM.
I&M
December 31, Remaining
Recovery
Period
Regulatory Assets: 2021 2020
(in millions)
Current Regulatory Assets
Under-recovered Fuel Costs, Michigan - earns a return $ 6.4 $ 5.4 1 year
Total Current Regulatory Assets $ 6.4 $ 5.4
Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:
Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval $ 0.1 $ 0.5
Total Regulatory Assets Currently Earning a Return 0.1 0.5
Regulatory Assets Currently Not Earning a Return
COVID-19 1.7 3.8
Other Regulatory Assets Pending Final Regulatory Approval 1.9 -
Total Regulatory Assets Currently Not Earning a Return (a) 3.6 3.8
Total Regulatory Assets Pending Final Regulatory Approval 3.7 4.3
Regulatory assets approved for recovery:
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant 170.8 191.5 7 years
Rockport Plant Dry Sorbent Injection System and Selective Catalytic Reduction 66.6 34.4 7 years
Cook Plant Uprate Project 27.7 30.2 12 years
Deferred Cook Plant Life Cycle Management Project Costs 13.1 14.1 13 years
Cook Plant Turbine 9.7 11.1 17 years
Cook Plant Study Costs - Indiana 9.4 10.1 14 years
Other Regulatory Assets Approved for Recovery 6.0 7.0 various
Total Regulatory Assets Currently Earning a Return 303.3 298.4
Regulatory Assets Currently Not Earning a Return
Cook Plant Nuclear Refueling Outage Levelization 32.0 39.5 3 years
PJM Costs and Off-system Sales Margin Sharing - Indiana 15.1 - 2 years
Unamortized Loss on Reacquired Debt 14.2 15.7 27 years
Storm-Related Costs - Indiana 12.6 0.3 2 years
Postemployment Benefits 9.0 4.9 3 years
Unrealized Loss on Forward Commitments 7.2 - 3 years
Pension and OPEB Funded Status - 25.7
Other Regulatory Assets Approved for Recovery 13.8 16.0 various
Total Regulatory Assets Currently Not Earning a Return 103.9 102.1
Total Regulatory Assets Approved for Recovery 407.2 400.5
Total Noncurrent Regulatory Assets $ 410.9 $ 404.8
(a)In February 2022, the IURC issued an order approving Indiana jurisdictional COVID-19 costs and certain other regulatory assets totaling $3 million. See “2021 Indiana Base Rate Case” section of Note 4 for additional information.
I&M
December 31, Remaining
Refund
Period
Regulatory Liabilities: 2021 2020
(in millions)
Current Regulatory Liabilities
Over-recovered Fuel Costs, Indiana - does not pay a return $ 1.5 $ 20.8 1 year
Total Current Regulatory Liabilities $ 1.5 $ 20.8
Noncurrent Regulatory Liabilities and
Deferred Investment Tax Credits
Regulatory liabilities approved for payment:
Regulatory Liabilities Currently Paying a Return
Asset Removal Costs $ 179.7 $ 168.2 (a)
Other Regulatory Liabilities Approved for Payment 21.9 17.4 various
Total Regulatory Liabilities Currently Paying a Return 201.6 185.6
Regulatory Liabilities Currently Not Paying a Return
Excess Nuclear Decommissioning Funding 1,939.7 1,476.6 (b)
Spent Nuclear Fuel 49.5 43.1 (b)
Pension OPEB Funded Status 27.6 - 12 years
Deferred Investment Tax Credits 22.4 21.3 29 years
Rockport Plant, Unit 2 Selective Catalytic Reduction 10.6 8.9 2 years
PJM Transmission Enhancement Refund 7.9 9.9 4 years
PJM Costs and Off-system Sales Margin Sharing - Indiana - 13.3
Other Regulatory Liabilities Approved for Payment 6.0 28.4 various
Total Regulatory Liabilities Currently Not Paying a Return 2,063.7 1,601.5
Income Tax Related Regulatory Liabilities (c)
Excess ADIT Associated with Certain Depreciable Property 433.6 450.6 (d)
Excess ADIT that is Not Subject to Rate Normalization Requirements 90.2 136.2 3 years
Income Taxes Subject to Flow Through (341.2) (332.0) 20 years
Total Income Tax Related Regulatory Liabilities 182.6 254.8
Total Regulatory Liabilities Approved for Payment 2,447.9 2,041.9
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 2,447.9 $ 2,041.9
(a)Relieved as removal costs are incurred.
(b)Relieved when plant is decommissioned.
(c)Predominately pays a return due to the inclusion of Excess ADIT in rate base.
(d)Refunded using ARAM.
OPCo
December 31, Remaining
Recovery
Period
Regulatory Assets: 2021 2020
(in millions)
Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs $ 3.8 $ 4.0
COVID-19 - 4.4
Total Regulatory Assets Pending Final Regulatory Approval 3.8 8.4
Regulatory assets approved for recovery:
Regulatory Assets Currently Earning a Return
Ohio Distribution Decoupling 41.6 46.6 2 years
Ohio Economic Development Rider 10.1 1.3 2 years
Ohio Basic Transmission Cost Rider 5.2 12.3 2 years
Total Regulatory Assets Currently Earning a Return 56.9 60.2
Regulatory Assets Currently Not Earning a Return
Unrealized Loss on Forward Commitments 92.1 110.0 11 years
Pension and OPEB Funded Status 83.3 130.7 12 years
Smart Grid Costs 19.3 19.2 2 years
Ohio Enhanced Service Reliability Plan 9.5 - 2 years
PJM Load Service Entity Formula Rate True-up 7.5 - 2 years
Postemployment Benefits 6.2 6.7 3 years
Distribution Investment Rider 2.1 7.4 2 years
OVEC Purchased Power - 27.4
Other Regulatory Assets Approved for Recovery 12.3 15.8 various
Total Regulatory Assets Currently Not Earning a Return 232.3 317.2
Total Regulatory Assets Approved for Recovery 289.2 377.4
Total Noncurrent Regulatory Assets $ 293.0 $ 385.8
OPCo
December 31, Remaining
Refund
Period
2021 2020
Regulatory Liabilities: (in millions)
Current Regulatory Liabilities
Over-recovered Fuel Costs - does not pay a return $ - $ 3.9
Total Current Regulatory Liabilities $ - $ 3.9
Noncurrent Regulatory Liabilities and
Deferred Investment Tax Credits
Regulatory liabilities pending final regulatory determination:
Regulatory Liabilities Currently Not Paying a Return
Other Regulatory Liabilities Pending Final Regulatory Determination $ 0.2 $ 0.2
Total Regulatory Liabilities Pending Final Regulatory Determination 0.2 0.2
Regulatory liabilities approved for payment:
Regulatory Liabilities Currently Paying a Return
Asset Removal Costs 467.6 458.4 (a)
Total Regulatory Liabilities Currently Paying a Return 467.6 458.4
Regulatory Liabilities Currently Not Paying a Return
Peak Demand Reduction/Energy Efficiency 22.5 19.9 2 years
PJM Transmission Enhancement Refund 19.6 24.5 4 years
Over-recovered Fuel Costs 15.2 - 11 years
OVEC Purchased Power 14.8 - 2 years
Ohio Enhanced Service Reliability Plan - 5.7
Other Regulatory Liabilities Approved for Payment 0.4 0.7 various
Total Regulatory Liabilities Currently Not Paying a Return 72.5 50.8
Income Tax Related Regulatory Liabilities (b)
Excess ADIT Associated with Certain Depreciable Property 325.0 334.6 (c)
Excess ADIT that is Not Subject to Rate Normalization Requirements 190.8 223.9 7 years
Income Taxes Subject to Flow Through (35.2) (62.7) 30 years
Total Income Tax Related Regulatory Liabilities 480.6 495.8
Total Regulatory Liabilities Approved for Payment 1,020.7 1,005.0
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
$ 1,020.9 $ 1,005.2
(a)Relieved as removal costs are incurred.
(b)Predominately pays a return due to the inclusion of Excess ADIT in rate base.
(c)Refunded using ARAM.
PSO
December 31, Remaining
Recovery
Period
2021 2020
Regulatory Assets: (in millions)
Current Regulatory Assets
Under-recovered Fuel Costs - earns a return $ 194.6 $ 30.1 1 year
Total Current Regulatory Assets $ 194.6 $ 30.1
Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:
Regulatory Assets Currently Earning a Return
Oklaunion Power Station Accelerated Depreciation $ - $ 34.4
Total Regulatory Assets Currently Earning a Return - 34.4
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs 13.9 15.8
COVID-19 0.3 0.3
Total Regulatory Assets Currently Not Earning a Return 14.2 16.1
Total Regulatory Assets Pending Final Regulatory Approval 14.2 50.5
Regulatory assets approved for recovery:
Regulatory Assets Currently Earning a Return
Unrecovered Winter Storm Fuel Costs 679.3 - (a)
Plant Retirement Costs - Unrecovered Plant (b) 227.6 180.8 25 years
Environmental Control Projects 25.2 26.5 19 years
Meter Replacement Costs 22.2 26.2 6 years
Storm-Related Costs 17.4 11.5 3 years
Red Rock Generating Facility 7.9 8.2 35 years
Other Regulatory Assets Approved for Recovery 1.9 0.5 various
Total Regulatory Assets Currently Earning a Return 981.5 253.7
Regulatory Assets Currently Not Earning a Return
Pension and OPEB Funded Status 22.9 52.3 12 years
Unamortized Loss on Reacquired Debt 5.7 6.1 17 years
Other Regulatory Assets Approved for Recovery 13.1 12.4 various
Total Regulatory Assets Currently Not Earning a Return 41.7 70.8
Total Regulatory Assets Approved for Recovery 1,023.2 324.5
Total Noncurrent Regulatory Assets $ 1,037.4 $ 375.0
(a)In February 2022, the OCC approved PSO’s securitization of the Unrecovered Winter Storm Fuel Costs. The timing of securitization is to be determined. See ”February 2021 Severe Winter Weather Impacts in SPP” section of PSO Rate Matters in Note 4 for additional information.
(b)Northeastern Plant, Unit 3 is approved for recovery through 2040, but expected to retire in 2026. PSO records a regulatory asset for accelerated depreciation. See “Regulated Generating Units to be Retired” section above for additional information.
PSO
December 31, Remaining
Refund
Period
2021 2020
Regulatory Liabilities: (in millions)
Noncurrent Regulatory Liabilities and
Deferred Investment Tax Credits
Regulatory liabilities pending final regulatory determination:
Income Tax Related Regulatory Liabilities (a)
Excess ADIT that is Not Subject to Rate Normalization Requirements (b) $ 56.2 $ -
Total Regulatory Liabilities Pending Final Regulatory Determination $ 56.2 $ -
Regulatory liabilities approved for payment:
Regulatory Liabilities Currently Paying a Return
Asset Removal Costs $ 300.2 $ 289.9 (c)
Total Regulatory Liabilities Currently Paying a Return 300.2 289.9
Regulatory Liabilities Currently Not Paying a Return
Deferred Investment Tax Credits 50.8 51.0 23 years
Other Regulatory Liabilities Approved for Payment 4.3 1.3 various
Total Regulatory Liabilities Currently Not Paying a Return 55.1 52.3
Income Tax Related Regulatory Liabilities (a)
Excess ADIT Associated with Certain Depreciable Property 389.3 397.0 (d)
Excess ADIT that is Not Subject to Rate Normalization Requirements 46.4 71.3 3 years
Income Taxes Subject to Flow Through (11.9) (8.3) 28 years
Total Income Tax Related Regulatory Liabilities 423.8 460.0
Total Regulatory Liabilities Approved for Payment 779.1 802.2
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
$ 835.3 $ 802.2
(a)Predominately pays a return due to the inclusion of Excess ADIT in rate base.
(b)Amount represents regulatory liabilities for Excess ADIT as a result of a change in the state income tax rate. See the “Federal and State Tax Legislation” section of Note 12 for additional information.
(c)Relieved as removal costs are incurred.
(d)Refunded using ARAM.
SWEPCo
December 31, Remaining
Recovery
Period
2021 2020
Regulatory Assets: (in millions)
Current Regulatory Assets
Under-recovered Fuel Costs - earns a return (a) $ 81.2 $ 2.6 1 year
Unrecovered Winter Storm Fuel Costs - earns a return (b) 62.7 - 1 year
Total Current Regulatory Assets $ 143.9 $ 2.6
Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:
Regulatory Assets Currently Earning a Return
Unrecovered Winter Storm Fuel Costs $ 367.5 $ -
Pirkey Power Plant Accelerated Depreciation 87.0 12.2
Dolet Hills Power Station Accelerated Depreciation (c) 72.3 71.2
Welsh Plant, Units 1 and 3 Accelerated Depreciation 45.9 3.6
Plant Retirement Costs - Unrecovered Plant, Louisiana 35.2 35.2
Dolet Hills Power Station Fuel Costs - Louisiana 30.9 -
Other Regulatory Assets Pending Final Regulatory Approval 2.4 2.2
Total Regulatory Assets Currently Earning a Return 641.2 124.4
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs 148.0 99.3
Asset Retirement Obligation - Louisiana 10.3 9.1
Other Regulatory Assets Pending Final Regulatory Approval 18.4 14.5
Total Regulatory Assets Currently Not Earning a Return 176.7 122.9
Total Regulatory Assets Pending Final Regulatory Approval 817.9 247.3
Regulatory assets approved for recovery:
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant, Arkansas 13.7 14.4 21 years
Environmental Controls Projects 11.0 12.1 11 years
Other Regulatory Assets Approved for Recovery 5.2 7.1 various
Total Regulatory Assets Currently Earning a Return 29.9 33.6
Regulatory Assets Currently Not Earning a Return
Pension and OPEB Funded Status 73.8 89.1 12 years
Plant Retirement Costs - Unrecovered Plant, Texas 51.9 16.1 25 years
Dolet Hills Power Station Fuel Costs - Arkansas 13.0 - 5 years
Other Regulatory Assets Approved for Recovery 18.8 17.0 various
Total Regulatory Assets Currently Not Earning a Return 157.5 122.2
Total Regulatory Assets Approved for Recovery 187.4 155.8
Total Noncurrent Regulatory Assets $ 1,005.3 $ 403.1
(a)2021 amount includes Arkansas, Louisiana and Texas jurisdictions. 2020 amount includes Louisiana jurisdiction.
(b)Unrecovered Winter Storm Fuel Costs are pending final regulatory approval as of December 31, 2021. The current asset balance represents amounts expected to be recovered in the Arkansas and Louisiana jurisdictions over the next 12 months. See “February 2021 Severe Winter Weather Impacts in SPP” section of SWEPCo Rate Matters in Note 4 for additional information.
(c)2021 amount includes Arkansas and Louisiana jurisdictions. 2020 amount includes Arkansas, Louisiana and Texas jurisdictions.
SWEPCo
December 31, Remaining
Refund
Period
2021 2020
Regulatory Liabilities: (in millions)
Current Regulatory Liabilities
Over-recovered Fuel Costs - pays a return (a) $ - $ 37.6
Total Current Regulatory Liabilities $ - $ 37.6
Noncurrent Regulatory Liabilities and
Deferred Investment Tax Credits
Regulatory liabilities pending final regulatory determination:
Income Tax Related Regulatory Liabilities (b)
Excess ADIT Associated with Certain Depreciable Property $ - $ 291.6
Excess ADIT that is Not Subject to Rate Normalization Requirements - 21.8
Total Regulatory Liabilities Pending Final Regulatory Determination - 313.4
Regulatory liabilities approved for payment:
Regulatory Liabilities Currently Paying a Return
Asset Removal Costs 461.3 470.9 (c)
Other Regulatory Liabilities Approved for Payment 2.4 2.4 various
Total Regulatory Liabilities Currently Paying a Return 463.7 473.3
Regulatory Liabilities Currently Not Paying a Return
Vegetation Management Costs - Texas 4.8 0.1 2 years
Unrealized Gains on Forward Commitments 3.7 0.2 2 years
Peak Demand Reduction/Energy Efficiency 2.6 5.2 2 years
Other Regulatory Liabilities Approved for Payment 1.9 2.7 various
Total Regulatory Liabilities Currently Not Paying a Return 13.0 8.2
Income Tax Related Regulatory Liabilities (b)
Excess ADIT Associated with Certain Depreciable Property 609.0 332.5 (d)
Excess ADIT that is Not Subject to Rate Normalization Requirements 7.0 11.5 1 year
Income Taxes Subject to Flow Through (285.8) (275.5) 27 years
Total Income Tax Related Regulatory Liabilities 330.2 68.5
Total Regulatory Liabilities Approved for Payment 806.9 550.0
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
$ 806.9 $ 863.4
(a)2020 amount includes Arkansas and Texas jurisdictions.
(b)Predominately pays a return due to the inclusion of Excess ADIT in rate base.
(c)Relieved as removal costs are incurred.
(d)Refunded using ARAM.
6. COMMITMENTS, GUARANTEES AND CONTINGENCIES
The disclosures in this note apply to all Registrants unless indicated otherwise.
The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants’ business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates.
For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements.
COMMITMENTS (Applies to all Registrants except AEP Texas and AEPTCo)
The AEP System has substantial commitments for fuel, energy and capacity contracts as part of the normal course of business. Certain contracts contain penalty provisions for early termination.
In accordance with the accounting guidance for “Commitments”, the following tables summarize the Registrants’ actual contractual commitments as of December 31, 2021:
Contractual Commitments - AEP Less Than
1 Year 2-3 Years 4-5 Years After
5 Years Total
(in millions)
Fuel Purchase Contracts (a)(b)(c) $ 706.4 $ 584.9 $ 167.8 $ 301.8 $ 1,760.9
Energy and Capacity Purchase Contracts 147.8 309.5 291.7 664.4 1,413.4
Total $ 854.2 $ 894.4 $ 459.5 $ 966.2 $ 3,174.3
Contractual Commitments - APCo Less Than
1 Year 2-3 Years 4-5 Years After
5 Years Total
(in millions)
Fuel Purchase Contracts (a)(c) $ 266.9 $ 171.8 $ 18.7 $ 18.4 $ 475.8
Energy and Capacity Purchase Contracts 40.4 81.8 80.4 150.0 352.6
Total $ 307.3 $ 253.6 $ 99.1 $ 168.4 $ 828.4
Contractual Commitments - I&M Less Than
1 Year 2-3 Years 4-5 Years After
5 Years Total
(in millions)
Fuel Purchase Contracts (a) $ 147.7 $ 245.7 $ 149.1 $ 283.3 $ 825.8
Energy and Capacity Purchase Contracts 167.2 212.6 203.3 305.9 889.0
Total $ 314.9 $ 458.3 $ 352.4 $ 589.2 $ 1,714.8
Contractual Commitments - OPCo Less Than
1 Year 2-3 Years 4-5 Years After
5 Years Total
(in millions)
Energy and Capacity Purchase Contracts $ 34.6 $ 69.1 $ 65.4 $ 180.0 $ 349.1
Contractual Commitments - PSO Less Than
1 Year 2-3 Years 4-5 Years After
5 Years Total
(in millions)
Fuel Purchase Contracts (a) $ 48.2 $ 23.0 $ - $ - $ 71.2
Energy and Capacity Purchase Contracts 32.2 67.3 67.9 125.9 293.3
Total $ 80.4 $ 90.3 $ 67.9 $ 125.9 $ 364.5
Contractual Commitments - SWEPCo Less Than
1 Year 2-3 Years 4-5 Years After
5 Years Total
(in millions)
Fuel Purchase Contracts (a) $ 158.8 $ 91.3 $ - $ - $ 250.1
Energy and Capacity Purchase Contracts 4.2 8.4 8.4 - 21.0
Total $ 163.0 $ 99.7 $ 8.4 $ - $ 271.1
(a)Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel.
(b)Includes $22 million of purchase fuel contracts for KPCo commitments that 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.
(c)In the first quarter of 2022, APCo entered into new fuel purchase contracts related to coal procurement. The new commitments were as follows: $95 million in less than 1 year, $449 million in 2-3 years and $96 million in 4-5 years. These commitments are not included in the tables above. All other new commitments in the first quarter of 2022 were immaterial.
GUARANTEES
Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third-parties unless specified below.
Letters of Credit (Applies to AEP and AEP Texas)
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 service reserves.
AEP has $4 billion and $1 billion revolving credit facilities due in March 2026 and 2023, respectively, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of December 31, 2021, no letters of credit were issued under the revolving credit facility.
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 were as follows:
Company Amount Maturity
(in millions)
AEP $ 168.5 January 2022 to December 2022
AEP Texas 2.2 July 2022
Guarantees of Equity Method Investees (Applies to AEP)
In 2019, AEP acquired Sempra Renewables LLC. The transaction resulted in the acquisition of a 50% ownership interest in five non-consolidated joint ventures and the acquisition of two tax equity partnerships. Parent has issued guarantees over the performance of the joint ventures. If a joint venture were to default on payments or
performance, Parent would be required to make payments on behalf of the joint venture. As of December 31, 2021, the maximum potential amount of future payments associated with these guarantees was $142 million, with the last guarantee expiring in December 2037. The non-contingent liability recorded associated with these guarantees was $28 million, with an additional $2 million expected credit loss liability for the contingent portion of the guarantees. Management considered historical losses, economic conditions, and reasonable and supportable forecasts in the calculation of the expected credit loss. As the joint ventures generate cash flows through PPAs, the measurement of the contingent portion of the guarantee liability is based upon assessments of the credit quality and default probabilities of the respective PPA counterparties. See “Acquisitions” section of Note 7 for additional information.
Indemnifications and Other Guarantees
Contracts
The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of December 31, 2021, there were no material liabilities recorded for any indemnifications.
AEPSC conducts power purchase-and-sale activity on behalf of APCo, I&M, KPCo and WPCo, who are jointly and severally liable for activity conducted on their behalf. AEPSC also conducts power purchase-and-sale activity on behalf of PSO and SWEPCo, who are jointly and severally liable for activity conducted on their behalf.
Lease Obligations
Certain Registrants lease equipment under master lease agreements. See “Master Lease Agreements” and “AEPRO Boat and Barge Leases” sections of Note 13 for additional information.
ENVIRONMENTAL CONTINGENCIES (Applies to All Registrants except AEPTCo)
The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation
By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and non-hazardous materials. The Registrants currently incur costs to dispose of these substances safely.
Superfund addresses clean-up of hazardous substances that are released to the environment. The Federal EPA administers the clean-up programs. Several states enacted similar laws. As of December 31, 2021, APCo, OPCo and SWEPCo are named as a Potentially Responsible Party (PRP) for one, three and one sites, respectively, by the Federal EPA for which alleged liability is unresolved. There are 11 additional sites for which APCo, I&M, KPCo, OPCo and SWEPCo received information requests which could lead to PRP designation. I&M has also been named potentially liable at three sites under state law. In those instances where a PRP or defendant has been named, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. Liability has been resolved for a number of sites with no significant effect on net income.
Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often non-hazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. As of December 31, 2021, management’s estimates do not anticipate material clean-up costs for identified Superfund sites.
NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M)
I&M owns and operates the two-unit 2,296 MW Cook Plant under licenses granted by the NRC. I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.
Decommissioning and Low-Level Waste Accumulation Disposal
The costs to decommission a nuclear plant are affected by NRC regulations and the SNF disposal program. Decommissioning costs are accrued over the service life of Cook Plant. The most recent decommissioning cost study was performed in 2021. According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste was $2.2 billion in 2021 non-discounted dollars, with additional ongoing costs of $7 million per year for post decommissioning storage of SNF and an eventual cost of $33 million for the subsequent decommissioning of the SNF storage facility, also in 2021 non-discounted dollars. I&M recovers estimated decommissioning costs for the Cook Plant in its rates. The amounts recovered in rates were $4 million, $4 million and $7 million for the years ended December 31, 2021, 2020 and 2019, respectively. Decommissioning costs recovered from customers are deposited in external trusts.
As of December 31, 2021 and 2020, the total decommissioning trust fund balances were $3.5 billion and $3 billion, respectively. Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from customers. The decommissioning costs (including unrealized gains and losses, interest and trust funds expenses) increase or decrease the recorded liability.
I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant. However, future net income and cash flows would be reduced and financial condition could be impacted if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered.
Spent Nuclear Fuel Disposal
The federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one-mill per KWh for fuel consumed after April 6, 1983 at the Cook Plant was collected from customers and remitted to the DOE through May 14, 2014. In May 2014, pursuant to court order from the U.S Court of Appeals for the District of Columbia Circuit, the DOE adjusted the fee to $0. As of December 31, 2021 and 2020, fees and related interest of $281 million and $281 million, respectively, for fuel consumed prior to April 7, 1983 were recorded as Long-term Debt and funds collected from customers along with related earnings totaling $329 million and $324 million, respectively, to pay the fee were recorded as part of Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program.
In 2011, I&M signed a settlement agreement with the federal government which permits I&M to make annual filings to recover certain SNF storage costs incurred as a result of the government’s delay in accepting SNF for permanent storage. Under the settlement agreement, I&M received $14 million, $24 million and $8 million in 2021, 2020 and 2019, respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2022. The proceeds reduced costs for dry cask storage. As of December 31, 2021 and 2020, I&M deferred $3 million and $14 million, respectively, in Prepayments and Other Current Assets and $21 million and $1 million, respectively, in Deferred Charges and Other Noncurrent Assets on the balance sheets for dry cask storage and related operation and maintenance costs for recovery under this agreement. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for additional information.
Nuclear Insurance
I&M carries nuclear property insurance of $2.7 billion to cover a nuclear incident at Cook Plant including coverage for decontamination and stabilization, as well as premature decommissioning caused by a nuclear incident. Insurance coverage for a nonnuclear property incident at Cook Plant is $500 million. Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage. I&M utilizes industry mutual insurers for the placement of this insurance coverage. Coverage from these industry mutual insurance programs require a contingent financial obligation of up to $42 million for I&M, which is assessable if the insurer’s financial resources would be inadequate to pay for industry losses.
The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public nuclear liability arising from a nuclear incident of $13.5 billion and applies to any incident at a licensed reactor in the U.S. Commercially available insurance, which must be carried for each licensed reactor, provides $450 million of primary coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $275 million per nuclear incident on Cook Plant’s reactors payable in annual installments of $41 million. The number of incidents for which payments could be required is not limited.
In the event of an incident of a catastrophic nature, I&M is covered for public nuclear liability for the first $450 million through commercially available insurance. The next level of liability coverage of up to $13.1 billion would be covered by claim premium assessments made under the Price-Anderson Act. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds, I&M would seek recovery of those amounts from customers through a rate increase. If recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition.
OPERATIONAL CONTINGENCIES
Insurance and Potential Losses
The Registrants maintain insurance coverage normal and customary for electric utilities, subject to various deductibles. The Registrants also maintain property and casualty insurance that may cover certain physical damage or third-party injuries caused by cyber security incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. The insurance programs also generally provide coverage against loss arising from certain claims made by third-parties and are in excess of retentions absorbed by the Registrants. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers. See “Nuclear Contingencies” section above for additional information.
Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cyber security incident or damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition.
Rockport Plant Litigation (Applies to AEP and I&M)
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.
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 “Rockport Lease section of Note 13 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.
Litigation Related to Ohio House Bill 6 (HB 6) (Applies to AEP and OPCo)
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.
7. ACQUISITIONS, ASSETS AND LIABILITIES HELD FOR SALE, DISPOSITIONS, AND IMPAIRMENTS
The disclosures in this note apply to AEP unless indicated otherwise.
ACQUISITIONS
Dry Lake Solar Project (Generation & Marketing Segment) (Applies to AEP)
In November 2020, AEP signed a Purchase and Sale Agreement with a nonaffiliate to acquire a 75% ownership interest in the entity that owns the 100 MW Dry Lake Solar Project (collectively referred to as Dry Lake) located in southern Nevada for approximately $114 million. In March 2021, AEP closed the transaction and the solar project was placed in-service in May 2021. Approximately $103 million of the purchase price was paid upon closing of the transaction and the remaining $11 million was paid when the project was placed in-service. In accordance with the accounting guidance for “Business Combinations,” management determined that the acquisition of Dry Lake represents an asset acquisition. Additionally, and in accordance with the accounting guidance for “Consolidation,” management concluded that Dry Lake is a VIE and that AEP is the primary beneficiary based on its power as managing member to direct the activities that most significantly impact Dry Lake’s economic performance. As the primary beneficiary of Dry Lake, AEP consolidates Dry Lake into its financial statements. As a result, to account for the initial consolidation of Dry Lake, management applied the acquisition method by allocating the purchase price based on the relative fair value of the assets acquired and noncontrolling interest assumed. The fair value of the primary assets acquired and the noncontrolling interest assumed was determined using the market approach. The key input assumptions were the transaction price paid for AEP’s interest in Dry Lake and recent third-party market transactions for similar solar generation facilities. See Note 17 - Variable Interest Entities and Equity Method Investments for additional information.
North Central Wind Energy Facilities (Vertically Integrated Utilities Segment) (Applies to AEP, PSO and SWEPCo)
In 2020, PSO and SWEPCo received regulatory approvals to acquire the NCWF, comprised of three Oklahoma wind facilities totaling 1,484 MWs, on a fixed cost turn-key basis at completion. PSO and SWEPCo will own undivided interests of 45.5% and 54.5% of the NCWF, respectively. In total, the three wind facilities will cost approximately $2 billion and consist of Traverse (998 MW), Maverick (287 MW) and Sundance (199 MW). Output from the NCWF will serve retail load in PSO’s Oklahoma service territory and both retail and FERC wholesale load in SWEPCo’s service territories in Arkansas and Louisiana. The Oklahoma and Louisiana portions of the NCWF revenue requirement, net of PTC benefit, are recoverable through authorized riders beginning at commercial operation and until such time as amounts are reflected in base rates. Recovery of the Arkansas portion of the NCWF revenue requirement is requested in SWEPCo’s pending 2021 Arkansas Base Rate Case. The NCWF are subject to various regulatory performance requirements. If these performance requirements are not met, PSO and SWEPCo would recognize a regulatory liability to refund retail customers. As of December 31, 2021 PSO and SWEPCo have not incurred a material regulatory liability related to performance requirements for NCWF.
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.
In accordance with the guidance for “Business Combinations,” management determined that the acquisitions of Sundance and Maverick represent asset acquisitions. 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. On an ongoing basis, management further determined that PSO and SWEPCo should apply the joint plant accounting model to account for their respective undivided interests in the assets, liabilities, revenues and expenses of Sundance and Maverick.
The Purchase and Sale Agreement (PSA) includes collective interests in numerous land contracts, as originally executed between the nonaffiliated party and the respective owners of the properties as defined in the contracts. These contracts provide for easement and access rights to the land that Sundance and Maverick were built upon. These interests as lessee in each of the land contracts were transferred to Sundance and Maverick (and subsequently to PSO and SWEPCo) as a part of the closing of the PSA. As of December 31, 2021, the Noncurrent Obligations Under Operating Leases for Sundance are $13 million and $15 million on the balance sheets for PSO and SWEPCo, respectively, and the Noncurrent Obligations Under Operating Leases for Maverick are $18 million and $22 million on the balance sheets for PSO and SWEPCo, respectively.
Desert Sky Wind Farm and Trent Wind Farm (Generation & Marketing Segment) (Applies to AEP)
In August 2020, AEP exercised its call right which required the nonaffiliated member of Desert Sky Wind Farm LLC and Trent Wind Farm LLC (collectively the LLCs) to sell its noncontrolling interest to AEP. The exercise price for the call right was determined using a discounted cash flow model with agreed input assumptions as well as updates to certain assumptions reasonably expected based on the actual results of the LLCs. As a result, the LLCs are wholly-owned by AEP and management has concluded that the LLCs are no longer VIEs. AEP paid $57 million in cash, derecognized $63 million of Redeemable Noncontrolling Interest within Mezzanine Equity and recorded an increase of $6 million of Paid-In Capital on the balance sheets. See Note 17 - Variable Interest Entities and Equity Method Investments for additional information.
Santa Rita East (Generation & Marketing Segment) (Applies to AEP)
In November 2020, AEP acquired an additional 10% interest in Santa Rita East for approximately $44 million resulting in AEP having a total interest of 85%. The acquisition of the incremental ownership interest was accounted for as an equity transaction in accordance with the accounting guidance for "Consolidation" and reduced Noncontrolling Interests on the balance sheets by approximately $44 million. See Note 17 - Variable Interest Entities and Equity Method Investments for additional information.
Sempra Renewables LLC (Generation & Marketing Segment) (Applies to AEP)
In April 2019, AEP acquired Sempra Renewables LLC and its ownership interests in 724 MWs of wind generation and battery assets valued at approximately $1.1 billion. This acquisition is part of AEP’s strategy to grow its renewable generation portfolio and to diversify generation resources. AEP paid $580 million in cash and acquired a 50% ownership interest in five non-consolidated joint ventures with net assets valued at $404 million as of the acquisition date (which includes $364 million of existing debt obligations). Additionally, the transaction included the acquisition of two tax equity partnerships and the associated recognition of noncontrolling tax equity interest of $135 million.
Purchase Price Allocation of Sempra Renewables LLC at Acquisition Date - April 22nd, 2019
Assets: Liabilities and Equity: Net Purchase Price
(in millions)
Current Assets $ 8.8 Current Liabilities $ 12.9
Property, Plant and Equipment 238.1 Asset Retirement Obligations 5.7
Investment in Joint Ventures 404.0 Total Liabilities 18.6
Other Noncurrent Assets 82.9 Noncontrolling Interest 134.8
Total Assets $ 733.8 Liabilities and Noncontrolling Interest $ 153.4 $ 580.4
Management allocated the purchase price based upon the fair value of the assets acquired and noncontrolling interests assumed. The fair value of the primary assets acquired and the noncontrolling interests assumed was determined using a discounted cash flow method under the income approach. The key input assumptions utilized in the determination of the fair value of these assets were the pricing and terms of the existing PPAs, forecasted market power prices, expected wind farm net capacity and discount rates reflecting risk inherent in the future cash flows and future power prices. Estimating forecasted market power prices involved determining the cost of constructing and operating a new wind plant over an assumed life in the same geographic region as of the acquisition date using third-party market participant assumptions. The expected wind farm net capacity was developed by evaluating each wind farm’s historical and expected generation against historical generation of comparable wind farms in the same locations. Discount rates were evaluated by considering the cost of capital of comparable businesses. Additional key input assumptions for the fair value of the noncontrolling interests include the terms of the limited liability company agreements that dictate the sharing of the tax attributes and cash flows associated with the tax equity partnerships.
Upon closing of the purchase, Sempra Renewables LLC was legally renamed AEP Wind Holdings LLC. AEP Wind Holdings LLC develops, owns and operates, or holds interests in wind generation facilities in the United States. The operating wind generation portfolio includes seven wind farms. Five wind farms are jointly-owned with BP Wind Energy, and two wind farms are consolidated by AEP and are tax equity partnerships with nonaffiliated noncontrolling interests. All seven wind farms have long-term PPAs for 100% of their energy production. The PPAs with I&M, OPCo and SWEPCo were executed prior to the acquisition of the wind farms and will be accounted for in accordance with the accounting guidance for “Related Parties.” See “Sempra Renewables LLC PPAs” section of Note 16 for additional information.
The acquired business contributed revenues and net income to AEP that were not material for the period April 22, 2019 to December 31, 2019. The pro-forma revenue and net income related to the acquisition of Sempra Renewables LLC were not material for the year ended December 31, 2019.
See Note 17 - Variable Interest Entities and Equity Method Investments for additional information related to the purchased wind farms.
Santa Rita East (Generation & Marketing Segment) (Applies to AEP)
In July 2019, AEP acquired a 75% interest, or 227 MWs, in Santa Rita East for approximately $356 million. In accordance with the accounting guidance for “Business Combinations,” management determined that the acquisition of Santa Rita East represents an asset acquisition. Additionally, and in accordance with the accounting guidance for “Consolidation,” management concluded that Santa Rita East is a VIE. As a result, to account for the initial consolidation of Santa Rita East, management applied the acquisition method by allocating the purchase price based on the relative fair value of the assets acquired and noncontrolling interest assumed. The fair value of the primary assets acquired and the noncontrolling interest assumed was determined using the market approach. The key input assumptions were the transaction price paid for AEP’s interest in Santa Rita East and recent third-party market transactions for similar wind farms. See “Santa Rita East” section of Note 17 for additional information.
ASSETS AND LIABILITIES HELD FOR SALE
Disposition of KPCo and KTCo (Vertically Integrated Utilities and AEP Transmission Holdco Segments) (Applies to AEP and AEPTCo)
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 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.
The Income Before Income Tax Expense (Benefit) and Equity Earnings of KPCo and KTCo were not material to AEP and AEPTCo for the years ended December 31, 2021, 2020 and 2019, respectively.
The major classes of KPCo and KTCo’s assets and liabilities presented in Assets Held for Sale and Liabilities Held for Sale on the balance sheets of AEP and AEPTCo as of December 31, 2021 are shown in the table below.
December 31, 2021
AEP AEPTCo
(in millions)
ASSETS
Accounts Receivable and Accrued Unbilled Revenues $ 33.2 $ 1.5
Fuel, Materials and Supplies 30.6 -
Property, Plant and Equipment, Net 2,302.7 165.3
Regulatory Assets 484.7 -
Other Classes of Assets that are not Major 68.5 1.1
Assets Held for Sale $ 2,919.7 $ 167.9
LIABILITIES
Accounts Payable $ 53.4 $ 1.1
Long-term Debt Due Within One Year 200.0 -
Customer Deposits 32.4 -
Deferred Income Taxes 441.6 15.4
Long-term Debt 903.1 -
Regulatory Liabilities and Deferred Investment Tax Credits 148.1 7.6
Other Classes of Liabilities that are not Major 102.3 3.5
Liabilities Held for Sale $ 1,880.9 $ 27.6
DISPOSITIONS
Disposition of Racine (Generation & Marketing Segment) (Applies to AEP)
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.
Conesville Plant (Generation & Marketing Segment) (Applies to AEP)
In June 2020, AEP and a nonaffiliated joint-owner executed an Environmental Liability and Property Transfer and Asset Purchase Agreement with a nonaffiliated third-party related to the merchant Conesville Plant site. The purchaser took ownership of the assets and assumed responsibility for environmental liabilities, including ash pond closure, asbestos abatement and decommissioning and demolition of the Conesville Plant site. In consideration of the transfer of the acquired assets to the purchaser and the purchaser’s assumption of liabilities, AEP will pay a total of approximately $98 million over three years, derecognized $106 million in ARO and recorded an immaterial gain on the transaction which is recorded in Other Operation on the statements of income. AEP paid approximately $26 million at closing in June 2020 and made additional payments totaling $57 million in quarterly installments from October 2020 to December 2021. AEP will make the final $15 million payment by July 2022.
