This report made by the Registrants contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Many forward-looking statements appear in “Item 7“Part I – Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the 2016 Annual Report and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in AEPTCo’s 2016 Annual Report included within AEPTCo’s Registration Statement,this quarterly report, but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook. These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected. Forward-looking statements in this document are presented as of the date of this document. Except to the extent required by applicable law, management undertakes no obligation to update or revise any forward-looking statement. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:
The forward-looking statements of the Registrants speak only as of the date of this report or as of the date they are made. The Registrants expressly disclaim any obligation to update any forward-looking information.information, except as required by law. For a more detailed discussion of these factors, see “Risk Factors” in Part I of the 20162022 Annual Report and in Part II of this report. Additionally, see “Risk Factors” in the AEPTCo 2016 Annual Report included within AEPTCo’s Registration Statement.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
EXECUTIVE OVERVIEW
Customer Demand
AEP’s weather-normalized retail sales volumes for the thirdfirst quarter of 20172023 increased by 3.3% from the first quarter of 2022. Weather-normalized residential sales decreased by 0.7%1.4% in the first quarter of 2023 from the first quarter of 2022. Weather-normalized commercial sales increased 7.8% in the first quarter of 2023 from the first quarter of 2022. The increase in commercial sales was primarily due to new data center loads. AEP’s first quarter 2023 industrial sales volumes increased by 5.1% compared to the thirdfirst quarter of 2016. AEP’s third quarter 2017 industrial sales increased by 1.7% compared to the third quarter of 2016.2022. The growthincrease in industrial sales was spread across many industriessectors.
Supply Chain Disruption and most operating companies. Weather-normalized residential sales decreased 2.4%Inflation
The Registrants have experienced certain supply chain disruptions driven by several factors including staffing and travel issues caused by the COVID-19 pandemic, international tensions including the ramifications of regional conflict, increased demand due to the economic recovery from the pandemic, inflation, labor shortages in certain trades and shortages in the third quarteravailability of 2017 compared to the third quarter of 2016. Weather-normalized commercial sales decreased by 1.3% in the third quarter of 2017 compared to the third quarter of 2016.
AEP’s weather-normalized retail sales volumes for the nine months ended September 30, 2017 decreased by 0.4% compared to the nine months ended September 30, 2016. AEP’s industrial sales volumes for the nine months ended September 30, 2017 increased 1.6% compared to the nine months ended September 30, 2016. The growth in industrial sales was spread across many industries and most operating companies. Weather-normalized residential and commercial sales decreased 1.5% and 1.4%, respectively, for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016.
Merchant Generation Assets
In September 2016, AEP signed an agreement to sell Darby, Gavin, Lawrenceburg and Waterford Plants (“Disposition Plants”) totaling 5,329 MWs of competitive generation to a nonaffiliated party. The sale closed in January 2017 for approximately $2.2 billion. The net proceeds from the transaction were approximately $1.2 billion in cash after taxes, repayment of debt associated with these assets and transaction fees, which resulted in an after tax gain of approximately $129 million. AEP primarily used these proceeds to reduce outstanding debt and invest in its regulated businesses including transmission, and contracted renewable projects.
The assets and liabilities included in the sale transactioncertain raw materials. These supply chain disruptions have been recorded as Assets Held for Sale and Liabilities Held for Sale, respectively, on the balance sheet as of December 31, 2016. See “Assets and Liabilities Held for Sale” section of Note 6 for additional information.
In February 2017, AEP signed an agreement to sell its 25.4% ownership share of Zimmer Plant to Dynegy Corporation. Simultaneously, AEP signed an agreement to purchase Dynegy Corporation’s 40% ownership share of Conesville Plant, Unit 4. The transactions closed in the second quarter of 2017 and did not havehad a material impact on the Registrants net income, cash flows orand financial condition, but have extended lead times for certain goods and services and have contributed to higher prices for fuel, materials, labor, equipment and other needed commodities. Management has implemented risk mitigation strategies in an attempt to mitigate the impacts of these supply chain disruptions.
AEP and its utilities finance its operations with commercial paper and other variable rate instruments that are subject to fluctuations in interest rates. The United States economy has experienced a significant level of inflation that has contributed to increased uncertainty in the outlook of near-term economic activity, including whether inflation will continue and at what rate. To the extent that the Federal Reserve continues to raise short-term interest rates, it could reduce future net income and cash flows and impact financial condition.
Management continues to evaluate potential alternatives for the remaining merchant generation assets. These potential alternatives may include, but are not limited to, transfer or sale of AEP’s ownership interests,A prolonged continuation or a wind downfurther increase in the severity of merchant coal-fired generation fleet operations. Management has not set a specific time frame for a decision on these assets. These alternativessupply chain and inflationary disruptions could result in additional lossesincreases in the cost of certain goods, services and cost of capital and further extend lead times which could reduce future net income and cash flows and impact financial condition.
Termination of Planned Disposition of KPCo and KTCo
In October 2021, AEP entered into a Stock Purchase Agreement (SPA) to sell KPCo and KTCo to Liberty Utilities Co., a subsidiary of Algonquin Power & Utilities Corp. (Liberty), for approximately a $2.85 billion enterprise value.The SPA was subsequently amended in September 2022 to reduce the purchase price to approximately $2.646 billion.The sale required approval from the KPSC and from the FERC under Section 203 of the Federal Power Act.The SPA contained certain termination rights if the closing of the sale did not occur by April 26, 2023.
In May 2022, the KPSC approved the sale of KPCo to Liberty subject to certain conditions contingent upon the closing of the sale.In December 2022, the FERC issued an order denying, without prejudice, authorization of the proposed sale stating the applicants failed to demonstrate the proposed transaction will not have an adverse effect on rates.In February 2023, a new filing for approval under Section 203 of the Federal Power Act was submitted.In March 2023, the KPSC and other intervenors made filings recommending the FERC reject AEP and Liberty’s new Section 203 application seeking approval of the sale.
In April 2023, AEP, AEPTCo and Liberty entered into a Mutual Termination Agreement (Termination Agreement) terminating the SPA.The parties entered into the Termination Agreement as all of the conditions precedent to closing the sale could not be satisfied prior to April 26, 2023.As a result of the March 2023 filings made by intervenors with the FERC and the Termination Agreement, the assets and liabilities of KPCo and KTCo were reclassified out of Held for Sale on the March 31, 2023 and December 31, 2022 balance sheets of AEP and AEPTCo.
The impact of the Termination Agreement did not have a material impact on AEP’s statements of income for the three months ended March 31, 2023. Upon reverting to a held and used model, AEP is required to present its investment in the Kentucky Operations at the lower of fair value or historical carrying value. As a result, AEP’s March 31, 2023 and December 31, 2022 balance sheets reflect a $335 million and $363 million, respectively, pretax reduction in the basis of its investment in KPCo’s assets which is recorded in Property, Plant and Equipment. The change in AEP’s basis of its investment in KPCo’s assets from December 31, 2022 to March 31, 2023 reflects the elimination of the expected costs to sell from the measurement.
Planned Disposition of the Competitive Contracted Renewables Portfolio
In February 2022, AEP management announced the initiation of a process to sell all or a portion of AEP Renewables’ competitive contracted renewables portfolio within the Generation & Marketing segment. As of March 31, 2023, the competitive contracted renewable portfolio assets totaled 1.4 gigawatts of generation resources representing consolidated solar and wind assets, with a net book value of $1.2 billion, and a 50% interest in four joint venture wind farms, totaling $247 million, accounted for as equity method investments.
In late January 2023, AEP received final bids from interested parties. In February 2023, AEP’s Board of Directors approved management’s plan to sell the competitive contracted renewables portfolio and AEP signed an agreement to sell the competitive contracted renewables portfolio to a nonaffiliated party for $1.5 billion including the assumption of project debt. AEP recorded a pretax loss of $112 million ($88 million after-tax), in the first quarter of 2023 as a result of reaching Held for Sale status. Management concluded the impact of any other than temporary decline in the fair value of the four joint venture wind farms was not material to AEP’s March 31, 2023 financial statements. See the "Assets and Liabilities Held for Sale" section of Note 6 for additional information.
Planned Sale of AEP Energy and AEP Onsite Partners
Management has continued a strategic evaluation of the business with a focus on core regulated utility operations, risk mitigation and simplification. As a result of these efforts, the following decisions have recently been made with respect to AEP Energy and AEP Onsite Partners.
AEP Energy
In October 2022, AEP initiated a strategic evaluation for its ownership in AEP Energy, a wholly-owned retail energy supplier that supplies electricity and/or natural gas on a price risk managed basis to residential, commercial and industrial customers. AEP Energy provides various energy solutions in Illinois, Pennsylvania, Delaware, Maryland, New Jersey, Ohio and Washington, D.C. AEP Energy had approximately 752,000 customer accounts as of March 31, 2023. In April 2023, management completed the strategic evaluation of AEP Energy and initiated a sale process. AEP currently estimates the sale process for these businesses will be completed by the first half of 2024. Depending on the outcome of the sales process, it could reduce future net income and impact financial condition.