Oklaunion Power Station (Transmission and Distribution Segment and Vertically Integrated Utilities Segment) (Applies to AEP, AEP Texas and PSO)
In October 2020, AEP Texas, PSO and a nonaffiliated joint-owner executed an Environmental Liability and Property Transfer and Asset Purchase Agreement with a nonaffiliated third-party related to the Oklaunion Power Station site. The purchaser took ownership of the assets and assumed responsibility for environmental liabilities, including ash pond closure, asbestos abatement and decommissioning and demolition of the Oklaunion Power Station site. The sale had an immaterial impact on the financial statements in the fourth quarter of 2020.
IMPAIRMENTS
2020 Texas Base Rate Case (Vertically Integrated Utilities Segment) (Applies to AEP and SWEPCo)
In January 2022, the PUCT issued a final order adopting the PFD with certain modifications which included a return of investment only for the recovery of the Dolet Hills Power Station. As a result of the final order, SWEPCo recorded a disallowance of $12 million associated with the lack of return on the Dolet Hills Power Station. In February 2022, SWEPCo filed a motion for rehearing with the PUCT challenging the denial of reasonable return or carrying costs on the Dolet Hills Power Station. See “2020 Texas Base Rate Case” section of Note 4 for additional information.
2019 Texas Base Rate Case (Transmission and Distribution Segment) (Applies to AEP and AEP Texas)
In December 2019, AEP Texas recorded a pretax impairment of $33 million in Asset Impairments and Other Related Charges on the statements of income due to regulatory disallowances in the 2019 Texas Base Rate Case.
Virginia Jurisdictional Book Value of Retired Coal-Fired Plants (Vertically Integrated Utilities Segment) (Applies to AEP and APCo)
In December 2019, based on management’s interpretation of Virginia law and more certainty regarding APCo’s triennial revenues, expenses and resulting earnings upon reaching the end of the three-year review period, APCo recorded a pretax expense of $93 million in Asset Impairments and Other Related Charges on the statements of income related to its previously retired coal-fired generation. As a result, management deemed these costs to be substantially recovered by APCo during the triennial review period. See “2017-2019 Virginia Triennial Review” section of Note 4 for additional information.
Merchant Generating Assets (Generation & Marketing Segment)
Due to a significant increase in the asset retirement costs recorded in December 2019 for the Ash Pond Complex at Conesville Plant, AEP performed an impairment analysis on Conesville Plant in accordance with accounting guidance for impairments of long-lived assets. AEP performed step one and step two of the impairment analysis using a cash flow model for the estimated useful life of Conesville Plant based upon energy and capacity price curves, which were developed internally with both observable Level 2 third-party quotations and unobservable Level 3 inputs, as well as management’s forecasts of operating expenses. The step two analysis resulted in a fair value determination for Conesville Plant of $0 and AEP recorded a $31 million pretax impairment, equal to the net book value of the plant, in Asset Impairments and Other Related Charges on AEP’s statements of income in the fourth quarter of 2019.
SUBSEQUENT EVENT
Planned Disposition of Competitive Contracted Renewable Assets (Generation & Marketing Segment)
In February 2022, AEP management announced the beginning of a process to sell all or a portion of the competitive contracted renewables portfolio included in the Generation & Marketing segment. As of December 31, 2021, the competitive contracted renewable portfolio assets totaled 1.6 gigawatts of generation resources.
8. BENEFIT PLANS
The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise.
For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Fair Value Measurements of Assets and Liabilities” and “Investments Held in Trust for Future Liabilities” sections of Note 1.
AEP sponsors a qualified pension plan and two unfunded non-qualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a non-qualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees.
Due to the Registrant Subsidiaries’ participation in AEP’s benefit plans, the assumptions used by the actuary, with the exception of the rate of compensation increase, and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant.
The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation - Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for rate-making purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.
Actuarial Assumptions for Benefit Obligations
The weighted-average assumptions used in the measurement of the Registrants’ benefit obligations are shown in the following tables:
Pension Plans OPEB
December 31,
Assumption 2021 2020 2021 2020
Discount Rate 2.90 % 2.50 % 2.90 % 2.55 %
Interest Crediting Rate 4.00 % 4.00 % NA NA
NA Not applicable.
Pension Plans
December 31,
Assumption - Rate of Compensation Increase (a)
2021 2020
AEP 5.10 % 5.00 %
AEP Texas 5.10 % 5.05 %
APCo 4.85 % 4.85 %
I&M 5.00 % 5.00 %
OPCo 5.30 % 5.25 %
PSO 5.10 % 5.05 %
SWEPCo 4.95 % 4.90 %
(a)Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
A duration-based method is used to determine the discount rate for the plans. 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 is the same for each Registrant.
For 2021, the rate of compensation increase assumed varies with the age of the employee, ranging from 3% per year to 11.5% per year, with the average increase shown in the table above. The compensation increase rates reflect variations in each Registrants’ population participating in the pension plan.
Actuarial Assumptions for Net Periodic Benefit Costs
The weighted-average assumptions used in the measurement of each Registrants’ benefit costs are shown in the following tables:
Pension Plans OPEB
Year Ended December 31,
Assumption 2021 2020 2019 2021 2020 2019
Discount Rate 2.50 % 3.25 % 4.30 % 2.55 % 3.30 % 4.30 %
Interest Crediting Rate 4.00 % 4.00 % 4.00 % NA NA NA
Expected Return on Plan Assets 4.75 % 5.75 % 6.25 % 4.75 % 5.50 % 6.25 %
NA Not applicable.
Pension Plans
Year Ended December 31,
Assumption - Rate of Compensation Increase (a)
2021 2020 2019
AEP 5.10 % 5.00 % 4.95 %
AEP Texas 5.10 % 5.05 % 5.00 %
APCo 4.85 % 4.85 % 4.75 %
I&M 5.00 % 5.00 % 4.95 %
OPCo 5.30 % 5.25 % 5.20 %
PSO 5.10 % 5.05 % 5.05 %
SWEPCo 4.95 % 4.90 % 4.90 %
(a)Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation, third-party forecasts and current prospects for economic growth. The expected return on plan assets is the same for each Registrant.
The health care trend rate assumptions used for OPEB plans measurement purposes are shown below:
December 31,
Health Care Trend Rates 2021 2020
Initial 6.25 % 6.50 %
Ultimate 4.50 % 4.50 %
Year Ultimate Reached 2029 2029
Significant Concentrations of Risk within Plan Assets
In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets. The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits. The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment. Management monitors the plans to control security diversification and ensure compliance with the investment policy. As of December 31, 2021, the assets were invested in compliance with all investment limits. See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details.
Benefit Plan Obligations, Plan Assets, Funded Status and Amounts Recognized on the Balance Sheets
For the year ended December 31, 2021, the pension plans had an actuarial gain primarily due to an increase in the discount rate, partially offset by less favorable demographic experience than expected, resulting from the updated census information as of January 1, 2021. For the year ended December 31, 2021, the OPEB plans had an actuarial gain primarily due to an increase in the discount rate and an update of the projected reimbursements from the Employer Group Waiver Program under Medicare Part D. For the year ended December 31, 2020, the pension plans had an actuarial loss primarily due to a decrease in the discount rate, partially offset by a decrease in the assumed rate used to convert account balances to annuities. For the year ended December 31, 2020, the OPEB plans had an actuarial loss primarily due to a decrease in the discount rate and an update to the health care trend assumption, partially offset by updated projected per capita claims costs due to rate negotiations for Medicare advantage premium rates. The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets, funded status and the presentation on the balance sheets. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively.
AEP Pension Plans OPEB
2021 2020 2021 2020
Change in Benefit Obligation (in millions)
Benefit Obligation as of January 1, $ 5,544.5 $ 5,236.8 $ 1,210.9 $ 1,225.4
Service Cost 129.2 111.9 9.5 10.0
Interest Cost 137.2 167.9 30.5 39.8
Actuarial (Gain) Loss (173.9) 434.7 (120.1) 39.3
Plan Amendments - - (5.4) (11.4)
Benefit Payments (450.0) (406.8) (126.0) (131.0)
Participant Contributions - - 41.3 38.2
Medicare Subsidy - - 0.6 0.6
Benefit Obligation as of December 31, $ 5,187.0 $ 5,544.5 $ 1,041.3 $ 1,210.9
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1, $ 5,556.6 $ 5,015.4 $ 1,946.7 $ 1,781.8
Actual Gain on Plan Assets 239.2 832.4 176.5 253.0
Company Contributions (a) 7.1 115.6 5.8 4.7
Participant Contributions - - 41.3 38.2
Benefit Payments (450.0) (406.8) (126.0) (131.0)
Fair Value of Plan Assets as of December 31, $ 5,352.9 $ 5,556.6 $ 2,044.3 $ 1,946.7
Funded Status as of December 31, $ 165.9 $ 12.1 $ 1,003.0 $ 735.8
(a)Contributions to the qualified pension plan were $0 and $110 million for the years ended December 31, 2021 and 2020, respectively. Contributions to the non-qualified pension plans were $7 million and $6 million for the years ended December 31, 2021 and 2020, respectively.
Pension Plans OPEB
December 31,
AEP
2021 2020 2021 2020
(in millions)
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs
$ 244.3 $ 93.5 $ 1,040.8 $ 771.9
Other Current Liabilities - Accrued Short-term Benefit Liability
(7.6) (6.7) (2.7) (2.4)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability
(70.8) (74.7) (35.1) (33.7)
Funded Status $ 165.9 $ 12.1 $ 1,003.0 $ 735.8
AEP Texas Pension Plans OPEB
2021 2020 2021 2020
Change in Benefit Obligation (in millions)
Benefit Obligation as of January 1, $ 453.2 $ 441.2 $ 96.3 $ 97.8
Service Cost 11.8 10.0 0.7 0.8
Interest Cost 11.2 13.9 2.4 3.2
Actuarial (Gain) Loss (10.9) 28.1 (12.3) 2.4
Plan Amendments - - (0.5) (1.0)
Benefit Payments (45.5) (40.0) (9.3) (10.0)
Participant Contributions - - 3.2 3.1
Benefit Obligation as of December 31, $ 419.8 $ 453.2 $ 80.5 $ 96.3
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1, $ 474.0 $ 435.1 $ 162.3 $ 148.1
Actual Gain on Plan Assets 16.0 67.2 12.5 21.1
Company Contributions 0.4 11.7 0.1 -
Participant Contributions - - 3.2 3.1
Benefit Payments (45.5) (40.0) (9.3) (10.0)
Fair Value of Plan Assets as of December 31, $ 444.9 $ 474.0 $ 168.8 $ 162.3
Funded Status as of December 31, $ 25.1 $ 20.8 $ 88.3 $ 66.0
Pension Plans OPEB
December 31,
AEP Texas
2021 2020 2021 2020
(in millions)
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs
$ 28.7 $ 24.7 $ 88.3 $ 66.0
Other Current Liabilities - Accrued Short-term Benefit Liability
(0.3) (0.4) - -
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability
(3.3) (3.5) - -
Funded Status $ 25.1 $ 20.8 $ 88.3 $ 66.0
APCo Pension Plans OPEB
2021 2020 2021 2020
Change in Benefit Obligation (in millions)
Benefit Obligation as of January 1, $ 670.8 $ 647.2 $ 198.2 $ 203.5
Service Cost 11.9 10.5 1.0 1.0
Interest Cost 16.4 20.3 4.9 6.6
Actuarial (Gain) Loss (28.5) 40.0 (21.4) 5.6
Plan Amendments - - (0.9) (1.8)
Benefit Payments (48.9) (47.2) (21.3) (23.2)
Participant Contributions - - 6.6 6.3
Medicare Subsidy - - 0.2 0.2
Benefit Obligation as of December 31, $ 621.7 $ 670.8 $ 167.3 $ 198.2
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1, $ 701.3 $ 637.0 $ 293.0 $ 271.0
Actual Gain on Plan Assets 30.9 104.5 21.9 36.8
Company Contributions - 7.0 2.1 2.1
Participant Contributions - - 6.6 6.3
Benefit Payments (48.9) (47.2) (21.3) (23.2)
Fair Value of Plan Assets as of December 31, $ 683.3 $ 701.3 $ 302.3 $ 293.0
Funded Status as of December 31, $ 61.6 $ 30.5 $ 135.0 $ 94.8
Pension Plans OPEB
December 31,
APCo
2021 2020 2021 2020
(in millions)
Employee Benefits and Pension Assets - Prepaid Benefit Costs $ 62.4 $ 31.0 $ 158.1 $ 119.1
Other Current Liabilities - Accrued Short-term Benefit Liability
- - (1.8) (1.8)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability
(0.8) (0.5) (21.3) (22.5)
Funded Status $ 61.6 $ 30.5 $ 135.0 $ 94.8
I&M Pension Plans OPEB
2021 2020 2021 2020
Change in Benefit Obligation (in millions)
Benefit Obligation as of January 1, $ 653.3 $ 616.1 $ 141.4 $ 142.9
Service Cost 17.5 15.4 1.3 1.4
Interest Cost 16.2 19.7 3.5 4.7
Actuarial (Gain) Loss (29.5) 44.3 (16.8) 5.1
Plan Amendments - - (0.7) (1.6)
Benefit Payments (45.4) (42.2) (15.3) (15.9)
Participant Contributions - - 5.2 4.8
Benefit Obligation as of December 31, $ 612.1 $ 653.3 $ 118.6 $ 141.4
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1, $ 698.1 $ 630.5 $ 238.2 $ 216.3
Actual Gain on Plan Assets 28.8 103.3 20.6 33.0
Company Contributions - 6.5 - -
Participant Contributions - - 5.2 4.8
Benefit Payments (45.4) (42.2) (15.3) (15.9)
Fair Value of Plan Assets as of December 31, $ 681.5 $ 698.1 $ 248.7 $ 238.2
Funded Status as of December 31, $ 69.4 $ 44.8 $ 130.1 $ 96.8
Pension Plans OPEB
December 31,
I&M
2021 2020 2021 2020
(in millions)
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs
$ 71.4 $ 46.5 $ 130.1 $ 96.8
Other Current Liabilities - Accrued Short-term Benefit Liability
(0.1) - - -
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability
(1.9) (1.7) - -
Funded Status $ 69.4 $ 44.8 $ 130.1 $ 96.8
OPCo Pension Plans OPEB
2021 2020 2021 2020
Change in Benefit Obligation (in millions)
Benefit Obligation as of January 1, $ 510.3 $ 487.8 $ 126.4 $ 130.2
Service Cost 11.4 9.7 0.8 0.9
Interest Cost 12.5 15.4 3.0 4.2
Actuarial (Gain) Loss (24.1) 33.4 (15.6) 3.1
Plan Amendments - - (0.6) (1.3)
Benefit Payments (39.4) (36.0) (13.6) (15.0)
Participant Contributions - - 4.5 4.3
Benefit Obligation as of December 31, $ 470.7 $ 510.3 $ 104.9 $ 126.4
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1, $ 543.1 $ 499.1 $ 213.0 $ 197.1
Actual Gain on Plan Assets 21.1 79.9 16.1 26.6
Company Contributions - 0.1 - -
Participant Contributions - - 4.5 4.3
Benefit Payments (39.4) (36.0) (13.6) (15.0)
Fair Value of Plan Assets as of December 31, $ 524.8 $ 543.1 $ 220.0 $ 213.0
Funded Status as of December 31, $ 54.1 $ 32.8 $ 115.1 $ 86.6
Pension Plans OPEB
December 31,
OPCo
2021 2020 2021 2020
(in millions)
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs
$ 54.8 $ 33.3 $ 115.1 $ 86.6
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability
(0.7) (0.5) - -
Funded Status $ 54.1 $ 32.8 $ 115.1 $ 86.6
PSO Pension Plans OPEB
2021 2020 2021 2020
Change in Benefit Obligation (in millions)
Benefit Obligation as of January 1, $ 279.9 $ 267.5 $ 64.0 $ 64.7
Service Cost 8.0 7.3 0.6 0.7
Interest Cost 6.7 8.5 1.6 2.1
Actuarial (Gain) Loss (17.2) 17.7 (6.8) 1.9
Plan Amendments - - (0.3) (0.7)
Benefit Payments (24.8) (21.1) (7.0) (6.8)
Participant Contributions - - 2.3 2.1
Benefit Obligation as of December 31, $ 252.6 $ 279.9 $ 54.4 $ 64.0
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1, $ 299.8 $ 276.2 $ 107.8 $ 98.0
Actual Gain on Plan Assets 11.1 44.6 10.9 14.5
Company Contributions 0.1 0.1 - -
Participant Contributions - - 2.3 2.1
Benefit Payments (24.8) (21.1) (7.0) (6.8)
Fair Value of Plan Assets as of December 31, $ 286.2 $ 299.8 $ 114.0 $ 107.8
Funded Status as of December 31, $ 33.6 $ 19.9 $ 59.6 $ 43.8
Pension Plans OPEB
December 31,
PSO
2021 2020 2021 2020
(in millions)
Employee Benefits and Pension Assets - Prepaid Benefit Costs
$ 35.5 $ 21.9 $ 59.6 $ 43.8
Other Current Liabilities - Accrued Short-term Benefit Liability
(0.1) (0.1) - -
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability
(1.8) (1.9) - -
Funded Status $ 33.6 $ 19.9 $ 59.6 $ 43.8
SWEPCo Pension Plans OPEB
2021 2020 2021 2020
Change in Benefit Obligation (in millions)
Benefit Obligation as of January 1, $ 334.5 $ 314.2 $ 77.1 $ 77.4
Service Cost 11.2 9.9 0.8 0.8
Interest Cost 8.5 10.2 1.9 2.5
Actuarial (Gain) Loss (3.5) 27.4 (9.2) 2.5
Plan Amendments - - (0.4) (0.8)
Benefit Payments (33.0) (27.2) (7.6) (7.7)
Participant Contributions - - 2.6 2.4
Benefit Obligation as of December 31, $ 317.7 $ 334.5 $ 65.2 $ 77.1
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1, $ 326.9 $ 296.9 $ 129.9 $ 117.2
Actual Gain on Plan Assets 14.3 48.2 11.7 18.0
Company Contributions 0.1 9.0 - -
Participant Contributions - - 2.6 2.4
Benefit Payments (33.0) (27.2) (7.6) (7.7)
Fair Value of Plan Assets as of December 31, $ 308.3 $ 326.9 $ 136.6 $ 129.9
Funded (Underfunded) Status as of December 31, $ (9.4) $ (7.6) $ 71.4 $ 52.8
Pension Plans OPEB
December 31,
SWEPCo
2021 2020 2021 2020
(in millions)
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs
$ - $ - $ 71.4 $ 52.8
Other Current Liabilities - Accrued Short-term Benefit Liability
(0.1) (0.1) - -
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability
(9.3) (7.5) - -
Funded (Underfunded) Status $ (9.4) $ (7.6) $ 71.4 $ 52.8
Amounts Included in Regulatory Assets, Deferred Income Taxes and AOCI
The following tables show the components of the plans included in Regulatory Assets, Deferred Income Taxes and AOCI and the items attributable to the change in these components:
AEP
Pension Plans OPEB
December 31,
2021 2020 2021 2020
Components (in millions)
Net Actuarial (Gain) Loss $ 894.7 $ 1,179.6 $ (103.6) $ 101.9
Prior Service Cost (Credit) 0.2 0.2 (161.9) (227.3)
Recorded as
Regulatory Assets $ 878.0 $ 1,182.4 $ (195.1) $ (99.0)
Deferred Income Taxes 3.6 (0.5) (14.7) (5.5)
Net of Tax AOCI 13.3 (2.1) (55.7) (20.9)
AEP
Pension Plans OPEB
2021 2020 2021 2020
Components (in millions)
Actuarial Gain During the Year $ (183.4) $ (132.9) $ (205.5) $ (118.0)
Amortization of Actuarial Loss (101.5) (93.7) - (5.9)
Prior Service Credit - - (5.5) (11.4)
Amortization of Prior Service Credit - - 70.9 69.8
Change for the Year Ended December 31, $ (284.9) $ (226.6) $ (140.1) $ (65.5)
AEP Texas
Pension Plans OPEB
December 31,
2021 2020 2021 2020
Components (in millions)
Net Actuarial (Gain) Loss $ 144.7 $ 160.5 $ (5.2) $ 12.3
Prior Service Credit - - (13.7) (19.3)
Recorded as
Regulatory Assets $ 136.7 $ 151.3 $ (17.7) $ (6.3)
Deferred Income Taxes 1.8 2.0 (0.2) (0.1)
Net of Tax AOCI 6.2 7.2 (1.0) (0.6)
AEP Texas
Pension Plans OPEB
2021 2020 2021 2020
Components (in millions)
Actuarial Gain During the Year $ (7.5) $ (16.4) $ (17.5) $ (10.7)
Amortization of Actuarial Loss (8.3) (7.8) - (0.5)
Prior Service Credit - - (0.4) (1.0)
Amortization of Prior Service Credit - - 6.0 5.9
Change for the Year Ended December 31, $ (15.8) $ (24.2) $ (11.9) $ (6.3)
APCo
Pension Plans OPEB
December 31,
2021 2020 2021 2020
Components (in millions)
Net Actuarial (Gain) Loss $ 83.9 $ 126.3 $ (18.9) $ 11.1
Prior Service Credit - - (23.8) (33.2)
Recorded as
Regulatory Assets $ 82.5 $ 124.7 $ (19.8) $ (10.3)
Deferred Income Taxes 0.3 0.3 (4.9) (2.5)
Net of Tax AOCI 1.1 1.3 (18.0) (9.3)
APCo
Pension Plans OPEB
2021 2020 2021 2020
Components (in millions)
Actuarial Gain During the Year $ (30.4) $ (30.8) $ (30.0) $ (16.8)
Amortization of Actuarial Loss (12.0) (11.2) - (0.9)
Prior Service Credit - - (0.9) (1.8)
Amortization of Prior Service Credit - - 10.3 10.2
Change for the Year Ended December 31, $ (42.4) $ (42.0) $ (20.6) $ (9.3)
I&M
Pension Plans OPEB
December 31,
2021 2020 2021 2020
Components (in millions)
Net Actuarial (Gain) Loss $ (1.6) $ 39.5 $ (10.7) $ 15.6
Prior Service Credit - - (22.1) (31.0)
Recorded as
Regulatory Assets/Liabilities (a) $ 3.1 $ 40.3 $ (30.7) $ (14.6)
Deferred Income Taxes (1.0) (0.1) (0.4) (0.2)
Net of Tax AOCI (3.7) (0.7) (1.7) (0.6)
(a)Recorded as a Regulatory Liability as of December 31, 2021 and recorded as a Regulatory Asset as of December 31, 2020.
I&M
Pension Plans OPEB
2021 2020 2021 2020
Components (in millions)
Actuarial Gain During the Year $ (29.4) $ (25.7) $ (26.3) $ (16.4)
Amortization of Actuarial Loss (11.7) (10.8) - (0.7)
Prior Service Credit - - (0.7) (1.5)
Amortization of Prior Service Credit - - 9.6 9.5
Change for the Year Ended December 31, $ (41.1) $ (36.5) $ (17.4) $ (9.1)
OPCo
Pension Plans OPEB
December 31,
2021 2020 2021 2020
Components (in millions)
Net Actuarial (Gain) Loss $ 118.1 $ 150.0 $ (18.5) $ 3.6
Prior Service Credit - - (16.3) (22.9)
Recorded as
Regulatory Assets $ 118.1 $ 150.0 $ (34.8) $ (19.3)
OPCo
Pension Plans OPEB
2021 2020 2021 2020
Components (in millions)
Actuarial Gain During the Year $ (22.8) $ (20.2) $ (22.1) $ (12.9)
Amortization of Actuarial Loss (9.1) (8.5) - (0.7)
Prior Service Credit - - (0.6) (1.3)
Amortization of Prior Service Credit - - 7.2 7.0
Change for the Year Ended December 31, $ (31.9) $ (28.7) $ (15.5) $ (7.9)
PSO
Pension Plans OPEB
December 31,
2021 2020 2021 2020
Components (in millions)
Net Actuarial (Gain) Loss $ 35.0 $ 55.9 $ (2.1) $ 10.5
Prior Service Credit - - (10.0) (14.1)
Recorded as
Regulatory Assets $ 35.0 $ 55.9 $ (12.1) $ (3.6)
PSO
Pension Plans OPEB
2021 2020 2021 2020
Components (in millions)
Actuarial Gain During the Year $ (16.0) $ (12.4) $ (12.6) $ (7.4)
Amortization of Actuarial Loss (4.9) (4.7) - (0.3)
Prior Service Credit - - (0.3) (0.7)
Amortization of Prior Service Credit - - 4.4 4.4
Change for the Year Ended December 31, $ (20.9) $ (17.1) $ (8.5) $ (4.0)
SWEPCo
Pension Plans OPEB
December 31,
2021 2020 2021 2020
Components (in millions)
Net Actuarial (Gain) Loss $ 76.4 $ 86.9 $ (3.5) $ 11.5
Prior Service Credit - - (12.3) (17.2)
Recorded as
Regulatory Assets $ 76.4 $ 86.9 $ (8.9) $ (3.0)
Deferred Income Taxes - - (1.4) (0.5)
Net of Tax AOCI - - (5.5) (2.2)
SWEPCo
Pension Plans OPEB
2021 2020 2021 2020
Components (in millions)
Actuarial Gain During the Year $ (4.3) $ (5.2) $ (15.0) $ (9.2)
Amortization of Actuarial Loss (6.2) (5.7) - (0.4)
Prior Service Credit - - (0.4) (0.8)
Amortization of Prior Service Credit - - 5.3 5.2
Change for the Year Ended December 31, $ (10.5) $ (10.9) $ (10.1) $ (5.2)
Determination of Pension Expense
The determination of pension expense or income is based 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.
Pension and OPEB Assets
The fair value tables within Pension and OPEB Assets present the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to the Registrant Subsidiaries using the percentages in the table below:
Pension Plan OPEB
December 31,
Company 2021 2020 2021 2020
AEP Texas 8.3 % 8.5 % 8.3 % 8.3 %
APCo 12.8 % 12.6 % 14.8 % 15.1 %
I&M 12.7 % 12.6 % 12.2 % 12.2 %
OPCo 9.8 % 9.8 % 10.8 % 10.9 %
PSO 5.3 % 5.4 % 5.6 % 5.5 %
SWEPCo 5.8 % 5.9 % 6.7 % 6.7 %
The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2021:
Asset Class Level 1 Level 2 Level 3 Other Total Year End
Allocation
(in millions)
Equities (a):
Domestic
$ 388.9 $ - $ - $ - $ 388.9 7.2 %
International
465.7 - - - 465.7 8.7 %
Common Collective Trusts (c)
- - - 463.9 463.9 8.7 %
Subtotal - Equities 854.6 - - 463.9 1,318.5 24.6 %
Fixed Income (a):
United States Government and Agency Securities
0.1 1,557.6 - - 1,557.7 29.1 %
Corporate Debt - 1,295.9 - - 1,295.9 24.2 %
Foreign Debt - 259.4 - - 259.4 4.8 %
State and Local Government - 57.1 - - 57.1 1.1 %
Other - Asset Backed - 1.3 - - 1.3 - %
Subtotal - Fixed Income 0.1 3,171.3 - - 3,171.4 59.2 %
Infrastructure (c) - - - 92.1 92.1 1.7 %
Real Estate (c) - - - 232.6 232.6 4.4 %
Alternative Investments (c) - - - 448.8 448.8 8.4 %
Cash and Cash Equivalents (c) - 64.3 - 53.4 117.7 2.2 %
Other - Pending Transactions and Accrued Income (b)
- - - (28.2) (28.2) (0.5) %
Total $ 854.7 $ 3,235.6 $ - $ 1,262.6 $ 5,352.9 100.0 %
(a)Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information.
(b)Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.
(c)Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share.
The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2021:
Asset Class Level 1 Level 2 Level 3 Other Total Year End
Allocation
(in millions)
Equities:
Domestic
$ 474.0 $ - $ - $ - $ 474.0 23.2 %
International
296.3 - - - 296.3 14.5 %
Common Collective Trusts (b)
- - - 265.0 265.0 13.0 %
Subtotal - Equities 770.3 - - 265.0 1,035.3 50.7 %
Fixed Income:
Common Collective Trust - Debt (b) - - - 167.7 167.7 8.2 %
United States Government and Agency Securities
- 222.4 - - 222.4 10.9 %
Corporate Debt - 233.2 - - 233.2 11.4 %
Foreign Debt - 39.8 - - 39.8 2.0 %
State and Local Government 91.9 13.6 - - 105.5 5.1 %
Subtotal - Fixed Income 91.9 509.0 - 167.7 768.6 37.6 %
Trust Owned Life Insurance:
International Equities - 23.4 - - 23.4 1.1 %
United States Bonds - 171.3 - - 171.3 8.4 %
Subtotal - Trust Owned Life Insurance - 194.7 - - 194.7 9.5 %
Cash and Cash Equivalents (b) 33.0 - - 6.7 39.7 1.9 %
Other - Pending Transactions and Accrued Income (a)
- - - 6.0 6.0 0.3 %
Total $ 895.2 $ 703.7 $ - $ 445.4 $ 2,044.3 100.0 %
(a)Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.
(b)Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share.
The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2020:
Asset Class Level 1 Level 2 Level 3 Other Total Year End
Allocation
(in millions)
Equities (a):
Domestic
$ 542.3 $ - $ - $ - $ 542.3 9.7 %
International
676.3 - - - 676.3 12.2 %
Common Collective Trusts (c)
- - - 650.0 650.0 11.7 %
Subtotal - Equities 1,218.6 - - 650.0 1,868.6 33.6 %
Fixed Income (a):
United States Government and Agency Securities
(1.4) 1,134.1 - - 1,132.7 20.4 %
Corporate Debt
- 1,425.0 - - 1,425.0 25.6 %
Foreign Debt
- 214.0 - - 214.0 3.9 %
State and Local Government
- 56.0 - - 56.0 1.0 %
Other - Asset Backed
- 0.8 - - 0.8 - %
Subtotal - Fixed Income (1.4) 2,829.9 - - 2,828.5 50.9 %
Infrastructure (c) - - - 91.1 91.1 1.6 %
Real Estate (c) - - - 231.6 231.6 4.2 %
Alternative Investments (c) - - - 431.8 431.8 7.8 %
Cash and Cash Equivalents (c) - 49.3 - 58.2 107.5 1.9 %
Other - Pending Transactions and Accrued Income (b)
- - - (2.5) (2.5) - %
Total $ 1,217.2 $ 2,879.2 $ - $ 1,460.2 $ 5,556.6 100.0 %
(a)Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information.
(b)Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.
(c)Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share.
The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2020:
Asset Class Level 1 Level 2 Level 3 Other Total Year End
Allocation
(in millions)
Equities:
Domestic
$ 399.9 $ - $ - $ - $ 399.9 20.6 %
International
290.7 - - - 290.7 14.9 %
Common Collective Trusts (b)
- - - 264.7 264.7 13.6 %
Subtotal - Equities 690.6 - - 264.7 955.3 49.1 %
Fixed Income:
Common Collective Trust - Debt (b)
- - - 186.4 186.4 9.6 %
United States Government and Agency Securities
(0.2) 199.7 - - 199.5 10.2 %
Corporate Debt
- 248.7 - - 248.7 12.8 %
Foreign Debt
- 34.9 - - 34.9 1.8 %
State and Local Government
73.9 13.1 - - 87.0 4.5 %
Subtotal - Fixed Income 73.7 496.4 - 186.4 756.5 38.9 %
Trust Owned Life Insurance:
International Equities
- 64.8 - - 64.8 3.3 %
United States Bonds
- 135.9 - - 135.9 7.0 %
Subtotal - Trust Owned Life Insurance - 200.7 - - 200.7 10.3 %
Cash and Cash Equivalents (b) 26.3 - - 5.7 32.0 1.6 %
Other - Pending Transactions and Accrued Income (a)
- - - 2.2 2.2 0.1 %
Total $ 790.6 $ 697.1 $ - $ 459.0 $ 1,946.7 100.0 %
(a)Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.
(b)Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share.
Accumulated Benefit Obligation
The accumulated benefit obligation for the pension plans is as follows:
Accumulated Benefit Obligation AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Qualified Pension Plan $ 4,822.5 $ 391.4 $ 597.0 $ 575.2 $ 440.0 $ 232.1 $ 291.4
Nonqualified Pension Plans 69.7 3.3 0.4 1.2 0.3 1.5 1.3
Total as of December 31, 2021 $ 4,892.2 $ 394.7 $ 597.4 $ 576.4 $ 440.3 $ 233.6 $ 292.7
Accumulated Benefit Obligation AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Qualified Pension Plan $ 5,171.3 $ 424.5 $ 645.8 $ 615.8 $ 479.2 $ 258.3 $ 307.1
Nonqualified Pension Plans 72.9 3.6 0.2 0.8 0.2 1.6 1.4
Total as of December 31, 2020 $ 5,244.2 $ 428.1 $ 646.0 $ 616.6 $ 479.4 $ 259.9 $ 308.5
Obligations in Excess of Fair Values
The tables below show the underfunded pension plans that had obligations in excess of plan assets.