AEP Onsite Partners
In April 2023, AEP also made a decision to include AEP Onsite Partners in a sale process. AEP OnSite Partners targets opportunities in distributed solar, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other energy solutions. As of March 31, 2023, AEP OnSite Partners owned projects located in 22 states, including approximately 168 MWs of installed solar capacity, and approximately 26 MWs of solar projects under construction. As of March 31, 2023, the net book value of these assets was $350 million. AEP currently estimates the sale process for these businesses will be completed by the first half of 2024.
AEP Onsite Partners also owns a 50% interest in NM Renewable Development, LLC, (NMRD) totaling $102 million accounted for as an equity method investment. NMRD owns 8 operating solar projects totaling 135 MWs, one 50 MW project is under construction and has 6 projects totaling 440 MWs in development. AEP and the joint owner have agreed to initiate a separate sales process for their respective interests in NMRD. AEP currently estimates the sale process for these businesses will be completed in the fourth quarter of 2023.
If AEP is unable to recover the net book value or carrying value of these assets as part of the sale process, it could reduce future net income and impact financial condition.
Strategic Evaluation of Certain Transmission Joint Ventures
In April 2023, AEP also initiated a strategic evaluation for its ownership of certain transmission joint ventures in the AEP Transmission HoldCo segment including Pioneer Transmission, LLC, Prairie Wind Transmission, LLC and Transource Energy. As of March 31, 2023 the net book value of Transource Energy was $272 million inclusive of $37 million related to noncontrolling interest on AEP’s balance sheet. As of March 31, 2023, AEP held investments in Pioneer Transmission, LLC, and Prairie Wind Transmission, LLC of $48 million and $20 million, respectively.
Potential alternatives may include continued ownership or a sale of all or certain of these joint ventures. Management has not made a decision regarding the potential alternatives, but expects to complete the strategic evaluation by the end of 2023.
Federal Tax Legislation
In August 2022, President Biden signed H.R. 5376 into law, commonly known as the Inflation Reduction Act of 2022 or IRA. Most notably this budget reconciliation legislation creates a 15% minimum tax on adjusted financial statement income (Corporate Alternative Minimum Tax or CAMT), extends and increases the value of PTCs and ITCs, adds a nuclear and clean hydrogen PTC, an energy storage ITC and allows the sale or transfer of tax credits to third parties for cash. As further significant guidance from Treasury and the IRS is expected on the tax provisions in the IRA, AEP will continue to monitor any issued guidance and evaluate the impact on future net income, cash flows and financial condition.
In December 2022, the IRS released Notice 2023-7 addressing time sensitive issues related to the CAMT. The notice provided initial guidance that AEP can begin to rely on in 2023 and also stated that additional guidance is expected, of which AEP will continue to monitor and assess. Notably, the interim guidance in Notice 2023-7 confirmed the CAMT depreciation adjustment includes tax depreciation that is capitalized to inventory under §263A and recovered as part of cost of goods sold, providing significant relief to AEP’s potential CAMT exposure.
AEP and subsidiaries expect to be applicable corporations for purposes of the CAMT beginning in 2023. CAMT cash taxes are expected to be partially offset by regulatory recovery, the utilization of tax credits and additionally the cash inflow generated by the sale of tax credits. The sale of tax credits will be presented in the operating section of the statements of cash flows consistent with the presentation of cash taxes paid. AEP will present the gain or loss on sale of tax credits through income tax expense.
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.
•2020-2022 Virginia Triennial Review - In March 2023, APCo submitted its 2020-2022 Virginia triennial review filing and base rate case with the Virginia SCC as required by state law. APCo requested a $213 million annual increase in Virginia base rates based upon a proposed 10.6% return on common equity. The requested annual increase includes $47 million related to vegetation management and a $35 million increase in depreciation expense. The requested increase in depreciation expense reflects, among other things, the impacts of incremental investments made since APCo’s last depreciation study using property balances as of December 31, 2022. Effective January 1, 2023 and in accordance with past Virginia SCC directives, APCo implemented updated Virginia depreciation rates. APCo’s proposed revenue requirement also includes the recovery of certain costs incurred that partially contributed to APCo’s calculated earnings shortfall for the 2020-2022 triennial period. For triennial review periods in which a Virginia utility earns below its authorized ROE band, the utility may file to recover expenses incurred, up to the bottom of the authorized ROE band, related to certain categories of costs, including major storm costs for severe weather events. As of March 31, 2023, APCo deferred approximately $38 million related to previously incurred major storm costs as a result of APCo’s calculation of Virginia earnings below the bottom of its authorized ROE band during the 2020-2022 Triennial Review period. Any APCo Virginia jurisdictional costs that are not recoverable or any refunds of revenues collected from customers during the triennial review period that are ordered by the Virginia SCC for the 2020-2022 Triennial Review period could reduce future net income and cash flows and impact financial condition.
•2012 Texas Base Rate Case - In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. In 2017, the Texas District Court upheld the PUCT’s 2014 order and intervenors filed appeals with the Texas Third Court of Appeals. In 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 judgment affirming the PUCT’s order on AFUDC, concluding that the language of the PUCT’s original 2008 order intended to include AFUDC in the Texas jurisdictional capital cost cap, and remanded the case to the PUCT for future proceedings. SWEPCo disagrees with the Court of Appeals decision. SWEPCo and the PUCT submitted Petitions for Review with the Texas Supreme Court in November 2021. In October 2022, the Texas Supreme Court denied the Petitions for Review submitted by SWEPCo and the PUCT. In December 2022, SWEPCo and the PUCT filed requests for rehearing with the Texas Supreme Court. In April 2023, SWEPCo and the PUCT filed replies to parties’ responses to the requests for rehearing. If SWEPCo’s request for rehearing is denied, the case will be remanded to the PUCT for future proceedings.
Management does not believe a disallowance of capitalized Turk Plant costs or a revenue refund is probable as of March 31, 2023. However, if SWEPCo is ultimately unable to recover 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 $90 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 $190 million related to revenues collected from February 2013 through March 2023 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 terminated energy efficiency programs as of December 31, 2020, including OPCo’s shared savings revenues of $26 million annually and phased out renewable mandates after 2026. HB 6 also provided for continued recovery of existing renewable energy contracts on a bypassable basis through 2032 and included a provision for continued recovery of OVEC costs through 2030 which is allocated to all electric distribution utility customers in Ohio on a non-bypassable basis. OPCo’s Inter-Company Power Agreement for OVEC terminates in June 2040. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of the Speaker of the Ohio House of Representatives, Larry Householder, four other individuals, and Generation Now, an entity registered as a 501(c)(4) social welfare organization, in connection with an alleged racketeering conspiracy involving the adoption of HB 6. Certain defendants in that case had previously plead guilty and, in March 2023, a federal jury convicted Larry Householder and another individual of participating in the racketeering conspiracy. In 2021, four AEP shareholders filed derivative actions purporting to assert claims on behalf of AEP against certain AEP officers and directors. See “Litigation Related to Ohio House Bill 6” section of Litigation below for additional information.
In March 2021, the Governor of Ohio signed legislation that, among other things, repealed the payments to the nonaffiliated owner of Ohio’s nuclear power plants that were previously authorized under HB 6. The new legislation, House Bill 128, went into effect in May 2021 and leaves unchanged other provisions of HB 6 regarding energy efficiency programs, recovery of renewable energy costs and recovery of OVEC costs. To the extent that the law changes or OPCo is unable to recover the costs of renewable energy contracts on a bypassable basis by the end of 2032, recover costs of OVEC after 2030 or incurs significant costs associated with the derivative actions, it could reduce future net income and cash flows and impact financial condition.
•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 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 $35 million to $50 million on an annual basis.
•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 March 2023, SWEPCo and the LPSC staff filed a joint stipulation and settlement agreement with the LPSC which confirmed the prudency of $150 million of deferred incremental storm restoration expenses. The agreement also authorized an interim carrying charge at a rate of 3.125% until the recovery mechanism is determined in phase two of this proceeding. SWEPCo will submit additional information in phase two of this proceeding to determine whether securitization of the costs is more cost effective than recovery through typical ratemaking. In April 2023, the LPSC issued an order approving the stipulation and settlement agreement.
•In March 2023, certain joint customers submitted a complaint and a formal challenge at the FERC related to the 2022 Annual Update of the 2021 PJM Transmission Formula Rates of the AEP transmission owning subsidiaries within PJM. This challenge primarily relates to stand-alone treatment of NOLCs in the transmission formula rates of the AEP transmission owning subsidiaries within PJM. In April 2023, AEPSC, on behalf of the AEP transmission owning subsidiaries within PJM, filed answers to the joint formal challenge and complaint with the FERC.
AEP transitioned to stand-alone treatment of NOLCs in its PJM and SPP transmission formula rates beginning with the 2022 projected transmission revenue requirements and 2021 true-up to actual transmission revenue requirements, and provided notice of this change in informational filings made with the FERC. Stand-alone treatment of NOLCs for transmission formula rates increased the annual revenue requirements for years 2023, 2022, and 2021 by $60 million, $60 million and $78 million, respectively (of which $40 million, $53 million, and $56 million relate to PJM transmission formula rates, respectively). Through the first quarter of 2023, AEP’s financial statements reflect a provision for refund for certain NOLC revenues billed by PJM and SPP. Also, a certain portion of the impact of inclusion of NOLCs in the 2021 annual formula rate true-up not yet billed by PJM and SPP is not reflected in the Registrants’ revenues and expenses as the Registrants have not met the requirements of alternative revenue recognition in accordance with the accounting guidance for “Regulated Operations”.
AEP is also transitioning to stand-alone treatment of NOLCs in retail jurisdiction base rate case filings. As a result of retail jurisdiction base rate cases in Arkansas, Indiana, Oklahoma and Texas, inclusion of NOLCs in rates in those jurisdictions is contingent upon a supportive private letter ruling from the IRS. If the Registrant Subsidiaries are successful in transitioning to stand-alone treatment of NOLCs, it could have a material, favorable impact on future net income.
•Securitization Legislation - In March 2023, Kentucky (Senate Bill 192) and West Virginia (House Bill 3308) both passed legislation that would allow the securitization of certain plant assets. Eligible costs to be securitized in Kentucky include certain retired generation costs with a minimum value of $200 million as well as certain other regulatory assets, including deferred extraordinary storm costs, as long as the cumulative total requested for securitization is at least $275 million. Eligible costs to be securitized in West Virginia include historical, and if deemed appropriate by the commission, projected costs relating to environmental control costs, expanded net energy costs, storm recovery costs and undepreciated generation utility plant balances.
In April 2023, the Virginia General Assembly approved the Governor’s proposed changes to House Bill 1777, modifying APCo’s earnings review and base rate process, with a biennial earnings review replacing APCo’s current triennial earnings review. APCo will submit its first biennial review filing in 2024 using only a 2023 test year. Also included in this approved legislation is the option for APCo to securitize deferred fuel costs.
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 2023. See Note 4 - Rate Matters for additional information.
Completed Base Rate Case Proceedings
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Approved Revenue | | | Approved | | New Rates |
| Company | | Jurisdiction | | Requirement Increase | | | ROE | | Effective |
| | | | (in millions) | | | | | |
| SWEPCo | | Louisiana | | $ | 21.0 | | (a) | | 9.5% | | February 2023 |
(a)See “2020 Louisiana Base Rate Case” section of Note 4 in the 2022 Annual Report for additional information.
Pending Base Rate Case Proceedings
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | Commission Staff/ |
| | | | Filing | | Requested Revenue | | Requested | | Intervenor Range of |
| Company | | Jurisdiction | | Date | | Requirement Increase | | ROE | | Recommended ROE |
| | | | | | (in millions) | | | | | |
| PSO | | Oklahoma | | November 2022 | | $ | 173.0 | | | 10.4% | | 8.6%-9.5% | |
| APCo | | Virginia | | March 2023 | | 213.0 | | | 10.6% | | (a) | |
(a)Intervenor testimony expected to be filed in the third quarter of 2023.
Deferred Fuel Costs
Increased fuel and purchased power prices in excess of amounts included in fuel-related revenues has led to an increase in the under collection of fuel costs from customers in most jurisdictions. The table below illustrates the increase (decrease) in the deferred fuel regulatory assets by company and jurisdiction, excluding the impacts of the February 2021 severe winter weather event. See the “February 2021 Severe Winter Weather Impacts in SPP” sections in Note 4 for additional information. If any of these deferred fuel costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Traditional FAC | | As of | | As of | | Increase/ |
| Company | | Jurisdiction | | Recovery Reset | | March 31, 2023 | | December 31, 2022 | | (Decrease) |
| APCo | | Virginia (a) | | Annually | | $ | 375.7 | | | $ | 407.9 | | | $ | (32.2) | |
| APCo | | West Virginia | | Annually | | 294.8 | | | 288.5 | | | 6.3 | |
| I&M | | Indiana | | Bi-Annually | | 33.3 | | | 38.1 | | | (4.8) | |
| I&M | | Michigan | | Annually | | 10.0 | | | 9.0 | | | 1.0 | |
| PSO | | Oklahoma (b) | | Annually | | 382.1 | | | 431.5 | | | (49.4) | |
| SWEPCo | | Arkansas | | Annually | | 45.7 | | | 65.8 | | | (20.1) | |
| | | | | | | | | | |
| SWEPCo | | Texas | | Tri-Annually | | 186.8 | | | 191.4 | | | (4.6) | |
| KPCo | | Kentucky | | Monthly | | 5.5 | | | 23.2 | | | (17.7) | |
| WPCo | | West Virginia | | Annually | | 244.2 | | | 231.1 | | | 13.1 | |
| | | | Total | | $ | 1,578.1 | | | $ | 1,686.5 | | | $ | (108.4) | |
(a)Includes $96 million and $223 million as of March 31, 2023 and December 31, 2022, respectively, of noncurrent deferred fuel classified as a Regulatory Asset on APCo’s balance sheets.
(b)Includes $203 million and $253 million as of March 31, 2023 and December 31, 2022, respectively, of noncurrent deferred fuel classified as a Regulatory Asset on PSO’s balance sheets.
The AEP utility subsidiaries are working with various state commissions on the timing of recovering deferred fuel balances and have made the following recent filings:
In April 2022, APCo and WPCo (the Companies) submitted their 2022 annual ENEC filing with the WVPSC requesting a $297 million annual increase in ENEC revenues, effective September 1, 2022. In February 2023, the WVPSC issued an order stating that the commission will not grant additional rate increases for fuel costs until the WVPSC staff completes its prudency review. In April 2023, the Companies submitted their 2023 annual ENEC filing with the WVPSC, proposing two alternatives to increase ENEC rates effective September 1, 2023. The first alternative is a $293 million annual increase in ENEC rates comprised of a $89 million increase for current year ENEC expense and a $200 million annual increase for the recovery of the Companies’ February 28, 2023 ENEC under-recovery balances over three years, including debt and equity carrying costs. The second alternative is a $89 million annual increase in ENEC rates with the Companies securitizing approximately $553 million relating to ENEC under-recoveries as of February 28, 2023. Additionally, in April 2023, the Staff submitted the prudency review prepared by an independent consultant retained by the WVPSC Staff of the Companies’ operation of the Amos, Mountaineer and Mitchell coal plants that Staff was directed to conduct by the WVPSC in May 2022 (Consultant’s Report). Adoption of the Consultant’s Report’s findings by the WVPSC could result in a disallowance of up to $285 million. The Companies disagree with the conclusions and recommendations contained in the Consultant’s Report and intend to dispute them in the appropriate proceedings before the WVPSC. See “ENEC Filings” section of Note 4 for additional information.
In September 2022, the Director of the Public Utility Division of the OCC approved a Fuel Cost Adjustment rate designed to collect a $402 million deferred fuel balance over a 27-month period, effective with the first billing cycle of October 2022. PSO’s fuel and purchased power expenses are subject to an annual prudency review by the OCC.
In October 2022, APCo submitted its annual Virginia fuel factor filing with interim FAC rates effective November 2022. To help mitigate the impact of rising fuel costs on customer bills, APCo proposed recovery of its deferred fuel balance as of October 31, 2022 over two years. In March 2023, the Virginia SCC issued an order approving APCo’s request to increase its annual fuel factor by approximately $279 million and APCo’s request to recover its October 31, 2022 deferred fuel balance over two years. As ordered by the Virginia SCC, APCo’s historical period fuel and purchased power expenses are subject to a prudency review.
In September 2022, SWEPCo filed a request with the APSC for an interim increase to its current Energy Cost Rate (ECR) to recover $44 million of additional fuel costs incurred from April 2022 through August 2022, subsequent to the last annual ECR rate change. The interim rate was effective with the first billing cycle of October 2022 and will be in effect until the ECR is reset in April 2023.
In October 2022, SWEPCo filed a request with the PUCT for an interim fuel surcharge to recover $83 million of additional fuel costs incurred through August 2022. An interim rate is effective February 2023, subject to final approval by the PUCT. In April 2023, the PUCT issued an order approving the request.
Dolet Hills Power Station and Related Fuel Operations
In December 2021, the Dolet Hills Power Station was retired. While in operation, DHLC provided 100% of the fuel supply to Dolet Hills Power Station.
The remaining book value of Dolet Hills Power Station non-fuel related assets are recoverable by SWEPCo through rate riders. As of March 31, 2023, SWEPCo’s share of the net investment in the Dolet Hills Power Station was $110 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 and are subject to prudency determinations by the various commissions. After closure of the DHLC mining operations and the Dolet Hills Power Station, additional reclamation and other land-related costs incurred by DHLC and Oxbow will continue to be billed to SWEPCo and included in existing fuel clauses. As of March 31, 2023, SWEPCo had a net under-recovered fuel balance of $233 million, inclusive of costs related to the Dolet Hills Power Station billed by DHLC, but excluding impacts of the February 2021 severe winter weather event.
In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $20 million of fuel costs in 2021 and defer approximately $33 million of additional costs with a recovery period to be determined at a later date. In August 2022, the LPSC staff filed testimony recommending fuel disallowances of $72 million, including denial of recovery of the $33 million deferral, with refunds to customers over five years. In September 2022, SWEPCo filed rebuttal testimony addressing the LPSC staff recommendations.
In March 2021, the APSC approved fuel rates that provide recovery of $20 million for the Arkansas share of the 2021 Dolet Hills Power Station fuel costs over five years through the existing fuel clause.
In August 2022, SWEPCo filed a fuel reconciliation with the PUCT covering the fuel period of January 1, 2020 through December 31, 2021. Intervenors submitted testimony and SWEPCo filed rebuttal testimony in the first quarter of 2023, and a decision from the PUCT is expected in the third quarter of 2023.