Projected Benefit Obligation
AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Projected Benefit Obligation $ 78.4 $ 3.6 $ 0.8 $ 1.9 $ 0.7 $ 1.9 $ 317.7
Fair Value of Plan Assets - - - - - - 308.3
Underfunded Projected Benefit Obligation as of December 31, 2021
$ (78.4) $ (3.6) $ (0.8) $ (1.9) $ (0.7) $ (1.9) $ (9.4)
AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Projected Benefit Obligation $ 81.4 $ 3.9 $ 0.5 $ 1.7 $ 0.6 $ 2.0 $ 334.5
Fair Value of Plan Assets - - - - - - 326.9
Underfunded Projected Benefit Obligation as of December 31, 2020
$ (81.4) $ (3.9) $ (0.5) $ (1.7) $ (0.6) $ (2.0) $ (7.6)
Accumulated Benefit Obligation
AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Accumulated Benefit Obligation $ 69.7 $ 3.3 $ 0.4 $ 1.2 $ 0.3 $ 1.5 $ 1.3
Fair Value of Plan Assets - - - - - - -
Underfunded Accumulated Benefit Obligation as of December 31, 2021
$ (69.7) $ (3.3) $ (0.4) $ (1.2) $ (0.3) $ (1.5) $ (1.3)
AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Accumulated Benefit Obligation $ 72.9 $ 3.6 $ 0.2 $ 0.8 $ 0.2 $ 1.6 $ 1.4
Fair Value of Plan Assets - - - - - - -
Underfunded Accumulated Benefit Obligation as of December 31, 2020
$ (72.9) $ (3.6) $ (0.2) $ (0.8) $ (0.2) $ (1.6) $ (1.4)
Estimated Future Benefit Payments and Contributions
The estimated pension benefit payments and contributions to the trust are at least the minimum amount required by the Employee Retirement Income Security Act plus payment of unfunded non-qualified benefits. For the qualified pension plan, additional discretionary contributions may also be made to maintain the funded status of the plan. For OPEB plans, expected payments include the payment of unfunded benefits. The following table provides the estimated contributions and payments by Registrant for 2022:
Company Pension Plans OPEB
(in millions)
AEP $ 133.6 $ 3.4
AEP Texas 5.9 0.1
APCo 1.4 1.8
I&M 1.1 -
PSO 0.1 -
SWEPCo 6.5 -
The tables below reflect the total benefits expected to be paid from the plan or from the Registrants’ assets. The payments include the participants’ contributions to the plan for their share of the cost. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results. The estimated payments for the pension benefits and OPEB are as follows:
Pension Plans AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
2022 $ 378.1 $ 36.3 $ 43.9 $ 41.3 $ 35.1 $ 20.3 $ 24.7
2023 380.8 35.9 45.0 40.9 33.7 21.3 25.4
2024 381.1 35.8 45.5 42.1 32.9 20.5 25.5
2025 373.7 34.9 43.1 42.0 33.0 20.4 25.8
2026 373.6 34.7 43.5 42.2 32.4 20.0 27.3
Years 2027 to 2031, in Total 1,722.9 145.5 202.9 201.8 149.1 87.1 112.4
OPEB Benefit Payments AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
2022 $ 123.9 $ 9.6 $ 20.5 $ 15.2 $ 13.5 $ 7.1 $ 7.7
2023 115.4 9.1 19.1 14.1 12.5 6.7 7.4
2024 119.4 9.8 19.7 14.7 12.9 7.0 7.9
2025 117.9 9.8 19.2 14.5 12.7 7.0 8.0
2026 116.0 9.8 18.8 14.4 12.3 6.8 7.9
Years 2027 to 2031, in Total 545.1 44.7 87.5 66.8 57.1 29.7 37.1
OPEB Medicare
Subsidy Receipts AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
2022 $ 0.2 $ - $ 0.1 $ - $ - $ - $ -
2023 0.3 - 0.1 - - - -
2024 0.3 - 0.1 - - - -
2025 0.3 - 0.1 - - - -
2026 0.3 - 0.1 - - - -
Years 2027 to 2031, in Total 1.5 - 0.5 - - - -
Components of Net Periodic Benefit Cost
The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans:
AEP
Pension Plans OPEB
Years Ended December 31,
2021 2020 2019 2021 2020 2019
(in millions)
Service Cost $ 129.2 $ 111.9 $ 95.5 $ 9.5 $ 10.0 $ 9.5
Interest Cost 137.2 167.9 204.4 30.5 39.8 50.5
Expected Return on Plan Assets (229.7) (264.9) (296.0) (91.1) (95.6) (93.7)
Amortization of Prior Service Credit - - - (70.9) (69.8) (69.1)
Amortization of Net Actuarial Loss 101.5 93.7 57.6 - 5.9 22.1
Settlements - - - - - -
Net Periodic Benefit Cost (Credit) 138.2 108.6 61.5 (122.0) (109.7) (80.7)
Capitalized Portion (55.7) (47.0) (38.6) (4.1) (4.2) (3.8)
Net Periodic Benefit Cost (Credit) Recognized in Expense $ 82.5 $ 61.6 $ 22.9 $ (126.1) $ (113.9) $ (84.5)
AEP Texas
Pension Plans OPEB
Years Ended December 31,
2021 2020 2019 2021 2020 2019
(in millions)
Service Cost $ 11.8 $ 10.0 $ 8.6 $ 0.7 $ 0.8 $ 0.8
Interest Cost 11.2 13.9 17.5 2.4 3.2 4.0
Expected Return on Plan Assets (19.5) (22.7) (25.8) (7.5) (8.0) (7.8)
Amortization of Prior Service Credit - - - (6.0) (5.9) (5.9)
Amortization of Net Actuarial Loss 8.3 7.8 4.9 - 0.5 1.8
Net Periodic Benefit Cost (Credit) 11.8 9.0 5.2 (10.4) (9.4) (7.1)
Capitalized Portion (6.6) (5.5) (4.5) (0.4) (0.4) (0.4)
Net Periodic Benefit Cost (Credit) Recognized in Expense $ 5.2 $ 3.5 $ 0.7 $ (10.8) $ (9.8) $ (7.5)
APCo
Pension Plans OPEB
Years Ended December 31,
2021 2020 2019 2021 2020 2019
(in millions)
Service Cost $ 11.9 $ 10.5 $ 9.4 $ 1.0 $ 1.0 $ 1.0
Interest Cost 16.4 20.3 25.2 4.9 6.6 8.7
Expected Return on Plan Assets (29.1) (33.6) (37.4) (13.5) (14.4) (14.6)
Amortization of Prior Service Credit - - - (10.3) (10.2) (10.1)
Amortization of Net Actuarial Loss 12.0 11.2 7.0 - 0.9 3.7
Net Periodic Benefit Cost (Credit) 11.2 8.4 4.2 (17.9) (16.1) (11.3)
Capitalized Portion (5.2) (4.5) (4.0) (0.4) (0.4) (0.4)
Net Periodic Benefit Cost (Credit) Recognized in Expense $ 6.0 $ 3.9 $ 0.2 $ (18.3) $ (16.5) $ (11.7)
I&M
Pension Plans OPEB
Years Ended December 31,
2021 2020 2019 2021 2020 2019
(in millions)
Service Cost $ 17.5 $ 15.4 $ 13.4 $ 1.3 $ 1.4 $ 1.4
Interest Cost 16.2 19.7 23.8 3.5 4.7 5.8
Expected Return on Plan Assets (28.9) (33.3) (36.8) (11.1) (11.7) (11.4)
Amortization of Prior Service Credit - - - (9.6) (9.5) (9.4)
Amortization of Net Actuarial Loss 11.7 10.8 6.6 - 0.7 2.7
Net Periodic Benefit Cost (Credit) 16.5 12.6 7.0 (15.9) (14.4) (10.9)
Capitalized Portion (4.9) (4.3) (3.4) (0.4) (0.4) (0.4)
Net Periodic Benefit Cost (Credit) Recognized in Expense $ 11.6 $ 8.3 $ 3.6 $ (16.3) $ (14.8) $ (11.3)
OPCo
Pension Plans OPEB
Years Ended December 31,
2021 2020 2019 2021 2020 2019
(in millions)
Service Cost $ 11.4 $ 9.7 $ 7.9 $ 0.8 $ 0.9 $ 0.8
Interest Cost 12.5 15.4 19.1 3.0 4.2 5.5
Expected Return on Plan Assets (22.3) (26.3) (29.3) (9.7) (10.5) (10.8)
Amortization of Prior Service Credit - - - (7.2) (7.0) (6.9)
Amortization of Net Actuarial Loss 9.1 8.5 5.3 - 0.7 2.5
Net Periodic Benefit Cost (Credit) 10.7 7.3 3.0 (13.1) (11.7) (8.9)
Capitalized Portion (6.2) (5.0) (3.7) (0.4) (0.5) (0.4)
Net Periodic Benefit Cost (Credit) Recognized in Expense $ 4.5 $ 2.3 $ (0.7) $ (13.5) $ (12.2) $ (9.3)
PSO
Pension Plans OPEB
Years Ended December 31,
2021 2020 2019 2021 2020 2019
(in millions)
Service Cost $ 8.0 $ 7.3 $ 6.5 $ 0.6 $ 0.7 $ 0.6
Interest Cost 6.7 8.5 10.6 1.6 2.1 2.6
Expected Return on Plan Assets (12.3) (14.5) (16.3) (5.0) (5.2) (5.1)
Amortization of Prior Service Credit - - - (4.4) (4.4) (4.3)
Amortization of Net Actuarial Loss 4.9 4.7 2.9 - 0.3 1.2
Net Periodic Benefit Cost (Credit) 7.3 6.0 3.7 (7.2) (6.5) (5.0)
Capitalized Portion (3.4) (2.8) (2.4) (0.3) (0.3) (0.2)
Net Periodic Benefit Cost (Credit) Recognized in Expense $ 3.9 $ 3.2 $ 1.3 $ (7.5) $ (6.8) $ (5.2)
SWEPCo
Pension Plans OPEB
Years Ended December 31,
2021 2020 2019 2021 2020 2019
(in millions)
Service Cost $ 11.2 $ 9.9 $ 8.6 $ 0.8 $ 0.8 $ 0.8
Interest Cost 8.5 10.2 12.4 1.9 2.5 3.1
Expected Return on Plan Assets (13.5) (15.7) (17.7) (6.1) (6.3) (5.9)
Amortization of Prior Service Credit - - - (5.3) (5.2) (5.2)
Amortization of Net Actuarial Loss 6.2 5.7 3.4 - 0.4 1.4
Net Periodic Benefit Cost (Credit) 12.4 10.1 6.7 (8.7) (7.8) (5.8)
Capitalized Portion (4.1) (3.4) (2.9) (0.3) (0.3) (0.3)
Net Periodic Benefit Cost (Credit) Recognized in Expense $ 8.3 $ 6.7 $ 3.8 $ (9.0) $ (8.1) $ (6.1)
American Electric Power System Retirement Savings Plan
AEP sponsors the American Electric Power System Retirement Savings Plan, a defined contribution retirement savings plan for substantially all employees who are not covered by a retirement savings plan of the UMWA. This qualified plan offers participants an opportunity to contribute a portion of their pay, includes features under Section 401(k) of the Internal Revenue Code and provides for company matching contributions. The matching contributions to the plan are 100% of the first 1% of eligible employee contributions and 70% of the next 5% of contributions.
The following table provides the cost for matching contributions to the retirement savings plans by Registrant:
Year Ended December 31,
Company 2021 2020 2019
(in millions)
AEP $ 79.9 $ 81.8 $ 76.4
AEP Texas 6.4 6.4 5.9
APCo 7.6 7.7 7.5
I&M 10.9 11.3 11.0
OPCo 7.2 7.3 6.6
PSO 4.6 4.9 4.6
SWEPCo 6.4 6.7 6.2
UMWA Benefits
Health and Welfare Benefits (Applies to AEP and APCo)
AEP provides health and welfare benefits negotiated with the UMWA for certain unionized employees, retirees and their survivors who meet eligibility requirements. APCo also provides the same UMWA health and welfare benefits for certain unionized mining retirees and their survivors who meet eligibility requirements. AEP and APCo administer the health and welfare benefits and pay them from their general assets.
Multiemployer Pension Benefits (Applies to AEP)
UMWA pension benefits are provided through the United Mine Workers of America 1974 Pension Plan (Employer Identification Number: 52-1050282, Plan Number 002), a multiemployer plan. The UMWA pension benefits are administered by a board of trustees appointed in equal numbers by the UMWA and the Bituminous Coal Operators’ Association (BCOA), an industry bargaining association. AEP makes contributions to the United Mine Workers of America 1974 Pension Plan based on provisions in its labor agreement and the plan documents. The UMWA pension plan is different from single-employer plans as an employer’s contributions may be used to provide benefits to employees of other participating employers. A withdrawing employer may be subject to a withdrawal liability, which is calculated based upon that employer’s share of the plan’s unfunded benefit obligations. If an employer fails to make required contributions or if its payments in connection with its withdrawal liability fall short of satisfying its share of the plan’s unfunded benefit obligations, the remaining employers may be allocated a greater share of the remaining unfunded plan obligations. Under the Pension Protection Act of 2006 (PPA), the UMWA pension plan was in Critical Status for the plan year ending June 30, 2021 and in Critical and Declining Status for the plan year ending June 30, 2020, without utilization of extended amortization provisions. As required under the PPA, the Plan adopted a Rehabilitation Plan in 2015. The Rehabilitation Plan has been updated annually, most recently in April 2021.
The amounts contributed by AEP affiliates in 2021, 2020 and 2019 were immaterial and represent less than 5% of the total contributions in the plan’s latest annual report based on the plan year ended June 30, 2020. The contributions in 2021, 2020 and 2019 did not include surcharges.
Under the terms of the UMWA pension plan, contributions will be required to continue beyond the March 31, 2023 expiration of the current collective bargaining agreement between the Cook Coal Terminal (CCT) facility and the UMWA, whether or not the term of that agreement is extended or a subsequent agreement is entered, so long as both the UMWA pension plan remains in effect and an AEP affiliate continues to operate the facility covered by the current collective bargaining agreement. The contribution rate applicable would be determined in accordance with the terms of the UMWA pension plan by reference to the National Bituminous Coal Wage Agreement, subject to periodic revisions, between the UMWA and the BCOA. If the UMWA pension plan would terminate or an AEP affiliate would cease operation of the facility without arranging for a successor operator to assume its liability, the withdrawal liability obligation would be triggered.
Based upon the planned closure of CCT in 2022, AEP records a UMWA pension withdrawal liability on the balance sheet. The UMWA pension withdrawal liability is re-measured annually and is the estimated value of the company’s anticipated contributions toward its proportionate share of the plan’s unfunded vested liabilities. As of December 31, 2021 and 2020, the liability balance was $22 million and $25 million, respectively. AEP recovers the estimated value of its UMWA pension withdrawal liability through fuel clauses in certain regulated jurisdictions. AEP records a regulatory asset on the balance sheets when the UMWA pension withdrawal liability exceeds the cumulative billings collected and a regulatory liability on the balance sheets when the cumulative billings collected exceed the withdrawal liability. As of December 31, 2021 and 2020, AEP recorded a regulatory asset on the balance sheets for $1 million and $6 million, respectively. If any portion of the UMWA pension withdrawal liability is not recoverable, it could reduce future net income and cash flows and impact financial condition.
9. BUSINESS SEGMENTS
The disclosures in this note apply to all Registrants unless indicated otherwise.
AEP’s Reportable Segments
AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.
AEP’s reportable segments 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 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 returns on equity.
•Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity.
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, income tax expense and other nonallocated costs.
The tables below present AEP’s reportable segment income statement information for the years ended December 31, 2021, 2020 and 2019 and reportable segment balance sheet information as of December 31, 2021 and 2020.
Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other (a) Reconciling Adjustments Consolidated
(in millions)
Revenues from:
External Customers
$ 9,852.2 $ 4,464.1 $ 351.1 $ 2,108.3 $ 16.3 $ - $ 16,792.0
Other Operating Segments
146.3 28.8 1,175.1 55.4 55.9 (1,461.5) -
Total Revenues $ 9,998.5 $ 4,492.9 $ 1,526.2 $ 2,163.7 $ 72.2 $ (1,461.5) $ 16,792.0
Asset Impairments and Other Related Charges
$ 11.6 $ - $ - $ - $ - $ - $ 11.6
Depreciation and Amortization
1,747.6 690.3 306.0 80.9 0.9 - 2,825.7
Interest Expense 574.2 300.9 146.3 15.6 180.8 (18.7) 1,199.1
Income Tax Expense (Benefit)
(11.2) 77.5 159.6 (48.8) (61.6) - 115.5
Equity Earnings (Loss) of Unconsolidated Subsidiaries 3.4 - 75.0 (10.6) 23.9 - 91.7
Net Income (Loss) $ 1,116.7 $ 543.4 $ 682.0 $ 210.2 $ (64.2) $ - $ 2,488.1
Gross Property Additions
$ 2,963.1 $ 1,766.0 $ 1,468.6 $ 232.8 $ 25.5 $ (29.2) $ 6,426.8
Total Property, Plant and Equipment
$ 48,368.9 $ 22,700.7 $ 13,213.0 $ 2,105.4 $ 418.4 $ - $ 86,806.4
Accumulated Depreciation and Amortization
15,471.6 4,102.4 801.8 241.0 188.3 - 20,805.1
Total Property, Plant and Equipment - Net
$ 32,897.3 $ 18,598.3 $ 12,411.2 $ 1,864.4 $ 230.1 $ - $ 66,001.3
Total Assets (e) $ 46,974.2 $ 21,120.2 $ 13,873.3 $ 4,263.6 $ 5,846.5 (b) $ (4,409.1) (c) $ 87,668.7
Investments in Equity Method Investees
$ 33.5 $ 2.5 $ 830.4 $ 487.8 $ 93.3 $ - $ 1,447.5
Long-term Debt Due Within One Year:
Nonaffiliated
$ 1,022.4 $ 716.1 $ 106.4 $ - $ 308.9 (d) $ - $ 2,153.8
Long-term Debt:
Affiliated
65.0 - - - - (65.0) -
Nonaffiliated
12,964.4 7,433.2 4,442.7 - 6,460.4 (d) - 31,300.7
Total Long-term Debt
$ 14,051.8 $ 8,149.3 $ 4,549.1 $ - $ 6,769.3 $ (65.0) $ 33,454.5
Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other (a) Reconciling Adjustments Consolidated
(in millions)
Revenues from:
External Customers
$ 8,753.2 $ 4,238.7 $ 297.4 $ 1,621.0 $ 8.2 $ - $ 14,918.5
Other Operating Segments
126.2 107.2 901.4 104.6 88.6 (1,328.0) -
Total Revenues $ 8,879.4 $ 4,345.9 $ 1,198.8 $ 1,725.6 $ 96.8 $ (1,328.0) $ 14,918.5
Depreciation and Amortization
$ 1,600.5 $ 751.1 $ 257.6 $ 72.8 $ 0.8 $ - $ 2,682.8
Interest Expense 565.0 289.2 133.2 24.0 196.4 (42.1) 1,165.7
Income Tax Expense (Benefit)
(7.0) 29.7 130.8 (108.0) (5.0) - 40.5
Equity Earnings of Unconsolidated Subsidiaries 2.9 - 82.4 3.2 2.6 - 91.1
Net Income (Loss) $ 1,064.5 $ 496.4 $ 508.5 $ 216.9 $ (89.6) $ - $ 2,196.7
Gross Property Additions
$ 2,291.2 $ 2,108.1 $ 1,649.3 $ 197.0 $ 16.0 $ (15.3) $ 6,246.3
Total Property, Plant and Equipment
$ 49,023.3 $ 21,145.0 $ 11,827.2 $ 1,910.2 $ 407.3 $ - $ 84,313.0
Accumulated Depreciation and Amortization
15,586.2 3,879.3 595.7 166.1 184.1 - 20,411.4
Total Property, Plant and Equipment - Net
$ 33,437.1 $ 17,265.7 $ 11,231.5 $ 1,744.1 $ 223.2 $ - $ 63,901.6
Total Assets $ 42,752.7 $ 19,765.9 $ 12,627.3 $ 3,585.9 $ 5,987.1 (b) $ (3,961.7) (c) $ 80,757.2
Investments in Equity Method Investees
$ 37.1 $ 2.1 $ 831.3 $ 467.0 $ 68.8 $ - $ 1,406.3
Long-term Debt Due Within One Year:
Nonaffiliated
$ 1,034.6 $ 588.8 $ 52.3 $ - $ 410.4 (d) $ - $ 2,086.1
Long-term Debt:
Affiliated
65.0 - - - - (65.0) -
Nonaffiliated
12,375.6 6,661.9 4,075.7 - 5,873.2 (d) - 28,986.4
Total Long-term Debt
$ 13,475.2 $ 7,250.7 $ 4,128.0 $ - $ 6,283.6 $ (65.0) $ 31,072.5
Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other (a) Reconciling Adjustments Consolidated
(in millions)
Revenues from:
External Customers
$ 9,245.7 $ 4,319.0 $ 260.2 $ 1,721.8 $ 14.7 $ - $ 15,561.4
Other Operating Segments
121.4 163.5 813.0 135.8 81.1 (1,314.8) -
Total Revenues $ 9,367.1 $ 4,482.5 $ 1,073.2 $ 1,857.6 $ 95.8 $ (1,314.8) $ 15,561.4
Asset Impairments and Other Related Charges
$ 92.9 $ 32.5 $ - $ 31.0 $ - $ - $ 156.4
Depreciation and Amortization
1,447.0 789.5 183.4 69.5 0.6 24.5 (f) 2,514.5
Interest Expense
568.3 243.3 103.3 30.0 193.7 (66.1) (f) 1,072.5
Income Tax Expense (Benefit) (97.7) (25.2) 136.2 (53.8) 27.6 - (12.9)
Equity Earnings (Loss) of Unconsolidated Subsidiaries 3.0 - 72.8 (3.8) 0.1 - 72.1
Net Income (Loss)
$ 985.6 $ 451.0 $ 520.1 $ 104.1 $ (141.0) $ - $ 1,919.8
Gross Property Additions
$ 2,437.4 $ 2,074.3 $ 1,458.9 $ 1,005.1 $ 14.5 $ (20.4) $ 6,969.8
Total Assets $ 41,228.8 $ 18,757.5 $ 11,143.5 $ 3,123.8 $ 5,440.0 (b) $ (3,801.3) (c)(f) $ 75,892.3
Investments in Equity Method Investees
$ 41.7 $ 2.5 $ 787.5 $ 459.5 $ 65.4 $ - $ 1,356.6
Long-term Debt Due Within One Year:
Affiliated $ 20.0 $ - $ - $ - $ - $ (20.0) $ -
Nonaffiliated
704.7 392.2 - - 501.8 (d) - 1,598.7
Long-term Debt:
Affiliated
39.0 - - - - (39.0) -
Nonaffiliated
12,162.0 6,248.1 3,593.8 - 3,122.9 (d) - 25,126.8
Total Long-term Debt
$ 12,925.7 $ 6,640.3 $ 3,593.8 $ - $ 3,624.7 $ (59.0) $ 26,725.5
(a)Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and other nonallocated costs.
(b)Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies.
(c)Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable.
(d)Amounts reflect the impact of fair value hedge accounting. See “Accounting for Fair Value Hedging Strategies” section of Note 10 for additional information.
(e)Amount includes Assets Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
(f)Includes eliminations due to an intercompany finance lease.
Registrant Subsidiaries’ Reportable Segments (Applies to all Registrant Subsidiaries except AEPTCo)
The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an integrated electricity transmission and distribution business for AEP Texas and OPCo. Other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
AEPTCo’s Reportable Segments
AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities. The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting.” The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the RTOs in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and provide service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by the FERC and earn revenues through tariff rates charged for the use of their electric transmission systems.
AEPTCo’s Chief Operating Decision Maker makes operating decisions, allocates resources to and assesses performance-based on these operating segments. The seven State Transcos operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities.
The tables below present AEPTCo’s reportable segment income statement information for the years ended December 31, 2021, 2020 and 2019 and reportable segment balance sheet information as of December 31, 2021 and 2020.
State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
2021 (in millions)
Revenues from:
External Customers
$ 315.1 $ - $ - $ 315.1
Sales to AEP Affiliates
1,153.9 - - 1,153.9
Other Revenues
0.3 - - 0.3
Total Revenues $ 1,469.3 $ - $ - $ 1,469.3
Depreciation and Amortization
$ 297.3 $ - $ - $ 297.3
Interest Income
0.1 158.1 (157.7) (a) 0.5
Allowance for Equity Funds Used During Construction 67.2 - - 67.2
Interest Expense 141.2 157.7 (157.7) (a) 141.2
Income Tax Expense 144.1 - - 144.1
Net Income $ 591.5 $ 0.2 (b) $ - $ 591.7
Gross Property Additions $ 1,442.7 $ - $ - $ 1,442.7
Total Transmission Property $ 12,708.5 $ - $ - $ 12,708.5
Accumulated Depreciation and Amortization 772.8 - - 772.8
Total Transmission Property - Net $ 11,935.7 $ - $ - $ 11,935.7
Notes Receivable - Affiliated $ - $ 4,343.9 $ (4,343.9) (c) $ -
Total Assets (f) $ 12,564.3 $ 4,389.5 (d) $ (4,429.4) (e) $ 12,524.4
Total Long-Term Debt $ 4,390.0 $ 4,343.9 $ (4,390.0) (c) $ 4,343.9
State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
2020 (in millions)
Revenues from:
External Customers
$ 248.8 $ - $ - $ 248.8
Sales to AEP Affiliates
896.3 - - 896.3
Other Revenues
0.6 - - 0.6
Total Revenues $ 1,145.7 $ - $ - $ 1,145.7
Depreciation and Amortization
$ 249.0 $ - $ - $ 249.0
Interest Income
0.9 149.6 (148.1) (a) 2.4
Allowance for Equity Funds Used During Construction 74.0 - - 74.0
Interest Expense 127.8 148.1 (148.1) (a) 127.8
Income Tax Expense 106.5 0.2 - 106.7
Net Income $ 422.3 $ 1.1 (b) $ - $ 423.4
Gross Property Additions $ 1,621.9 $ - $ - $ 1,621.9
Total Transmission Property $ 11,345.6 $ - $ - $ 11,345.6
Accumulated Depreciation and Amortization 572.8 - - 572.8
Total Transmission Property - Net $ 10,772.8 $ - $ - $ 10,772.8
Notes Receivable - Affiliated $ - $ 3,948.5 $ (3,948.5) (c) $ -
Total Assets $ 11,185.1 $ 4,084.0 (d) $ (4,023.1) (e) $ 11,246.0
Total Long-Term Debt $ 3,990.0 $ 3,948.5 $ (3,990.0) (c) $ 3,948.5
State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
2019 (in millions)
Revenues from:
External Customers
$ 214.6 $ - $ - $ 214.6
Sales to AEP Affiliates
806.7 - - 806.7
Other Revenue 0.1 - - 0.1
Total Revenues $ 1,021.4 $ - $ - $ 1,021.4
Depreciation and Amortization
$ 176.0 $ - $ - $ 176.0
Interest Income
1.3 123.8 (122.1) (a) 3.0
Allowance for Equity Funds Used During Construction 84.3 - - 84.3
Interest Expense 97.4 122.1 (122.1) (a) 97.4
Income Tax Expense 117.1 0.3 - 117.4
Net Income $ 438.6 $ 1.1 (b) $ - $ 439.7
Gross Property Additions $ 1,419.5 $ - $ - $ 1,419.5
Total Assets $ 9,865.0 $ 3,519.1 (d) $ (3,493.3) (e) $ 9,890.8
Total Long-Term Debt $ 3,465.0 $ 3,427.3 $ (3,465.0) (c) $ 3,427.3
(a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement.
(b) Includes elimination of AEPTCo Parent’s equity earnings in the State Transcos.
(c) Elimination of intercompany debt.
(d) Includes elimination of AEPTCo Parent’s investments in the State Transcos.
(e) Primarily relates to elimination of Notes Receivable from the State Transcos.
(f) Amount includes Assets Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
10. DERIVATIVES AND HEDGING
The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any derivative and hedging activity.
OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS
AEPSC is agent for and transacts on behalf of certain AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries.
The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk and credit risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks.
STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES
Risk Management Strategies
The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.
The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors.
The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts:
December 31, 2021
Primary Risk
Exposure Unit of
Measure AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Commodity:
Power MWhs 287.9 - 33.1 13.6 2.7 11.9 3.4
Natural Gas MMBtus 34.1 - - - - 1.3 5.1
Heating Oil and Gasoline Gallons 7.4 1.9 1.1 0.7 1.5 0.8 1.0
Interest Rate USD $ 116.5 $ - $ - $ - $ - $ - $ -
Interest Rate on Long-term Debt USD $ 950.0 $ - $ - $ - $ - $ - $ -
December 31, 2020
Primary Risk
Exposure Unit of
Measure AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Commodity:
Power MWhs 331.3 - 46.9 19.7 3.0 11.9 4.0
Natural Gas MMBtus 26.9 - - - - - 7.9
Heating Oil and Gasoline Gallons 6.9 1.8 1.1 0.6 1.4 0.7 0.9
Interest Rate USD $ 129.8 $ - $ - $ - $ - $ - $ -
Interest Rate on Long-term Debt USD $ 1,150.0 $ - $ 200.0 $ - $ - $ - $ -
Fair Value Hedging Strategies (Applies to AEP)
Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating-rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges.
Cash Flow Hedging Strategies
The Registrants utilize cash flow hedges on certain derivative transactions for the purchase-and-sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk.
The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure.
ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS
The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes and other assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality.
Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts.
According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third-party contractual agreements and risk profiles. AEP netted cash collateral received from third-parties against short-term and long-term risk management assets in the amounts of $263 million and $3 million as of December 31, 2021 and 2020, respectively. AEP netted cash collateral paid to third-parties against short-term and long-term risk management liabilities in the amounts of $3 million and $7 million as of December 31, 2021 and 2020, respectively. The netted cash collateral from third-parties against short-term and long-term risk management assets and netted cash collateral paid to third-parties against short-term and long-term risk management liabilities were immaterial for the Registrant Subsidiaries as of December 31, 2021 and 2020.
The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets:
AEP
December 31, 2021
Risk
Management
Contracts Hedging Contracts Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized Gross
Amounts
Offset in the
Statement of
Financial
Position (b) Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a)
(in millions)
Current Risk Management Assets (d) $ 513.4 $ 176.0 $ 1.2 $ 690.6 $ (496.2) $ 194.4
Long-term Risk Management Assets 370.5 89.1 - 459.6 (192.6) 267.0
Total Assets 883.9 265.1 1.2 1,150.2 (688.8) 461.4
Current Risk Management Liabilities (e) 395.7 40.9 - 436.6 (361.2) 75.4
Long-term Risk Management Liabilities 243.9 16.7 38.1 298.7 (68.4) 230.3
Total Liabilities 639.6 57.6 38.1 735.3 (429.6) 305.7
Total MTM Derivative Contract Net Assets (Liabilities) $ 244.3 $ 207.5 $ (36.9) $ 414.9 $ (259.2) $ 155.7
December 31, 2020
Risk
Management
Contracts Hedging Contracts Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized Gross
Amounts
Offset in the
Statement of
Financial
Position (b) Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a)
(in millions)
Current Risk Management Assets $ 239.1 $ 21.1 $ 5.0 $ 265.2 $ (170.5) $ 94.7
Long-term Risk Management Assets 275.9 18.0 - 293.9 (51.7) 242.2
Total Assets 515.0 39.1 5.0 559.1 (222.2) 336.9
Current Risk Management Liabilities 193.0 54.4 3.4 250.8 (172.0) 78.8
Long-term Risk Management Liabilities 222.2 60.1 4.1 286.4 (53.6) 232.8
Total Liabilities 415.2 114.5 7.5 537.2 (225.6) 311.6
Total MTM Derivative Contract Net Assets (Liabilities) $ 99.8 $ (75.4) $ (2.5) $ 21.9 $ 3.4 $ 25.3
AEP Texas
December 31, 2021
Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts - in the Statement of Presented in the Statement
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c)
(in millions)
Current Risk Management Assets $ 0.6 $ (0.6) $ -
Long-term Risk Management Assets - - -
Total Assets 0.6 (0.6) -
Current Risk Management Liabilities - - -
Long-term Risk Management Liabilities - - -
Total Liabilities - - -
Total MTM Derivative Net Assets (Liabilities) $ 0.6 $ (0.6) $ -
December 31, 2020
Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts - in the Statement of Presented in the Statement
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c)
(in millions)
Current Risk Management Assets $ 0.4 $ (0.4) $ -
Long-term Risk Management Assets - - -
Total Assets 0.4 (0.4) -
Current Risk Management Liabilities - - -
Long-term Risk Management Liabilities - - -
Total Liabilities - - -
Total MTM Derivative Net Assets (Liabilities) $ 0.4 $ (0.4) $ -
APCo
December 31, 2021
Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts - in the Statement of Presented in the Statement
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c)
(in millions)
Current Risk Management Assets $ 47.5 $ (5.5) $ 42.0
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets 0.2 (0.2) -
Total Assets 47.7 (5.7) 42.0
Other Current Liabilities - Current Risk Management Liabilities 7.2 (6.4) 0.8
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities 0.2 (0.2) -
Total Liabilities 7.4 (6.6) 0.8
Total MTM Derivative Net Assets $ 40.3 $ 0.9 $ 41.2
December 31, 2020
Risk Gross Amounts of Risk Gross Amounts Net Amounts of Assets/
Management Hedging Management Offset in the Liabilities Presented in
Contracts - Contracts Assets/Liabilities Statement of the Statement of
Balance Sheet Location Commodity (a) Interest Rate (a) Recognized Financial Position (b) Financial Position (c)
(in millions)
Current Risk Management Assets $ 38.8 $ 2.4 $ 41.2 $ (18.8) $ 22.4
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets 0.7 - 0.7 (0.6) 0.1
Total Assets 39.5 2.4 41.9 (19.4) 22.5
Other Current Liabilities - Current Risk Management Liabilities 19.7 3.4 23.1 (18.5) 4.6
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities 0.6 - 0.6 (0.5) 0.1
Total Liabilities 20.3 3.4 23.7 (19.0) 4.7
Total MTM Derivative Contract Net Assets (Liabilities) $ 19.2 $ (1.0) $ 18.2 $ (0.4) $ 17.8
I&M
December 31, 2021
Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts - in the Statement of Presented in the Statement
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c)
(in millions)
Current Risk Management Assets $ 11.1 $ (7.8) $ 3.3
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets 0.2 (0.2) -
Total Assets 11.3 (8.0) 3.3
Current Risk Management Liabilities 14.8 (9.8) 5.0
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities 0.2 (0.2) -
Total Liabilities 15.0 (10.0) 5.0
Total MTM Derivative Contract Net Assets (Liabilities) $ (3.7) $ 2.0 $ (1.7)
December 31, 2020
Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts - in the Statement of Presented in the Statement
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c)
(in millions)
Current Risk Management Assets $ 17.2 $ (13.6) $ 3.6
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets 0.5 (0.4) 0.1
Total Assets 17.7 (14.0) 3.7
Current Risk Management Liabilities 12.1 (12.0) 0.1
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities 0.4 (0.3) 0.1
Total Liabilities 12.5 (12.3) 0.2
Total MTM Derivative Contract Net Assets (Liabilities) $ 5.2 $ (1.7) $ 3.5
OPCo
December 31, 2021
Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts - in the Statement of Presented in the Statement
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c)
(in millions)
Current Risk Management Assets $ 0.5 $ (0.5) $ -
Long-term Risk Management Assets - - -
Total Assets 0.5 (0.5) -
Current Risk Management Liabilities 6.7 - 6.7
Long-term Risk Management Liabilities 85.8 - 85.8
Total Liabilities 92.5 - 92.5
Total MTM Derivative Contract Net Liabilities $ (92.0) $ (0.5) $ (92.5)
December 31, 2020
Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts - in the Statement of Presented in the Statement
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c)
(in millions)
Current Risk Management Assets $ 0.3 $ (0.3) $ -
Long-term Risk Management Assets - - -
Total Assets 0.3 (0.3) -
Current Risk Management Liabilities 8.7 - 8.7
Long-term Risk Management Liabilities 101.6 - 101.6
Total Liabilities 110.3 - 110.3
Total MTM Derivative Contract Net Liabilities $ (110.0) $ (0.3) $ (110.3)
PSO
December 31, 2021
Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts - in the Statement of Presented in the Statement
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c)
(in millions)
Current Risk Management Assets $ 12.4 $ (0.3) $ 12.1
Long-term Risk Management Assets - - -
Total Assets 12.4 (0.3) 12.1
Current Risk Management Liabilities 3.7 - 3.7
Long-term Risk Management Liabilities - - -
Total Liabilities 3.7 - 3.7
Total MTM Derivative Net Assets (Liabilities) $ 8.7 $ (0.3) $ 8.4
December 31, 2020
Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts - in the Statement of Presented in the Statement
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c)
(in millions)
Current Risk Management Assets $ 10.5 $ (0.2) $ 10.3
Long-term Risk Management Assets - - -
Total Assets 10.5 (0.2) 10.3
Current Risk Management Liabilities - - -
Long-term Risk Management Liabilities - - -
Total Liabilities - - -
Total MTM Derivative Net Assets (Liabilities) $ 10.5 $ (0.2) $ 10.3
SWEPCo
December 31, 2021
Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts - in the Statement of Presented in the Statement
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c)
(in millions)
Current Risk Management Assets $ 10.1 $ (0.3) $ 9.8
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets 1.1 - 1.1
Total Assets 11.2 (0.3) 10.9
Current Risk Management Liabilities 2.1 - 2.1
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities - - -
Total Liabilities 2.1 - 2.1
Total MTM Derivative Net Assets (Liabilities) $ 9.1 $ (0.3) $ 8.8
December 31, 2020
Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts - in the Statement of Presented in the Statement
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c)
(in millions)
Current Risk Management Assets $ 3.4 $ (0.2) $ 3.2
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets - - -
Total Assets 3.4 (0.2) 3.2
Current Risk Management Liabilities 0.7 - 0.7
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities 1.0 - 1.0
Total Liabilities 1.7 - 1.7
Total MTM Derivative Net Assets (Liabilities) $ 1.7 $ (0.2) $ 1.5
(a)Derivative instruments within these categories are disclosed as gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”
(b)Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”
(c)All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position.
(d)Amount excludes Risk Management Assets of $6 million classified as Assets Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
(e)Amount excludes Risk Management Liabilities of $0.1 million classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
The tables below present the Registrants’ amount of gain (loss) recognized on risk management contracts:
Year Ended December 31, 2021
Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Vertically Integrated Utilities Revenues $ (0.6) $ - $ - $ - $ - $ - $ -
Generation & Marketing Revenues 169.1 - - - - - -
Electric Generation, Transmission and Distribution Revenues - - (0.5) (0.1) - - -
Purchased Electricity for Resale 2.0 - 1.8 - - - -
Other Operation 2.8 0.8 0.3 0.3 0.5 0.3 0.4
Maintenance 3.4 1.0 0.5 0.3 0.6 0.4 0.5
Regulatory Assets (a) (9.1) - (2.7) (14.8) 10.0 (3.6) 3.6
Regulatory Liabilities (a) 156.4 0.2 55.9 (3.9) - 48.9 37.0
Total Gain (Loss) on Risk Management Contracts $ 324.0 $ 2.0 $ 55.3 $ (18.2) $ 11.1 $ 46.0 $ 41.5
Year Ended December 31, 2020
Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Vertically Integrated Utilities Revenues $ 0.8 $ - $ - $ - $ - $ - $ -
Generation & Marketing Revenues 9.5 - - - - - -
Electric Generation, Transmission and Distribution Revenues - - 0.4 0.1 - - 0.1
Purchased Electricity for Resale 1.4 - 1.2 0.1 - - -
Other Operation (2.0) (0.6) (0.2) (0.2) (0.3) (0.2) (0.3)
Maintenance (2.9) (0.8) (0.4) (0.3) (0.5) (0.3) (0.4)
Regulatory Assets (a) (4.8) - - (0.1) (6.6) - 1.4
Regulatory Liabilities (a) 114.9 0.4 20.3 12.4 12.4 39.1 20.2
Total Gain (Loss) on Risk Management Contracts $ 116.9 $ (1.0) $ 21.3 $ 12.0 $ 5.0 $ 38.6 $ 21.0
Year Ended December 31, 2019
Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Vertically Integrated Utilities Revenues $ 0.7 $ - $ - $ - $ - $ - $ -
Generation & Marketing Revenues 25.1 - - - - - -
Electric Generation, Transmission and Distribution Revenues - - 0.1 0.5 - - 0.1
Purchased Electricity for Resale 1.9 - 1.6 0.1 - - -
Other Operation (0.8) (0.2) (0.1) (0.1) (0.2) (0.1) (0.1)
Maintenance (0.8) (0.2) (0.2) (0.1) (0.2) (0.1) (0.1)
Regulatory Assets (a) (3.7) 0.7 0.3 0.3 (3.7) 1.2 (1.5)
Regulatory Liabilities (a) 102.6 - 2.4 24.5 10.1 34.6 26.6
Total Gain on Risk Management Contracts $ 125.0 $ 0.3 $ 4.1 $ 25.2 $ 6.0 $ 35.6 $ 25.0
(a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis.
The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge.
For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same line item on the statements of income as that of the associated risk being hedged. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
Accounting for Fair Value Hedging Strategies (Applies to AEP)
For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts net income during the period of change.
AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income.
The following table shows the impacts recognized on the balance sheets related to the hedged items in fair value hedging relationships:
Carrying Amount of the Hedged
Assets/(Liabilities) Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Assets/(Liabilities)
December 31, 2021 December 31, 2020 December 31, 2021 December 31, 2020
(in millions)
Long-term Debt (a) (b) $ (952.3) $ (995.9) $ (8.5) $ (51.7)
(a)Amounts included on the balance sheets within Long-term Debt Due within One Year and Long-term Debt, respectively.
(b)Amounts include $(46) million and $(53) million as of December 31, 2021 and 2020, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued.
The pretax effects of fair value hedge accounting on income were as follows:
Years Ended December 31,
2021 2020 2019
(in millions)
Gain (Loss) on Interest Rate Contracts:
Fair Value Hedging Instruments (a) $ (35.5) $ 41.1 $ 31.9
Fair Value Portion of Long-term Debt (a) 35.5 (41.1) (31.9)
(a)Gain (Loss) is included in Interest Expense on the statements of income.
In June 2020, AEP terminated a $500 million notional amount interest rate swap resulting in the discontinuance of the hedging relationship. A gain of $57 million on the fair value of the hedging instrument was settled in cash and recorded within operating activities on the statement of cash flows. Subsequent to the discontinuation of hedge accounting, the remaining adjustment to the carrying amount of the hedged item of $57 million will be amortized on a straight-line basis through November 2027 in Interest Expense on the statements of income.
Accounting for Cash Flow Hedging Strategies (Applies to AEP, APCo, I&M, PSO and SWEPCo)
For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects net income.
Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the years ended 2021, 2020 and 2019, AEP applied cash flow hedging to outstanding power derivatives and the Registrant Subsidiaries did not.
The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the years ended 2021, 2020 and 2019, AEP applied cash flow hedging to outstanding interest rate derivatives. During the years ended 2021 and 2020, APCo applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not. During the year ended 2019, the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives.
For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 - Comprehensive Income.
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were:
Impact of Cash Flow Hedges on AEP’s Balance Sheets
December 31, 2021 December 31, 2020
Commodity Interest Rate Commodity Interest Rate
(in millions)
AOCI Gain (Loss) Net of Tax $ 163.7 $ (21.3) $ (60.6) $ (47.5)
Portion Expected to be Reclassed to Net Income During the Next Twelve Months 106.7 (3.3) (27.1) (5.7)
As of December 31, 2021 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 111 months and 108 months for commodity and interest rate hedges, respectively.
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets
December 31, 2021 December 31, 2020
Interest Rate
Expected to be Expected to be
Reclassified to Reclassified to
Net Income During Net Income During
AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next
Company Net of Tax Twelve Months Net of Tax Twelve Months
(in millions)
AEP Texas $ (1.3) $ (1.1) $ (2.3) $ (1.1)
APCo 7.5 0.8 (0.8) 0.4
I&M (6.7) (1.6) (8.3) (1.6)
PSO - - 0.1 0.1
SWEPCo 1.2 0.1 (0.3) (1.5)
The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.
Credit Risk
Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.
Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit, surety bonds and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required.
Collateral Triggering Events
Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo)
A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. The Registrants have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. AEP had derivative contracts with collateral triggering events in a net liability position as of December 31, 2021, with a total exposure of $9 million. The Registrant Subsidiaries had no derivative contracts with collateral triggering events in a net liability position as of December 31, 2021. The Registrants had no derivative contracts with collateral triggering events in a net liability position as of December 31, 2020.
Cross-Default Triggers (Applies to AEP, APCo, I&M and SWEPCo)
In addition, a majority of non-exchange-traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third-party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount that the exposure has been reduced by cash collateral posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering contractual netting arrangements:
December 31, 2021
Liabilities for Additional
Contracts with Cross Settlement
Default Provisions Liability if Cross
Prior to Contractual Amount of Cash Default Provision
Company Netting Arrangements Collateral Posted is Triggered
(in millions)
AEP $ 159.5 $ - $ 115.4
APCo 0.5 - 0.3
I&M 0.3 - 0.2
PSO 1.7 - 1.7
SWEPCo 2.7 - 2.7
December 31, 2020
Liabilities for Additional
Contracts with Cross Settlement
Default Provisions Liability if Cross
Prior to Contractual Amount of Cash Default Provision
Company Netting Arrangements Collateral Posted is Triggered
(in millions)
AEP $ 188.4 $ - $ 169.2
APCo 4.3 - 3.5
I&M 0.5 - 0.1
SWEPCo 1.8 - 1.8
Warrants Held in Investee (Applies to AEP)
AEP holds an investment in ChargePoint, which completed an initial public offering (IPO) in February 2021 via a reverse merger with a public special purpose acquisition company. Before the IPO, AEP’s interests in ChargePoint consisted of a noncontrolling equity interest of preferred shares, which were accounted for at their historical cost of $8 million as of December 31, 2020, and common share warrants. After the IPO, AEP’s interests in ChargePoint consisted of a noncontrolling equity interest of common shares, which were accounted for at their fair value of $29 million as of December 31, 2021, and common share warrants. AEP recorded an unrealized gain of $26 million associated with the common shares for the twelve months ended December 31, 2021 presented in Other Income (Expense) on AEP’s statements of income.
Management has determined the common share warrants are derivative instruments based on the accounting guidance for “Derivatives and Hedging”. As of December 31, 2021 and 2020, the warrants were valued at $15 million and $32 million, respectively, and were recorded in Deferred Charges and Other Noncurrent Assets on AEP’s balance sheets. AEP recognized an unrealized loss of $17 million and an unrealized gain of $32 million associated with the warrants for the years ended December 31, 2021 and 2020, respectively, presented in Other Income (Expense) on AEP’s statements of income.
Management utilized a Black-Scholes options pricing model to value the warrants as of December 31, 2021 and 2020. The valuation contemplated a liquidity adjustment that resulted in the overall fair value of the warrants being categorized as Level 3 in the fair value hierarchy as of December 31, 2020. After the IPO, there was an observable publicly traded stock price to use in the Black-Scholes options pricing model, which resulted in the warrants being categorized as Level 2 as of December 31, 2021. The common shares are categorized as Level 1 based on the observable publicly traded stock price. See “Fair Value Measurements of Financial Assets and Liabilities” section of Note 11 for additional information.
11. FAIR VALUE MEASUREMENTS
The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise.
Fair Value Measurements of Long-term Debt (Applies to all Registrants)
The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The fair value of AEP’s Equity Units (Level 1) are valued based on publicly-traded securities issued by AEP.
The book values and fair values of Long-term Debt are summarized in the following table:
December 31,
2021 2020
Company Book Value Fair Value Book Value Fair Value
(in millions)
AEP (a)(b)(c) $ 33,454.5 $ 37,564.7 $ 31,072.5 $ 37,457.0
AEP Texas 5,180.8 5,663.8 4,820.4 5,682.6
AEPTCo 4,343.9 4,968.2 3,948.5 4,984.3
APCo 4,938.9 6,037.1 4,834.1 6,391.8
I&M 3,195.0 3,748.0 3,029.9 3,775.3
OPCo 2,968.5 3,437.5 2,430.2 3,154.9
PSO 1,913.5 2,163.7 1,373.8 1,732.1
SWEPCo 3,395.2 3,792.9 2,636.4 3,210.1
(a)The fair value amounts include debt related to AEP’s Equity Units and had a fair value of $1.7 billion and $1.7 billion as of December 31, 2021 and 2020, respectively. See “Equity Units” section of Note 14 for additional information.
(b)The 2021 book value amount excludes Long-term Debt of $1.1 billion classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
(c)The 2021 fair value amount excludes Long-term Debt of $1.2 billion related to KPCo. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
Fair Value Measurements of Other Temporary Investments (Applies to AEP)
Other Temporary Investments include marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS. See “Other Temporary Investments” section of Note 1 for additional information.
The following is a summary of Other Temporary Investments and Restricted Cash:
December 31, 2021
Gross Gross
Unrealized Unrealized Fair
Other Temporary Investments and Restricted Cash Cost Gains Losses Value
(in millions)
Restricted Cash (a) $ 48.0 $ - $ - $ 48.0
Other Cash Deposits 10.0 - - 10.0
Fixed Income Securities - Mutual Funds (b) 154.3 0.5 - 154.8
Equity Securities - Mutual Funds 19.7 35.9 - 55.6
Total Other Temporary Investments and Restricted Cash $ 232.0 $ 36.4 $ - $ 268.4
December 31, 2020
Gross Gross
Unrealized Unrealized Fair
Other Temporary Investments and Restricted Cash Cost Gains Losses Value
(in millions)
Restricted Cash (a) $ 45.6 $ - $ - $ 45.6
Other Cash Deposits 22.7 - - 22.7
Fixed Income Securities - Mutual Funds (b) 120.7 2.8 - 123.5
Equity Securities - Mutual Funds 25.9 28.7 - 54.6
Total Other Temporary Investments and Restricted Cash $ 214.9 $ 31.5 $ - $ 246.4
(a)Primarily represents amounts held for the repayment of debt.
(b)Primarily short and intermediate maturities which may be sold and do not contain maturity dates.
The following table provides the activity for fixed income and equity securities within Other Temporary Investments:
Years Ended December 31,
2021 2020 2019
(in millions)
Proceeds from Investment Sales $ 15.0 $ 50.9 $ 21.2
Purchases of Investments 26.9 41.6 45.0
Gross Realized Gains on Investment Sales 3.6 3.8 -
Gross Realized Losses on Investment Sales - 0.2 0.4
Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M)
Securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF are recorded at fair value. See “Nuclear Trust Funds” section of Note 1 for additional information.
The following is a summary of nuclear trust fund investments:
December 31,
2021 2020
Gross Other-Than- Gross Other-Than-
Fair Unrealized Temporary Fair Unrealized Temporary
Value Gains Impairments Value Gains Impairments
(in millions)
Cash and Cash Equivalents $ 84.7 $ - $ - $ 25.8 $ - $ -
Fixed Income Securities:
United States Government 1,156.4 66.3 (7.9) 1,025.6 98.5 (7.1)
Corporate Debt 76.7 6.7 (2.1) 86.3 9.6 (1.7)
State and Local Government 7.3 0.4 (0.1) 114.3 0.9 (0.4)
Subtotal Fixed Income Securities 1,240.4 73.4 (10.1) 1,226.2 109.0 (9.2)
Equity Securities - Domestic (a) 2,541.9 1,901.3 - 2,054.7 1,400.8 -
Spent Nuclear Fuel and Decommissioning Trusts $ 3,867.0 $ 1,974.7 $ (10.1) $ 3,306.7 $ 1,509.8 $ (9.2)
(a)Amount reported as Gross Unrealized Gains includes unrealized gains of $1.9 billion and $1.4 billion and unrealized losses of $4 million and $9 million as of December 31, 2021 and 2020, respectively.
The following table provides the securities activity within the decommissioning and SNF trusts:
Years Ended December 31,
2021 2020 2019
(in millions)
Proceeds from Investment Sales $ 1,886.4 $ 1,593.4 $ 1,473.0
Purchases of Investments 1,928.2 1,637.2 1,531.0
Gross Realized Gains on Investment Sales 103.2 26.4 76.5
Gross Realized Losses on Investment Sales 16.5 26.1 24.3
The base cost of fixed income securities was $1.2 billion and $1.1 billion as of December 31, 2021 and 2020, respectively. The base cost of equity securities was $641 million and $654 million as of December 31, 2021 and 2020, respectively.
The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2021 was as follows:
Fair Value of Fixed
Income Securities
(in millions)
Within 1 year $ 302.4
After 1 year through 5 years 431.2
After 5 years through 10 years 227.7
After 10 years 279.1
Total $ 1,240.4
Fair Value Measurements of Financial Assets and Liabilities
For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1.
The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
AEP
December 31, 2021
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Other Temporary Investments and Restricted Cash
Restricted Cash $ 48.0 $ - $ - $ - $ 48.0
Other Cash Deposits (a) - - - 10.0 10.0
Fixed Income Securities - Mutual Funds 154.8 - - - 154.8
Equity Securities - Mutual Funds (b) 55.6 - - - 55.6
Total Other Temporary Investments and Restricted Cash 258.4 - - 10.0 268.4
Risk Management Assets
Risk Management Commodity Contracts (c) (d) (i) 7.4 648.5 226.3 (642.4) 239.8
Cash Flow Hedges:
Commodity Hedges (c) - 242.9 19.2 (41.7) 220.4
Fair Value Hedges - 1.2 - - 1.2
Total Risk Management Assets 7.4 892.6 245.5 (684.1) 461.4
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e) 77.7 - - 7.0 84.7
Fixed Income Securities:
United States Government - 1,156.4 - - 1,156.4
Corporate Debt - 76.7 - - 76.7
State and Local Government - 7.3 - - 7.3
Subtotal Fixed Income Securities - 1,240.4 - - 1,240.4
Equity Securities - Domestic (b) 2,541.9 - - - 2,541.9
Total Spent Nuclear Fuel and Decommissioning Trusts 2,619.6 1,240.4 - 7.0 3,867.0
Other Investments (h) 28.8 14.9 - - 43.7
Total Assets $ 2,914.2 $ 2,147.9 $ 245.5 $ (667.1) $ 4,640.5
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (d) (j) $ 5.3 $ 485.0 $ 147.6 $ (383.2) $ 254.7
Cash Flow Hedges:
Commodity Hedges (c) - 54.0 0.6 (41.7) 12.9
Fair Value Hedges - 38.1 - - 38.1
Total Risk Management Liabilities $ 5.3 $ 577.1 $ 148.2 $ (424.9) $ 305.7
AEP
December 31, 2020
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Other Temporary Investments and Restricted Cash
Restricted Cash $ 45.6 $ - $ - $ - $ 45.6
Other Cash Deposits (a) 12.2 - - 10.5 22.7
Fixed Income Securities - Mutual Funds 123.5 - - - 123.5
Equity Securities - Mutual Funds (b) 54.6 - - - 54.6
Total Other Temporary Investments and Restricted Cash 235.9 - - 10.5 246.4
Risk Management Assets
Risk Management Commodity Contracts (c) (f) 0.9 258.8 252.4 (190.0) 322.1
Cash Flow Hedges:
Commodity Hedges (c) - 34.4 3.9 (28.5) 9.8
Interest Rate Hedges - 2.4 - - 2.4
Fair Value Hedges - 2.6 - - 2.6
Total Risk Management Assets 0.9 298.2 256.3 (218.5) 336.9
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e) 16.8 - - 9.0 25.8
Fixed Income Securities:
United States Government - 1,025.6 - - 1,025.6
Corporate Debt - 86.3 - - 86.3
State and Local Government - 114.3 - - 114.3
Subtotal Fixed Income Securities - 1,226.2 - - 1,226.2
Equity Securities - Domestic (b) 2,054.7 - - - 2,054.7
Total Spent Nuclear Fuel and Decommissioning Trusts 2,071.5 1,226.2 - 9.0 3,306.7
Other Investments (h) - - 31.8 - 31.8
Total Assets $ 2,308.3 $ 1,524.4 $ 288.1 $ (199.0) $ 3,921.8
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (f) $ 0.9 $ 244.2 $ 167.2 $ (193.4) $ 218.9
Cash Flow Hedges:
Commodity Hedges (c) - 106.1 7.6 (28.5) 85.2
Interest Rate Hedges - 3.4 - - 3.4
Fair Value Hedges - 4.1 - - 4.1
Total Risk Management Liabilities $ 0.9 $ 357.8 $ 174.8 $ (221.9) $ 311.6
AEP Texas
December 31, 2021
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Restricted Cash for Securitized Funding $ 30.4 $ - $ - $ - $ 30.4
Risk Management Assets
Risk Management Commodity Contracts (c) - 0.6 - (0.6) -
Total Assets $ 30.4 $ 0.6 $ - $ (0.6) $ 30.4
December 31, 2020
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Restricted Cash for Securitized Funding $ 28.7 $ - $ - $ - $ 28.7
Risk Management Assets
Risk Management Commodity Contracts (c) - 0.4 - (0.4) -
Total Assets $ 28.7 $ 0.4 $ - $ (0.4) $ 28.7
APCo
December 31, 2021
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Restricted Cash for Securitized Funding $ 17.6 $ - $ - $ - $ 17.6
Risk Management Assets
Risk Management Commodity Contracts (c) (g) - 5.8 42.0 (5.8) 42.0
Total Assets $ 17.6 $ 5.8 $ 42.0 $ (5.8) $ 59.6
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g) $ - $ 7.2 $ 0.3 $ (6.7) $ 0.8
December 31, 2020
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Restricted Cash for Securitized Funding $ 16.9 $ - $ - $ - $ 16.9
Risk Management Assets
Risk Management Commodity Contracts (c) (g) - 19.4 19.9 (19.2) 20.1
Cash Flow Hedges:
Interest Rate Hedges - 2.4 - - 2.4
Total Risk Management Assets - 21.8 19.9 (19.2) 22.5
Total Assets $ 16.9 $ 21.8 $ 19.9 $ (19.2) $ 39.4
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g) $ - $ 19.5 $ 0.6 $ (18.8) $ 1.3
Cash Flow Hedges:
Interest Rate Hedges - 3.4 - - 3.4
Total Risk Management Liabilities $ - $ 22.9 $ 0.6 $ (18.8) $ 4.7
I&M
December 31, 2021
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g) $ - $ 3.8 $ 7.6 $ (8.1) $ 3.3
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e) 77.7 - - 7.0 84.7
Fixed Income Securities:
United States Government - 1,156.4 - - 1,156.4
Corporate Debt - 76.7 - - 76.7
State and Local Government - 7.3 - - 7.3
Subtotal Fixed Income Securities - 1,240.4 - - 1,240.4
Equity Securities - Domestic (b) 2,541.9 - - - 2,541.9
Total Spent Nuclear Fuel and Decommissioning Trusts 2,619.6 1,240.4 - 7.0 3,867.0
Total Assets $ 2,619.6 $ 1,244.2 $ 7.6 $ (1.1) $ 3,870.3
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g) $ - $ 6.7 $ 8.3 $ (10.0) $ 5.0
December 31, 2020
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g) $ - $ 15.1 $ 2.5 $ (13.9) $ 3.7
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e) 16.8 - - 9.0 25.8
Fixed Income Securities:
United States Government - 1,025.6 - - 1,025.6
Corporate Debt - 86.3 - - 86.3
State and Local Government - 114.3 - - 114.3
Subtotal Fixed Income Securities - 1,226.2 - - 1,226.2
Equity Securities - Domestic (b) 2,054.7 - - - 2,054.7
Total Spent Nuclear Fuel and Decommissioning Trusts 2,071.5 1,226.2 - 9.0 3,306.7
Total Assets $ 2,071.5 $ 1,241.3 $ 2.5 $ (4.9) $ 3,310.4
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g) $ - $ 12.0 $ 0.4 $ (12.2) $ 0.2
OPCo
December 31, 2021
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g) $ - $ 0.5 $ - $ (0.5) $ -
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g) $ - $ - $ 92.5 $ - $ 92.5
December 31, 2020
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g) $ - $ 0.3 $ - $ (0.3) $ -
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g) $ - $ - $ 110.3 $ - $ 110.3
PSO
December 31, 2021
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g) $ - $ 0.3 $ 12.2 $ (0.4) $ 12.1
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g) $ - $ 3.7 $ 0.1 $ (0.1) $ 3.7
December 31, 2020
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g) $ - $ 0.2 $ 10.3 $ (0.2) $ 10.3
SWEPCo
December 31, 2021
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g) $ - $ 0.3 $ 11.0 $ (0.4) $ 10.9
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g) $ - $ 2.1 $ 0.1 $ (0.1) $ 2.1
December 31, 2020
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g) $ - $ 0.1 $ 3.3 $ (0.2) $ 3.2
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g) $ - $ - $ 1.7 $ - $ 1.7
(a)Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or third-parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.
(b)Amounts represent publicly-traded equity securities and equity-based mutual funds.
(c)Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.”
(d)The December 31, 2021 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $1 million in 2022 and $1 million in periods 2023-2025; Level 2 matures $42 million in 2022, $109 million in periods 2023-2025, $10 million in periods 2026-2027 and $3 million in periods 2028-2033; Level 3 matures $82 million in 2022, $10 million in periods 2023-2025, $9 million in periods 2026-2027 and $(17) million in periods 2028-2033. Risk management commodity contracts are substantially comprised of power contracts.
(e)Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
(f)The December 31, 2020 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 2 matures $3 million in periods 2022-2024, $11 million in periods 2025-2026 and $1 million in periods 2027-2033; Level 3 matures $47 million in 2021, $37 million in periods 2022-2024, $14 million in periods 2025-2026 and $(13) million in periods 2027-2033. Risk management commodity contracts are substantially comprised of power contracts.
(g)Substantially comprised of power contracts for the Registrant Subsidiaries.
(h)See “Warrants Held in Investee” section of Note 10 for additional information.
(i)Amount excludes Risk Management Assets of $6 million classified as Assets Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
(j)Amount excludes Risk Management Liabilities of $0.1 million classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:
Year Ended December 31, 2021 AEP APCo I&M OPCo PSO SWEPCo
(in millions)
Balance as of December 31, 2020 $ 113.3 $ 19.3 $ 2.1 $ (110.3) $ 10.3 $ 1.6
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 48.6 8.3 (0.1) 2.4 16.1 9.5
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) (45.2) - - - - -
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) 24.2 - - - - -
Settlements (89.0) (28.0) (2.2) 6.3 (26.4) (15.5)
Transfers into Level 3 (d) (e) (3.8) - - - - -
Transfers out of Level 3 (e) (34.4) - - - - -
Changes in Fair Value Allocated to Regulated Jurisdictions (f) 89.4 42.1 (0.5) 9.1 12.1 15.3
Assets and Liabilities Held for Sale related to KPCo (g) (h) (5.8) - - - - -
Balance as of December 31, 2021 $ 97.3 $ 41.7 $ (0.7) $ (92.5) $ 12.1 $ 10.9
Year Ended December 31, 2020 AEP APCo I&M OPCo PSO SWEPCo
(in millions)
Balance as of December 31, 2019 $ 109.9 $ 37.7 $ 5.8 $ (103.6) $ 15.8 $ 1.4
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 39.5 13.2 2.5 (1.6) 11.9 2.8
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 35.3 - - - - -
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) 13.8 - - - - -
Settlements (113.1) (51.6) (8.6) 8.9 (27.6) (6.6)
Transfers into Level 3 (d) (e) (3.8) - - - - -
Transfers out of Level 3 (e) 5.6 0.7 0.4 - - -
Changes in Fair Value Allocated to Regulated Jurisdictions (f) 26.1 19.3 2.0 (14.0) 10.2 4.0
Balance as of December 31, 2020 $ 113.3 $ 19.3 $ 2.1 $ (110.3) $ 10.3 $ 1.6
Year Ended December 31, 2019 AEP APCo I&M OPCo PSO SWEPCo
(in millions)
Balance as of December 31, 2018 $ 131.2 $ 57.8 $ 8.9 $ (99.4) $ 9.5 $ 2.3
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 15.8 (13.9) 4.7 (0.9) 13.5 6.0
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) (0.1) - - - - -
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) (15.1) - - - - -
Settlements (117.6) (42.5) (13.0) 6.6 (23.0) (9.6)
Transfers into Level 3 (d) (e) (0.6) (0.5) (0.3) - - -
Transfers out of Level 3 (e) 35.6 (0.7) (0.4) - - -
Changes in Fair Value Allocated to Regulated Jurisdictions (f)
60.7 37.5 5.9 (9.9) 15.8 2.7
Balance as of December 31, 2019 $ 109.9 $ 37.7 $ 5.8 $ (103.6) $ 15.8 $ 1.4
(a)Included in revenues on the statements of income.
(b)Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c)Included in cash flow hedges on the statements of comprehensive income.
(d)Represents existing assets or liabilities that were previously categorized as Level 2.
(e)Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
(f)Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These changes in fair value are recorded as regulatory liabilities for net gains and as regulatory assets for net losses or accounts payable.
(g)Amount excludes Risk Management Assets of $6.4 million classified as Assets Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
(h)Amount excludes Risk Management Liabilities of $0.6 million classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions:
AEP
December 31, 2021
Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input Low High Average (c)
(in millions)
Energy Contracts (g) $ 164.4 $ 135.2 Discounted Cash Flow Forward Market Price (a) $ 10.30 $ 76.70 $ 37.11
Natural Gas Contracts 3.6 - Discounted Cash Flow Forward Market Price (b) 3.11 4.02 3.47
FTRs (e) (f) 77.5 13.0 Discounted Cash Flow Forward Market Price (a) (23.93) 26.38 0.86
Total $ 245.5 $ 148.2
December 31, 2020
Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input Low High Average
(in millions)
Energy Contracts $ 213.5 $ 169.7 Discounted Cash Flow Forward Market Price (a) (c) $ 5.33 $ 100.47 $ 32.73
Natural Gas Contracts - 1.7 Discounted Cash Flow Forward Market Price (b) (c) 2.18 2.77 2.40
FTRs 42.8 3.4 Discounted Cash Flow Forward Market Price (a) (c) (15.08) 9.66 0.19
Other Investments 31.8 - Black-Scholes Model Liquidity Adjustment (d) 10 % 20 % 15 %
Total $ 288.1 $ 174.8
APCo
December 31, 2021
Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input (a) Low High Average (c)
(in millions)
Energy Contracts $ - $ 0.3 Discounted Cash Flow Forward Market Price $ 32.20 $ 56.54 $ 44.77
FTRs 42.0 - Discounted Cash Flow Forward Market Price (0.30) 26.38 2.63
Total $ 42.0 $ 0.3
December 31, 2020
Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input (a) Low High Average (c)
(in millions)
Energy Contracts $ 1.0 $ 0.6 Discounted Cash Flow Forward Market Price $ 10.84 $ 41.09 $ 25.08
FTRs 18.9 - Discounted Cash Flow Forward Market Price 0.04 5.61 1.13
Total $ 19.9 $ 0.6
I&M
December 31, 2021
Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input (a) Low High Average (c)
(in millions)
Energy Contracts $ - $ 0.2 Discounted Cash Flow Forward Market Price $ 32.20 $ 56.54 $ 44.77
FTRs 7.6 8.1 Discounted Cash Flow Forward Market Price (5.45) 17.78 (0.12)
Total $ 7.6 $ 8.3
December 31, 2020
Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input (a) Low High Average (c)
(in millions)
Energy Contracts $ 0.6 $ 0.3 Discounted Cash Flow Forward Market Price $ 10.84 $ 41.09 $ 25.08
FTRs 1.9 0.1 Discounted Cash Flow Forward Market Price (1.96) 3.69 0.33
Total $ 2.5 $ 0.4
OPCo
December 31, 2021
Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input (a) Low High Average (c)
(in millions)
Energy Contracts $ - $ 92.5 Discounted Cash Flow Forward Market Price $ 14.26 $ 52.98 $ 30.68
December 31, 2020
Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input (a) Low High Average (c)
(in millions)
Energy Contracts $ - $ 110.3 Discounted Cash Flow Forward Market Price $ 16.19 $ 46.98 $ 28.30
PSO
December 31, 2021
Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input (a) Low High Average (c)
(in millions)
FTRs $ 12.2 $ 0.1 Discounted Cash Flow Forward Market Price $ (18.39) $ 1.87 $ (2.57)
December 31, 2020
Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input (a) Low High Average (c)
(in millions)
FTRs $ 10.3 $ - Discounted Cash Flow Forward Market Price $ (6.93) $ 0.48 $ (1.93)
SWEPCo
December 31, 2021
Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input Low High Average (c)
(in millions)
Natural Gas Contracts $ 3.6 $ - Discounted Cash Flow Forward Market Price (b) $ 3.11 $ 4.02 $ 3.47
FTRs 7.4 0.1 Discounted Cash Flow Forward Market Price (a) (18.39) 1.87 (2.57)
Total $ 11.0 $ 0.1
December 31, 2020
Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input Low High Average (c)
(in millions)
Natural Gas Contracts $ - $ 1.7 Discounted Cash Flow Forward Market Price (b) $ 2.18 $ 2.77 $ 2.41
FTRs 3.3 - Discounted Cash Flow Forward Market Price (a) (6.93) 0.48 (1.93)
Total $ 3.3 $ 1.7
(a)Represents market prices in dollars per MWh.
(b)Represents market prices in dollars per MMBtu.
(c)The weighted-average is the product of the forward market price of the underlying commodity and volume weighted by term.
(d)Represents percentage discount applied to the publically available share price.
(e)Amount excludes Risk Management Assets of $6 million classified as Assets Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
(f)Amount excludes Risk Management Liabilities of $0.5 million classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
(g)Amount excludes Risk Management Liabilities of $0.1 million classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
The following table provides the measurement uncertainty of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts, Natural Gas Contracts, FTRs and Other Investments for the Registrants as of December 31, 2021 and 2020:
Uncertainty of Fair Value Measurements
Significant Unobservable Input Position Change in Input Impact on Fair Value
Measurement
Forward Market Price Buy
Increase (Decrease) Higher (Lower)
Forward Market Price Sell Increase (Decrease) Lower (Higher)
Liquidity Adjustment Buy Increase (Decrease) Lower (Higher)
12. INCOME TAXES
The disclosures in this note apply to all Registrants unless indicated otherwise.
Income Tax Expense (Benefit)
The details of the Registrants’ Income Tax Expense (Benefit) as reported are as follows:
Year Ended December 31, 2021 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Federal:
Current $ (27.8) $ (1.2) $ 69.8 $ 5.0 $ 26.9 $ 6.8 $ (109.6) $ (16.7)
Deferred 182.6 40.5 54.1 14.9 (35.5) 25.2 105.6 26.2
Total Federal 154.8 39.3 123.9 19.9 (8.6) 32.0 (4.0) 9.5
State and Local:
Current 6.0 3.0 5.8 2.2 (0.6) (3.1) - 0.4
Deferred (a) (45.3) 0.8 14.4 - (1.4) 5.5 8.1 (10.5)
Total State and Local (39.3) 3.8 20.2 2.2 (2.0) 2.4 8.1 (10.1)
Income Tax Expense (Benefit) $ 115.5 $ 43.1 $ 144.1 $ 22.1 $ (10.6) $ 34.4 $ 4.1 $ (0.6)
(a)Benefit at AEP is primarily due to an out of period adjustment related to Deferred Income Taxes and Income Tax Expense (Benefit). Management concluded the misstatement and subsequent correction was not material to prior or current period financial statements.
Year Ended December 31, 2020 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Federal:
Current $ (138.2) $ 5.2 $ 22.2 $ 21.4 $ 11.3 $ (26.6) $ (11.4) $ (13.6)
Deferred 146.9 (15.4) 65.4 (27.1) (20.6) 74.0 8.3 19.6
Total Federal 8.7 (10.2) 87.6 (5.7) (9.3) 47.4 (3.1) 6.0
State and Local:
Current (16.7) (0.1) 2.8 9.3 1.9 (5.4) 0.1 (8.2)
Deferred 48.5 (0.9) 16.3 0.7 (0.1) 3.2 8.2 11.6
Total State and Local 31.8 (1.0) 19.1 10.0 1.8 (2.2) 8.3 3.4
Income Tax Expense (Benefit) $ 40.5 $ (11.2) $ 106.7 $ 4.3 $ (7.5) $ 45.2 $ 5.2 $ 9.4
Year Ended December 31, 2019 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Federal:
Current $ (7.4) $ (31.8) $ 23.7 $ 36.7 $ 48.1 $ (10.0) $ 25.5 $ 6.9
Deferred (71.6) (24.7) 71.7 (126.1) (57.1) 40.6 (26.0) (10.0)
Total Federal (79.0) (56.5) 95.4 (89.4) (9.0) 30.6 (0.5) (3.1)
State and Local:
Current 4.4 2.9 2.4 12.0 (2.4) 1.1 0.2 0.8
Deferred 61.7 - 19.6 (0.6) 0.8 3.2 7.8 (2.4)
Total State and Local 66.1 2.9 22.0 11.4 (1.6) 4.3 8.0 (1.6)
Income Tax Expense (Benefit) $ (12.9) $ (53.6) $ 117.4 $ (78.0) $ (10.6) $ 34.9 $ 7.5 $ (4.7)
The following are reconciliations for the Registrants between the federal income taxes computed by multiplying pretax income by the federal statutory tax rate and the income taxes reported:
AEP Years Ended December 31,
2021 2020 2019
(in millions)
Net Income $ 2,488.1 $ 2,196.7 $ 1,919.8
Less: Equity Earnings - Dolet Hills (3.4) (2.9) (3.0)
Income Tax Expense (Benefit) 115.5 40.5 (12.9)
Pretax Income $ 2,600.2 $ 2,234.3 $ 1,903.9
Income Taxes on Pretax Income at Statutory Rate (21%)
$ 546.0 $ 469.2 $ 399.8
Increase (Decrease) in Income Taxes Resulting from the Following Items:
Reversal of Origination Flow-Through 25.9 26.5 20.4
Investment Tax Credit Amortization (22.0) (18.8) (13.0)
Production Tax Credits (98.8) (83.1) (59.6)
State and Local Income Taxes, Net 39.4 25.1 52.2
Removal Costs (20.0) (18.6) (22.2)
AFUDC (30.6) (32.5) (37.1)
Tax Adjustments (a) (55.1) - -
Tax Reform Excess ADIT Reversal (255.6) (268.2) (353.2)
CARES Act - (48.0) -
Other (13.7) (11.1) (0.2)
Income Tax Expense (Benefit) $ 115.5 $ 40.5 $ (12.9)
Effective Income Tax Rate 4.4 % 1.8 % (0.7) %
(a)Represents an out of period adjustment related to Deferred Income Taxes and Income Tax Expense (Benefit). Management concluded the misstatement and subsequent correction was not material to prior or current period financial statements.
AEP Texas Years Ended December 31,
2021 2020 2019
(in millions)
Net Income $ 289.8 $ 241.0 $ 178.3
Income Tax Expense (Benefit) 43.1 (11.2) (53.6)
Pretax Income $ 332.9 $ 229.8 $ 124.7
Income Taxes on Pretax Income at Statutory Rate (21%)
$ 69.9 $ 48.3 $ 26.2
Increase (Decrease) in Income Taxes Resulting from the Following Items:
State and Local Income Taxes, Net 2.4 (0.8) 2.3
AFUDC (4.5) (4.1) (3.2)
Parent Company Loss Benefit (3.2) (4.5) (3.8)
Tax Reform Excess ADIT Reversal (21.3) (47.9) (73.4)
Other (0.2) (2.2) (1.7)
Income Tax Expense (Benefit) $ 43.1 $ (11.2) $ (53.6)
Effective Income Tax Rate 12.9 % (4.9) % (43.0) %
AEPTCo Years Ended December 31,
2021 2020 2019
(in millions)
Net Income $ 591.7 $ 423.4 $ 439.7
Income Tax Expense 144.1 106.7 117.4
Pretax Income $ 735.8 $ 530.1 $ 557.1
Income Taxes on Pretax Income at Statutory Rate (21%)
$ 154.5 $ 111.3 $ 117.0
Increase (Decrease) in Income Taxes Resulting from the Following Items:
State and Local Income Taxes, Net 19.8 15.1 17.4
AFUDC (14.1) (15.5) (17.7)
Parent Company Loss Benefit (18.3) (7.0) (4.2)
Other 2.2 2.8 4.9
Income Tax Expense $ 144.1 $ 106.7 $ 117.4
Effective Income Tax Rate 19.6 % 20.1 % 21.1 %
APCo Years Ended December 31,
2021 2020 2019
(in millions)
Net Income $ 348.9 $ 369.7 $ 306.3
Income Tax Expense (Benefit) 22.1 4.3 (78.0)
Pretax Income $ 371.0 $ 374.0 $ 228.3
Income Taxes on Pretax Income at Statutory Rate (21%)
$ 77.9 $ 78.5 $ 47.9
Increase (Decrease) in Income Taxes Resulting from the Following Items:
Reversal of Origination Flow-Through 11.7 12.7 10.8
State and Local Income Taxes, Net 2.1 7.9 9.0
Removal Costs (7.3) (5.7) (6.4)
AFUDC (4.6) (4.5) (5.2)
Parent Company Loss Benefit - (6.2) (4.1)
Tax Adjustments (a) 4.5 - -
Tax Reform Excess ADIT Reversal (60.5) (72.3) (130.4)
Federal Return to Provision (1.6) (7.2) (1.0)
Other (0.1) 1.1 1.4
Income Tax Expense (Benefit) $ 22.1 $ 4.3 $ (78.0)
Effective Income Tax Rate 6.0 % 1.1 % (34.2) %
(a)Represents an out of period adjustment related to Deferred Income Taxes and Income Tax Expense (Benefit). Management concluded the misstatement and subsequent correction was not material to prior or current period financial statements.
I&M Years Ended December 31,
2021 2020 2019
(in millions)
Net Income $ 279.8 $ 284.8 $ 269.4
Income Tax Benefit (10.6) (7.5) (10.6)
Pretax Income $ 269.2 $ 277.3 $ 258.8
Income Taxes on Pretax Income at Statutory Rate (21%)
$ 56.5 $ 58.2 $ 54.3
Increase (Decrease) in Income Taxes Resulting from the Following Items:
Reversal of Origination Flow-Through 3.5 1.6 4.0
Investment Tax Credit Amortization (6.4) (4.5) (3.6)
State and Local Income Taxes, Net (1.3) 1.5 (1.2)
Removal Costs (9.7) (10.5) (12.8)
AFUDC (2.7) (2.4) (4.1)
Parent Company Loss Benefit (2.8) (6.4) (3.3)
Tax Reform Excess ADIT Reversal (46.3) (46.8) (42.5)
Other (1.4) 1.8 (1.4)
Income Tax Benefit $ (10.6) $ (7.5) $ (10.6)
Effective Income Tax Rate (3.9) % (2.7) % (4.1) %
OPCo Years Ended December 31,
2021 2020 2019
(in millions)
Net Income $ 253.6 $ 271.4 $ 297.1
Income Tax Expense 34.4 45.2 34.9
Pretax Income $ 288.0 $ 316.6 $ 332.0
Income Taxes on Pretax Income at Statutory Rate (21%)
$ 60.5 $ 66.5 $ 69.7
Increase (Decrease) in Income Taxes Resulting from the Following Items:
Reversal of Origination Flow-Through 2.2 3.7 (1.4)
State and Local Income Taxes, Net - (1.7) 3.4
AFUDC (2.3) (2.6) (3.8)
Tax Adjustments (a) 8.9 - -
Tax Reform Excess ADIT Reversal (32.6) (27.2) (27.3)
Federal Return to Provision (1.2) 6.5 (3.7)
Other (1.1) - (2.0)
Income Tax Expense $ 34.4 $ 45.2 $ 34.9
Effective Income Tax Rate 11.9 % 14.3 % 10.5 %
(a)Represents an out of period adjustment related to Deferred Income Taxes and Income Tax Expense (Benefit). Management concluded the misstatement and subsequent correction was not material to prior or current period financial statements.