If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
Pirkey Plant and Related Fuel Operations
In March 2023, the Pirkey Plant was retired. SWEPCo is recovering, or will seek recovery of, the remaining net book value of Pirkey Plant non-fuel costs. As of March 31, 2023, SWEPCo’s share of the net investment in the Pirkey Plant was $177 million, including materials and supplies, net of cost of removal. See the “Regulated Generating Units that have been Retired” section in Note 4 for additional information. Fuel costs are recovered through active fuel clauses and are subject to prudency determinations by the various commissions. As of March 31, 2023, SWEPCo fuel deliveries, including billings of all fixed costs, from Sabine ceased. Additionally, as of March 31, 2023, SWEPCo had a net under-recovered fuel balance of $233 million, inclusive of costs related to the Pirkey Plant billed by Sabine, but excluding impacts of the February 2021 severe winter weather event. Remaining 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 Portfolio
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.
ContractedRecent Renewable Generation FacilitiesFilings
AEP utilizes two subsidiaries withinRecently, the Generation & Marketing segment to further develop its renewable portfolio. AEP OnSite Partners, LLC works 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. AEP OnSite Partners, LLC pursues projects where a suitable termed agreement is entered into with a creditworthy counterparty. AEP Renewables, LLC develops and/or acquires large scale renewable generation projects that are backed with long-term contracts with creditworthy counterparties. As of September 30, 2017, these subsidiariesRegistrants have approximately 148 MWs of renewable generation projects in operation and $292 million of capital costs have been incurred related to these projects. In addition, as of September 30, 2017, these subsidiaries have approximately 42 MWs of renewable generation projects under construction and estimated capital costs of $54 million related to these projects. As of September 30, 2017, total estimated capital costs related to these renewable generation projects were approximately $346 million.
Regulated Renewable Generation Facilities
In July 2017, APCo submittedmade filings with the Virginia SCC and the WVPSC requestingvarious state regulatory commissions seeking approval to acquire two wind2,607 MWs of owned renewable generation facilities totaling approximately 225 MW$6.1 billion, in addition to 484 MWs of wind generation. The wind generating facilities are located in West Virginia and Ohio and, if approved, are anticipated to be in-servicerenewable purchased power agreements as included in the second half of 2019. APCo will assume ownership of the facilities at or near the anticipated in-service date. APCo currently plans to sell the Renewable Energy Certificates associated with the generation from these facilities.following table:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Company | | Generation Type | | Expected Commercial Operation | | Owned/PPA | | Generating Capacity |
| | | | | | | | (in MWs) |
| APCo | | Solar | | Q2 2024 through Q1 2026 | | PPA | | 204 | |
| APCo | | Wind | | Q4 2025 | | Owned | | 143 | |
| I&M | | Solar | | Q4 2025 through Q2 2026 | | Owned/PPA | | 749 | |
| PSO (a) | | Solar | | Q2 2025 through Q4 2025 | | Owned | | 443 | |
| PSO (a) | | Wind | | Q2 2025 through Q4 2025 | | Owned | | 553 | |
| SWEPCo (b) | | Solar | | Q4 2025 | | Owned | | 200 | |
| SWEPCo (b) | | Wind | | Q4 2024 through Q4 2025 | | Owned | | 799 | |
| Total Renewable Projects | | | | 3,091 | |
(a)In July 2017,April 2023, PSO and SWEPCo submitted filingsfiled an unopposed settlement agreement with the OCC LPSC, APSC and PUCT requesting various regulatory approvals needed to fully proceed withthat supported approval of the Wind Catcher Project. The Wind Catcher Project includes the acquisition of a wind generation facility, totaling approximately 2,000 MW of wind generation, and the construction of a generation interconnection tie-line totaling approximately 350 miles. Total investment for the projectprojects. An order is estimated to be $4.5 billion and will serve both retail and FERC wholesale load. PSO and SWEPCo will have a 30% and 70% ownership share, respectively, in these assets. The wind generating facility is located in Oklahoma and, if approved by all state commissions, is anticipated to be in-service by the end of 2020. In July 2017, the LPSC approved SWEPCo’s request for an exemption to the Market Based Mechanism. In August 2017, the Oklahoma Attorney General filed a motion to dismiss with the OCC. In August 2017, the motion to dismiss was denied by the OCC. Hearings at the APSC, LPSC, OCC and PUCT are scheduled in the first quarter of 2018.
Hurricane Harvey
In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. As restoration efforts are ongoing, AEP Texas’ total costs related to this storm are not yet known. AEP Texas’ current estimated cost is approximately $250 million to $300 million, including capitalized expenditures. AEP Texas currently estimates that it will incur approximately $90 million of operation and maintenance costs related to service restoration efforts. AEP Texas has a PUCT approved catastrophe reserve in base rates and can defer incremental storm expenses. AEP Texas currently recovers approximately $1 million of storm costs annually through base rates. As of September 30, 2017, the total balance of AEP Texas’ deferred storm costs is approximately $97 million including approximately $73 million of incremental storm expenses as a regulatory asset related to Hurricane Harvey. Management is currently in the early stages of analyzing the impact of potential insurance claims and recoveries and, at this time, cannot estimate this amount. Any future insurance recoveries received will be applied to and will offset the regulatory asset and property, plant and equipment, as applicable. AEP Texas is currently evaluating recovery options for the regulatory asset; however, management believes the asset is probable of recovery. The other named hurricanes did not have a material impact on AEP’s operationsexpected in the third quarter of 2017. If2023.
(b)In January 2023, SWEPCo filed an unopposed joint settlement agreement with the ultimate costsAPSC that supported approval of the incident are not recovered by insurance or throughprojects. An order from the APSC is expected in the second quarter of 2023. In March 2023, SWEPCo filed a joint settlement with the LPSC Staff that supported approval of the projects.In April 2023, the LPSC denied SWEPCo’s application.SWEPCo intends to file a motion for rehearing.In April 2023, administrative law judges in Texas issued a proposal for decision recommending that the certificate of convenience and necessity authorization be granted. An order from the PUCT is expected in the second quarter of 2023.
Significant Renewable Generation Requests for Proposal (RFP)
As part of AEP’s transition to diversify the company’s generation resources and build its renewable generation portfolio, the Registrants issue RFPs to identify potential wind and solar projects.The table below includes RFPs recently issued for owned generation.These projects would be subject to regulatory process, it could haveapproval.
| | | | | | | | | | | | | | | | | | | | |
| Company | | Issuance Date | | Generation Type | | Generating Capacity |
| | | | | | (in MWs) |
| SWEPCo | | September 2022 | | Wind (a) | | 1,900 | |
| SWEPCo | | September 2022 | | Solar (a) | | 500 | |
| I&M | | March 2023 | | Wind (b) | | 800 | |
| I&M | | March 2023 | | Solar (b)(c) | | 850 | |
| APCo | | April 2023 | | Wind and/or Solar (a)(d) | | 800 | |
| Total Significant RFPs | | | | 4,850 | |
(a)Includes an adverse effect on future net income, cash flowsoption for battery storage.
(b)RFP is an all-source solicitation seeking proposals for both owned projects and financial condition.PPAs from various types of generation including 315 MWs of storage and 540 MWs of natural gas.
(c)Includes consideration for 300 MWs of solar paired with up to 60 MWs of battery storage.
(d)Includes RFP for up to 200 MWs of PPAs.
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 into servicein-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.
The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximatelyApproximately 20%).
Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN. In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN. This share of the Turk Plant output is currently not subject to cost-based rate recovery andin Arkansas. This portion of the plant’s output is being sold into the wholesale market. Approximately 80% of the Turk Plant investment is recovered under retail cost-based rate recovery in Texas, Louisiana (subject to prudence review) and through SWEPCo’s wholesale customers under FERC-basedFERC-approved rates. In November 2022, SWEPCo filed a Certificate of Public Convenience and Necessity with the APSC for approval to operate the Turk plant to serve Arkansas customers and recover the associated costs through a cost recovery rider. Cost-based recovery of the Turk Plant would aid SWEPCo’s near-term capacity needs and support compliance with SPP’s 2023 increased capacity planning reserve margin requirements. In April 2023, intervenors filed testimony recommending the APSC deny the Certificate of Public Convenience and Necessity at this time. As of September 30, 2017,March 31, 2023, the net book value of the Turk Plant was $1.5$1.4 billion, before cost of removal including materialsCWIP and supplies inventory and CWIP. In October 2017, the LPSC staff filed a prudence review of the Turk Plant. See “Louisiana Turk Plant Prudence Review” section of Note 4.
inventory. If SWEPCo cannot ultimately recover its investment and expenses related to the Arkansas retail portion of the Turk Plant, it could reduce future net income and cash flows and impact financial condition.
June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024
In March 2016, a contested stipulation agreement related to the PPA rider application was modified and approved by the PUCO. The approved PPA rider is subject to audit and review by the PUCO. Consistent with the terms of a modified and approved stipulation agreement, and based upon a September 2016 PUCO order, in November 2016, OPCo refiled its amended ESP extension application and supporting testimony. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Renewable Resource Rider.
In August 2017, OPCo and various intervenors filed a stipulation agreement with the PUCO. The stipulation extends the term of the ESP through May 2024 and includes: (a) an extension of the OVEC PPA rider, (b) a proposed 10% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) rate caps related to OPCo’s DIR ranging from $215 million to $290 million for the periods 2018 through 2021, (e) the addition of various new riders, including a Smart City Rider and a Renewable Generation Rider, (f) a decrease in annual depreciation rates based on a depreciation study using data through December 2015 and (g) amortization of approximately $24 million annually beginning January 2018 of OPCo’s excess distribution accumulated depreciation reserve, which was $239 million as of December 31, 2015. Upon PUCO approval of the stipulation, effective January 2018, OPCo will cease recording $39 million in annual amortization previously approved to end in December 2018 in accordance with PUCO’s December 2011 OPCo distribution base rate case order. In the stipulation, OPCo and intervenors agree that OPCo can request in future proceedings a change in meter depreciation rates due to retired meters pursuant to the smart grid Phase 2 project. DIR rate caps will be reset in OPCo’s next distribution base rate case which must be filed by June 2020.
In October 2017, intervenor testimony opposing the stipulation agreement was filed recommending: (a) a return on common equity to not exceed 9.3% for riders earning a return on capital investments, (b) that OPCo should file a base distribution case concurrent with the conclusion of the current ESP in May 2018 and (c) denial of certain new riders proposed in OPCo’s ESP extension. The stipulation is subject to review by the PUCO. A hearing at the PUCO is scheduled for November 2017.
If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. See “Ohio Electric Security Plan Filings” section of Note 4.
2016 SEET Filing
In December 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings. In May 2017, OPCo submitted its 2016 SEET filing with the PUCO in which
management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group. Although management believes that OPCo’s adjusted 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s SEET treatment of the Global Settlement issues described above or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could reduce future net income and cash flows and impact financial condition. See “2016 SEET Filing” section of Note 4.
Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR)
In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NOx from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million, excluding AFUDC, to be shared equally between I&M and AEGCo. As of September 30, 2017, total costs incurred related to this project, including AFUDC, were approximately $17 million. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to I&M and KPCo and will be subject to future regulatory approval for recovery. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport Plant, Unit 2 lease. A hearing at the IURC was held in March 2017. An order from the IURC is pending. In July 2017, I&M filed a motion with the U.S. District Court for the Southern District of Ohio to remove the requirement to install SCR technology at Rockport Plant, Unit 2. In August 2017, the district court delayed the deadline for installation of the SCR technology until March 2020.
2017 Indiana Base Rate Case
In July 2017, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to a temporary offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures. The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Plant Life Cycle Management Project. A hearing at the IURC is scheduled for January 2018. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
2017 Michigan Base Rate Case
In May 2017, I&M filed a request with the MPSC for a $52 million annual increase in Michigan base rates based upon a proposed 10.6% return on common equity with the increase to be implemented no later than April 2018. The proposed annual increase includes $23 million related to increased annual depreciation rates and a $4 million increase related to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the proposed change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project. Additionally, the total proposed increase includes incremental costs related to the Cook Plant Life Cycle Management Program and increased vegetation management expenses. In October 2017, the MPSC staff and intervenors filed testimony. The MPSC staff recommended an annual net revenue increase of $49 million including proposed retirement dates of 2028 for both Rockport Plant, Units 1 (from 2044) and 2 (from 2022) and a return on common equity of 9.8%. The intervenors
proposed certain adjustments to I&M’s request including no change to the current 2044 retirement date of Rockport Plant, Unit 1, but did not propose an annual net revenue increase. Their recommended return on common equity ranged from 9.3% to 9.5%. A hearing at the MPSC is scheduled for November 2017. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
Louisiana Turk Plant Prudence Review
Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 33%) of the Turk Plant, have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed into service in December 2012. In October 2017, the LPSC staff filed testimony contending that SWEPCo failed to continue to evaluate the suspension or cancellation of the Turk Plant during its construction period. The testimony also identified five individual items totaling approximately $51 million for potential disallowance relating to Louisiana’s jurisdictional share of Turk Plant. As a result of SWEPCo’s alleged failure to meet its continuing prudence obligations, the LPSC staff recommends one of the following potential unfavorable scenarios: (a) 50/50 sharing of construction cost overruns between SWEPCo and ratepayers, (b) an imposition of a cost cap similar to Texas or (c) approximately a 1% reduction of the rate on common equity for the Turk Plant. As SWEPCo has included the full value of the Turk Plant in rate base since its in-service date, SWEPCo may be required to refund potential over-collections from January 2013 through the date new rates are implemented. As of September 30, 2017, if the LPSC adopts one of these potential scenarios, and disallows the five individual items, pretax write-offs could range from $50 million to $80 million and refund provisions, including interest, could range from $15 million to $27 million. Future annual revenue reductions could range from $3 million to $4 million. Management will continue to vigorously defend against these claims. If the LPSC orders in favor of one of these scenarios, it could reduce future net income and cash flows and impact financial condition. A hearing at the LPSC is scheduled for December 2017.
2017 Oklahoma Base Rate Case
In June 2017, PSO filed an application for a base rate review with the OCC that requested a net increase in annual revenues of $156 million based upon a proposed 10% return on common equity. The proposed base rate increase includes (a) environmental compliance investments, including recovery of previously deferred environmental compliance related costs currently recorded as regulatory assets, (b) Advanced Metering Infrastructure investments, (c) additional capital investments and costs to serve PSO’s customers, and (d) an annual $42 million depreciation rate increase due primarily to shorter service lives and lower net salvage estimates. As part of this filing, consistent with the OCC’s final order in its previous base rate case, PSO requested recovery through 2040 of Northeastern Plant, Unit 3, including the environmental control investment, and the net book value of Northeastern Plant, Unit 4 that was retired in 2016. As of September 30, 2017, the net book value of Northeastern Plant, Unit 4 was $82 million.
In September 2017, various intervenors and the OCC staff filed testimony that included annual net revenue increase recommendations ranging from $28 million to $108 million. The recommended returns on common equity ranged from 8% to 9%. In addition, certain parties recommended investment disallowances that ranged from $27 million to $82 million related to Northeastern Plant, Unit 4 and $38 million associated with capitalized incentives. Also, a party recommended a potential refund of $43 million related to an SPP rider claiming that PSO did not adequately support the related SPP costs. The combined total impact could result in a write-off and refund of up to approximately $163 million. In addition, if similar plant recovery issues would apply to Northeastern Plant, Unit 3, the net book value of plant, including regulatory assets, materials and supplies inventory and CWIP of $346 million as of September 30, 2017, could be adversely impacted. A hearing at the OCC is scheduled to begin in October 2017.
If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
2017 Kentucky Base Rate Case
In June 2017, KPCo filed a request with the KPSC for a $66 million annual increase in Kentucky base rates based upon a proposed 10.31% return on common equity with the increase to be implemented no later than January 2018. The proposed increase includes: (a) lost load since KPCo last changed base rates in July 2015, (b) incremental costs
related to OATT charges from PJM not currently recovered from retail ratepayers, (c) increased depreciation expense including updated Big Sandy Plant, Unit 1 depreciation rates using a proposed retirement date of 2031, (d) recovery of other Big Sandy Plant, Unit 1 generation costs currently recovered through a retail rider and (e) incremental purchased power costs. Additionally, KPCo requested a $4 million annual increase in environmental surcharge revenues.
In August 2017, KPCo submitted a supplemental filing with the KPSC that decreased the proposed annual base rate revenue request to $60 million. The modification was due to a lower interest expense related to June 2017 debt refinancings. In October 2017, various intervenors filed testimony that included annual net revenue increase recommendations ranging from $13 million to $40 million. Intervenors recommended returns on common equity ranging from 8.6% to 8.85%. Intervenors also recommended significant delays in KPCo’s proposed recoveries of: (a) depreciation expense related to Big Sandy Plant, Unit 1 (gas unit), proposing a 30-year depreciable life instead of KPCo’s proposed 15-year life and (b) lease expense on Rockport Plant, Unit 2 billed from AEGCo, proposing that the approximate $100 million of lease expense for the period 2018 through 2022 be deferred with a WACC carrying charge for recovery over 10 years beginning 2023. Testimony on behalf of the Attorney General also discussed that the KPSC could consider disallowing all or a portion of the costs currently being recovered over 25 years through the Big Sandy Plant, Unit 2 retirement rider. As of September 30, 2017, KPCo’s regulatory asset related to the retired Big Sandy Plant, Unit 2 was $289 million. A hearing at the KPSC is scheduled for December 2017.
If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
2016 Texas Base Rate Case
In December 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. In September 2017, the Administrative Law Judges (ALJs) issued their proposal for decision including an annual net revenue increase of $50 million including recovery of Welsh Plant, Unit 2 environmental investments as of June 30, 2016. The ALJs proposed a return on common equity of 9.6% and recovery of but no return on Welsh Plant, Unit 2. The ALJs rejected SWEPCo’s proposed transmission cost recovery mechanism. The estimated potential write-off associated with the ALJs proposal is approximately $22 million which includes $9 millionassociated with the lack of a return on Welsh Plant, Unit 2.
If any of these costs are not recoverable, including environmental investments and retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. See “2016 Texas Base Rate Case” section of Note 4.