PSO Years Ended December 31,
2021 2020 2019
(in millions)
Net Income $ 141.1 $ 123.0 $ 137.6
Income Tax Expense 4.1 5.2 7.5
Pretax Income $ 145.2 $ 128.2 $ 145.1
Income Taxes on Pretax Income at Statutory Rate (21%)
$ 30.5 $ 26.9 $ 30.5
Increase (Decrease) in Income Taxes Resulting from the Following Items:
Investment Tax Credit Amortization (1.8) (2.1) (0.5)
Production Tax Credits (6.0) - -
State and Local Income Taxes, Net 6.4 6.5 6.3
Parent Company Loss Benefit - (0.2) (2.1)
Tax Reform Excess ADIT Reversal (25.4) (25.5) (24.5)
Other 0.4 (0.4) (2.2)
Income Tax Expense $ 4.1 $ 5.2 $ 7.5
Effective Income Tax Rate 2.8 % 4.1 % 5.2 %
SWEPCo Years Ended December 31,
2021 2020 2019
(in millions)
Net Income $ 242.1 $ 183.7 $ 162.2
Less: Equity Earnings - Dolet Hills (3.4) (2.9) (3.0)
Income Tax Expense (Benefit) (0.6) 9.4 (4.7)
Pretax Income $ 238.1 $ 190.2 $ 154.5
Income Taxes on Pretax Income at Statutory Rate (21%)
$ 50.0 $ 39.9 $ 32.4
Increase (Decrease) in Income Taxes Resulting from the Following Items:
Reversal of Origination Flow-Through 1.8 1.9 1.9
Depletion (2.7) (3.4) (3.4)
Production Tax Credits (7.2) - -
State and Local Income Taxes, Net (8.0) 2.7 (1.3)
Parent Company Loss Benefit - (5.6) (1.6)
Tax Reform Excess ADIT Reversal (31.1) (21.9) (29.9)
Other (3.4) (4.2) (2.8)
Income Tax Expense (Benefit) $ (0.6) $ 9.4 $ (4.7)
Effective Income Tax Rate (0.3) % 4.9 % (3.0) %
Net Deferred Tax Liability
The following tables show elements of the net deferred tax liability and significant temporary differences for each Registrant:
AEP December 31,
2021 2020
(in millions)
Deferred Tax Assets $ 3,277.0 $ 3,259.7
Deferred Tax Liabilities (11,479.5) (11,500.6)
Net Deferred Tax Liabilities $ (8,202.5) $ (8,240.9)
Property Related Temporary Differences $ (7,020.3) $ (7,340.5)
Amounts Due to Customers for Future Income Taxes 1,033.0 1,075.8
Deferred State Income Taxes (1,116.7) (1,317.6)
Securitized Assets (128.8) (140.0)
Regulatory Assets (645.4) (391.6)
Accrued Nuclear Decommissioning (743.2) (626.4)
Net Operating Loss Carryforward 285.7 112.9
Tax Credit Carryforward 439.8 323.6
Operating Lease Liability 114.2 183.7
Investment in Partnership (392.1) (362.0)
All Other, Net (28.7) 241.2
Net Deferred Tax Liabilities $ (8,202.5) $ (8,240.9)
AEP Texas December 31,
2021 2020
(in millions)
Deferred Tax Assets $ 173.8 $ 183.6
Deferred Tax Liabilities (1,262.7) (1,200.3)
Net Deferred Tax Liabilities $ (1,088.9) $ (1,016.7)
Property Related Temporary Differences $ (1,060.2) $ (1,039.6)
Amounts Due to Customers for Future Income Taxes 110.0 114.4
Deferred State Income Taxes (32.2) (29.1)
Securitized Transition Assets (84.4) (90.2)
Regulatory Assets (45.1) (47.4)
Operating Lease Liability 15.8 18.0
All Other, Net 7.2 57.2
Net Deferred Tax Liabilities $ (1,088.9) $ (1,016.7)
AEPTCo December 31,
2021 2020
(in millions)
Deferred Tax Assets $ 158.8 $ 166.5
Deferred Tax Liabilities (1,121.7) (1,073.4)
Net Deferred Tax Liabilities $ (962.9) $ (906.9)
Property Related Temporary Differences $ (997.0) $ (937.8)
Amounts Due to Customers for Future Income Taxes 118.2 118.9
Deferred State Income Taxes (94.5) (98.3)
Net Operating Loss Carryforward 8.1 13.2
All Other, Net 2.3 (2.9)
Net Deferred Tax Liabilities $ (962.9) $ (906.9)
APCo December 31,
2021 2020
(in millions)
Deferred Tax Assets $ 495.1 $ 500.6
Deferred Tax Liabilities (2,299.8) (2,250.5)
Net Deferred Tax Liabilities $ (1,804.7) $ (1,749.9)
Property Related Temporary Differences $ (1,476.5) $ (1,412.0)
Amounts Due to Customers for Future Income Taxes 182.1 198.3
Deferred State Income Taxes (288.8) (336.5)
Securitized Assets (39.3) (44.7)
Regulatory Assets (177.0) (114.8)
Operating Lease Liability 14.2 16.7
All Other, Net (19.4) (56.9)
Net Deferred Tax Liabilities $ (1,804.7) $ (1,749.9)
I&M December 31,
2021 2020
(in millions)
Deferred Tax Assets $ 1,072.2 $ 989.5
Deferred Tax Liabilities (2,172.4) (2,053.9)
Net Deferred Tax Liabilities $ (1,100.2) $ (1,064.4)
Property Related Temporary Differences $ (286.2) $ (409.2)
Amounts Due to Customers for Future Income Taxes 135.5 147.9
Deferred State Income Taxes (222.0) (211.1)
Regulatory Assets (23.6) (16.5)
Accrued Nuclear Decommissioning (743.2) (626.4)
Operating Lease Liability 13.5 46.6
All Other, Net 25.8 4.3
Net Deferred Tax Liabilities $ (1,100.2) $ (1,064.4)
OPCo December 31,
2021 2020
(in millions)
Deferred Tax Assets $ 204.4 $ 210.8
Deferred Tax Liabilities (1,205.3) (1,165.9)
Net Deferred Tax Liabilities $ (1,000.9) $ (955.1)
Property Related Temporary Differences $ (1,042.0) $ (1,016.0)
Amounts Due to Customers for Future Income Taxes 117.7 121.1
Deferred State Income Taxes (58.8) (40.7)
Regulatory Assets (39.8) (53.7)
Operating Lease Liability 17.2 19.4
All Other, Net 4.8 14.8
Net Deferred Tax Liabilities $ (1,000.9) $ (955.1)
PSO December 31,
2021 2020
(in millions)
Deferred Tax Assets $ 170.0 $ 239.8
Deferred Tax Liabilities (952.3) (928.3)
Net Deferred Tax Liabilities $ (782.3) $ (688.5)
Property Related Temporary Differences $ (708.6) $ (661.8)
Amounts Due to Customers for Future Income Taxes 111.5 118.5
Deferred State Income Taxes (83.2) (107.7)
Regulatory Assets (228.0) (39.1)
Net Operating Loss Carryforward 111.4 12.9
All Other, Net 14.6 (11.3)
Net Deferred Tax Liabilities $ (782.3) $ (688.5)
SWEPCo December 31,
2021 2020
(in millions)
Deferred Tax Assets $ 336.4 $ 338.1
Deferred Tax Liabilities (1,424.0) (1,355.7)
Net Deferred Tax Liabilities $ (1,087.6) $ (1,017.6)
Property Related Temporary Differences $ (989.6) $ (985.1)
Amounts Due to Customers for Future Income Taxes 154.8 162.7
Deferred State Income Taxes (234.9) (214.7)
Regulatory Assets (101.4) (26.2)
Net Operating Loss Carryforward 67.4 33.4
All Other, Net 16.1 12.3
Net Deferred Tax Liabilities $ (1,087.6) $ (1,017.6)
AEP System Tax Allocation Agreement
AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax loss of the parent company (Parent Company Loss Benefit) to the AEP System subsidiaries with taxable income reducing their current tax expense proportionately. The consolidated NOL of the AEP System is allocated to each company in the consolidated group with taxable losses. With the exception of the allocation of the consolidated AEP System NOL, the loss of the Parent and tax credits, the method of allocation reflects a separate return result for each company in the consolidated group.
Federal and State Income Tax Audit Status
The statute of limitations for the IRS to examine AEP and subsidiaries originally filed federal return has expired for tax years 2016 and earlier. In the third quarter of 2019, AEP and subsidiaries elected to amend the 2014 through 2017 federal returns. In the first quarter of 2020, the IRS notified AEP that it was beginning an examination of these amended returns, including the net operating loss carryback to 2015 that originated in the 2017 return. As of December 31, 2021, the IRS has not issued any proposed adjustments and the IRS is limited in their proposed adjustments to the amount AEP claimed on the amended returns. AEP has agreed to extend the statute of limitations on the 2017 tax return to December 31, 2022 to allow time for the audit to be completed and the Congressional Joint Committee on Taxation to approve the associated refund claim.
AEP and subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns, and AEP and subsidiaries are currently under examination in several state and local jurisdictions. The Registrants are no longer subject to state or local examinations by tax authorities for years before 2012. In addition, management is monitoring and continues to evaluate the potential impact of federal legislation and corresponding state conformity.
Net Income Tax Operating Loss Carryforward
As of December 31, 2021, AEP has no federal net income tax operating loss carryforward from prior years but does expect to generate a tax operating loss of $674 million for tax year 2021. AEP, AEPTCo, APCo, OPCo, PSO and SWEPCo have state net income tax operating loss carryforwards as indicated in the table below:
State Net Income
Tax Operating Loss Years of
Company State/Municipality Carryforward Expiration
(in millions)
AEP Arkansas $ 161.8 2022 - 2031
AEP Colorado 82.8 2041
AEP Illinois 55.2 2031 - 2041
AEP Indiana 304.4 2039 - 2041
AEP Kentucky 230.4 2030 - 2037
AEP Louisiana 566.7 NA
AEP Michigan 65.2 2029 - 2031
AEP New Jersey 36.5 2036 - 2041
AEP New Mexico 32.6 2037 - 2039
AEP Ohio Municipal 1,027.9 2022 - 2026
AEP Oklahoma 1,357.1 2034 - 2037
AEP Pennsylvania 82.7 2030 - 2041
AEP Tennessee 53.0 2030 - 2036
AEP Virginia 20.9 2030 - 2037
AEP West Virginia 99.5 2029 - 2037
AEPTCo Oklahoma 107.8 2034 - 2037
APCo West Virginia 62.9 NA
OPCo Ohio Municipal 76.0 2022 - 2026
PSO Oklahoma 1,229.8 2034 - 2037
SWEPCo Arkansas 160.7 2022 - 2031
SWEPCo Louisiana 554.7 NA
As of December 31, 2021, AEP recorded a valuation allowance of $25 million, against certain state and municipal net income tax operating loss carryforwards since future taxable income is not expected to be sufficient to realize the remaining state net income tax operating loss tax benefits before the carryforward expires. Management anticipates future taxable income will be sufficient to realize the remaining state net income tax operating loss tax benefits before the carryforward expires for each state.
Tax Credit Carryforward
Federal and state net income tax operating losses sustained in 2016, 2017 and 2019 resulted in unused federal and state income tax credits. As of December 31, 2021, the Registrants have federal tax credit carryforwards and AEP and PSO have state tax credit carryforwards as indicated in the table below. If these credits are not utilized, federal general business tax credits will expire in the years 2036 through 2041 and state tax credits will remain available indefinitely.
Total Federal Total State
Tax Credit Tax Credit
Company Carryforward Carryforward
(in millions)
AEP $ 439.8 $ 38.8
AEP Texas 0.3 -
AEPTCo 0.1 -
APCo 1.3 -
I&M 16.9 -
OPCo 0.4 -
PSO 6.3 38.8
SWEPCo 7.9 -
The Registrants anticipate future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused.
Valuation Allowance
AEP assesses the available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate tax character will be generated to realize the benefits of existing deferred tax assets. When the evaluation of the evidence indicates that it is more-likely-than-not that AEP will not be able to realize the benefits of existing deferred tax assets, a valuation allowance is recorded to reduce existing deferred tax assets to the net realizable amount. Objective evidence evaluated includes whether AEP has a history of recognizing income, future reversals of existing temporary differences and tax planning strategies.
Valuation allowance activity for the years ended December 31, 2021, 2020 and 2019 was not material.
Uncertain Tax Positions
The reconciliations of the beginning and ending amounts of unrecognized tax benefits for AEP are presented below. The amount and activity of unrecognized tax benefits for Registrant Subsidiaries was immaterial for periods presented:
AEP
2021 2020 2019
(in millions)
Balance as of January 1, $ 13.2 $ 24.1 $ 14.6
Increase - Tax Positions Taken During a Prior Period 1.2 0.6 8.8
Decrease - Tax Positions Taken During a Prior Period (3.2) (14.5) (2.1)
Increase - Tax Positions Taken During the Current Year 3.1 3.0 2.8
Decrease - Tax Positions Taken During the Current Year - - -
Decrease - Settlements with Taxing Authorities - - -
Decrease - Lapse of the Applicable Statute of Limitations - - -
Balance as of December 31, $ 14.3 $ 13.2 $ 24.1
Management believes that there will be no significant net increase or decrease in unrecognized benefits within 12 months of the reporting date. The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for AEP as of December 31, 2021, 2020 and 2019 were $14 million, $12 million, and $20 million, respectively.
Federal and State Tax Legislation
In March 2020, the CARES Act was signed into law. The CARES Act includes tax relief provisions including a 5-year NOL carryback from years 2018-2020. In the third quarter of 2020, AEP requested a $95 million refund of taxes paid in 2014 under the 5-year NOL carryback provision of the CARES Act. AEP carried back a NOL generated on the 2019 Federal income tax return at a 21% federal corporate income tax rate to the 2014 Federal income tax return at a 35% corporate income tax rate. As a result of the change in the corporate income tax rates between the two periods, AEP realized a tax benefit of $48 million during the third quarter of 2020 primarily at the Generation & Marketing segment. AEP received the $95 million refund in the fourth quarter of 2021.
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 IRC 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 in June 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 is extended to six years. Prior guidance (IRS 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 is 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 used.
In April 2021, West Virginia enacted House Bill (HB) 2026. HB 2026 changes the state income tax apportionment formula from a ratio that includes property, payroll and sales to a single sales factor apportionment regime effective for tax years beginning on or after January 1, 2022. HB 2026 also eliminates the “throw out” rule related to sales of tangible personal property for sales factor apportionment calculation purposes and introduces a market-based sourcing for sales of services and intangible property. During 2021, AEP recorded $23 million in Income Tax Expense as a result of remeasuring West Virginia deferred taxes under the new apportionment methodology. The enacted legislation does not impact AEP Texas, PSO or SWEPCo.
In May 2021, Oklahoma enacted HB 2960. HB 2960 reduces the Oklahoma corporate income tax rate from 6% to 4%. During 2021, AEP recorded an immaterial amount of Income Tax Benefit as a result of remeasuring Oklahoma deferred taxes at the lowered statutory tax rate of 4%. The enacted legislation does not impact APCo, I&M or OPCo.
In November 2021, Louisiana approved Constitutional Amendment 2, thereby also enacting HB 292. HB 292 reduces the Louisiana corporate income tax rate from 8% to 7.5%. In the fourth quarter of 2021, AEP recorded an immaterial amount of Income Tax Expense as a result of remeasuring Louisiana deferred taxes at the lowered statutory tax rate of 7.5%. The enacted legislation does not impact AEP Texas, APCo, I&M, OPCo or PSO.
In December 2021, Arkansas enacted HB 1001. HB 1001 reduces the Arkansas corporate income tax rate from 5.9% to 5.7%, with additional reductions to 5.3% contingent upon future events. In the fourth quarter of 2021, AEP recorded an immaterial amount of Income Tax Expense as a result of remeasuring Arkansas deferred taxes at the lowered statutory tax rate of 5.7%. The enacted legislation does not impact AEP Texas, APCo, I&M, OPCo or PSO.
13. LEASES
The disclosures in this note apply to all Registrants unless indicated otherwise.
The Registrants lease property, plant and equipment including, but not limited to, fleet, information technology and real estate leases. These leases require payments of non-lease components, including related property taxes, operating and maintenance costs. AEP does not separate non-lease components from associated lease components. Many of these leases have purchase or renewal options. Leases not renewed are often replaced by other leases. Options to renew or purchase a lease are included in the measurement of lease assets and liabilities if it is reasonably certain the Registrant will exercise the option.
Lease obligations are measured using the discount rate implicit in the lease when that rate is readily determinable. AEP has visibility into the rate implicit in the lease when assets are leased from selected financial institutions under master leasing agreements. When the implicit rate is not readily determinable, the Registrants measure their lease obligation using their estimated secured incremental borrowing rate. Incremental borrowing rates are comprised of an underlying risk-free rate and a secured credit spread relative to the lessee on a matched maturity basis.
Operating lease rentals and finance lease amortization costs are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. The amortization costs related to the Rockport finance lease are charged to Depreciation and Amortization, see “Rockport Lease” below for additional information. Interest on finance lease liabilities is generally charged to Interest Expense. Lease costs associated with capital projects are included in Property, Plant and Equipment on the balance sheets. For regulated operations with finance leases, a finance lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Finance leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs were as follows:
Year Ended December 31, 2021 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Operating Lease Cost
$ 275.3 $ 18.4 $ 1.7 $ 19.3 $ 90.2 $ 19.0 $ 8.7 $ 12.1
Finance Lease Cost:
Amortization of Right-of-Use Assets
74.7 6.7 - 7.7 12.9 4.9 3.2 11.0
Interest on Lease Liabilities
14.4 1.4 - 2.4 3.0 0.8 0.6 2.5
Total Lease Rental Costs (a) $ 364.4 $ 26.5 $ 1.7 $ 29.4 $ 106.1 $ 24.7 $ 12.5 $ 25.6
Year Ended December 31, 2020 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Operating Lease Cost
$ 279.6 $ 17.4 $ 2.6 $ 19.1 $ 101.5 $ 17.1 $ 7.8 $ 9.4
Finance Lease Cost:
Amortization of Right-of-Use Assets
61.9 6.3 - 7.4 6.5 4.7 3.5 10.9
Interest on Lease Liabilities
15.4 1.5 - 2.7 3.1 0.9 0.7 2.2
Total Lease Rental Costs (a) $ 356.9 $ 25.2 $ 2.6 $ 29.2 $ 111.1 $ 22.7 $ 12.0 $ 22.5
Year Ended December 31, 2019 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Operating Lease Cost
$ 286.0 $ 16.5 $ 2.5 $ 19.5 $ 93.1 $ 18.0 $ 6.8 $ 8.0
Finance Lease Cost:
Amortization of Right-of-Use Assets
70.8 5.1 0.1 6.7 5.7 3.5 3.1 11.0
Interest on Lease Liabilities
16.4 1.4 - 2.9 2.9 0.7 0.6 2.9
Total Lease Rental Costs (a) $ 373.2 $ 23.0 $ 2.6 $ 29.1 $ 101.7 $ 22.2 $ 10.5 $ 21.9
(a)Excludes variable and short-term lease costs, which were immaterial.
Supplemental information related to leases are shown in the tables below:
December 31, 2021 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
Weighted-Average Remaining Lease Term (years):
Operating Leases
10.39 5.91 2.95 5.68 5.87 6.69 20.89 20.24
Finance Leases
2.95 5.51 0.00 4.97 2.10 5.54 6.18 4.53
Weighted-Average Discount Rate:
Operating Leases
3.35 % 3.53 % 0.90 % 3.42 % 3.46 % 3.56 % 3.35 % 3.34 %
Finance Leases
3.26 % 4.31 % - % 7.16 % 3.02 % 4.19 % 4.23 % 4.68 %
December 31, 2020 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
Weighted-Average Remaining Lease Term (years):
Operating Leases
5.30 6.51 2.01 6.27 3.50 7.44 7.03 7.54
Finance Leases
5.43 6.07 0.00 5.75 5.79 5.90 6.16 4.95
Weighted-Average Discount Rate:
Operating Leases
3.44 % 3.60 % 1.51 % 3.48 % 3.42 % 3.60 % 3.39 % 3.45 %
Finance Leases
5.68 % 4.39 % - % 7.33 % 8.29 % 4.25 % 4.35 % 4.77 %
Year Ended December 31, 2021 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Cash paid for amounts included in the measurement of lease liabilities:
Operating Cash Flows Used for Operating Leases
$ 279.9 $ 18.0 $ 1.6 $ 19.3 $ 92.9 $ 19.0 $ 8.7 $ 11.6
Operating Cash Flows Used for Finance Leases
14.3 1.4 - 2.4 2.9 0.8 0.6 2.5
Financing Cash Flows Used for Finance Leases
64.0 6.7 - 7.7 6.8 4.9 3.2 10.9
Non-cash Acquisitions Under Operating Leases $ 117.0 $ 4.4 $ 2.1 $ 4.2 $ 2.6 $ 4.2 $ 33.4 $ 42.9
Year Ended December 31, 2020 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Cash paid for amounts included in the measurement of lease liabilities:
Operating Cash Flows Used for Operating Leases
$ 280.3 $ 17.1 $ 2.6 $ 19.2 $ 102.2 $ 16.9 $ 7.7 $ 9.4
Operating Cash Flows Used for Finance Leases
15.4 1.5 - 2.7 3.1 0.9 0.7 2.2
Financing Cash Flows Used for Finance Leases
61.7 6.3 - 7.4 6.5 4.7 3.5 10.9
Non-cash Acquisitions Under Operating Leases $ 161.7 $ 15.8 $ 1.8 $ 16.2 $ 18.1 $ 18.1 $ 12.3 $ 18.4
The following tables show property, plant and equipment under finance leases and noncurrent assets under operating leases and related obligations recorded on the balance sheets. Unless shown as a separate line on the balance sheets due to materiality, net operating lease assets are included in Deferred Charges and Other Noncurrent Assets, current finance lease obligations are included in Other Current Liabilities and long-term finance lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets. Lease obligations are not recognized on the balance sheets for lease agreements with a lease term of less than twelve months.
December 31, 2021 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Property, Plant and Equipment Under Finance Leases:
Generation $ 388.8 $ - $ - $ 42.8 $ 156.8 $ - $ 0.6 $ 34.3
Other Property, Plant and Equipment 323.8 50.7 - 20.4 42.1 32.1 23.9 55.7
Total Property, Plant and Equipment 712.6 50.7 - 63.2 198.9 32.1 24.5 90.0
Accumulated Amortization 222.4 19.9 - 27.5 38.2 12.8 9.2 47.8
Net Property, Plant and Equipment Under Finance Leases
$ 490.2 (a) $ 30.8 $ - $ 35.7 $ 160.7 $ 19.3 $ 15.3 $ 42.2
Obligations Under Finance Leases:
Noncurrent Liability $ 196.1 $ 24.2 $ - $ 28.1 $ 31.7 $ 14.9 $ 12.3 $ 38.9
Liability Due Within One Year 304.6 6.6 - 7.6 130.5 4.4 3.0 10.8
Total Obligations Under Finance Leases
$ 500.7 (b) $ 30.8 $ - $ 35.7 $ 162.2 $ 19.3 $ 15.3 $ 49.7
(a) Amount excludes $3 million of Net Property, Plant and Equipment Under Finance Leases classified as Assets Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
(b) Amount excludes $3 million of Obligations Under Finance Leases classified as Liabilities Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
December 31, 2020 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Property, Plant and Equipment Under Finance Leases:
Generation $ 138.2 $ - $ - $ 42.8 $ 28.8 $ - $ 0.7 $ 37.7
Other Property, Plant and Equipment 322.8 49.7 - 20.3 40.2 31.4 23.0 52.4
Total Property, Plant and Equipment 461.0 49.7 - 63.1 69.0 31.4 23.7 90.1
Accumulated Amortization 176.8 16.6 - 21.4 27.3 9.8 8.7 36.5
Net Property, Plant and Equipment Under Finance Leases
$ 284.2 $ 33.1 $ - $ 41.7 $ 41.7 $ 21.6 $ 15.0 $ 53.6
Obligations Under Finance Leases:
Noncurrent Liability $ 231.0 $ 26.8 $ - $ 34.4 $ 35.3 $ 16.9 $ 11.9 $ 44.6
Liability Due Within One Year 58.1 6.3 - 7.3 6.4 4.7 3.1 10.7
Total Obligations Under Finance Leases
$ 289.1 $ 33.1 $ - $ 41.7 $ 41.7 $ 21.6 $ 15.0 $ 55.3
December 31, 2021 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Operating Lease Assets
$ 578.3 (a) $ 73.6 $ 2.0 $ 66.9 $ 63.5 $ 81.2 $ 68.9 $ 80.1
Obligations Under Operating Leases:
Noncurrent Liability $ 492.8 $ 61.3 $ 1.3 $ 52.4 $ 48.9 $ 68.6 $ 62.2 $ 77.7
Liability Due Within One Year 97.6 14.0 0.9 15.1 15.5 13.1 6.9 8.1
Total Obligations Under Operating Leases
$ 590.4 (b) $ 75.3 $ 2.2 $ 67.5 $ 64.4 $ 81.7 $ 69.1 $ 85.8
(a) Amount excludes $11 million of Operating Lease Assets classified as Assets Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
(b) Amount excludes $11 million of Obligations Under Operating Leases classified as Liabilities Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
December 31, 2020 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Operating Lease Assets
$ 866.4 $ 84.1 $ 1.6 $ 78.8 $ 218.1 $ 92.0 $ 42.6 $ 48.5
Obligations Under Operating Leases:
Noncurrent Liability $ 638.4 $ 71.0 $ 0.4 $ 64.4 $ 135.9 $ 79.5 $ 36.2 $ 44.1
Liability Due Within One Year 241.3 14.5 1.2 14.9 85.6 13.1 6.5 7.9
Total Obligations Under Operating Leases
$ 879.7 $ 85.5 $ 1.6 $ 79.3 $ 221.5 $ 92.6 $ 42.7 $ 52.0
Future minimum lease payments consisted of the following as of December 31, 2021:
Finance Leases AEP (a) AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
2022 $ 317.3 $ 7.8 $ - $ 9.8 $ 133.7 $ 5.1 $ 3.6 $ 12.6
2023 61.0 7.1 - 9.1 8.6 4.4 3.3 11.8
2024 64.7 5.9 - 8.3 11.6 3.7 2.8 15.9
2025 35.6 4.5 - 7.2 5.9 2.5 2.1 5.6
2026 20.1 3.5 - 2.7 3.5 2.0 1.8 2.3
After 2026 39.2 5.9 - 4.1 10.1 4.0 3.9 6.0
Total Future Minimum Lease Payments
537.9 34.7 - 41.2 173.4 21.7 17.5 54.2
Less: Imputed Interest
37.2 3.9 - 5.5 11.2 2.4 2.2 4.5
Estimated Present Value of Future Minimum Lease Payments $ 500.7 $ 30.8 $ - $ 35.7 $ 162.2 $ 19.3 $ 15.3 $ 49.7
(a) Amount excludes $3 million of Obligations Under Finance Leases classified as Liabilities Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
Operating Leases AEP (a) AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
2022 $ 119.6 $ 16.7 $ 0.9 $ 17.5 $ 17.6 $ 16.2 $ 9.2 $ 13.0
2023 102.2 15.5 0.7 14.8 11.7 15.2 8.9 11.8
2024 89.9 14.1 0.4 11.9 10.4 13.8 8.1 10.0
2025 76.7 11.7 0.2 9.1 9.3 12.1 6.9 8.7
2026 64.0 9.5 - 7.2 7.3 11.0 6.0 7.5
After 2026 272.4 16.9 - 14.1 15.0 24.2 62.6 80.4
Total Future Minimum Lease Payments
724.8 84.4 2.2 74.6 71.3 92.5 101.7 131.4
Less: Imputed Interest 134.4 9.1 - 7.1 6.9 10.8 32.6 45.6
Estimated Present Value of Future Minimum Lease Payments $ 590.4 $ 75.3 $ 2.2 $ 67.5 $ 64.4 $ 81.7 $ 69.1 $ 85.8
(a) Amount excludes $11 million of Obligations Under Operating Leases classified as Liabilities Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
Master Lease Agreements (Applies to all Registrants except AEPTCo)
The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the amount guaranteed. As of December 31, 2021, the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:
Company Maximum
Potential Loss
(in millions)
AEP $ 47.4
AEP Texas 11.1
APCo 6.2
I&M 4.1
OPCo 7.5
PSO 4.6
SWEPCo 5.2
Rockport Lease (Applies to AEP and I&M)
AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2. The trusts were capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors.
The trusts own undivided interests in Rockport Plant, Unit 2 and leases equal portions to AEGCo and I&M. In April 2021, AEGCo and I&M executed an agreement to purchase 100% of the interests in Rockport Plant, Unit 2 effective at the end of the lease term in December 2022. In December 2021, AEGCo and I&M satisfied the necessary regulatory approvals to complete the acquisition. Upon receipt of the regulatory approvals, the addition of the lessee forward purchase obligation resulted in the modified lease changing classification from operating to finance for AEGCo and I&M. The future minimum lease payments as of December 31, 2021, inclusive of the purchase obligation, were as follows:
Future Minimum Lease Payments AEP (a) I&M
(in millions)
2022 $ 248.7 $ 124.4
Total Future Minimum Lease Payments $ 248.7 $ 124.4
(a) AEP’s future minimum lease payments include equal shares from AEGCo and I&M.
The lease modification also created variable interests in the trusts that own the undivided interests in Rockport Plant, Unit 2 for I&M and AEGCo. Neither I&M nor AEGCo are the primary beneficiaries of the trusts because AEGCo nor I&M has the power to direct the most significant activities of the trusts. AEP and I&M’s maximum exposure to loss associated with the trusts is equal to the total future minimum lease payments, inclusive of the purchase obligation, as shown in the table above.
AEPRO Boat and Barge Leases (Applies to AEP)
In 2015, AEP sold its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. Certain boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the respective lessors, ensuring future payments under such leases with maturities up to 2027. As of December 31, 2021, the maximum potential amount of future payments required under the guaranteed leases was $42 million. Under the terms of certain of the arrangements, upon the lessors exercising their rights after an event of default by the nonaffiliated party, AEP is entitled to enter into new lease arrangements as a lessee that would have substantially the same terms as the existing leases. Alternatively, for the arrangements with one of the lessors, upon an event of default by the nonaffiliated party and the lessor exercising its rights, payment to the lessor would allow AEP to step into the lessor’s rights as well as obtaining title to the assets. Under either situation, AEP would have the ability to utilize the assets in the normal course of barging operations. AEP would also have the right to sell the acquired assets for which it obtained title. As of December 31, 2021, AEP’s boat and barge lease guarantee liability was $2 million, of which $1 million was recorded in Other Current Liabilities and $1 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet.
In February 2020, the nonaffiliated party filed Chapter 11 bankruptcy. The party entered into a restructuring support agreement and has announced it expects to continue their operations as normal. In March 2020, the bankruptcy court approved the party’s recapitalization plan. In April 2020, the nonaffiliated party emerged from bankruptcy. Management has determined that it is reasonably possible that enforcement of AEP’s liability for future payments under these leases will be exercised within the next twelve months. In such an event, if AEP is unable to sell or incorporate any of the acquired assets into its fleet operations, it could reduce future net income and cash flows and impact financial condition.
Lessor Activity
The Registrants’ lessor activity was immaterial as of and for the twelve months ended December 31, 2021 and December 31, 2020, respectively.
14. FINANCING ACTIVITIES
The disclosures in this note apply to all Registrants, unless indicated otherwise.
Common Stock (Applies to AEP)
The following table is a reconciliation of common stock share activity:
Shares of AEP Common Stock Issued Held in Treasury
Balance, December 31, 2018 513,450,036 20,204,160
Issued 923,595 -
Balance, December 31, 2019 514,373,631 20,204,160
Issued 2,434,723 -
Balance, December 31, 2020 516,808,354 20,204,160
Issued 7,607,821 -
Balance, December 31, 2021 524,416,175 20,204,160
ATM Program
In 2020, AEP filed a prospectus supplement and executed an Equity Distribution Agreement, pursuant to which AEP may sell, from time to time, up to an aggregate of $1 billion of its common stock through an ATM offering program, including an equity forward sales component. The compensation paid to the selling agents by AEP may be up to 2% of the gross offering proceeds of the shares. For the year ended December 31, 2021, AEP issued 5,701,825 shares of common stock and received net cash proceeds of $484 million under the ATM program.
Long-term Debt
The following table details long-term debt outstanding:
Weighted-Average Interest Rate Ranges as of Outstanding as of
Interest Rate as of December 31, December 31,
Company Maturity December 31, 2021 2021 2020 2021 2020
AEP (in millions)
Senior Unsecured Notes 2021-2051 3.69% 0.61%-7.00% 0.70%-8.13% $ 27,497.3 $ 25,116.1
Pollution Control Bonds (a) 2021-2036 (b) 2.40% 0.19%-4.55% 0.18%-4.63% 1,804.5 1,936.7
Notes Payable - Nonaffiliated (c) 2021-2032 2.41% 0.79%-6.37% 0.84%-6.37% 211.3 239.1
Securitization Bonds 2023-2029 (d) 2.84% 2.01%-3.77% 2.01%-3.77% 603.5 716.4
Spent Nuclear Fuel Obligation (e) 281.3 281.2
Junior Subordinated Notes (f) 2023-2027 2.81% 1.30%-3.88% 1.30%-3.40% 2,373.0 1,624.1
Other Long-term Debt 2021-2059 1.63% 0.91%-13.72% 0.81%-13.72% 683.6 1,158.9
Total Long-term Debt Outstanding (g) $ 33,454.5 $ 31,072.5
AEP Texas
Senior Unsecured Notes 2022-2051 3.67% 2.10%-6.76% 2.10%-6.76% $ 4,135.5 $ 3,687.6
Pollution Control Bonds 2023-2030 (b) 3.42% 0.90%-4.55% 0.90%-4.55% 439.9 439.7
Securitization Bonds 2024-2029 (d) 2.53% 2.06%-2.84% 2.06%-2.84% 404.7 492.6
Other Long-term Debt 2022-2059 1.37% 1.35%-4.50% 1.40%-4.50% 200.7 200.5
Total Long-term Debt Outstanding
$ 5,180.8 $ 4,820.4
AEPTCo
Senior Unsecured Notes 2021-2051 3.73% 2.75%-5.52% 3.10%-5.52% $ 4,343.9 $ 3,948.5
Total Long-term Debt Outstanding
$ 4,343.9 $ 3,948.5
APCo
Senior Unsecured Notes 2021-2050 4.70% 2.70%-7.00% 3.30%-7.00% $ 4,083.7 $ 3,937.2
Pollution Control Bonds (a) 2021-2036 (b) 1.67% 0.19%-2.75% 0.19%-4.63% 529.5 546.3
Securitization Bonds 2023-2028 (d) 3.46% 2.01%-3.77% 2.01%-3.77% 198.8 223.8
Other Long-term Debt 2022-2026 1.42% 1.24%-13.72% 1.32%-13.72% 126.9 126.8
Total Long-term Debt Outstanding
$ 4,938.9 $ 4,834.1
I&M
Senior Unsecured Notes 2023-2051 4.19% 3.20%-6.05% 3.20%-6.05% $ 2,595.5 $ 2,152.2
Pollution Control Bonds (a) 2021-2025 (b) 2.49% 0.75%-3.05% 0.18%-3.05% 188.7 240.5
Notes Payable - Nonaffiliated (c) 2021-2025 0.99% 0.79%-1.24% 0.84%-1.29% 122.2 146.7
Spent Nuclear Fuel Obligation (e) 281.3 281.2
Other Long-term Debt 2021-2025 6.00% 6.00% 1.28%-6.00% 7.3 209.3
Total Long-term Debt Outstanding
$ 3,195.0 $ 3,029.9
OPCo
Senior Unsecured Notes 2021-2051 3.87% 1.63%-6.60% 2.60%-6.60% $ 2,967.8 $ 2,429.4
Other Long-term Debt 2028 1.15% 1.15% 1.15% 0.7 0.8
Total Long-term Debt Outstanding
$ 2,968.5 $ 2,430.2
PSO
Senior Unsecured Notes 2021-2051 3.74% 2.20%-6.63% 3.05%-6.63% $ 1,785.5 $ 1,246.3
Other Long-term Debt 2022-2027 1.50% 1.47%-3.00% 1.42%-3.00% 128.0 127.5
Total Long-term Debt Outstanding
$ 1,913.5 $ 1,373.8
SWEPCo
Senior Unsecured Notes 2022-2051 3.57% 1.65%-6.20% 2.75%-6.20% $ 3,295.1 $ 2,430.8
Notes Payable - Nonaffiliated (c) 2024-2032 5.34% 4.58%-6.37% 4.58%-6.37% 59.1 62.4
Other Long-term Debt 2021-2035 4.68% 4.68% 2.25%-4.68% 41.0 143.2
Total Long-term Debt Outstanding
$ 3,395.2 $ 2,636.4
(a)For certain series of Pollution Control Bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets.
(b)Certain Pollution Control Bonds are subject to redemption earlier than the maturity date.
(c)Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates.
(d)Dates represent the scheduled final payment dates for the securitization bonds. The legal maturity date is one to two years later. These bonds have been classified for maturity and repayment purposes based on the scheduled final payment date.
(e)Spent Nuclear Fuel Obligation consists of a liability along with accrued interest for disposal of SNF. See “Spent Nuclear Fuel Disposal” section of Note 6 for additional information.
(f)See “Equity Units” section below for additional information.
(g)2021 amount excludes $1.1 billion of Total Long-term Debt Outstanding classified as Liabilities Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
As of December 31, 2021, outstanding long-term debt was payable as follows:
AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
2022 $ 2,153.8 $ 716.0 $ 104.0 $ 480.7 $ 67.0 $ 0.1 $ 125.5 $ 6.2
2023 2,629.9 (a) 278.5 60.0 26.6 289.8 0.1 0.5 6.2
2024 1,462.2 (b) 96.0 95.0 113.5 16.8 0.1 0.6 31.2
2025 1,762.4 324.5 90.0 443.9 195.9 0.1 125.6 6.2
2026 1,497.9 75.0 425.0 30.9 - 0.1 50.6 906.2
After 2026 24,246.7 3,732.0 3,616.0 3,887.4 2,656.3 3,000.2 1,625.3 2,469.3
Principal Amount 33,752.9 5,222.0 4,390.0 4,983.0 3,225.8 3,000.7 1,928.1 3,425.3
Unamortized Discount, Net and Debt Issuance Costs
(298.4) (41.2) (46.1) (44.1) (30.8) (32.2) (14.6) (30.1)
Total Long-term Debt Outstanding
$ 33,454.5 (c) $ 5,180.8 $ 4,343.9 $ 4,938.9 $ 3,195.0 $ 2,968.5 $ 1,913.5 $ 3,395.2
(a) Amount includes $850 million of Junior Subordinated Notes. See “Equity Units” section below for additional information.
(b) Amount includes $805 million of Junior Subordinated Notes. See “Equity Units” section below for additional information.
(c) Amount excludes $1.1 billion of Total Long-term Debt Outstanding classified as Liabilities Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
Long-term Debt Subsequent Events
In January and February 2022, I&M retired $8 million and $8 million, respectively, of Notes Payable related to DCC Fuel.
In February 2022, PSO issued $500 million of variable rate Other Long-term Debt due in 2022.
In February 2022, AEP Texas retired $11 million of Securitization Bonds.
In February 2022, APCo retired $13 million of Securitization Bonds.
Equity Units (Applies to AEP)
2020 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. The proceeds were used to support AEP’s overall capital expenditure plans.
Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 1.30% Junior Subordinated Notes (notes) due in 2025 and a forward equity purchase contract which settles after three years in 2023. The notes are expected to be remarketed in 2023, at which time the interest rate will reset at the then-current market rate. Investors may choose to remarket their notes to receive the remarketing proceeds and use those funds to settle the forward equity purchase contract, or accept the remarketed debt and use other funds for the equity purchase. If the remarketing is unsuccessful, investors have the right to put their notes to AEP at a price equal to the principal. The Equity Units carry an annual distribution rate of 6.125%, which is comprised of a quarterly coupon rate of interest of 1.30% and a quarterly forward equity purchase contract payment of 4.825%.
Each forward equity purchase contract obligates the holder to purchase, and AEP to sell, for $50 a number of shares in common stock in accordance with the conversion ratios set forth below (subject to an anti-dilution adjustment):
•If the AEP common stock market price is equal to or greater than $99.95: 0.5003 shares per contract.
•If the AEP common stock market price is less than $99.95 but greater than $83.29: a number of shares per contract equal to $50 divided by the applicable market price. The holder receives a variable number of shares at $50.
•If the AEP common stock market price is less than or equal to $83.29: 0.6003 shares per contract.
A holder’s ownership interest in the notes is pledged to AEP to secure the holder’s obligation under the related forward equity purchase contract. If a holder of the forward equity purchase contract chooses at any time to no longer be a holder of the notes, such holder’s obligation under the forward equity purchase contract must be secured by a U.S. Treasury security which must be equal to the aggregate principal amount of the notes.
At the time of issuance, the $850 million of notes were recorded within Long-term Debt on the balance sheets. The present value of the purchase contract payments of $121 million were recorded in Deferred Credits and Other Noncurrent Liabilities with a current portion in Other Current Liabilities at the time of issuance, representing the obligation to make forward equity contract payments, with an offsetting reduction to Paid-in Capital. The difference between the face value and present value of the purchase contract payments will be accreted to Interest Expense on the statements of income over the three year period ending in 2023. The liability recorded for the contract payments is considered non-cash and excluded from the statements of cash flows. Until settlement of the forward equity purchase contract, earnings per-share dilution resulting from the equity unit issuance will be determined under the treasury stock method. The maximum amount of shares AEP will be required to issue to settle the purchase contract is 10,205,100 shares (subject to an anti-dilution adjustment).
2019 Equity Units
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. The proceeds were used to support AEP’s overall capital expenditure plans including the acquisition of Sempra Renewables LLC.
Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 3.40% Junior Subordinated Notes (notes) due in 2024 and a forward equity purchase contract which settles after three years in 2022. 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.
Each forward equity purchase contract obligates the holder to purchase, and AEP to sell, for $50 a number of shares in common stock in accordance with the conversion ratios set forth below (subject to an anti-dilution adjustment):
•If the AEP common stock market price is equal to or greater than $99.58: 0.5021 shares per contract.
•If the AEP common stock market price is less than $99.58 but greater than $82.98: a number of shares per contract equal to $50 divided by the applicable market price. The holder receives a variable number of shares at $50.
•If the AEP common stock market price is less than or equal to $82.98: 0.6026 shares per contract.
A holder’s ownership interest in the notes is pledged to AEP to secure the holder’s obligation under the related forward equity purchase contract. If a holder of the forward equity purchase contract chooses at any time to no longer be a holder of the notes, such holder’s obligation under the forward equity purchase contract must be secured by a U.S. Treasury security which must be equal to the aggregate principal amount of the notes.
At the time of issuance, the $805 million of notes were recorded within Long-term Debt on the balance sheets. The present value of the purchase contract payments of $62 million were recorded in Deferred Credits and Other Noncurrent Liabilities with a current portion in Other Current Liabilities at the time of issuance, representing the obligation to make forward equity contract payments, with an offsetting reduction to Paid-in Capital. The difference between the face value and present value of the purchase contract payments will be accreted to Interest Expense on the statements of income over the three year period ending in 2022. The liability recorded for the contract payments is considered non-cash and excluded from the statements of cash flows. Until settlement of the forward equity purchase contract, earnings per-share dilution resulting from the equity unit issuance will be
determined under the treasury stock method. The maximum amount of shares AEP will be required to issue to settle the purchase contract is 9,701,860 shares (subject to an anti-dilution adjustment).
Debt Covenants (Applies to AEP and AEPTCo)
Covenants in AEPTCo’s note purchase agreements and indenture limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. AEPTCo’s contractually-defined priority debt was 1.1% of consolidated tangible net assets as of December 31, 2021. The method for calculating the consolidated tangible net assets is contractually-defined in the note purchase agreement.
Dividend Restrictions
Utility Subsidiaries’ Restrictions
Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. 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.
All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. The Federal Power Act also creates a reserve on retained earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to APCo and I&M.
Certain AEP subsidiaries have credit agreements that contain covenants that limit their debt to capitalization ratio to 67.5%. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements.
The most restrictive dividend limitation for certain AEP subsidiaries is through the Federal Power Act restriction, while for other AEP subsidiaries the most restrictive dividend limitation is through the credit agreements. As of December 31, 2021, the maximum amount of restricted net assets of AEP’s subsidiaries that may not be distributed to the Parent in the form of a loan, advance or dividend was $15.5 billion.
The Federal Power Act restriction limits the ability of the AEP subsidiaries owning hydroelectric generation to pay dividends out of retained earnings. Additionally, the credit agreement covenant restrictions can limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. As of December 31, 2021, the amount of any such restrictions were as follows:
AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Restricted Retained Earnings
$ 2,655.2 (a) $ 791.8 $ - $ 313.4 $ 648.5 $ - $ - $ 577.9
(a) Includes the restrictions of consolidated and non-consolidated subsidiaries.
Parent Restrictions (Applies to AEP)
The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries.
Pursuant to the leverage restrictions in credit agreements, AEP must 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 the credit agreements. As of December 31, 2021, AEP had $8.2 billion of available retained earnings to pay dividends to common shareholders. AEP paid $1.5 billion, $1.4 billion and $1.3 billion of dividends to common shareholders for the years ended December 31, 2021, 2020 and 2019, respectively.
Lines of Credit and Short-term Debt (Applies to AEP and SWEPCo)
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. As of December 31, 2021, AEP had $5 billion in revolving credit facilities to support its commercial paper program. The commercial paper program for the year ended 2021, had a weighted-average interest rate of 0.24% and a maximum amount outstanding of $2.5 billion. AEP’s outstanding short-term debt was as follows:
December 31,
2021 2020
Company Type of Debt Outstanding
Amount Interest
Rate (a) Outstanding
Amount Interest
Rate (a)
(in millions) (in millions)
AEP Securitized Debt for Receivables (b) $ 750.0 0.19 % $ 592.0 0.85 %
AEP Commercial Paper 1,364.0 0.34 % 1,852.3 0.29 %
AEP 364-Day Term Loan 500.0 0.81 % - - %
SWEPCo Notes Payable - - % 35.0 2.55 %
Total Short-term Debt $ 2,614.0 $ 2,479.3
(a) Weighted-average rate.
(b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.
Corporate Borrowing Program - AEP System (Applies to Registrant Subsidiaries)
The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and direct borrowing from AEP. The AEP System Utility Money Pool operates in accordance with the terms and conditions of its agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of December 31, 2021 and 2020 are included in Advances to Affiliates and Advances from Affiliates, respectively, on the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and corresponding authorized borrowing limits are described in the following tables:
Year Ended December 31, 2021:
Maximum Average Net Loans to
Borrowings Maximum Borrowings Average (Borrowings from) Authorized
from the Loans to the from the Loans to the the Utility Money Short-term
Utility Utility Utility Utility Pool as of Borrowing
Company Money Pool Money Pool Money Pool Money Pool December 31, 2021 Limit
(in millions)
AEP Texas $ 355.5 $ 104.7 $ 172.5 $ 40.0 $ (26.9) $ 500.0
AEPTCo 444.9 117.3 189.1 29.7 (108.0) (b) 820.0 (a)
APCo 199.3 616.9 87.5 118.3 (178.5) 500.0
I&M 166.5 368.2 110.4 67.7 (71.8) 500.0
OPCo 259.2 622.9 61.6 127.2 42.0 500.0
PSO 267.7 747.3 134.0 113.1 (72.3) 400.0
SWEPCo 280.3 561.9 142.4 287.4 153.8 400.0
Year Ended December 31, 2020:
Maximum Average Net Loans to
Borrowings Maximum Borrowings Average (Borrowings from) Authorized
from the Loans to the from the Loans to the the Utility Money Short-term
Utility Utility Utility Utility Pool as of Borrowing
Company Money Pool Money Pool Money Pool Money Pool December 31, 2020 Limit
(in millions)
AEP Texas $ 320.4 $ 313.4 $ 132.0 $ 139.0 $ (67.1) $ 500.0
AEPTCo 358.4 259.7 116.3 55.0 (155.4) 820.0 (a)
APCo 434.3 189.0 242.8 76.3 2.8 500.0
I&M 218.6 13.4 114.5 13.3 (89.7) 500.0
OPCo 353.9 32.8 182.4 25.2 (259.2) 500.0
PSO 155.4 57.1 72.3 28.4 (155.4) 300.0
SWEPCo 178.9 - 113.0 - (124.6) 350.0
(a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
(b) Amount excludes $1 million of Advances from Affiliates classified as Liabilities Held for Sale on the AEP Transco balance sheet. See “Dispositions of KPCo and KTCo” section of Note 7 for additional information.
The activity in the above tables does not include short-term lending activity of certain AEP nonutility subsidiaries. AEP Texas’ wholly-owned subsidiary, AEP Texas North Generation Company, LLC and SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC participate in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of December 31, 2021 and 2020 are included in Advances to Affiliates on each subsidiaries’ balance sheets. The Nonutility Money Pool participants’ money pool activity is described in the following tables:
Year Ended December 31, 2021:
Maximum Loans Average Loans Loans to the Nonutility
to the Nonutility to the Nonutility Money Pool as of
Company Money Pool Money Pool December 31, 2021
(in millions)
AEP Texas $ 7.1 $ 6.9 $ 6.9
SWEPCo 2.1 2.1 2.1
Year Ended December 31, 2020:
Maximum Loans Average Loans Loans to the Nonutility
to the Nonutility to the Nonutility Money Pool as of
Company Money Pool Money Pool December 31, 2020
(in millions)
AEP Texas $ 7.5 $ 7.1 $ 7.1
SWEPCo 2.1 2.1 2.1
AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to and borrowings from AEP as of December 31, 2021 and 2020 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct financing activities with AEP and corresponding authorized borrowing limits are described in the following tables:
Year Ended December 31, 2021:
Maximum Maximum Average Average Borrowings from Loans to Authorized
Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term
from AEP to AEP from AEP to AEP December 31, 2021 December 31, 2021 Borrowing Limit
(in millions)
$ 14.6 $ 224.2 $ 1.8 $ 118.0 $ 1.5 $ 12.7 $ 50.0 (a)
Year Ended December 31, 2020:
Maximum Maximum Average Average Borrowings from Loans to Authorized
Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term
from AEP to AEP from AEP to AEP December 31, 2020 December 31, 2020 Borrowing Limit
(in millions)
$ 1.4 $ 215.3 $ 1.3 $ 132.6 $ 1.2 $ 109.0 $ 50.0 (a)
(a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool are summarized in the following table:
Years Ended December 31,
2021 2020 2019
Maximum Interest Rate 0.48 % 2.70 % 3.43 %
Minimum Interest Rate 0.02 % 0.27 % 1.77 %
The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized in the following table:
Average Interest Rate for Funds Borrowed
from the Utility Money Pool for the
Years Ended December 31, Average Interest Rate for Funds Loaned
to the Utility Money Pool for the
Years Ended December 31,
Company 2021 2020 2019 2021 2020 2019
AEP Texas 0.33 % 1.51 % 2.63 % 0.26 % 0.81 % 2.03 %
AEPTCo 0.32 % 1.29 % 2.64 % 0.10 % 1.99 % 2.41 %
APCo 0.41 % 2.12 % 2.45 % 0.25 % 0.85 % 2.66 %
I&M 0.33 % 1.07 % 2.34 % 0.23 % 1.18 % 2.60 %
OPCo 0.27 % 0.99 % 2.67 % 0.14 % 2.06 % 2.68 %
PSO 0.34 % 0.92 % 2.85 % 0.07 % 1.95 % 2.27 %
SWEPCo 0.26 % 1.27 % 2.72 % 0.18 % - % 2.22 %
Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized in the following table:
Maximum Interest Rate Minimum Interest Rate Average Interest Rate
Year Ended for Funds Loaned to for Funds Loaned to for Funds Loaned to
December 31, Company the Nonutility Money Pool the Nonutility Money Pool the Nonutility Money Pool
2021 AEP Texas 0.58 % 0.21 % 0.37 %
2021 SWEPCo 0.58 % 0.21 % 0.37 %
2020 AEP Texas 2.70 % 0.27 % 1.18 %
2020 SWEPCo 2.70 % 0.27 % 1.18 %
2019 AEP Texas 3.02 % 1.91 % 2.56 %
2019 SWEPCo 3.02 % 1.91 % 2.55 %
AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table:
Maximum Minimum Maximum Minimum Average Average
Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate
for Funds for Funds for Funds for Funds for Funds for Funds
Year Ended Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to
December 31, AEP AEP AEP AEP AEP AEP
2021 0.86 % 0.25 % 0.86 % 0.25 % 0.38 % 0.35 %
2020 2.70 % 0.27 % 2.70 % 0.27 % 1.20 % 1.13 %
2019 3.02 % 1.91 % 3.02 % 1.91 % 2.55 % 2.51 %
Interest expense and interest income related to the Utility Money Pool, Nonutility Money Pool and direct borrowing financing relationship are included in Interest Expense and Interest Income, respectively, on each of the Registrant Subsidiaries’ statements of income. The interest expense and interest income related to the corporate borrowing programs were immaterial for the years ended December 31, 2021, 2020 and 2019.
Credit Facilities
See “Letters of Credit” section of Note 6 for additional information.
Securitized Accounts Receivables - AEP Credit (Applies to AEP)
AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections.
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.
Accounts receivable information for AEP Credit was as follows:
Years Ended December 31,
2021 2020 2019
(dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable 0.19 % 0.85 % 2.42 %
Net Uncollectible Accounts Receivable Written Off $ 26.5 $ 15.3 $ 26.6
December 31,
2021 2020
(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 995.2 $ 958.4
Short-term - Securitized Debt of Receivables
750.0 592.0
Delinquent Securitized Accounts Receivable 57.9 62.3
Bad Debt Reserves Related to Securitization 42.8 60.0
Unbilled Receivables Related to Securitization 307.1 296.8
AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due.
Securitized Accounts Receivables - AEP Credit (Applies to Registrant Subsidiaries, except AEP Texas and AEPTCo)
Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. KPCo terminated selling accounts receivable to AEP Credit in the first quarter of 2022, based on the pending sale to Liberty. As a result of the termination, in the first quarter of 2022, KPCo will record an allowance for uncollectible accounts on its balance sheet for those receivables no longer sold to AEP Credit. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder.
The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement were:
December 31,
Company 2021 2020
(in millions)
APCo $ 153.1 $ 136.0
I&M 156.9 170.5
OPCo 392.7 398.8
PSO 114.5 85.0
SWEPCo 153.0 158.6
The fees paid to AEP Credit for customer accounts receivable sold were:
Years Ended December 31,
Company 2021 (a) 2020 2019
(in millions)
APCo $ 4.9 $ 5.2 $ 7.4
I&M 7.0 7.9 11.1
OPCo 8.3 24.1 27.1
PSO 3.4 4.8 7.8
SWEPCo 5.4 6.7 10.2
(a)In 2020, an increase in allowance for doubtful accounts was recognized in response to the anticipated impact of COVID-19 on the collectability of accounts receivable, which caused an increase in fees paid by the registrants. In 2021, due to higher than expected collections of accounts receivables, allowance for doubtful accounts was adjusted resulting in the issuance of credits to offset the higher fees previously paid and to lower subsequent fees paid.
The proceeds on the sale of receivables to AEP Credit were:
Years Ended December 31,
Company 2021 2020 2019
(in millions)
APCo $ 1,324.1 $ 1,272.9 $ 1,310.3
I&M 1,927.0 1,891.8 1,824.2
OPCo 2,458.5 2,366.2 2,293.6
PSO 1,406.4 1,221.0 1,442.5
SWEPCo 1,636.1 1,593.8 1,618.5
15. STOCK-BASED COMPENSATION
The disclosures in this note apply to AEP only. The impact of AEP’s share-based compensation plans is insignificant to the financial statements of the Registrant Subsidiaries.
Awards under AEP’s long-term incentive plan may be granted to employees and directors. The Amended and Restated American Electric Power System Long-Term Incentive Plan (Prior Plan), was replaced prospectively for new grants by the American Electric Power System 2015 Long-Term Incentive Plan (2015 LTIP) effective in April 2015. The 2015 LTIP was subsequently amended in September 2016. The 2015 LTIP provides for a maximum of 10 million AEP common shares to be available for grant to eligible employees and directors. As of December 31, 2021, 5,976,468 shares remained available for issuance under the 2015 LTIP. No new awards may be granted under the Prior Plan. The 2015 LTIP awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock-based awards. Shares issued pursuant to a stock option or a stock appreciation right reduce the shares remaining available for grants under the 2015 LTIP by 0.286 of a share. Each share issued for any other award that settles in AEP stock reduces the shares remaining available for grants under the 2015 LTIP by one share. Cash settled awards do not reduce the number of shares remaining available under the 2015 LTIP. The following sections provide further information regarding each type of stock-based compensation award granted under these plans.
Performance Shares
Performance units granted prior to 2017 were settled in cash rather than AEP common stock and did not reduce the number of shares remaining available under the 2015 LTIP. Those performance units had a fair value upon vesting equal to the average closing market price of AEP common stock for the last 20 trading days of the performance period. Performance shares granted in and after 2017 are settled in AEP common stock and reduce the aggregate share authorization. In all cases the number of performance shares held at the end of the three-year performance period is multiplied by the performance score for such period to determine the actual number of performance shares that participants realize. The performance score can range from 0% to 200% and is determined at the end of the performance period based on performance measures, which include both performance and market conditions, established for each grant at the beginning of the performance period by the Human Resources Committee of AEP’s Board of Directors (HR Committee).
Certain employees must satisfy a minimum stock ownership requirement. If those employees have not met their stock ownership requirement, a portion or all of their performance shares are mandatorily deferred as AEP career shares to the extent needed to meet their stock ownership requirement. AEP career shares are a form of non-qualified deferred compensation that has a value equivalent to a share of AEP common stock. AEP career shares are settled in AEP common stock after the participant’s termination of employment.
AEP career shares are recorded in Paid-in Capital on the balance sheets. Amounts equivalent to cash dividends on both performance shares and AEP career shares accrue as additional shares. Management records compensation cost for performance shares over an approximately three-year vesting period. Performance shares are recorded as mezzanine equity on the balance sheets until the vesting date and compensation cost is calculated at fair value based on metrics for each grant. Performance shares granted in 2021 and 2020 have three performance metrics: (a) three-year cumulative operating earnings per-share with a 50% weight, (b) total shareholder return with a 40% weight and (c) non-emitting generation capacity as a percentage of total owned and purchased capacity with a 10% weight. Performance shares granted in 2019 have two equally-weighted performance metrics: (a) three-year cumulative operating earnings per-share and (b) total shareholder return. The three-year cumulative operating earnings per-share metric and non-emitting generating capacity metric are adjusted quarterly for changes in performance relative to a target approved by the HR Committee. The total shareholder return metric is measured relative to a peer group of similar companies and is based on a third-party Monte Carlo valuation. The value related to this metric does not change over the three-year vesting period.
The HR Committee awarded performance shares and reinvested dividends on outstanding performance shares and AEP career shares as follows:
Years Ended December 31,
Performance Shares 2021 2020 2019
Awarded Shares (in thousands) 565.0 424.8 535.0
Weighted-Average Share Fair Value at Grant Date $ 81.02 $ 116.56 $ 83.21
Vesting Period (in years) 3 3 3
Performance Shares and AEP Career Shares
(Reinvested Dividends Portion) Years Ended December 31,
2021 2020 2019
Awarded Shares (in thousands) 74.5 73.4 66.4
Weighted-Average Fair Value at Grant Date $ 84.48 $ 84.87 $ 88.73
Vesting Period (in years) (a) (a) (a)
(a)The vesting period for the reinvested dividends on performance shares is equal to the remaining life of the related performance shares. Dividends on AEP career shares vest immediately when the dividend is awarded but are not settled in AEP common stock until after the participant’s AEP employment ends.
Performance scores and final awards are determined and approved by the HR Committee in accordance with the pre-established performance measures within approximately two months after the end of the performance period.
The certified performance scores and shares earned for the three-year periods were as follows:
Years Ended December 31,
Performance Shares 2021 2020 2019
Certified Performance Score 102.9 % 128.2 % 132.7 %
Performance Shares Earned 537,166 757,858 792,897
Performance Shares Mandatorily Deferred as AEP Career Shares 14,613 13,614 10,063
Performance Shares Voluntarily Deferred into the Incentive Compensation Deferral Program
22,915 26,936 49,392
Performance Shares to be Settled (a) 499,638 717,308 733,442
(a)Performance shares settled in AEP common stock in the quarter following the end of the year shown.
The settlements were as follows:
Years Ended December 31,
Performance Shares and AEP Career Shares 2021 2020 2019
(in millions)
Cash Settlements for Performance Units $ - $ - $ 58.3
AEP Common Stock Settlements for Performance Shares 54.7 75.4 -
AEP Common Stock Settlements for Career Share Distributions 4.0 1.9 6.6
A summary of the status of AEP’s nonvested Performance Shares as of December 31, 2021 and changes during the year ended December 31, 2021 were as follows:
Nonvested Performance Shares Shares Weighted
Average
Grant Date
Fair Value
(in thousands)
Nonvested as of January 1, 2021 938.6 $ 98.05
Awarded 565.0 81.02
Dividends 53.4 84.45
Vested (a) (529.0) 83.87
Forfeited (104.2) 87.65
Nonvested as of December 31, 2021 923.8 96.15
(a)The vested Performance Shares will be converted to 500 thousand shares based on the closing share price on the day before settlement.
Monte Carlo Valuation
AEP engages a third-party for a Monte Carlo valuation to calculate the fair value of the total shareholder return metric for the performance shares awarded during and after 2017. The valuations use a lattice model and the expected volatility assumptions used were the historical volatilities for AEP and the members of their peer group. The assumptions used in the Monte Carlo valuations were as follows:
Years Ended December 31,
Assumptions 2021 2020 2019
Valuation Period (in years) (a) 2.88 2.87 2.87
Expected Volatility Minimum 25.87 % 13.67 % 14.83 %
Expected Volatility Maximum 39.90 % 28.15 % 25.57 %
Expected Volatility Average 31.01 % 16.39 % 17.39 %
Dividend Rate (b) - % - % - %
Risk Free Rate 0.19 % 1.40 % 2.49 %
(a)Period from award date to vesting date.
(b)Equivalent to reinvesting dividends.
Restricted Stock Units
The HR Committee grants restricted stock units (RSUs), which generally vest, subject to the participant’s continued employment, over at least three years in approximately equal annual increments. The RSUs accrue dividends as additional RSUs. The additional RSUs granted as dividends vest on the same date as the underlying RSUs. RSUs are converted into shares of AEP common stock upon vesting, except the RSUs granted prior to 2017 to AEP’s executive officers which settled in cash. Executive officers are those officers who are subject to the disclosure requirements set forth in Section 16 of the Securities Exchange Act of 1934. For RSUs that settle in shares, compensation cost is measured at fair value on the grant date and recorded over the vesting period. Fair value is determined by multiplying the number of RSUs granted by the grant date market closing price. For RSUs that settled in cash, compensation cost was recorded over the vesting period and adjusted for changes in fair value until vested. The fair value at vesting was determined by multiplying the number of RSUs vested by the 20-day average closing price of AEP common stock. The maximum contractual term of outstanding RSUs is approximately 40 months from the grant date.
The HR Committee awarded RSUs, including additional units awarded as dividends, as follows:
Years Ended December 31,
Restricted Stock Units 2021 2020 2019
Awarded Units (in thousands) 280.0 268.7 304.8
Weighted-Average Grant Date Fair Value $ 80.39 $ 94.38 $ 81.57
The total fair value and total intrinsic value of restricted stock units vested were as follows:
Years Ended December 31,
Restricted Stock Units 2021 2020 2019
(in millions)
Fair Value of Restricted Stock Units Vested $ 20.5 $ 22.9 $ 16.3
Intrinsic Value of Restricted Stock Units Vested (a) 22.0 25.2 21.6
(a)Intrinsic value is calculated as market price at the vesting date.
A summary of the status of AEP’s nonvested RSUs as of December 31, 2021 and changes during the year ended December 31, 2021 were as follows:
Nonvested Restricted Stock Units Shares/Units Weighted
Average
Grant Date
Fair Value
(in thousands)
Nonvested as of January 1, 2021 448.0 $ 86.56
Awarded 280.0 80.39
Vested (250.5) 81.92
Forfeited (53.2) 85.80
Nonvested as of December 31, 2021 424.3 84.86
The total aggregate intrinsic value of nonvested RSUs as of December 31, 2021 was $38 million and the weighted-average remaining contractual life was 1.77 years.
Other Stock-Based Plans
AEP also has a Stock Unit Accumulation Plan for Non-Employee Directors providing each non-employee director with AEP stock units as a substantial portion of the compensation for their services as a director. The number of stock units provided is based on the closing price of AEP common stock on the last trading day of the quarter for which the stock units were earned. Amounts equivalent to cash dividends on the stock units accrue as additional AEP stock units. The stock units granted to non-employee directors are fully vested on their grant date. Stock units are settled in cash upon termination of board service or up to 10 years later if the participant so elects. Cash settlements for stock units are calculated based on the average closing price of AEP common stock for the last 20 trading days prior to the distribution date. Effective in June 2022, these stock units become payable in AEP common stock rather than cash. After five years of service on the Board of Directors, non-employee directors receive subsequent AEP stock units as contributions to an AEP stock fund awarded under the Stock Unit Accumulation Plan. Such amounts may be exchanged into other market-based investments that are similar to the investment options available to employees that participate in AEP’s Incentive Compensation Deferral Plan. These balances are also paid in cash upon termination of board service or up to 10 years later if the participant so elects.
Management records compensation cost for stock units when the units are awarded and adjusts the liability for changes in value based on the current 20-day average closing price of AEP common stock on the valuation date.
Cash settlements for stock unit distributions were $5 million for the year ended December 31, 2021. For the years ended December 31, 2020 and 2019, cash settlements for stock unit distributions were immaterial.
The Board of Directors awarded stock units, including units awarded for dividends, as follows:
Years Ended December 31,
Stock Unit Accumulation Plan for Non-Employee Directors 2021 2020 2019
Awarded Units (in thousands) 12.6 12.1 10.0
Weighted-Average Grant Date Fair Value $ 84.54 $ 83.80 $ 89.13
Share-based Compensation Plans
For share-based payment arrangements the compensation cost, the actual tax benefit from the tax deductions for compensation cost recognized in income and the total compensation cost capitalized were as follows:
Years Ended December 31,
Share-based Compensation Plans 2021 2020 2019
(in millions)
Compensation Cost for Share-based Payment Arrangements (a) $ 61.1 $ 53.8 $ 57.9
Actual Tax Benefit 8.7 7.2 8.4
Total Compensation Cost Capitalized 16.9 20.4 20.0
(a)Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance expenses on the statements of income.
As of December 31, 2021, there was $73 million of total unrecognized compensation cost related to unvested share-based compensation arrangements granted under the 2015 LTIP. Unrecognized compensation cost related to unvested share-based arrangements will change as the fair value of performance shares is adjusted each period and as forfeitures for all award types are realized. AEP’s unrecognized compensation cost will be recognized over a weighted-average period of 1.39 years.
Under the 2015 LTIP, AEP is permitted to use authorized but unissued shares, treasury shares, shares acquired in the open market specifically for distribution under these plans, or any combination thereof to fulfill share commitments. AEP’s current practice is to use authorized but unissued shares to fulfill share commitments. The number of shares used to fulfill share commitments is generally reduced to offset tax withholding obligations.
16. RELATED PARTY TRANSACTIONS
The disclosures in this note apply to all Registrant Subsidiaries unless indicated otherwise.
For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 12 in addition to “Corporate Borrowing Program - AEP System” and “Securitized Accounts Receivables - AEP Credit” sections of Note 14.
Power Coordination Agreement (Applies to all Registrant Subsidiaries except AEP Texas and AEPTCo)
Effective January 1, 2014, the FERC approved the PCA. Under the PCA, APCo, I&M, KPCo and WPCo are individually responsible for planning their respective capacity obligations. The PCA allows, but does not obligate, APCo, I&M, KPCo and WPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective Off-system Sales and purchase activities.
AEPSC conducts power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on behalf of APCo, I&M, KPCo, PSO, SWEPCo and WPCo. Certain power and natural gas risk management activities for APCo, I&M, KPCo and WPCo are allocated based on the four member companies’ respective equity positions, while power and natural gas risk management activities for PSO and SWEPCo are allocated based on the Operating Agreement. With the transfer of OPCo’s generation assets to AGR in 2014, AEPSC conducts only gasoline, diesel fuel, energy procurement and risk management activities on OPCo’s behalf.
System Integration Agreement (Applies to APCo, I&M, PSO and SWEPCo)
Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and natural gas risk management activities based upon the location of such activity. Margins resulting from trading and marketing activities originating in PJM generally accrue to the benefit of APCo, I&M, KPCo and WPCo, while trading and marketing activities originating in SPP generally accrue to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among APCo, I&M, KPCo, PSO, SWEPCo and WPCo based upon the equity positions of these companies.
Affiliated Revenues and Purchases
The tables below represent revenues from affiliates, net of respective provisions for refund, by type of revenue for the Registrant Subsidiaries:
Related Party Revenues AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Year Ended December 31, 2021
Direct Sales to East Affiliates $ - $ - $ 128.6 $ - $ - $ - $ -
Transmission Revenues
- 1,136.1 60.3 (2.5) (1.1) - 39.6
Other Revenues 3.9 17.8 9.0 6.3 25.9 4.2 1.4
Total Affiliated Revenues $ 3.9 $ 1,153.9 $ 197.9 $ 3.8 $ 24.8 $ 4.2 $ 41.0
Related Party Revenues AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Year Ended December 31, 2020
Direct Sales to East Affiliates $ - $ - $ 112.5 $ - $ - $ - $ -
Auction Sales to OPCo (a) - - 5.3 3.1 - - -
Direct Sales to AEPEP 87.5 - - - - - -
Transmission Revenues
- 885.0 49.1 2.9 16.6 - 37.4
Other Revenues 3.3 11.3 7.8 4.5 24.9 5.2 1.6
Total Affiliated Revenues $ 90.8 $ 896.3 $ 174.7 $ 10.5 $ 41.5 $ 5.2 $ 39.0
Related Party Revenues AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Year Ended December 31, 2019
Direct Sales to East Affiliates $ - $ - $ 128.6 $ - $ - $ - $ -
Auction Sales to OPCo (a) - - 11.4 6.7 - - -
Direct Sales to AEPEP 157.2 - - - - - (0.1)
Transmission Revenues
- 795.5 58.5 0.7 7.7 1.3 3.6
Other Revenues 3.3 11.2 6.8 3.1 19.6 4.8 1.4
Total Affiliated Revenues $ 160.5 $ 806.7 $ 205.3 $ 10.5 $ 27.3 $ 6.1 $ 4.9
(a)Refer to the Ohio Auctions section below for further information regarding these amounts.
The tables below represent the purchased power expenses incurred for purchases from affiliates. AEP Texas, AEPTCo, APCo, PSO and SWEPCo did not purchase any power from affiliates for the years ended December 31, 2021, 2020 and 2019.
Related Party Purchases I&M OPCo
(in millions)
Year Ended December 31, 2021
Auction Purchases from AEPEP (a) $ - $ 26.6
Auction Purchases from AEP Energy (a) - 25.3
Direct Purchases from AEGCo 217.9 -
Total Affiliated Purchases $ 217.9 $ 51.9
Related Party Purchases I&M OPCo
(in millions)
Year Ended December 31, 2020
Auction Purchases from AEPEP (a) $ - $ 51.0
Auction Purchases from AEP Energy (a) - 58.7
Auction Purchases from AEPSC (a) - 10.0
Direct Purchases from AEGCo 172.8 -
Total Affiliated Purchases $ 172.8 $ 119.7
Related Party Purchases I&M OPCo
(in millions)
Year Ended December 31, 2019
Auction Purchases from AEPEP (a) $ - $ 64.6
Auction Purchases from AEP Energy (a) - 69.9
Auction Purchases from AEPSC (a) - 21.5
Direct Purchases from AEGCo 214.9 -
Total Affiliated Purchases $ 214.9 $ 156.0
(a) Refer to the Ohio Auctions section below for further information regarding this amount.
The above summarized related party revenues and expenses are reported in Sales to AEP Affiliates and Purchased Electricity from AEP Affiliates, respectively, on the Registrant Subsidiaries’ statements of income. Since the Registrant Subsidiaries are included in AEP’s consolidated results, the above summarized related party transactions are eliminated in total in AEP’s consolidated revenues and expenses.
PJM and SPP Transmission Service Charges (Applies to all Registrant Subsidiaries except AEP Texas)
The AEP East Companies are parties to the TA, which defines how transmission costs through the PJM OATT are allocated among the AEP East Companies on a 12-month average coincident peak basis. Additional costs for transmission services provided by AEPTCo and other transmission affiliates are billed to AEP East Companies through the PJM OATT.
The following table shows the net transmission service charges recorded by APCo, I&M and OPCo:
Years Ended December 31,
Company 2021 2020 2019
(in millions)
APCo $ 302.0 $ 243.2 $ 222.3
I&M 186.7 145.9 143.5
OPCo 508.9 417.4 373.4
The charges shown above are recorded in Other Operation expenses on the statements of income.
PSO, SWEPCo and AEPSC are parties to the TCA in connection with the operation of the transmission assets of PSO and SWEPCo. The TCA has been approved by the FERC and establishes a coordinating committee, which is charged with overseeing the coordinated planning of the transmission facilities of the parties to the agreement. This includes the performance of transmission planning studies, the interaction of such companies with independent system operators and other regional bodies interested in transmission planning and compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such a tariff.
Under the TCA, the parties to the agreement delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. The allocations have been governed by the FERC-approved OATT for the SPP. Additional costs for transmission services provided by AEPTCo and other transmission affiliates are billed to PSO and SWEPCo through the SPP OATT.
The following table shows the net transmission service charges recorded by PSO and SWEPCo:
Years Ended December 31,
Company 2021 2020 2019
(in millions)
PSO $ 94.7 $ 69.7 $ 46.9
SWEPCo 56.2 31.3 20.1
The charges shown above are recorded in Other Operation expenses on the statements of income.
AEPTCo provides transmission services to affiliates in accordance with the OATT, TA and TCA. AEPTCo recorded affiliated transmission revenues in Sales to AEP Affiliates on the statements of income. Refer to the Affiliated Revenues and Purchases section above for amounts related to these transactions.
ERCOT Transmission Service Charges (Applies to AEP and AEP Texas)
Pursuant to an order from the PUCT, ETT bills AEP Texas for its ERCOT wholesale transmission services. ETT billed AEP Texas $28 million, $28 million and $27 million for transmission services for the years ended December 31, 2021, 2020 and 2019, respectively. The billings are recorded in Other Operation expenses on AEP Texas’ statements of income.
Oklaunion PPA between AEP Texas and AEPEP (Applies to AEP Texas)
In 2007, AEP Texas entered into a PPA with an affiliate, AEPEP, whereby AEP Texas agreed to sell AEPEP 100% of AEP Texas’ capacity and associated energy from its undivided interest (54.69%) in the Oklaunion Power Station. The PPA was approved by the FERC. In September 2018, the co-owners of Oklaunion Power Station voted to close the plant in 2020. Effective October 2018, AEP Texas increased depreciation expense to ensure the plant balances are fully depreciated as of September 2020 and recovered through the PPA billings to AEPEP. Under the early termination provisions of the PPA, AEPEP paid AEP Texas the full Property, Plant and Equipment balance through depreciation payments until termination of the PPA due to the plant closing in September 2020. See “Dispositions” section of Note 7 for additional information.
AEP Texas recorded revenue of $0, $88 million and $157 million from AEPEP for the years ended December 31, 2021, 2020 and 2019, respectively. These amounts are included in Sales to AEP Affiliates on AEP Texas’ statements of income.
Joint License Agreement (Applies to AEPTCo, APCo, I&M, OPCo and PSO)
AEPTCo entered into a 50-year joint license agreement with APCo, I&M, KPCo, OPCo and PSO, respectively, allowing either party to occupy the granting party’s facilities or real property. In addition, AEPTCo entered into a 5-year joint license agreement with APCo and WPCo. After the expiration of these agreements, the term shall automatically renew for successive one-year terms unless either party provides notice. The joint license billing provides compensation to the granting party for the cost of carrying assets, including depreciation expense, property taxes, interest expense, return on equity and income taxes. AEPTCo recorded the following costs in Other Operation expense related to these agreements:
Years Ended December 31,
Billing Company 2021 2020 2019
(in millions)
APCo $ 2.4 $ 0.9 $ 0.2
I&M 4.8 3.0 1.5
KPCo 0.5 0.4 0.3
OPCo 4.6 4.5 2.2
PSO 0.4 0.4 0.3
WPCo 0.2 0.2 0.1
APCo, I&M, KPCo, OPCo, PSO and WPCo recorded income related to these agreements in Sales to AEP Affiliates on the statements of income.
Ohio Auctions (Applies to APCo, I&M and OPCo)
In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015. AEP Energy, AEPEP, APCo, KPCo, I&M and WPCo participate in the auction process and have been awarded tranches of OPCo’s SSO load. Refer to the Affiliated Revenues and Purchases section above for amounts related to these transactions.
Unit Power Agreements (Applies to I&M)
UPA between AEGCo and I&M
A UPA between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility. Subsequently, I&M assigns 30% of the power to KPCo. See the “UPA between AEGCo and KPCo” section below. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) net of amounts received by AEGCo from any other sources, sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC. The I&M Power Agreement will continue in effect until the debt obligations of AEGCo secured by the Rockport Plant have been satisfied and discharged (currently expected to be December 2028).