FERC Transmission Complaint - AEP’s PJM Participants
In October 2016, several parties filed a joint complaint at the FERC that states the base return on common equity used by AEP’s eastern transmission subsidiaries in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.
Modifications to AEP’s PJM Transmission Rates
In November 2016, AEP’s eastern transmission subsidiaries filed an application at the FERC to modify the PJM OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to projected expenses. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017, the modified PJM OATT formula rates were implemented, subject to refund, based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
FERC Transmission Complaint - AEP’s SPP Participants
In June 2017, several parties filed a joint complaint at the FERC that states the base return on common equity used by AEP’s western transmission subsidiaries in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36%, effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.
FERC SWEPCo Power Supply Agreements Complaint - East Texas Electric Cooperative, Inc. (ETEC) and Northeast Texas Electric Cooperative, Inc. (NTEC)
In September 2017, ETEC and NTEC filed a complaint at the FERC that states the base return on common equity used by SWEPCo in calculating their power supply formula rates is excessive and should be reduced from 11.1% to 8.41%, effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.
Welsh Plant - Environmental Impact
Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could total approximately $850 million, excluding AFUDC. As of September 30, 2017, SWEPCo had incurred costs of $398 million, including AFUDC, related to these projects. Management continues to evaluate the impact of environmental rules and related project cost estimates. As of September 30, 2017, the total net book value of Welsh Plant, Units 1 and 3 was $626 million, before cost of removal, including materials and supplies inventory and CWIP.
In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas filed base rate proceeding. In December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant. In April 2017, the LPSC approved SWEPCo’s recovery of these deferred costs effective May 2017. SWEPCo’s approved Louisiana jurisdictional share of Welsh Plant deferrals: (a) are $11 million, excluding $6 million of unrecognized equity as of September 30, 2017, (b) is subject to review by the LPSC, and (c) includes a WACC return on environmental investments and the related depreciation expense and taxes. Effective May 2017, SWEPCo began recovering $131 million in investments related to its Louisiana jurisdictional share of environmental costs. SWEPCo has sought recovery of its project costs from retail customers in its current Texas base rate case at the PUCT and is recovering these costs from wholesale customers through SWEPCo’s FERC-approved agreements.
If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See “Welsh Plant - Environmental Impact” section of Note 4.
Westinghouse Electric Company Bankruptcy Filing
In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the U.S. Bankruptcy Code. It intends to reorganize, not cease business operations. However, it is in the early stages of the bankruptcy process and it is unclear whether the company can successfully reorganize. Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication, and ongoing engineering projects. The most significant of these relate to Cook Plant fuel fabrication. I&M is evaluating how this reorganization affects these contracts. Westinghouse has stated that it intends to continue performance on I&M’s contracts, but given the importance of upcoming dates in the fuel fabrication process for Cook Plant, and their vital part in Cook Plant’s ongoing operations, I&M continues to work with Westinghouse in the bankruptcy proceedings to avoid any interruptions to that service. In the unlikely event Westinghouse rejects I&M’s contracts, or is unable to reorganize or sell its profitable businesses in the bankruptcy, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services.
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. For details on the regulatory proceedings and pending litigation see Note 4 - Rate Matters, Note 6 - Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2016 Annual Report. Additionally, see Note 4 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies included herein. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition. See Note 4 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies for additional information.
Rockport Plant 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 2013,2020, an investigation led by the Wilmington Trust CompanyU.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 complaintputative class action lawsuit in U.S.the U. S. District Court for the Southern District of New YorkOhio against AEGCoAEP and I&M alleging that it will be unlawfully burdened bycertain of its officers for alleged violations of securities laws. In December 2021, 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 or retirement of the unit. The plaintiffs further allege that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M.
In January 2015, thedistrict court issued an opinion and order grantingdismissing the motion in part and denyingsecurities litigation complaint with prejudice, determining that the motion in part.complaint failed to plead any actionable misrepresentations or omissions. The court dismissed certain ofplaintiffs did not appeal the plaintiffs’ claims, including the dismissal without prejudice of plaintiffs’ claims seeking compensatory damages. Several claims remained, including the claim for breach of the participation agreement and a claim alleging breach ofruling.
In January 2021, an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&MAEP shareholder filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. In November 2015, AEGCo and I&M filed a motion to strike the plaintiffs’ motion for partial judgment and filed a motion to dismiss the case for failure to state a claim.
In March 2016, the court entered an opinion and orderderivative action in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, plaintiffs filed an appeal in the U.S. Court of Appeals for the Sixth Circuit on whether AEGCo and I&M are in breach of certain contract provisions that plaintiffs allege operate to protect the plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing.
In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions which had dismissed certain of plaintiffs’ claims for breach of contract and remanding the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. In April 2017, AEGCo and I&M filed a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit, which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reverses the district court’s dismissal of certain of the owners’ claims under the lease agreements, vacates the denial of the owners’ motion for partial summary judgment and remands the case to the district court for further proceedings. The amended opinion and judgment also affirms the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims and removes the instruction to the district court in the original opinion to enter summary judgment in favor of the owners.
In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio seekingpurporting to modifyassert 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 consent decreeCourt 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 eliminatethose alleged in the obligation to install future controls at Rockport Plant, Unit 2 if AEP does not acquire ownershipputative securities class action lawsuit filed against AEP. The derivative complaints together assert claims for: (a) breach of that Unit,fiduciary duty, (b) waste of corporate assets, (c) unjust enrichment, (d) breach of duty for insider trading and to modify the consent decree in other respects to preserve the environmental benefits(e) contribution for violations of sections 10(b) and 21D of the consent decree. In October 2017,Securities Exchange Act of 1934; and seek monetary damages and changes to AEP’s corporate governance and internal policies among other forms of relief. The court entered a scheduling order in the ownersNew York state court derivative action staying the case other than with respect to briefing the motion to dismiss. AEP filed substantive and forum-based motions to dismiss on April 29, 2022. On September 13, 2022, the New York state court granted the forum-based motion to dismiss with prejudice and the plaintiff subsequently filed a notice of appeal with the New York appellate court. On January 20, 2023, the New York plaintiff filed a motion to stay their claimsintervene in the pending Ohio federal court action and withdrew his appeal in New York. The two derivative actions pending in federal district court in Ohio have been consolidated and the plaintiffs in the consolidated action filed an amended complaint. AEP filed a motion to dismiss the amended complaint and subsequently filed a brief in opposition to the New York plaintiffs’ motion to intervene in the consolidated action in Ohio. On March 20, 2023, the federal district court issued an order granting the motion to dismiss with prejudice and denying the New York plaintiffs’ motion to intervene. On April 20, 2023, one of the plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Sixth Circuit of the Ohio federal district court order dismissing the consolidated action and denying the intervention. On June 15, 2022, the Ohio state court entered an order continuing the stays of that case until January 2018, to afford time forthe final resolution of AEP’s motion to modify the consent decree.
Managementconsolidated derivative actions pending in Ohio federal district court. The defendants will continue to defend against the claims. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, managementManagement is unable to determine a range of potential losses that areis reasonably possible of occurring.
In March 2021, AEP received a litigation demand letter from counsel representing a purported AEP shareholder. The litigation demand letter was directed to the Board of Directors of AEP (AEP Board) and contained factual allegations involving HB 6 that were generally consistent with those in the derivative litigation filed in state and federal court. The shareholder that sent the letter has since withdrawn the litigation demand, which is now terminated and of no further effect. In April 2023, AEP received a litigation demand from counsel representing the purported AEP shareholder who filed the dismissed derivative action in New York state court and unsuccessfully tried to intervene in the consolidated derivative actions in Ohio federal court. The litigation demand letter is directed to the AEP Board and contains factual allegations involving HB6 that are generally consistent with those in the derivative litigation filed in state and federal court. The letter demands, among other things, that the AEP Board undertake an independent investigation into alleged legal violations by certain current and former directors and officers, and that AEP commence a civil action for breaches of fiduciary duty and related claims against any individuals who allegedly harmed AEP. The AEP Board will act in response to the letter as appropriate. Management is unable to determine a range of potential losses that is reasonably possible of occurring.
In May 2021, AEP received a subpoena from the SEC’s Division of Enforcement seeking various documents, including documents relating to the passage of HB 6 and documents relating to AEP’s policies and financial processes and controls. In August 2022, AEP received a second subpoena from the SEC seeking various additional documents relating to its ongoing investigation. AEP is cooperating fully with the SEC’s investigation, which has included taking testimony from certain individuals. Although the outcome of the SEC’s investigation cannot be predicted, management does not believe the results of this investigation will have a material impact on financial condition, results of operations or cash flows.
Claims for Indemnification Related to Damages Resulting from the Federal EPA’s Denial of Alternative Closure Deadline for Gavin Plant and Associated Findings of Compliance
In November 2022, the Federal EPA issued a final decision denying Gavin Power LLC’s requested extension to allow a CCR surface impoundment at the Gavin Power Station to continue to receive CCR and non-CCR waste streams after April 11, 2021 until May 4, 2023 (the Gavin Denial). As part of the Gavin Denial, the Federal EPA made several determinations related to the CCR Rule (see “Coal Combustion Residual (CCR) Rule” section below for additional information), including a determination that the closure of the 300 acre unlined fly ash reservoir (FAR) is noncompliant with the CCR Rule in multiple respects. The Gavin Power Station was formerly owned and operated by AEP and was sold to Gavin Power LLC and Lightstone Generation LLC in 2017. Pursuant to the PSA, AEP maintained responsibility to complete closure of the FAR in accordance with the closure plan approved by the Ohio EPA which was completed in July 2021. The PSA contains indemnification provisions, pursuant to which the owners of the Gavin Power Station have notified AEP they believe they are entitled to indemnification for any damages that may result from the Gavin Denial, as well as any future enforcement or litigation resulting from the Federal EPA’s determinations of noncompliance with various aspects of the CCR Rule as part of the Gavin Denial. Management does not believe that the owners of the Gavin Power Station have any valid claim for indemnity or otherwise against AEP under the PSA. In addition, Gavin Power LLC, several AEP subsidiaries, and other parties have filed Petitions for Review of the Gavin Denial with the U.S. Court of Appeals for the District of Columbia Circuit. Management is unable to determine a range of potential losses that is reasonably possible of occurring.
Claims for Damages Related to Sabine Coal Supply Contract
In April 2023, AEP received a letter from North American Coal Corporation (NACC) alleging that SWEPCo breached it’s coal supply contract with Sabine, a subsidiary of NACC. The letter contends that SWEPCo is obligated to run the Pirkey Plant until 2035 or to pay $85 million in damages representing lost mining fees to Sabine. The letter threatens legal action for unspecified injunctive relief and breach of contract. Management does not believe SWEPCo is obligated to run the Pirkey Plant for any period of time beyond its useful life or that there is a valid claim for breach of contract or damages. Management is unable to determine a range of potential losses that is reasonably possible of occurring.
ENVIRONMENTAL ISSUES
AEP has a substantial capital investment program and is incurringincurs additional operational costs to comply with environmental control requirements. Additional investments and operational changes will need to be made in response to existing and anticipated requirements such as new CAA requirements to reduce emissions from fossil fuel-fired power plants,generation and in response to rules governing the beneficial use and disposal of coal combustion products,by-products, clean water rules and renewal permits for certain water discharges.
AEP is engaged in litigation about environmental issues, was notified of potential responsibility for the clean-up of contaminated sites and incurred costs for disposal of SNF and future decommissioning of the nuclear units. AEP, along with various industry groups, affected states and other parties challenged some of the Federal EPA requirements in court. Management is also engaged in the development of possible future requirements including the items discussed below. Management believes that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.
See a complete discussion of these matters in the “Environmental Issues” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2016 Annual Report. AEP will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances. If AEP is unable tocannot recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.
Environmental Controls Impact on the Generating Fleet
The rules and proposed environmental controls discussed in the next several sectionsbelow will have a materialan impact on theAEP System generating units in the AEP System.units. Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance. As of September 30, 2017,March 31, 2023, the AEP System had a totalowned generating capacity of approximately 25,60024,600 MWs, of which approximately 13,50010,700 MWs arewere coal-fired. Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on the fossil generating facilities. Based upon management estimates, AEP’s investment to meet these existing and proposed requirements ranges from approximately $2.2 billion to $2.8 billion between 2017 and 2025.generation.
The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in finalizing proposed rules or reviewing and revising certain existing requirements. The cost estimates will also change based on: (a) the states’ implementation of these regulatory programs, including the potential for state implementation plans (SIPs) or federal implementation plans (FIPs)rules that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed, on the units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity, (g) compliance with the Federal EPA’s revised coal combustion residual rules and (g)(h) other factors. In addition, management is continuingcontinues to evaluate the economic feasibility of environmental investments on both regulated and competitive plants.
The table below represents the plants or units of plants retired in 2016 and 2015 with a remaining net book value. As of September 30, 2017, the net book value before cost of removal, including related materials and supplies inventory and CWIP balances, of the units listed below was approved for recovery, except for $338 million. Management is seeking or will seek recovery of the remaining net book value associated with these plants in future rate proceedings.
|
| | | | | | | | | |
| | | | | Generating | | Amounts Pending |
| Company | | Plant Name and Unit | | Capacity | | Regulatory Approval |
| | | | | (in MWs) | | (in millions) |
| APCo | | Kanawha River Plant | | 400 |
| | $ | 42.3 |
|
| APCo | | Clinch River Plant, Unit 3 | | 235 |
| | 32.7 |
|
| APCo (a) | | Clinch River Plant, Units 1 and 2 | | 470 |
| | 31.8 |
|
| APCo | | Sporn Plant | | 600 |
| | 17.2 |
|
| APCo | | Glen Lyn Plant | | 335 |
| | 13.4 |
|
| I&M (b) | | Tanners Creek Plant | | 995 |
| | 42.6 |
|
| PSO (c) | | Northeastern Plant, Unit 4 | | 470 |
| | 82.4 |
|
| SWEPCo (d) | | Welsh Plant, Unit 2 | | 528 |
| | 75.9 |
|
| Total | | | | 4,033 |
| | $ | 338.3 |
|
| |
(a) | APCo obtained permits following the Virginia SCC’s and WVPSC’s approval to convert its 470 MW Clinch River Plant, Units 1 and 2 to natural gas. In 2015, APCo retired the coal-related assets of Clinch River Plant, Units 1 and 2. Clinch River Plant, Unit 1 and Unit 2 began operations as natural gas units in February 2016 and April 2016, respectively. |
| |
(b) | I&M requested recovery of the Indiana (approximately 65%) and Michigan (approximately 14%) jurisdictional shares of the remaining retirement costs of Tanners Creek Plant in the 2017 Indiana and Michigan base rate cases. |
| |
(c) | For Northeastern Plant, Unit 4, in November and December 2016, the OCC issued orders that provided no determination related to the return of and return on the post-retirement remaining net book value. In June 2017, PSO filed an application for a base rate review with the OCC. As part of this filing, PSO requested recovery of approximately $82 millionthrough 2040 related tothe net book value of Northeastern Plant, Unit 4 that was retired in 2016. This regulatory asset is pending regulatory approval.
|
| |
(d) | SWEPCo requested recovery of the Texas jurisdictional share (approximately 33%) of the net book value of Welsh Plant, Unit 2 in the 2016 Texas Base Rate Case. This regulatory asset is pending regulatory approval. |
In January 2017, Dayton Power and Light Company announced the future retirement of the 2,308 MW Stuart Plant, Units 1-4. The retirement is scheduled for June 2018. Stuart Plant, Units 1-4 are operated by Dayton Power and Light Company and are jointly owned by AGR and nonaffiliated entities. AGR owns 600 MWs of the Stuart Plant, Units 1-4. As of September 30, 2017, AGR’s net book value of the Stuart Plant, Units 1-4 was zero.
To the extent existing generation assets and the cost of new equipment and converted facilities are not recoverable, it could materially reduce future net income and cash flows and impact financial condition.
Proposed Modification of the New Source Review (NSR) Litigation Consent Decree
In 2007, the U.S. District Court for the Southern District of Ohio approved a consent decree between the 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 it 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.
In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio seeking to modify the consent decree to eliminate an obligation to install future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. The district court granted AEP’s request to delay the deadline to install SCR technology at Rockport Plant, Unit 2 until March 2020, pending resolution of the motion. AEP also proposes to retire Conesville Plant, Units 5 and 6 by December 31, 2022 and to retire one Rockport Plant unit by December 31, 2028.
AEP is seeking to modify the consent decree as a means to resolve or substantially narrow the issues in pending litigation with the owners of Rockport Plant, Unit 2. See “Rockport Plant Litigation” in Management’s Discussion and Analysis of Financial Condition and Results of Operations and in Note 5 - Commitments, Guarantees and Contingencies for additional information.
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 the National Ambient Air Quality Standards (NAAQS)NAAQS and the development of SIPs to achieve any more stringent standards;standards, (b) implementation of the regional haze program by the states and the Federal EPA;EPA, (c) regulation of hazardous air pollutant emissions under the Mercury and Air Toxics Standards (MATS) Rule;MATS, (d) implementation and review of the Cross-State Air Pollution Rule (CSAPR), a FIP designed to eliminate significant contributions from sources in upwind states to nonattainment or maintenance areas in downwind statesCSAPR and (e) the Federal EPA’s regulation of greenhouse gas emissions from fossil-fueled electric generating unitsfossil generation under Section 111 of the CAA.
In March 2017, President Trump issued a series of executive orders designed to allow the Federal EPA to review and take appropriate action to revise or rescind regulatory requirements that place undue burdens on affected entities, including specific orders directing the Federal EPA to review rules that unnecessarily burden the production and use of energy. The Federal EPA published notice and an opportunity to comment on how to identify such requirements and what steps can be taken to reduce or eliminate such burdens. Future changes that result from this effort may affect AEP’s compliance plans.
Notable developments in significant CAA regulatory requirements affecting AEP’s operations are discussed in the following sections.