UPA between AEGCo and KPCo
Pursuant to an assignment between I&M and KPCo and a UPA between AEGCo and KPCo, AEGCo sells KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo pays to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KPCo UPA ends in December 2022.
Cook Coal Terminal (Applies to I&M, PSO and SWEPCo)
Cook Coal Terminal, which is owned by AEGCo, performs coal transloading and storage services at cost for I&M. The coal transloading costs were $11 million, $12 million and $13 million for the years ended December 31, 2021, 2020 and 2019, respectively. I&M recorded the cost of transloading services in Fuel on the balance sheets.
Cook Coal Terminal also performs railcar maintenance services at cost for I&M, PSO and SWEPCo. The railcar maintenance costs were as follows:
Years Ended December 31,
Company 2021 2020 2019
(in millions)
I&M $ 0.3 $ 0.9 $ 1.3
PSO 0.4 0.7 0.8
SWEPCo 2.8 3.0 4.0
I&M, PSO and SWEPCo recorded the cost of the railcar maintenance services in Fuel on the balance sheets.
I&M Barging, Urea Transloading and Other Services (Applies to APCo and I&M)
I&M provides barging, urea transloading and other transportation services to affiliates. Urea is a chemical used to control NOx emissions at certain generation plants in the AEP System. I&M recorded revenues from barging, transloading and other services in Other Revenues - Affiliated on the statements of income. The affiliated companies recorded these costs paid to I&M as fuel expenses or other operation expenses. The amounts of affiliated expenses were:
Years Ended December 31,
Company 2021 2020 2019
(in millions)
AEGCo $ 7.6 $ 10.6 $ 14.9
APCo 40.1 43.7 38.9
KPCo 3.1 3.2 4.8
WPCo
3.2 3.3 4.8
Central Machine Shop (Applies to APCo, I&M, OPCo, PSO and SWEPCo)
APCo operates a facility which repairs and rebuilds specialized components for the generation plants across the AEP System. APCo defers the cost of performing these services on the balance sheet and then transfers the cost to the affiliate for reimbursement. The AEP subsidiaries recorded these billings as capital or maintenance expenses depending on the nature of the services received. These billings are recoverable from customers. The following table provides the amounts billed by APCo to the following affiliates:
Years Ended December 31,
Company 2021 2020 2019
(in millions)
AGR $ 0.4 $ 2.9 $ 0.8
I&M 2.4 3.2 2.3
KPCo 1.0 0.9 1.4
OPCo 0.4 - -
PSO 0.7 0.9 1.1
SWEPCo 2.7 0.5 1.1
Sales and Purchases of Property
Certain AEP subsidiaries had affiliated sales and purchases of electric property individually amounting to $100 thousand or more, sales and purchases of meters and transformers, and sales and purchases of transmission property. There were no gains or losses recorded on the transactions. The following tables show the sales and purchases, recorded at net book value:
Sales
Years Ended December 31,
Company 2021 2020 2019
(in millions)
AEP Texas $ 0.4 $ 0.9 $ 0.9
AEPTCo 1.4 0.2 -
APCo 6.2 5.7 5.5
I&M 7.0 1.5 7.5
OPCo 9.2 7.0 7.0
PSO 0.5 1.1 0.8
SWEPCo 0.4 0.8 0.2
Purchases
Years Ended December 31,
Company 2021 2020 2019
(in millions)
AEP Texas $ 0.4 $ 1.5 $ 0.3
AEPTCo 16.7 6.0 10.2
APCo 1.0 1.3 6.0
I&M 0.6 3.4 0.9
OPCo 1.4 1.2 3.0
PSO 0.3 0.4 0.5
SWEPCo 0.3 2.8 0.7
The amounts above are recorded in Property, Plant and Equipment on the balance sheets.
Sempra Renewables LLC PPAs (Applies to I&M, OPCo and SWEPCo)
In April 2019, AEP acquired Sempra Renewables LLC and its ownership interests in 724 MWs of wind generation. The operating wind generation portfolio includes seven wind farms. Prior to the acquisition, two wind farms had existing PPAs with I&M, OPCo and SWEPCo. One of the joint venture wind farms has PPAs with I&M and OPCo for a portion of its energy production. The I&M portion totaled $10 million, $11 million and $9 million and the OPCo portion totaled $20 million, $23 million and $17 million respectively, for the years ended December 31, 2021, 2020 and 2019, respectively. Another joint venture wind farm has a PPA with SWEPCo for a portion of its energy production which totaled $14 million, $14 million and $10 million of purchased electricity for the years ended December 31, 2021, 2020 and 2019, respectively. See “Acquisitions” section of Note 7 for additional information.
Intercompany Billings
The Registrant Subsidiaries and other AEP subsidiaries perform certain utility services for each other when necessary or practical. The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable basis of proration for services that benefit multiple companies. The billings for services are made at cost and include no compensation for the use of equity capital.
Charitable Contributions to AEP Foundation
The American Electric Power Foundation is funded by American Electric Power and its utility operating units. The Foundation provides a permanent, ongoing resource for charitable initiatives and multi-year commitments in the communities served by AEP and initiatives outside of AEP’s 11-state service area. Charitable contributions to the AEP Foundation were recorded in Other Operation on the statements of income. In 2021 and 2020, there were no charitable contributions made to the AEP Foundation. The charitable contributions to the AEP Foundation recorded in 2019 were as follows:
Year Ended
Company December 31, 2019
(in millions)
AEP $ 50.0
AEP Texas 6.2
AEPTCo 6.5
APCo 8.9
I&M 9.0
OPCo 5.4
PSO 3.4
SWEPCo 5.5
OKTCo Radial Assets Transfer (Applies to AEP, AEPTCo and PSO)
In August 2020, AEPSC filed a request with FERC, on behalf of PSO and OKTCo, to transfer OKTCo’s interests in its radial assets to PSO. OKTCo had previously constructed radial assets in the PSO service territory and after the radial assets were placed into service, management determined the radial assets were not eligible to be included as part of OKTCo’s SPP OATT formula rates. In October 2020, FERC approved the request and in December 2020, OKTCo completed the transfer of its interest in the radial assets to PSO, through Parent, at net book value. At the transfer date, the net book value of the radial assets were $60 million, before associated tax liabilities.
17. VARIABLE INTEREST ENTITIES AND EQUITY METHOD INVESTMENTS
The disclosures in this note apply to all Registrants unless indicated otherwise.
The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a variable interest in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently.
AEP holds ownership interests in businesses with varying ownership structures. Partnership interests and other variable interests are evaluated to determine if each entity is a VIE, and if so, whether or not the VIE should be consolidated into AEP’s financial statements. AEP has not provided material financial or other support that was not previously contractually required to any of its consolidated VIEs. If an entity is determined not to be a VIE, or if the entity is determined to be a VIE and AEP is not deemed to be the primary beneficiary, the entity is accounted for under the equity method of accounting.
Consolidated Variable Interests Entities
Sabine (Applies to AEP and SWEPCo)
Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the years ended December 31, 2021, 2020 and 2019 were $162 million, $131 million and $110 million, respectively. See the tables below for the classification of Sabine’s assets and liabilities on SWEPCo’s balance sheets.
As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $155 million. Since SWEPCo uses self-bonding, the guarantee commits SWEPCo to complete the reclamation, in the event, Sabine does not complete the work. This guarantee ends upon completion of reclamation. The mine end-of-life has been adjusted to March 2023, in order to align with the announced closure of the Pirkey Power Plant. Reclamation is expected to be complete by 2037 at an estimated cost of $104 million. Actual reclamation costs could vary due to inflation and scope changes to the mine reclamation. SWEPCo recovers these costs through its fuel clauses. As of December 31, 2021, SWEPCo has recorded $94 million of mine reclamation costs in Asset Retirement Obligations and has collected $85 million through a rider for reclamation costs. The remaining $10 million is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets.
DCC Fuel (Applies to AEP and I&M)
I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the years ended December 31, 2021, 2020 and 2019 were $91 million, $94 million and $95 million, respectively. The leases were recorded as finance leases on I&M’s balance sheets as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months. Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The finance leases are eliminated upon consolidation. See the tables below for the classification of DCC Fuel’s assets and liabilities on I&M’s balance sheets.
Transition Funding (Applies to AEP and AEP Texas)
Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. Management has concluded that AEP Texas is the primary beneficiary of Transition Funding because AEP Texas has the power to direct the most significant activities of the VIE and AEP Texas’ equity interest could potentially be significant. Therefore, AEP Texas is required to consolidate Transition Funding. As of December 31, 2021 and 2020, $68 million and $66 million of the securitized bonds were included in Long-term Debt Due Within One Year - Nonaffiliated, respectively, and $141 million and $209 million were included in Long-term Debt - Nonaffiliated, respectively, on the balance sheets. Transition Funding has securitized transition assets of $184 million and $242 million as of December 31, 2021 and 2020, respectively, which are presented separately on the face of the balance sheets. The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from AEP Texas under-recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to AEP Texas or any other AEP entity. AEP Texas acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding’s assets and liabilities on the balance sheets.
Restoration Funding (Applies to AEP and AEP Texas)
Restoration Funding was formed for the sole purpose of issuing and servicing securitization bonds related to storm restoration of AEP Texas’ distribution system primarily due to damage caused by Hurricane Harvey. Management has concluded that AEP Texas is the primary beneficiary of Restoration Funding because AEP Texas has the power to direct the most significant activities of the VIE and AEP Texas’ equity interest could potentially be significant. Therefore, AEP Texas is required to consolidate Restoration Funding. As of December 31, 2021 and 2020, $23 million and $23 million of the securitized bonds were included in Long-term Debt Due Within One Year - Nonaffiliated, respectively, and $173 million and $195 million were included in Long-term Debt - Nonaffiliated, respectively, on the balance sheets. Restoration Funding has securitized assets of $183 million and $205 million as of December 31, 2021 and 2020, respectively, which are presented separately on the face of the balance sheets. The securitized restoration assets represent the right to impose and collect Texas storm restoration costs from customers receiving electric transmission or distribution service from AEP Texas under-recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to AEP Texas or any other AEP entity. AEP Texas acts as the servicer for Restoration Funding’s securitized assets and remits all related amounts collected from customers to Restoration Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Restoration Funding’s assets and liabilities on the balance sheets.
Appalachian Consumer Rate Relief Funding (Applies to AEP and APCo)
Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo’s under-recovered ENEC deferral balance. Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo’s equity interest could potentially be significant. Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding. As of December 31, 2021 and 2020, $26 million and $25 million of the securitized bonds were included in Long-term Debt Due Within One Year - Nonaffiliated, respectively, and $173 million and $199 million were included in Long-term Debt - Nonaffiliated, respectively, on the balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $185 million and $210 million as of December 31, 2021 and 2020, respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding’s securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s balance sheets.
AEP Credit (Applies to AEP)
AEP Credit is a wholly-owned subsidiary of Parent. AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements. AEP provides a minimum of 5% equity and up to 25% of AEP Credit’s short-term borrowing needs in excess of third-party financings. Any third-party financing of AEP Credit only has recourse to the receivables securitized for such financing. Based on AEP’s control of AEP Credit, management concluded that AEP is the primary beneficiary and is required to consolidate AEP Credit. See the tables below for the classification of AEP Credit’s assets and liabilities on the balance sheets. See “Securitized Accounts Receivables - AEP Credit” section of Note 14.
EIS (Applies to AEP)
AEP’s subsidiaries participate in one protected cell of EIS for six lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell’s only participant, but allows certain third-parties access to this insurance. AEP’s subsidiaries and any allowed third-parties share in the insurance coverage, premiums and risk of loss from claims. Based on AEP’s control and the structure of the protected cell of EIS, management concluded that AEP is the primary beneficiary of the protected cell and is required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the years ended December 31, 2021, 2020 and 2019 was $30 million, $31 million and $34 million, respectively. See the tables below for the classification of the protected cell’s assets and liabilities on the balance sheets. The amount reported as equity is the protected cell’s policy holders’ surplus.
Transource Energy (Applies to AEP)
Transource Energy was formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. AEP has equity and voting ownership of 86.5% with the other owner having 13.5% interest. Management has concluded that Transource Energy is a VIE and that AEP is the primary beneficiary because AEP has the power to direct the most significant activities of the entity and AEP’s equity interest could potentially be significant. Therefore, AEP is required to consolidate Transource Energy. Transource Energy’s activities consist of the development, construction and operation of FERC-regulated transmission assets in Missouri, West Virginia, Pennsylvania, Maryland and Oklahoma. Transource Energy has a credit facility agreement where borrowings are loaned through intercompany lending agreements to its subsidiaries. The creditor to the agreement has no recourse to the general credit of AEP. Transource Energy’s credit facility agreement contains certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%. See the tables below for the classification of Transource Energy’s assets and liabilities on the balance sheets.
Apple Blossom Wind Holdings LLC and Black Oak Getty Wind Holdings LLC (Applies to AEP)
In April 2019, AEP acquired an equity interest in Apple Blossom Wind Holdings LLC (Apple Blossom) and Black Oak Getty Wind Holdings LLC (Black Oak) (collectively the Project Entities) as part of the purchase of Sempra Renewables LLC. Both of the Project Entities have long-term PPAs for 100% of their energy production. The Project Entities are tax equity partnerships with nonaffiliated noncontrolling interests to which a percentage of earnings, tax attributes and cash flows are allocated in accordance with the respective limited liability company agreements. Management has concluded that the Project Entities are VIEs and that AEP is the primary beneficiary based on its power as managing member to direct the activities that most significantly impact the Project Entities’ economic performance. In addition, AEP has not provided material financial or other support to the Project Entities that was not previously contractually required. As the primary beneficiary of the Project Entities, AEP consolidates the Project Entities into its financial statements. See the table below for the classification of Project Entities’ assets and liabilities on the balance sheets.
The nonaffiliated interests in the Project Entities is presented in Noncontrolling Interests on the balance sheets. As of December 31, 2021 and 2020, AEP recorded $108 million and $119 million, respectively, of Noncontrolling Interests related to the Project Entities in Equity on the balance sheets.
The Project Entities’ tax equity partnerships represent substantive profit-sharing arrangements. The method for attributing income and loss to the noncontrolling interests is a balance sheet approach referred to as the hypothetical liquidation at book value (HLBV) method. Under the HLBV method, the income and loss attributable to the noncontrolling interests reflect changes in the amounts the members would hypothetically receive at each balance sheet date under the liquidation provisions of the respective limited liability company agreements, assuming the net assets of these entities were liquidated at recorded amounts, after taking into account any capital transactions, such as contributions or distributions, between the entities and the members. For the years ended December 31, 2021 and 2020, the HLBV method resulted in a loss of $7 million and $6 million, respectively, allocated to Noncontrolling Interests.
Santa Rita East (Applies to AEP)
In July 2019, AEP acquired a 75% interest in Santa Rita East Wind Energy Holdings, LLC and its wholly-owned subsidiary, Santa Rita East Wind Energy, LLC (collectively, Santa Rita East). In November 2020, AEP acquired an additional 10% interest in Santa Rita East resulting in AEP having a total interest of 85%. Santa Rita East is a partnership whose sole purpose is to own and operate a 302 MW wind generation facility in west Texas. Santa Rita East delivers energy and provides renewable energy credits through three long-term PPAs totaling 260 MWs. The remaining 42 MWs of energy are sold at wholesale into ERCOT. Management has concluded that Santa Rita East is a VIE and that AEP is the primary beneficiary based on its power as managing member of the partnership to direct the activities that most significantly impact Santa Rita East’s economic performance. As the primary beneficiary of Santa Rita East, AEP consolidates Santa Rita East into its financial statements. See the tables below for the classification of Santa Rita East’s assets and liabilities on the balance sheets.
AEP recognized $25 million and $23 million of PTC attributable to Santa Rita East for the years ended December 31, 2021 and 2020, respectively, which was recorded in Income Tax Expense (Benefit) on the statements of income. The nonaffiliated interest in Santa Rita East is presented in Noncontrolling Interests on the balance sheets. As of December 31, 2021 and 2020, AEP recorded $59 million and $61 million, respectively, of Noncontrolling Interests related to Santa Rita East in Equity on the balance sheets.
Dry Lake (Applies to AEP)
In November 2020, AEP signed a Purchase and Sale Agreement with a nonaffiliate to acquire a 75% ownership interest in the entity that owns Dry Lake Solar Project (collectively, Dry Lake). Dry Lake is a partnership whose sole purpose is to own, operate and maintain a 100 MW solar generation facility in southern Nevada. In March 2021, AEP closed the transaction and the solar project was placed in-service in May 2021. Dry Lake delivers energy and provides renewable energy credits through a long-term PPA. Management has concluded that Dry Lake is a VIE and that AEP is the primary beneficiary based on its power as managing member to direct the activities that most significantly impact Dry Lake’s economic performance. As the primary beneficiary of Dry Lake, AEP consolidates Dry Lake into its financial statements. See the table below for the classification of Dry Lake assets and liabilities on the balance sheets.
AEP recognized $33 million of ITC attributable to Dry Lake for the year ended December 31, 2021 which was recorded in Income Tax Expense (Benefit) on the statements of income. The nonaffiliated interest in Dry Lake is presented in Noncontrolling Interests on the balance sheets. As of December 31, 2021, AEP recognized $35 million of Noncontrolling Interest on the balance sheets.
The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation.
American Electric Power Company, Inc. and Subsidiary Companies
Variable Interest Entities
December 31, 2021
Registrant Subsidiaries
SWEPCo
Sabine I&M
DCC Fuel AEP Texas Transition Funding AEP Texas Restoration Funding APCo
Appalachian
Consumer
Rate
Relief Funding
(in millions)
ASSETS
Current Assets $ 77.2 $ 65.2 $ 24.9 $ 24.3 $ 16.0
Net Property, Plant and Equipment 51.8 118.6 - - -
Other Noncurrent Assets 104.1 57.2 208.3 (a) 192.6 (b) 187.8 (c)
Total Assets $ 233.1 $ 241.0 $ 233.2 $ 216.9 $ 203.8
LIABILITIES AND EQUITY
Current Liabilities $ 18.9 $ 65.1 $ 71.2 $ 36.1 $ 29.0
Noncurrent Liabilities 214.3 175.9 157.8 179.6 172.9
Equity (0.1) - 4.2 1.2 1.9
Total Liabilities and Equity $ 233.1 $ 241.0 $ 233.2 $ 216.9 $ 203.8
(a)Includes an intercompany item eliminated in consolidation of $24 million.
(b)Includes an intercompany item eliminated in consolidation of $8 million.
(c)Includes an intercompany item eliminated in consolidation of $2 million.
American Electric Power Company, Inc. and Subsidiary Companies
Variable Interest Entities
December 31, 2021
Other Consolidated VIEs
AEP Credit Protected
Cell
of EIS Transource Energy Apple Blossom and Black Oak Santa Rita East Dry Lake
(in millions)
ASSETS
Current Assets $ 996.6 $ 217.3 $ 38.8 $ 9.9 $ 7.6 $ 4.0
Net Property, Plant and Equipment - - 475.4 217.3 437.6 146.1
Other Noncurrent Assets 10.4 - 3.0 11.3 - 0.3
Total Assets $ 1,007.0 $ 217.3 $ 517.2 $ 238.5 $ 445.2 $ 150.4
LIABILITIES AND EQUITY
Current Liabilities $ 953.1 $ 37.5 $ 12.5 $ 6.6 $ 5.8 $ 0.9
Noncurrent Liabilities 0.9 82.3 216.9 5.2 7.0 0.6
Equity 53.0 97.5 287.8 226.7 432.4 148.9
Total Liabilities and Equity $ 1,007.0 $ 217.3 $ 517.2 $ 238.5 $ 445.2 $ 150.4
American Electric Power Company, Inc. and Subsidiary Companies
Variable Interest Entities
December 31, 2020
Registrant Subsidiaries
SWEPCo
Sabine I&M
DCC Fuel AEP Texas Transition Funding AEP Texas Restoration Funding APCo
Appalachian
Consumer
Rate
Relief Funding
(in millions)
ASSETS
Current Assets $ 88.0 $ 76.1 $ 61.2 $ 23.3 $ 16.8
Net Property, Plant and Equipment 97.3 138.9 - - -
Other Noncurrent Assets 99.3 70.9 273.9 (a) 214.9 (b) 212.7 (c)
Total Assets $ 284.6 $ 285.9 $ 335.1 $ 238.2 $ 229.5
LIABILITIES AND EQUITY
Current Liabilities $ 57.7 $ 76.0 $ 69.8 $ 33.9 $ 28.7
Noncurrent Liabilities 225.3 209.9 246.5 203.1 198.9
Equity 1.6 - 18.8 1.2 1.9
Total Liabilities and Equity $ 284.6 $ 285.9 $ 335.1 $ 238.2 $ 229.5
(a)Includes an intercompany item eliminated in consolidation of $32 million.
(b)Includes an intercompany item eliminated in consolidation of $9 million.
(c)Includes an intercompany item eliminated in consolidation of $3 million.
American Electric Power Company, Inc. and Subsidiary Companies
Variable Interest Entities
December 31, 2020
Other Consolidated VIEs
AEP Credit Protected
Cell
of EIS Transource Energy Apple Blossom and Black Oak Santa Rita East
(in millions)
ASSETS
Current Assets $ 960.4 $ 198.1 $ 22.2 $ 9.6 $ 6.0
Net Property, Plant and Equipment - - 458.7 223.1 453.1
Other Noncurrent Assets 12.9 - 3.7 12.1 -
Total Assets $ 973.3 $ 198.1 $ 484.6 $ 244.8 $ 459.1
LIABILITIES AND EQUITY
Current Liabilities $ 827.2 $ 43.1 $ 32.6 $ 5.3 $ 3.5
Noncurrent Liabilities 0.8 62.5 185.0 4.9 6.7
Equity 145.3 92.5 267.0 234.6 448.9
Total Liabilities and Equity $ 973.3 $ 198.1 $ 484.6 $ 244.8 $ 459.1
Non-Consolidated Significant Variable Interests
DHLC (Applies to AEP and SWEPCo)
DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO. The operations of DHLC are governed by the lignite mining agreement among SWEPCo, CLECO and DHLC. SWEPCo and CLECO share the executive board seats and voting rights equally. In accordance with the lignite mining agreement, each entity is responsible for 50% of DHLC’s obligations, including debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo’s total billings from DHLC for the years ended December 31, 2021, 2020 and 2019 were $47 million, $142 million and $55 million, respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets.
SWEPCo’s investment in DHLC was:
December 31,
2021 2020
As Reported on
the Balance Sheet Maximum
Exposure As Reported on
the Balance Sheet Maximum
Exposure
(in millions)
Capital Contribution from SWEPCo $ 7.6 $ 7.6 $ 7.6 $ 7.6
Retained Earnings 23.8 23.8 20.4 20.4
SWEPCo’s Share of Obligations - 50.3 - 98.5
Total Investment in DHLC $ 31.4 $ 81.7 $ 28.0 $ 126.5
OVEC (Applies to AEP and OPCo)
AEP and several nonaffiliated utility companies jointly own OVEC. As of December 31, 2021, AEP’s ownership in OVEC was 43.47%. Parent owns 39.17% and OPCo owns 4.3%. APCo, I&M and OPCo are members to an intercompany power agreement. The Registrants’ power participation ratios are 15.69% for APCo, 7.85% for I&M and 19.93% for OPCo. Participants of this agreement are entitled to receive and are obligated to pay for all OVEC generating capacity, approximately 2,400 MWs, in proportion to their respective power participation ratios. The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs, including outstanding indebtedness, and provide a return on capital. The intercompany power agreement ends in June 2040.
AEP and other nonaffiliated owners authorized environmental investments related to their ownership interests. OVEC financed capital expenditures in connection with the engineering and construction of FGD projects and the associated waste disposal landfills at its two generation plants. These environmental projects were funded through debt issuances. As of December 31, 2021 and 2020, OVEC’s outstanding indebtedness was approximately $1.1 billion and $1.3 billion, respectively. Although they are not an obligor or guarantor, the Registrants’ are responsible for their respective ratio of OVEC’s outstanding debt through the intercompany power agreement. Principal and interest payments related to OVEC’s outstanding indebtedness are disclosed in accordance with the accounting guidance for “Commitments.” See the “Commitments” section of Note 6 for additional information.
AEP is not required to consolidate OVEC as it is not the primary beneficiary, although AEP and its subsidiary holds a significant variable interest in OVEC. Power to control decision making that significantly impacts the economic performance of OVEC is shared amongst the owners through their representation on the Board of Directors of OVEC and the representation of the sponsoring companies on the Operating Committee under the intercompany power agreement.
AEP’s investment in OVEC was:
December 31,
2021 2020
As Reported on
the Balance Sheet Maximum
Exposure As Reported on
the Balance Sheet Maximum Exposure
(in millions)
Capital Contribution from AEP $ 4.4 $ 4.4 $ 4.4 $ 4.4
AEP’s Ratio of OVEC Debt (a) - 492.0 - 555.0
Total Investment in OVEC $ 4.4 $ 496.4 $ 4.4 $ 559.4
(a)Based on the Registrants’ power participation ratios APCo, I&M and OPCo’s share of OVEC debt was $177 million, $89 million and $226 million as of December 31, 2021 and $200 million, $100 million and $255 million as of December 31, 2020, respectively.
Power purchased by the Registrant Subsidiaries from OVEC is included in Purchased Electricity for Resale on the statements of income and is shown in the table below:
Years Ended December 31,
Company 2021 2020 2019
(in millions)
APCo $ 104.3 $ 94.4 $ 104.5
I&M 52.2 47.2 52.3
OPCo 133.0 120.8 132.7
AEPSC (Applies to AEP)
AEPSC provides certain managerial and professional services to AEP’s subsidiaries. Parent is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct-charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP.
Total AEPSC billings to the Registrant Subsidiaries were as follows:
Years Ended December 31,
Company 2021 2020 2019
(in millions)
AEP Texas $ 206.9 $ 199.4 $ 206.6
AEPTCo 267.1 270.3 242.3
APCo 313.3 294.9 308.3
I&M 200.9 210.2 184.8
OPCo 234.9 232.8 230.4
PSO 123.7 113.2 125.7
SWEPCo 168.6 161.8 169.5
The carrying amount and classification of variable interest in AEPSC’s accounts payable were as follows:
December 31,
2021 2020
Company As Reported on
the Balance Sheet Maximum
Exposure As Reported on
the Balance Sheet Maximum
Exposure
(in millions)
AEP Texas $ 22.2 $ 22.2 $ 30.5 $ 30.5
AEPTCo 23.3 23.3 45.9 45.9
APCo 44.1 44.1 42.8 42.8
I&M 21.8 21.8 27.1 27.1
OPCo 25.5 25.5 33.9 33.9
PSO 13.7 13.7 15.7 15.7
SWEPCo 20.5 20.5 22.0 22.0
AEGCo (Applies to AEP)
AEGCo, a wholly-owned subsidiary of Parent, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1 and leases a 50% interest in Rockport Plant, Unit 2. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. Total billings to I&M from AEGCo for the years ended December 31, 2021, 2020 and 2019 were $218 million, $173 million and $215 million, respectively. The carrying amounts of I&M’s liabilities associated with AEGCo as of December 31, 2021 and 2020 were $18 million and $9 million, respectively. Management estimates the maximum exposure of loss to be equal to the amount of such liability. See “Rockport Lease” section of Note 13 for additional information.
Significant Equity Method Investments in Unconsolidated Entities (Applies to AEP)
For a discussion of the equity method of accounting, see the “Equity Investment in Unconsolidated Entities” section of Note 1.
Sempra Renewables LLC
In April 2019, AEP acquired a 50% interest in five wind farms in multiple states as part of the purchase of Sempra Renewables LLC. The wind farms are joint ventures with BP Wind Energy who holds the other 50% interest. All five wind farms have long-term PPAs for 100% of their energy production. One of the jointly-owned wind farms has PPAs with I&M and OPCo for a portion of its energy production. Another jointly-owned wind farm has a PPA with SWEPCo for a portion of its energy production. The joint venture wind farms are not considered VIEs and AEP is not required to consolidate them as AEP does not have a controlling financial interest. However, AEP is able to exercise significant influence over the wind farms and therefore applies the equity method of accounting. As of December 31, 2021 and 2020, AEP’s carrying value of the investment in the five joint venture wind farms was $399 million and $376 million, respectively. The difference between AEP’s carrying value and the amount of underlying equity in net assets is immaterial. The investment includes amounts recognized in AOCI related to interest rate cash flow hedges. AEP’s equity earnings associated with the five joint venture wind farms was a loss of $12 million and earnings of $2 million for the years ended December 31, 2021 and 2020, respectively. AEP recognized $33 million and $36 million of PTC attributable to the joint venture wind farms for the years ended December 31, 2021 and 2020, respectively, which was recorded in Income Tax Expense (Benefit) on the statements of income.
ETT
ETT designs, acquires, constructs, owns and operates certain transmission facilities in ERCOT. Berkshire Hathaway Energy, a nonaffiliated entity, holds a 50% membership interest in ETT and AEP Transmission Holdco holds a 50% membership interest in ETT. As a result, AEP, through its wholly-owned subsidiary, holds a 50% membership interest in ETT. As of December 31, 2021 and 2020, AEP’s investment in ETT was $733 million and $732 million, respectively. AEP’s equity earnings associated with ETT were $66 million, $68 million and $66 million for the years ended December 31, 2021, 2020 and 2019 respectively.
18. PROPERTY, PLANT AND EQUIPMENT
The disclosures in this note apply to all Registrants unless indicated otherwise.
Property, Plant and Equipment is shown functionally on the face of the balance sheets. The following tables include the total plant balances as of December 31, 2021 and 2020:
December 31, 2021 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Regulated Property, Plant and Equipment
Generation
$ 21,196.8 (a) $ - $ - $ 6,683.9 $ 5,531.8 $ - $ 1,802.4 $ 4,734.5 (a)
Transmission 29,866.0 5,849.9 10,886.3 4,322.4 1,783.1 2,992.8 1,107.7 2,316.9
Distribution 24,440.0 4,917.2 - 4,683.3 2,800.1 6,070.6 3,004.9 2,514.3
Other 5,249.8 958.7 427.2 668.9 755.1 982.2 433.5 542.0
CWIP 3,632.4 (a) 551.3 1,394.8 469.9 302.8 365.0 156.0 240.7 (a)
Less: Accumulated Depreciation
20,375.5 1,642.9 772.9 5,047.4 3,885.3 2,457.4 1,707.0 3,002.2
Total Regulated Property, Plant and Equipment - Net
64,009.5 10,634.2 11,935.4 11,781.0 7,287.6 7,953.2 4,797.5 7,346.2
Nonregulated Property, Plant and Equipment - Net
1,991.8 1.2 0.3 23.3 23.3 9.8 5.3 53.9
Total Property, Plant and Equipment - Net
$ 66,001.3 (b) $ 10,635.4 $ 11,935.7 (b) $ 11,804.3 $ 7,310.9 $ 7,963.0 $ 4,802.8 $ 7,400.1
December 31, 2020 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Regulated Property, Plant and Equipment
Generation
$ 21,587.8 (a) $ - $ - $ 6,633.7 $ 5,264.7 $ - $ 1,480.7 $ 4,681.4 (a)
Transmission 27,841.5 5,279.6 9,593.5 3,900.5 1,696.4 2,831.9 1,069.9 2,165.7
Distribution 23,972.1 4,580.8 - 4,464.3 2,594.6 5,708.3 2,853.0 2,382.5
Other 4,852.4 866.0 328.8 598.0 644.6 888.5 388.1 564.5
CWIP 3,815.0 (a) 614.1 1,422.6 484.6 362.4 362.3 128.7 228.3 (a)
Less: Accumulated Depreciation
20,094.2 1,528.1 572.8 4,711.0 3,538.6 2,348.8 1,607.3 3,032.0
Total Regulated Property, Plant and Equipment - Net
61,974.6 9,812.4 10,772.1 11,370.1 7,024.1 7,442.2 4,313.1 6,990.4
Nonregulated Property, Plant and Equipment - Net
1,927.0 1.2 0.7 24.0 28.2 9.9 6.9 97.8
Total Property, Plant and Equipment - Net
$ 63,901.6 $ 9,813.6 $ 10,772.8 $ 11,394.1 $ 7,052.3 $ 7,452.1 $ 4,320.0 $ 7,088.2
(a)AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant.
(b)Amount excludes $2.3 billion and $165 million for AEP and AEPTCo, respectively, of Property, Plant and Equipment - Net classified as Assets Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
Depreciation, Depletion and Amortization
The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. The following tables provide total regulated annual composite depreciation rates and depreciable lives for the Registrants:
AEP
2021 2020 2019
Functional Class of Property Annual Composite
Depreciation Rate Ranges Depreciable
Life Ranges Annual Composite
Depreciation Rate Ranges Depreciable
Life Ranges Annual Composite
Depreciation Rate Ranges Depreciable
Life Ranges
(in years) (in years) (in years)
Generation 2.7% - 7.8% 20 - 132 2.7% - 6.3% 20 - 132 2.5% - 5.5% 20 - 132
Transmission 2.0% - 2.6% 15 - 75 2.0% - 2.6% 15 - 75 1.8% - 2.6% 15 - 81
Distribution 2.8% - 3.6% 7 - 80 2.7% - 3.7% 7 - 78 2.7% - 3.7% 7 - 78
Other 3.0% - 12.5% 5 - 75 2.8% - 11.3% 5 - 75 2.6% - 9.5% 5 - 75
AEP Texas
2021 2020 2019
Functional Class of Property Annual Composite
Depreciation Rate Depreciable
Life Ranges Annual Composite
Depreciation Rate Depreciable
Life Ranges Annual Composite
Depreciation Rate Depreciable
Life Ranges
(in years) (in years) (in years)
Transmission 2.2% 50 - 75 2.0% 50 - 75 1.8% 45 - 81
Distribution 2.9% 7 - 70 3.1% 7 - 70 3.5% 7 - 70
Other 5.8% 5 - 50 6.1% 5 - 50 6.3% 5 - 50
AEPTCo
2021 2020 2019
Functional Class of Property Annual Composite
Depreciation Rate Depreciable
Life Ranges Annual Composite
Depreciation Rate Depreciable
Life Ranges Annual Composite
Depreciation Rate Depreciable
Life Ranges
(in years) (in years) (in years)
Transmission 2.5% 24 - 75 2.4% 24 - 75 2.0% 24 - 75
Other 6.7% 5 - 56 6.3% 5 - 64 5.8% 5 - 64
APCo
2021 2020 2019
Functional Class of Property Annual Composite
Depreciation Rate Depreciable
Life Ranges Annual Composite
Depreciation Rate Depreciable
Life Ranges Annual Composite
Depreciation Rate Depreciable
Life Ranges
(in years) (in years) (in years)
Generation 3.6% 35 - 118 3.3% 35 - 118 3.2% 35 - 118
Transmission 2.1% 15 - 75 2.2% 15 - 75 1.8% 15 - 71
Distribution 3.5% 12 - 57 3.7% 12 - 57 3.7% 12 - 57
Other 8.5% 5 - 55 7.8% 5 - 55 7.2% 5 - 55
I&M
2021 2020 2019
Functional Class of Property Annual Composite
Depreciation Rate Depreciable
Life Ranges Annual Composite
Depreciation Rate Depreciable
Life Ranges Annual Composite
Depreciation Rate Depreciable
Life Ranges
(in years) (in years) (in years)
Generation 4.7% 20 - 132 4.6% 20 - 132 4.0% 20 - 132
Transmission 2.4% 45 - 70 2.3% 45 - 70 1.9% 50 - 73
Distribution 3.4% 14 - 71 3.4% 14 - 71 3.4% 9 - 75
Other 9.0% 5 - 51 10.2% 5 - 51 9.4% 5 - 50
OPCo
2021 2020 2019
Functional Class of Property Annual Composite
Depreciation Rate Depreciable
Life Ranges Annual Composite
Depreciation Rate Depreciable
Life Ranges Annual Composite
Depreciation Rate Depreciable
Life Ranges
(in years) (in years) (in years)
Transmission 2.3% 39 - 60 2.3% 39 - 60 2.3% 39 - 60
Distribution 2.9% 11 - 70 3.1% 14 - 65 3.1% 14 - 65
Other 6.1% 5 - 50 5.0% 5 - 50 4.9% 5 - 50
PSO
2021 2020 2019
Functional Class of Property Annual Composite
Depreciation Rate Depreciable
Life Ranges Annual Composite
Depreciation Rate Depreciable
Life Ranges Annual Composite
Depreciation Rate Depreciable
Life Ranges
(in years) (in years) (in years)
Generation 2.8% 30 - 75 3.1% 35 - 75 2.9% 35 - 75
Transmission 2.4% 42 - 75 2.2% 45 - 75 2.4% 45 - 75
Distribution 2.9% 15 - 78 2.9% 15 - 78 2.9% 15 - 78
Other 6.1% 5 - 56 5.7% 5 - 64 5.6% 5 - 64
SWEPCo
2021 2020 2019
Functional Class of Property Annual Composite
Depreciation Rate Depreciable
Life Ranges Annual Composite
Depreciation Rate Depreciable
Life Ranges Annual Composite
Depreciation Rate Depreciable
Life Ranges
(in years) (in years) (in years)
Generation 2.7% 30 - 65 2.7% 35 - 65 2.5% 40 - 70
Transmission 2.4% 49 - 74 2.3% 47 - 73 2.4% 50 - 73
Distribution 2.8% 15 - 80 2.7% 15 - 67 2.7% 25 - 70
Other 8.6% 5 - 58 8.5% 5 - 52 7.6% 5 - 55
The following table includes the nonregulated annual composite depreciation rate ranges and nonregulated depreciable life ranges for AEP. Depreciation rate ranges and depreciable life ranges are not meaningful for nonregulated property of AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo for 2021, 2020 and 2019.
2021 2020 2019
Functional Class of Property Annual Composite
Depreciation Rate Ranges Depreciable
Life Ranges Annual Composite
Depreciation Rate Ranges Depreciable
Life Ranges Annual Composite
Depreciation Rate Ranges Depreciable
Life Ranges
(in years) (in years) (in years)
Generation 3.8% - 10.4% 10 - 59 3.6% - 4.0% 15 - 59 3.2% - 21.2% 15 - 59
Transmission 2.6% 30 - 40 2.5% 30 - 40 2.5% 30 - 40
Distribution NA NA NA NA 2.3% 40
Other 16.5% 5 - 35 (a) 16.1% 5 - 50 17.6% 5 - 50
(a)In 2020 management announced plans to retire the Pirkey Plant in 2023 and the related depreciable lives have been adjusted accordingly. See Note 5 - Effects of Regulation for additional information.
NA Not applicable.
SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset’s estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. SWEPCo includes these costs in fuel expense.
For regulated operations, the composite depreciation rate generally includes a component for non-ARO removal costs, which is credited to Accumulated Depreciation and Amortization on the balance sheets. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred.
Asset Retirement Obligations (Applies to all Registrants except AEPTCo)
The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, wind farms, solar farms and certain coal-mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected.
The Registrants recorded the following revisions to ARO estimates as of December 31, 2021 and 2020:
•As of December 31, 2021 and 2020, I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $1.93 billion and $1.80 billion, respectively. These liabilities are reflected in Asset Retirement Obligations on I&M’s balance sheets. As of December 31, 2021 and 2020, the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $3.54 billion and $2.98 billion, respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s balance sheets. In December 2021, I&M recorded a $58 million revision for Cook Plant as a result of the latest decommissioning cost study. The ARO liability was updated and changes from the previous study were driven primarily by general increases in the projected cost of labor and materials.
•In 2020, Virginia’s Governor signed House Bill 443 (HB 443) requiring APCo to close certain ash disposal units at the retired Glen Lyn Station by removal of all coal combustion material. In June 2020, APCo recorded a revision to increase estimated Glen Lyn Station ash disposal ARO liabilities by $199 million due to the enactment of HB 443. In June 2021, management completed fully designed and costed project plans for the Glen Lyn Station site and increased ash disposal ARO liabilities by an additional $79 million. HB 443 provides for the recovery of all costs associated with closure by removal through the Virginia environmental rate adjustment clause. APCo is permitted to record carrying costs on the unrecovered balance of closure costs as a weighted-average cost of capital approved by the Virginia SCC. The legislation provides for regulatory recovery of these costs.
•In 2020, SWEPCo recorded a revision to increase estimated ARO liabilities by $21 million primarily due to the revision in the useful life of DHLC. See Note 5 - Effects of Regulation for additional information. In September 2020, SWEPCo recorded an $18 million revision due to a reduction in estimated ash pond closure costs.
•In 2020, AEP Texas and PSO recorded a revision to decrease estimated ARO liabilities by $17 million and $5 million, respectively, due to the retirement of the Oklaunion Power Station in September 2020. See “Oklaunion Power Station” section of Note 7 for additional information.
•In 2020, AGR derecognized $106 million of Conesville Plant related ARO liabilities as a result of the Environmental Liability and Property Transfer and Asset Purchase Agreement executed with a non-affiliated third-party. See “Conesville Plant” section of Note 7 for additional information.
The following is a reconciliation of the 2021 and 2020 aggregate carrying amounts of ARO by Registrant:
Company ARO as of December 31, 2020 Accretion
Expense Liabilities
Incurred Liabilities
Settled Revisions in
Cash Flow
Estimates (a) ARO as of December 31, 2021
(in millions)
AEP (b)(c)(d)(e)(f) $ 2,516.7 $ 105.0 $ 22.8 $ (41.4) $ 138.6 $ 2,741.7
AEP Texas (b)(e) 4.6 0.2 - (0.4) - 4.4
APCo (b)(e) 313.1 13.7 - (6.9) 84.7 404.6
I&M (b)(c)(e) 1,813.8 72.9 0.3 (0.1) 59.4 1,946.3
OPCo (e) 1.9 0.1 - (0.1) - 1.9
PSO (b)(e) 47.4 3.3 7.6 (0.7) - 57.6
SWEPCo (b)(d)(e) 222.1 9.8 9.2 (20.9) 2.5 222.7
Company ARO as of December 31, 2019 Accretion
Expense Liabilities
Incurred Liabilities
Settled Revisions in
Cash Flow
Estimates (a) ARO as of December 31, 2020
(in millions)
AEP (b)(c)(d)(e) $ 2,418.9 $ 102.4 $ 0.3 $ (188.0) $ 183.1 $ 2,516.7
AEP Texas (b)(e) 29.1 0.8 - (8.5) (16.8) 4.6
APCo (b)(e) 111.1 8.9 - (7.8) 200.9 313.1
I&M (b)(c)(e) 1,748.6 70.2 0.1 (0.2) (4.9) 1,813.8
OPCo (e) 1.8 0.1 - - - 1.9
PSO (b)(e) 52.2 3.1 - (3.1) (4.8) 47.4
SWEPCo (b)(d)(e) 212.2 10.7 - (10.9) 10.1 222.1
(a)Unless discussed above, primarily related to ash ponds, landfills and mine reclamation, generally due to changes in estimated closure area, volumes and/or unit costs.
(b)Includes ARO related to ash disposal facilities.
(c)Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.93 billion and $1.80 billion as of December 31, 2021 and 2020, respectively.
(d)Includes ARO related to Sabine and DHLC.
(e)Includes ARO related to asbestos removal.
(f)Includes $18 million of ARO classified as Liabilities Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.
Allowance for Funds Used During Construction and Interest Capitalization
The Registrants’ amounts of Allowance for Equity Funds Used During Construction are summarized in the following table:
Years Ended December 31,
Company 2021 2020 2019
(in millions)
AEP $ 139.7 $ 148.1 $ 168.4
AEP Texas 21.5 19.4 15.2
AEPTCo 67.2 74.0 84.3
APCo 15.6 14.6 16.6
I&M 12.8 11.5 19.4
OPCo 10.8 12.5 18.2
PSO 2.4 4.0 2.7
SWEPCo 7.0 7.7 6.8
The Registrants’ amounts of allowance for borrowed funds used during construction, including capitalized interest, are summarized in the following table:
Years Ended December 31,
Company 2021 2020 2019
(in millions)
AEP $ 53.8 $ 66.0 $ 88.7
AEP Texas 10.5 12.5 20.0
AEPTCo 21.0 25.5 32.2
APCo 7.5 7.9 9.3
I&M 5.1 5.7 8.9
OPCo 4.7 6.2 6.7
PSO 0.7 2.0 1.9
SWEPCo 3.0 3.9 4.0
Jointly-owned Electric Facilities (Applies to AEP, I&M, PSO and SWEPCo)
The Registrants have electric facilities that are jointly-owned with affiliated and nonaffiliated companies. Using its own financing, each participating company is obligated to pay its share of the costs of these jointly-owned facilities in the same proportion as its ownership interest. Each Registrant’s proportionate share of the operating costs associated with these facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows:
Registrant’s Share as of December 31, 2021
Fuel
Type Percent of
Ownership Utility Plant
in Service Construction
Work in
Progress Accumulated
Depreciation
(in millions)
AEP
Dolet Hills Power Station, Unit 1 (a) Lignite 40.2 % $ - $ - $ -
Flint Creek Generating Station, Unit 1 (b) Coal 50.0 % 377.6 6.3 133.5
Pirkey Power Plant, Unit 1 (b) Lignite 85.9 % 613.8 - 528.3
Turk Generating Plant (b) Coal 73.3 % 1,598.0 10.2 285.6
Total
$ 2,589.4 $ 16.5 $ 947.4
I&M
Rockport Generating Plant (c)(d)(e) Coal 50.0 % $ 1,247.2 $ 13.9 $ 794.5
PSO
North Central Wind Energy Facilities (f)(g) Wind 45.5 % $ 313.7 $ - $ 4.2
SWEPCo
Dolet Hills Power Station, Unit 1 (a) Lignite 40.2 % $ - $ - $ -
Flint Creek Generating Station, Unit 1 (b) Coal 50.0 % 377.6 6.3 133.5
Pirkey Power Plant, Unit 1 (b) Lignite 85.9 % 613.8 - 528.3
Turk Generating Plant (b) Coal 73.3 % 1,598.0 10.2 285.6
North Central Wind Energy Facilities (f)(g) Wind 54.5 % 376.2 - 5.4
Total $ 2,965.6 $ 16.5 $ 952.8
Registrant’s Share as of December 31, 2020
Fuel
Type Percent of
Ownership Utility Plant
in Service Construction
Work in
Progress Accumulated
Depreciation
(in millions)
AEP
Dolet Hills Power Station, Unit 1 (a) Lignite 40.2 % $ 342.4 $ 4.6 $ 295.4
Flint Creek Generating Station, Unit 1 (b) Coal 50.0 % 377.2 3.0 116.0
Pirkey Power Plant, Unit 1 (b) Lignite 85.9 % 602.8 3.7 441.0
Turk Generating Plant (b) Coal 73.3 % 1,594.3 2.8 257.3
Total
$ 2,916.7 $ 14.1 $ 1,109.7
I&M
Rockport Generating Plant (c)(d)(e) Coal 50.0 % $ 1,228.5 $ 19.6 $ 677.3
SWEPCo
Dolet Hills Power Station, Unit 1 (a) Lignite 40.2 % $ 342.4 $ 4.6 $ 295.4
Flint Creek Generating Station, Unit 1 (b) Coal 50.0 % 377.2 3.0 116.0
Pirkey Power Plant, Unit 1 (b) Lignite 85.9 % 602.8 3.7 441.0
Turk Generating Plant (b) Coal 73.3 % 1,594.3 2.8 257.3
Total
$ 2,916.7 $ 14.1 $ 1,109.7
(a)Operated by CLECO, a nonaffiliated company. The Dolet Hills Power Station was retired in December 2021.
(b)Operated by SWEPCo.
(c)Operated by I&M.
(d)Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to a finance lease with a nonaffiliated company. See the “Rockport Lease” section of Note 13 for additional information.
(e)AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2.
(f)PSO and SWEPCo own undivided interests of 45.5% and 54.5% of the NCWF, respectively. Sundance was placed into service in April 2021. Maverick was placed into service in September 2021. See the “Acquisitions” section of Note 7 for additional information.
(g)Operated by PSO.
19. REVENUE FROM CONTRACTS WITH CUSTOMERS
The disclosures in this note apply to all Registrants, unless indicated otherwise.
Disaggregated Revenues from Contracts with Customers
The table below represents AEP’s reportable segment revenues from contracts with customers, net of respective provisions for refund, by type of revenue:
Year Ended December 31, 2021
Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other Reconciling Adjustments AEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues $ 3,952.6 $ 2,138.2 $ - $ - $ - $ - $ 6,090.8
Commercial Revenues 2,208.5 1,081.2 - - - - 3,289.7
Industrial Revenues 2,168.2 395.2 - - - (0.8) 2,562.6
Other Retail Revenues 170.6 43.9 - - - - 214.5
Total Retail Revenues 8,499.9 3,658.5 - - - (0.8) 12,157.6
Wholesale and Competitive Retail Revenues:
Generation Revenues 942.6 - - 137.9 - - 1,080.5
Transmission Revenues (a) 355.5 572.4 1,456.4 - - (1,206.0) 1,178.3
Renewable Generation Revenues (b) - - - 86.9 - (3.6) 83.3
Retail, Trading and Marketing Revenues (c) - - - 1,722.6 1.4 (51.6) 1,672.4
Total Wholesale and Competitive Retail Revenues
1,298.1 572.4 1,456.4 1,947.4 1.4 (1,261.2) 4,014.5
Other Revenues from Contracts with Customers (b) 187.5 194.2 17.1 7.2 60.1 (115.2) 350.9
Total Revenues from Contracts with Customers
9,985.5 4,425.1 1,473.5 1,954.6 61.5 (1,377.2) 16,523.0
Other Revenues:
Alternative Revenues (b) 13.5 48.8 52.7 - - (73.6) 41.4
Other Revenues (b) (d) (0.5) 19.0 - 209.1 10.7 (10.7) 227.6
Total Other Revenues 13.0 67.8 52.7 209.1 10.7 (84.3) 269.0
Total Revenues $ 9,998.5 $ 4,492.9 $ 1,526.2 $ 2,163.7 $ 72.2 $ (1,461.5) $ 16,792.0
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $1.1 billion. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $52 million. The remaining affiliated amounts were immaterial.
(d)Generation & Marketing includes economic hedge activity.
Year Ended December 31, 2020
Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other Reconciling Adjustments AEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues $ 3,606.8 $ 2,086.9 $ - $ - $ - $ - $ 5,693.7
Commercial Revenues 2,016.2 1,048.6 - - - - 3,064.8
Industrial Revenues 2,018.0 390.1 - - - (0.7) 2,407.4
Other Retail Revenues 155.6 42.5 - - - - 198.1
Total Retail Revenues 7,796.6 3,568.1 - - - (0.7) 11,364.0
Wholesale and Competitive Retail Revenues:
Generation Revenues 588.3 - - 131.9 - - 720.2
Transmission Revenues (a) 334.5 467.0 1,257.0 - - (1,006.7) 1,051.8
Renewable Generation Revenues (b) - - - 60.9 - (1.6) 59.3
Retail, Trading and Marketing Revenues (c) - - - 1,486.9 (5.5) (103.0) 1,378.4
Total Wholesale and Competitive Retail Revenues
922.8 467.0 1,257.0 1,679.7 (5.5) (1,111.3) 3,209.7
Other Revenues from Contracts with Customers (b) 163.2 157.8 22.4 2.3 92.5 (148.6) 289.6
Total Revenues from Contracts with Customers
8,882.6 4,192.9 1,279.4 1,682.0 87.0 (1,260.6) 14,863.3
Other Revenues:
Alternative Revenues (b) (3.2) 70.0 (80.6) - - 7.5 (6.3)
Other Revenues (b) (d) - 83.0 - 43.6 9.8 (74.9) 61.5
Total Other Revenues (3.2) 153.0 (80.6) 43.6 9.8 (67.4) 55.2
Total Revenues $ 8,879.4 $ 4,345.9 $ 1,198.8 $ 1,725.6 $ 96.8 $ (1,328.0) $ 14,918.5
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $965 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $103 million. The remaining affiliated amounts were immaterial.
(d)Generation & Marketing includes economic hedge activity.
Year Ended December 31, 2019
Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other Reconciling Adjustments AEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues $ 3,643.7 $ 2,069.9 $ - $ - $ - $ - $ 5,713.6
Commercial Revenues 2,155.3 1,152.9 - - - - 3,308.2
Industrial Revenues 2,179.0 429.1 - - - (0.9) 2,607.2
Other Retail Revenues 179.1 43.8 - - - - 222.9
Total Retail Revenues 8,157.1 3,695.7 - - - (0.9) 11,851.9
Wholesale and Competitive Retail Revenues:
Generation Revenues 807.6 - - 254.8 - - 1,062.4
Transmission Revenues (a) 292.1 435.1 1,077.2 - - (825.0) 979.4
Renewable Generation Revenues (b) - - - 57.3 - - 57.3
Retail, Trading and Marketing Revenues (c) - - - 1,480.7 - (135.6) 1,345.1
Total Wholesale and Competitive Retail Revenues
1,099.7 435.1 1,077.2 1,792.8 - (960.6) 3,444.2
Other Revenues from Contracts with Customers (b) 168.2 169.4 16.6 4.9 104.7 (147.1) 316.7
Total Revenues from Contracts with Customers
9,425.0 4,300.2 1,093.8 1,797.7 104.7 (1,108.6) 15,612.8
Other Revenues:
Alternative Revenues (b) (57.9) 32.3 (20.6) - - (66.9) (113.1)
Other Revenues (b) (d) - 150.0 - 59.9 (8.9) (139.3) 61.7
Total Other Revenues (57.9) 182.3 (20.6) 59.9 (8.9) (206.2) (51.4)
Total Revenues $ 9,367.1 $ 4,482.5 $ 1,073.2 $ 1,857.6 $ 95.8 $ (1,314.8) $ 15,561.4
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $794 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $136 million. The remaining affiliated amounts were immaterial.
(d)Generation & Marketing includes economic hedge activity.
The table below represents revenues from contracts with customers, net of respective provisions for refund, by type of revenue for the Registrant Subsidiaries:
Year Ended December 31, 2021
AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Retail Revenues:
Residential Revenues $ 550.3 $ - $ 1,379.6 $ 805.4 $ 1,587.9 $ 651.9 $ 709.5
Commercial Revenues 358.5 - 556.3 507.2 722.7 378.9 529.3
Industrial Revenues 108.9 - 584.3 557.0 286.3 274.1 344.4
Other Retail Revenues 31.3 - 70.8 5.2 12.6 77.7 10.0
Total Retail Revenues 1,049.0 - 2,591.0 1,874.8 2,609.5 1,382.6 1,593.2
Wholesale Revenues:
Generation Revenues (a) - - 302.7 318.1 - 22.9 386.6
Transmission Revenues (b) 497.5 1,393.9 128.8 33.7 74.9 37.5 122.7
Total Wholesale Revenues 497.5 1,393.9 431.5 351.8 74.9 60.4 509.3
Other Revenues from Contracts with Customers (c) 41.2 17.0 70.4 104.1 153.1 31.3 23.5
Total Revenues from Contracts with Customers 1,587.7 1,410.9 3,092.9 2,330.7 2,837.5 1,474.3 2,126.0
Other Revenues:
Alternative Revenues (d) 6.1 58.4 12.3 (4.0) 42.6 0.1 5.8
Other Revenues (d) - - - - 19.0 - -
Total Other Revenues 6.1 58.4 12.3 (4.0) 61.6 0.1 5.8
Total Revenues $ 1,593.8 $ 1,469.3 $ 3,105.2 $ 2,326.7 $ 2,899.1 $ 1,474.4 $ 2,131.8
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $129 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $1.1 billion. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $60 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.
Year Ended December 31, 2020
AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Retail Revenues:
Residential Revenues $ 563.6 $ - $ 1,250.6 $ 794.1 $ 1,523.4 $ 579.4 $ 630.8
Commercial Revenues 366.7 - 517.0 499.3 682.0 320.1 466.7
Industrial Revenues 120.1 - 553.5 547.4 270.0 221.1 328.8
Other Retail Revenues 29.5 - 67.6 6.6 13.1 66.0 9.1
Total Retail Revenues 1,079.9 - 2,388.7 1,847.4 2,488.5 1,186.6 1,435.4
Wholesale Revenues:
Generation Revenues (a) - - 230.2 274.6 - 15.1 162.0
Transmission Revenues (b) 399.9 1,210.3 130.8 29.0 67.0 27.5 111.2
Total Wholesale Revenues 399.9 1,210.3 361.0 303.6 67.0 42.6 273.2
Other Revenues from Contracts with Customers (c) 48.2 22.4 59.5 85.0 109.5 34.7 26.7
Total Revenues from Contracts with Customers
1,528.0 1,232.7 2,809.2 2,236.0 2,665.0 1,263.9 1,735.3
Other Revenues:
Alternative Revenues (d) 3.4 (87.0) (13.0) 5.8 66.6 2.2 3.2
Other Revenues (d) 87.5 - - - 17.5 - -
Total Other Revenues 90.9 (87.0) (13.0) 5.8 84.1 2.2 3.2
Total Revenues $ 1,618.9 $ 1,145.7 $ 2,796.2 $ 2,241.8 $ 2,749.1 $ 1,266.1 $ 1,738.5
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $112 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $952 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $69 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.
Year Ended December 31, 2019
AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Retail Revenues:
Residential Revenues $ 571.5 $ - $ 1,266.9 $ 730.0 $ 1,502.0 $ 650.2 $ 638.6
Commercial Revenues 411.5 - 559.9 494.2 738.5 388.5 485.4
Industrial Revenues 129.4 - 592.2 550.7 299.9 303.5 338.7
Other Retail Revenues 29.9 - 75.2 7.3 13.1 81.6 9.0
Total Retail Revenues 1,142.3 - 2,494.2 1,782.2 2,553.5 1,423.8 1,471.7
Wholesale Revenues:
Generation Revenues (a) - - 251.5 402.4 - 39.5 194.7
Transmission Revenues (b) 379.2 1,025.5 103.6 25.1 56.0 27.5 106.7
Total Wholesale Revenues 379.2 1,025.5 355.1 427.5 56.0 67.0 301.4
Other Revenues from Contracts with Customers (c) 30.1 16.6 61.8 98.4 139.3 22.0 26.1
Total Revenues from Contracts with Customers 1,551.6 1,042.1 2,911.1 2,308.1 2,748.8 1,512.8 1,799.2
Other Revenues:
Alternative Revenues (d) 0.6 (20.7) 13.6 (1.4) 31.7 (31.0) (48.3)
Other Revenues (d) 157.1 - - - 17.1 - -
Total Other Revenues 157.7 (20.7) 13.6 (1.4) 48.8 (31.0) (48.3)
Total Revenues $ 1,709.3 $ 1,021.4 $ 2,924.7 $ 2,306.7 $ 2,797.6 $ 1,481.8 $ 1,750.9
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $129 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $782 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $73 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.
Performance Obligations
AEP has performance obligations as part of its normal course of business. A performance obligation is a promise to transfer a distinct good or service, or a series of distinct goods or services that are substantially the same and have the same pattern of transfer to a customer. The invoice practical expedient within the accounting guidance for “Revenue from Contracts with Customers” allows for the recognition of revenue from performance obligations in the amount of consideration to which there is a right to invoice the customer and when the amount for which there is a right to invoice corresponds directly to the value transferred to the customer.
The purpose of the invoice practical expedient is to depict an entity’s measure of progress toward completion of the performance obligation within a contract and can only be applied to performance obligations that are satisfied over time and when the invoice is representative of services provided to date. AEP subsidiaries elected to apply the invoice practical expedient to recognize revenue for performance obligations satisfied over time as the invoices from the respective revenue streams are representative of services or goods provided to date to the customer. Performance obligations for AEP’s subsidiaries are summarized as follows:
Retail Revenues
AEP’s subsidiaries within the Vertically Integrated Utilities and Transmission and Distribution Utilities segments have performance obligations to generate, transmit and distribute electricity for sale to rate-regulated retail customers. The performance obligation to deliver electricity is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Revenues are variable as they are subject to the customer’s usage requirements.
Rate-regulated retail customers typically have the right to discontinue receiving service at will, therefore these contracts between AEP’s subsidiaries and their customers for rate-regulated services are generally limited to the services requested and received to date for such arrangements. Retail customers are generally billed on a monthly basis, and payment is typically due within 15 to 20 days after the issuance of the invoice. Payments from REPs are due to AEP Texas within 35 days.
Wholesale Revenues - Generation
AEP’s subsidiaries within the Vertically Integrated Utilities and Generation & Marketing segments have performance obligations to sell electricity to wholesale customers from generation assets in PJM, SPP and ERCOT. The performance obligation to deliver electricity from generation assets is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Wholesale generation revenues are variable as they are subject to the customer’s usage requirements.
AEP’s subsidiaries within the Vertically Integrated Utilities and Generation & Marketing segments also have performance obligations to stand ready in order to promote grid reliability. Stand ready services are sold into PJM’s RPM capacity market. RPM entails a base auction and at least three incremental auctions for a specific PJM delivery year, with the incremental auctions spanning three years. The performance obligation to stand ready is satisfied over time and the consideration for which is variable until the occurrence of the final incremental auction, at which point the performance obligation becomes fixed.
Payments from the RTO for stand ready services are typically received within one week from the issuance of the invoice, which is typically issued weekly. Gross margin resulting from generation sales within the Vertically Integrated Utilities segment are primarily subject to margin sharing agreements with customers and vary by state, where the revenues are reflected gross in the disaggregated revenues tables above.
APCo has a performance obligation to supply wholesale electricity to KGPCo through a PPA. The FERC regulates the cost-based wholesale power transactions between APCo and KGPCo. The purchased power agreement includes a component for the recovery of transmission costs under the FERC OATT. The transmission cost component of purchased power is cost-based and regulated by the Tennessee Regulatory Authority. APCo’s performance obligation under the purchased power agreement is satisfied over time as KGPCo simultaneously receives and consumes the wholesale electricity. APCo’s revenues from the purchased power agreement are presented within the Generation Revenues line in the disaggregated revenues tables above.
Wholesale Revenues - Transmission
AEP’s subsidiaries within the Vertically Integrated Utilities, Transmission and Distribution Utilities and AEP Transmission Holdco segments have performance obligations to transmit electricity to wholesale customers through assets owned and operated by AEP subsidiaries. The performance obligation to provide transmission services in PJM, SPP and ERCOT encompass a time frame greater than a year, where the performance obligation within each RTO is partially fixed for a period of one year or less. Payments from the RTO for transmission services are typically received within one week from the issuance of the invoice, which is issued monthly for SPP and ERCOT and weekly for PJM.
AEP subsidiaries within the PJM and SPP regions collect revenues through transmission formula rates. The FERC-approved rates establish the annual transmission revenue requirement (ATRR) and transmission service rates for transmission owners. The formula rates establish rates for a one year period and also include a true-up calculation for the prior year’s billings, allowing for over/under-recovery of the transmission owner’s ATRR. The annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for “Regulated Operations,” and are therefore presented as such in the disaggregated revenues tables above. AEP subsidiaries within the ERCOT region collect revenues through a combination of base rates and interim Transmission Costs of Services filings that are approved by the PUCT.
The AEP East Companies are parties to the TA, which defines how transmission costs are allocated among the AEP East Companies on a 12-month average coincident peak basis. PSO, SWEPCo and AEPSC are parties to the TCA by and among PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two AEP utility subsidiaries. AEPTCo is a transmission owner within the PJM and SPP regions providing transmission services to affiliates in accordance with the OATT, TA and TCA. Affiliate revenues as a result of the respective TA and the TCA are reflected as Transmission Revenues in the disaggregated revenues tables above.
Marketing, Competitive Retail and Renewable Revenues
AEP’s subsidiaries within the Generation & Marketing segment have performance obligations to deliver electricity to competitive retail and wholesale customers. Performance obligations for marketing, competitive retail and renewable offtake sales are satisfied over time as the customer simultaneously receives and consumes the benefits provided. Revenues are primarily variable as they are subject to customer’s usage requirements; however, certain contracts mandate a delivery of a set quantity of electricity at a predetermined price, resulting in a fixed performance obligation.
Payment terms under marketing arrangements typically follow standard Edison Electric Institute and International Swaps and Derivatives Association terms, which call for payment in 20 days. Payments for competitive retail and offtake arrangements for renewable assets range from 15 to 60 days and are dependent on the product sold, location and the creditworthiness of customer. Invoices for marketing arrangements, competitive retail and offtake arrangements for renewable assets are issued monthly.
Fixed Performance Obligations
The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of December 31, 2021. Fixed performance obligations primarily include wholesale transmission services, electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market. The Registrant Subsidiaries amounts shown in the table below include affiliated and nonaffiliated revenues.
Company 2022 2023-2024 2025-2026 After 2026 Total
(in millions)
AEP $ 1,231.9 $ 160.8 $ 157.9 $ 97.0 $ 1,647.6
AEP Texas 531.0 - - - 531.0
AEPTCo 1,510.3 - - - 1,510.3
APCo 201.5 32.2 23.2 11.6 268.5
I&M 37.7 8.8 8.8 4.5 59.8
OPCo 78.3 - - - 78.3
PSO 13.1 - - - 13.1
SWEPCo 43.0 - - - 43.0
Contract Assets and Liabilities
Contract assets are recognized when the Registrants have a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. The Registrants did not have any material contract assets as of December 31, 2021 and 2020.
When the Registrants receive consideration, or such consideration is unconditionally due from a customer prior to transferring goods or services to the customer under the terms of a sales contract, they recognize a contract liability on the balance sheet in the amount of that consideration. Revenue for such consideration is subsequently recognized in the period or periods in which the remaining performance obligations in the contract are satisfied. The Registrants’ contract liabilities typically arise from services provided under joint use agreements for utility poles. The Registrants did not have any material contract liabilities as of December 31, 2021 and 2020.
Accounts Receivable from Contracts with Customers
Accounts receivable from contracts with customers are presented on the Registrants’ balance sheets within the Accounts Receivable - Customers line item. The Registrants’ balances for receivables from contracts that are not recognized in accordance with the accounting guidance for “Revenue from Contracts with Customers” included in Accounts Receivable - Customers were not material as of December 31, 2021 and 2020. See “Securitized Accounts Receivable - AEP Credit” section of Note 14 for additional information.
The following table represents the amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable - Affiliated Companies on the Registrant Subsidiaries’ balance sheets:
Years Ended December 31,
Company 2021 2020
(in millions)
AEP Texas $ 0.4 $ 0.2
AEPTCo 95.5 81.0
APCo 117.8 52.7
I&M 61.2 34.8
OPCo 51.7 45.9
PSO 18.8 7.8
SWEPCo 24.7 11.2
Contract Costs
Contract costs to obtain or fulfill a contract for AEP subsidiaries within the Generation & Marketing segment are accounted for under the guidance for “Other Assets and Deferred Costs” and presented as a single asset and are neither bifurcated nor reclassified between current and noncurrent assets on the Registrants’ balance sheets. Contract costs to acquire a contract are amortized in a manner consistent with the transfer of goods or services to the customer in Other Operation on the Registrants’ income statements. The Registrants did not have material contract costs as of December 31, 2021 and 2020.
20. GOODWILL
The disclosure in this note applies to AEP only.
The changes in AEP’s carrying amount of goodwill for the years ended December 31, 2021 and 2020 by operating segment are as follows:
Corporate and Other Generation
&
Marketing AEP Consolidated
(in millions)
Balance as of December 31, 2019 $ 37.1 $ 15.4 $ 52.5
Impairment Losses - - -
Balance as of December 31, 2020 37.1 15.4 52.5
Impairment Losses - - -
Balance as of December 31, 2021 $ 37.1 $ 15.4 $ 52.5
In the fourth quarters of 2021 and 2020, annual impairment tests were performed. The fair values of the reporting units with goodwill were estimated using cash flow projections and other market value indicators. There were no goodwill impairment losses. AEP does not have any accumulated impairment on existing goodwill.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo
Information required by this item is set forth under the caption Proposal to Ratify the Appointment of the Independent Registered Public Accounting Firm in the 2022 Proxy Statement, which is incorporated by reference into this item.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
During 2021, management, including the principal executive officer and principal financial officer of each of the Registrants evaluated each respective Registrant’s disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrant that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to each Registrant’s management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
As of December 31, 2021, the principal executive officer and financial officer of each of the Registrants concluded that the disclosure controls and procedures in place were effective at the reasonable assurance level. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting and to maintain dynamic systems that change as events warrant.
Changes in Internal Control over Financial Reporting
There have been no changes in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter 2021 that materially affected, or are reasonably likely to materially affect, the Registrants’ internal control over financial reporting.
Internal Control over Financial Reporting
See Management’s Report on Internal Control over Financial Reporting for each Registrant under Item 8. As discussed in that report, management assessed and reported on the effectiveness of each Registrant’s internal control over financial reporting as of December 31, 2021. As a result of that assessment, management concluded that each Registrant’s internal control over financial reporting was effective as of December 31, 2021.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
AEP
Directors, Director Nomination Process and Audit Committee
Certain of the information called for in this Item 10, including the information relating to directors, is incorporated herein by reference to AEP’s definitive proxy information statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2022 Annual Meeting of Shareholders (the 2022 Annual Meeting) including under the captions “Election of Directors,” “AEP’s Board of Directors and Committees,” “Directors” and “Nominees for Directors.”
Executive Officers
Reference also is made under the caption “Information About our Executive Officers” in Part I, Item 1 of this report.
Code of Ethics
AEP’s Principles of Business Conduct is the code of ethics that applies to AEP’s Chief Executive Officer, Chief Financial Officer and principal accounting officer. The Principles of Business Conduct is available on AEP’s website at www.aep.com. The Principles of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Investor Relations, American Electric Power Company, Inc., 1 Riverside Plaza, Columbus, Ohio 43215.
If any substantive amendments to the Principles of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Principles of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or principal accounting officer, AEP will disclose the nature of such amendment or waiver on AEP’s website, www.aep.com, or in a report on Form 8-K.
Delinquent Section 16(a) Reports
None.
AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo
Omitted pursuant to Instruction I(2)(c).

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
AEP
The information called for by this Item 11 is incorporated herein by reference to AEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2022 Annual Meeting including under the captions “Compensation Discussion and Analysis,” “Executive Compensation”, “Director Compensation” and “2021 Director Compensation Table”. The information set forth under the subcaption “Human Resources Committee Report” and “Audit Committee Report” should not be deemed filed nor should it be incorporated by reference into any other filing under the Securities Act of 1933, as amended, or the Exchange Act except to the extent AEP specifically incorporates such report by reference therein.
AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo
Omitted pursuant to Instruction I(2)(c).

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
AEP
The information relating to Security Ownership of Certain Beneficial Owners is incorporated herein by reference to AEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to 2022 Annual Meeting under the caption “Share Ownership of Certain Beneficial Owners” and “Share Ownership of Directors and Executive Officers.”
EQUITY COMPENSATION PLAN INFORMATION
The following table summarizes the ability of AEP to issue common stock pursuant to equity compensation plans as of December 31, 2021:
Plan Category Number of Securities to be Issued upon Exercise of Outstanding Options Warrants and Rights (a) Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b) Number of Securities Remaining
Available for Future Issuance under Equity Compensation Plans
Equity Compensation Plans Approved by Security Holders 2,453,084 - 5,976,468
Equity Compensation Plans Not Approved by Security Holders - - -
Total 2,453,084 - 5,976,468
(a)The balance includes unvested performance units and restricted stock units as well as vested performance units deferred as AEP career shares, all of which will be settled and paid in shares of AEP common stock. For performance units, the total includes the target number of shares that could be granted if performance meets target objectives. The number of securities that would be granted, with respect to performance units, if performance meets the maximum payout level, is two times the amount included in this total.
(b)No consideration is required from participants for the exercise or vesting of any outstanding AEP equity compensation awards.
AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo
Omitted pursuant to Instruction I(2)(c).

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
AEP
The information called for by this Item 13 is incorporated herein by reference to AEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2022 Annual Meeting under the captions “Transactions with Related Persons” and “Director Independence.”
AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo
Omitted pursuant to Instruction I(2)(c).

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
AEP
The information called for by this Item 14 is incorporated herein by reference to AEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2022 Annual Meeting under the captions “Audit and Non-Audit Fees,” “Audit Committee Report” and “Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of the Independent Auditor.”
AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo
Each of the above is a wholly-owned subsidiary of AEP and does not have a separate audit committee. A description of the AEP Audit Committee pre-approval policies, which apply to these companies, is contained in the definitive proxy statement of AEP for the 2022 Annual Meeting of shareholders. The following table presents directly billed fees for professional services rendered by PricewaterhouseCoopers LLP for the audit of these companies’ annual financial statements for the years ended December 31, 2021 and 2020, and fees directly billed for other services rendered by PricewaterhouseCoopers LLP during those periods. PricewaterhouseCoopers LLP also provides additional professional and other services to the AEP System, the cost of which may ultimately be allocated to these companies though not billed directly to them. For a description of these fees and services, see the description of principal accounting fees and services for AEP above.
AEP Texas AEPTCo APCo
2021 2020 2021 2020 2021 2020
Audit Fees $ 1,279,272 $ 1,204,518 $ 1,443,675 $ 1,249,959 $ 1,702,193 $ 1,747,977
Audit-Related Fees 42,000 80,000 - - 47,143 44,857
Tax Fees 15,122 6,349 15,347 6,433 19,603 9,090
Total $ 1,336,394 $ 1,290,867 $ 1,459,022 $ 1,256,392 $ 1,768,939 $ 1,801,924
I&M OPCo PSO
2021 2020 2021 2020 2021 2020
Audit Fees $ 1,637,968 $ 1,383,356 $ 1,169,647 $ 1,096,241 $ 729,463 $ 577,138
Audit-Related Fees 11,143 10,607 11,143 10,607 5,143 4,857
Tax Fees 17,848 8,169 12,923 5,701 6,991 3,281
Total $ 1,666,959 $ 1,402,132 $ 1,193,713 $ 1,112,549 $ 741,597 $ 585,276
SWEPCo
2021 2020
Audit Fees $ 1,118,206 $ 951,594
Audit-Related Fees 27,143 25,857
Tax Fees 11,848 5,523
Total $ 1,157,197 $ 982,974
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
The following documents are filed as a part of this report:
1.FINANCIAL STATEMENTS:
The following financial statements have been incorporated herein by reference pursuant to Item 8.
AEP and Subsidiary Companies:
Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting; Consolidated Statements of Income for the years ended December 31, 2021, 2020 and 2019; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2021, 2020 and 2019; Consolidated Statements of Changes in Equity for the years ended December 31, 2021, 2020 and 2019; Consolidated Balance Sheets as of December 31, 2021 and 2020; Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019; Notes to Financial Statements of Registrants.
AEP Texas, APCo, I&M and OPCo:
Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting; Consolidated Statements of Income for the years ended December 31, 2021, 2020 and 2019; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2021, 2020 and 2019; Consolidated Statements of Changes in Common Shareholder’s Equity for the years ended December 31, 2021, 2020 and 2019; Consolidated Balance Sheets as of December 31, 2021 and 2020; Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019; Notes to Financial Statements of Registrants.
AEPTCo:
Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting; Consolidated Statements of Income for the years ended December 31, 2021, 2020 and 2019; Consolidated Statements of Changes in Member’s Equity for the years ended December 31, 2021, 2020 and 2019; Consolidated Balance Sheets as of December 31, 2021 and 2020; Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019; Notes to Financial Statements of Registrants.
PSO:
Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting; Statements of Income for the years ended December 31, 2021, 2020 and 2019; Statements of Comprehensive Income (Loss) for the years ended December 31, 2021, 2020 and 2019; Statements of Changes in Common Shareholder’s Equity for the years ended December 31, 2021, 2020 and 2019; Balance Sheets as of December 31, 2021 and 2020; Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019; Notes to Financial Statements of Registrants.
SWEPCo:
Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting; Consolidated Statements of Income for the years ended December 31, 2021, 2020 and 2019; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2021, 2020 and 2019; Consolidated Statements of Changes in Equity for the years ended December 31, 2021, 2020 and 2019; Consolidated Balance Sheets as of December 31, 2021 and 2020; Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019; Notes to Financial Statements of Registrants.
2. FINANCIAL STATEMENT SCHEDULES: Page Number
Financial Statement Schedules are listed in the Index of Financial Statement Schedules. (Certain schedules have been omitted because the required information is contained in the notes to financial statements or because such schedules are not required or are not applicable). Reports of Independent Registered Public Accounting Firm. S-1
3. EXHIBITS:
Exhibits for AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo are listed in the Exhibit Index beginning on page E-1 and are incorporated herein by reference. E-1