National Ambient Air Quality Standards (NAAQS)
The Federal EPA issued new, more stringentperiodically reviews and revises the NAAQS for SO2criteria pollutants under the CAA. Revisions tend to increase the stringency of the standards, which in 2010, PMturn may require AEP to make investments in 2012pollution control equipment at existing generating units, or, since most units are already well controlled, to make changes in how units are dispatched and ozone in 2015. Implementation of these standards is underway. States are still in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the 2010 SO2 NAAQS and may develop additional requirements for AEP’s facilities as a result of those evaluations.operated. In April 2017,January 2023, the Federal EPA requested a stay of proceedings inannounced its proposed decision to strengthen the U.S. Court of Appealsprimary (health-based) annual PM2.5 standard. The Biden administration has previously indicated that it is likely to revisit the NAAQS for the District of Columbia Circuit where challenges to the 2015 ozone, standard are pending, to allow reconsideration of that standardwhich were left unchanged by the new administration. The Federal EPA initially announced a one-year delay in the designation of ozone non-attainment areas, but withdrew that decision. Final designations were due October 1, 2017, but have not yet been announced.prior administration following its review. Management cannot currently predict the nature, stringencyif any changes to either standard are likely to be finalized or timing of additional requirements for AEP’s facilities based on the outcome of these activities.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), detailing how the CAA’s requirement that certain in 2005, which could require power plants and other facilities to install best available retrofit technology (BART) willto address regional haze in federal parks and other protected areas. BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants. CAVR will beis implemented by the states, through SIPs, or if SIPs are not adequate or are not developed on schedule,by the Federal EPA, through FIPs. In January 2017, the Federal EPA revised the rules governing submission of SIPs to implement the visibility programs, including a provision that postponespostponed the due date for the next comprehensive SIP revisions until 2021. Petitions for review of the final rule revisions have been filed in the U.S. Court of Appeals for the District of Columbia Circuit.
The Federal EPA proposed disapproval ofArkansas has an approved regional haze SIPsSIP and all of SWEPCo's affected units are in a few states, including Arkansas and Texas. In March 2012, the Federal EPA disapproved certain portions of the Arkansas regional haze SIP. In April 2015, the Federal EPA published a proposed FIP to replace the disapproved portions, including revised BART determinations for the Flint Creek Plant that were consistentcompliance with the environmental controls currently under construction. relevant requirements.
In September 2016, the Federal EPA published a final FIP that retains its BART determinations, but accelerates the schedule for
implementation of certain required controls. The final rule is being challenged in the courts. In March 2017, the Federal EPA filed a motion that was granted by the U.S. Court of Appeals for the Eighth Circuit Court to hold the case in abeyance for 90 days to allow the parties to engage in settlement negotiations. Arkansas issued a proposed SIP revision to allow sources to participate in the CSAPR ozone season program in lieu of the source-specific NOx BART requirements in the FIP, and the Federal EPA has proposed to approve that SIP revision. Arkansas and the Federal EPA have asked the Eighth Circuit to continue to hold litigation in abeyance until October 31, 2017 to facilitate settlement discussions. Management cannot predict the outcome of these proceedings.
In January 2016,Texas, the Federal EPA disapproved portions of the Texas regional haze SIP and promulgated a final FIP that did not include any BART determinations. That rule was challenged and stayed by the U.S. Court of Appeals for the Fifth Circuit Court. The parties engaged in a settlement discussion but were unable to reach an agreement. In March 2017, the U.S. Court of Appeals for the Fifth Circuit granted partial remand of the final rule. In January 2017, the Federal EPA proposed source-specific BART requirements for SO2 from sources in Texas, including Welsh Plant, Unit 1. Management submitted comments on the proposal and is engaged in discussions with the Texas Commission on Environmental Quality (TCEQ) regarding the development of an alternative to source-specific BART. In September 2017, the Federal EPA issued a final rule withdrawing Texas from the annual CSAPR budget programs. The Federal EPA then issued a separate rule finalizing the regional haze requirements for electric generating units in Texas and confirmed TCEQ’s determination that no new PM limitations are required for regional haze. The Federal EPA also finalized a FIP that allows participation in the CSAPR ozone season program to satisfy the NOx Xregional haze obligations for electric generating units.units in Texas. Additionally, the Federal EPA finalized an intrastate SO2 emissions trading program based on CSAPR allowance allocations as an alternativeallocations. Legal challenges to source-specific SO2 requirements. The proposed source-specific approach calledthese various rulemakings are pending in both the U.S. Court of Appeals for a wet FGD system to be installed on Welsh Plant, Unit 1. The opportunity to use emissions trading to satisfy the regional haze requirements for NOxFifth Circuit and SO2 at AEP’s affected generating units provides greater flexibility and lower cost compliance options than the original proposal.
In June 2012, the Federal EPA published revisions to the regional haze rules to allow states participating in the CSAPR trading programs to use those programs in place of source-specific BART for SO2 and NOx emissions based on its determination that CSAPR results in greater visibility improvements than source-specific BART in the CSAPR states. This rule is being challenged in 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 with CSAPR programs as satisfactionalternative to source-specific controls and has intervened in the litigation in support of the BART requirements.Federal EPA.
Cross-State Air Pollution Rule (CSAPR)
In 2011,CSAPR is a regional trading program that the Federal EPA issued CSAPR as a replacement for the CAIR, a regional trading programbegan implementing in 2015, which was designed to address interstate transport of emissions that contributedcontribute significantly to downwind nonattainmentnon-attainment and interfere with maintenance of the 1997 ozone NAAQS and the 1997 and 2006 PM NAAQS. Certain revisions to the rule were finalizedNAAQS in 2012.downwind states. CSAPR relies on newly-created SO2 and NOx Xallowances 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. The Federal EPA has revised, or updated, the CSAPR trading programs several times since they were established.
Numerous affected entities,In January 2021, the Federal EPA finalized a revised CSAPR, which substantially reduced the ozone season NOX budgets for several states, including states where AEP operates, beginning in ozone season 2021. Several utilities and other parties filed petitionsentities potentially subject to review the CSAPR in the U.S. Court of Appeals for the District of Columbia Circuit. The court stayed implementation of the rule. Following extended proceedingsFederal EPA’s NOX regulations challenged that final rule in the U.S. Court of Appeals for the District of Columbia Circuit and oral argument was held in September 2022. In March 2023, the court rejected the challenge and upheld the rule. Management 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. In addition, in February 2023, the Federal EPA Administrator finalized the disapproval of interstate transport SIPs submitted by 19 states addressing the 2015 Ozone NAAQS. Disapproval of the SIPs provides the Federal EPA with authority to impose a FIP for those states, replacing the SIPs that were disapproved. Various legal challenges have been brought by several states, utilities and other industry parties challenging the SIP disapproval. SWEPCo filed a petition for review of the disapproval of the Arkansas SIP in the U.S. Supreme Court but whileof Appeals for the litigation was stillEighth Circuit on April 14, 2023. In March 2023, the Federal EPA finalized a FIP that further revises the ozone season NOX budgets under the existing CSAPR program in states to which the FIP applies. The FIP is expected to take effect during the 2023 ozone season. In May 2023, the U.S. Court of Appeals for the Fifth Circuit stayed the Federal EPA’s disapproval of the Texas and Louisiana SIPs pending a decision on the merits of the appeal, calling into question the Federal EPA’s ability to enforce the FIP in those states. Management is evaluating the impacts of the FIP and cannot predict the outcome of the litigation.
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 District of Columbia Circuit grantedvacated the ACE rule and remanded it to the Federal EPA’s motion to liftEPA. In October 2021, the stayUnited States Supreme Court granted certiorari and allow Phase Icombined four separate petitions seeking review of CSAPR to take effect on January 1, 2015 and Phase II to take effect on January 1, 2017. In July 2015, the U.S. Court of Appeals for the District of Columbia Circuit found thatCourt decisions. Oral arguments were held in February 2022 and on June 30, 2022, the Federal EPA over-controlled the SO2 and/or NOx budgets of 14 states. The U.S.United States Supreme Court of Appeals forreversed the District of Columbia Circuit Court’s decision and
remanded for further proceedings. The Federal EPA must take some action before anything is required of the rule toutilities as a result of this decision. At a minimum, if the Federal EPA intends to timely reviseimplement the ACE rule, consistent with the court’s opinion while CSAPR remains in place.
In October 2016, a final rule was issuedit must conduct additional rulemaking to address the remand and to incorporate additional changes necessary to address the 2008 ozone standard. The final rule significantly reduces ozone season budgets in many states and discounts the value of banked CSAPR ozone season allowances beginning with the 2017 ozone season. The rule has been challenged in the courts and petitions for administrative reconsiderationupdate its applicable deadlines, which have been filed. The rule remains in effect. Management is complying with the more stringent ozone season budgets while these petitions are being considered.
Mercury and Other Hazardous Air Pollutants (HAPs) Regulation
In 2012,all passed. Alternatively, the Federal EPA issuedmay abandon the ACE rule and proceed to regulate greenhouse gases through a new rule, addressingthe scope of which is unknown. The Federal EPA has announced it expects to propose a broad range of HAPs from coal and oil-fired power plants. Thenew rule establishes unit-specific emission rates for units burning coal on a 30-day rolling average basis for mercury, PM (as a surrogate for particles of nonmercury metals) and hydrogen chloride (as a surrogate for acid gases). In addition,in 2023. Management is unable to predict how the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans. Compliance was required within three years. Management obtained administrative extensions for upFederal EPA will respond to one year at several units to facilitate the installation of controls or to avoid a serious reliability problem.Court’s remand.
In April 2014,2018, 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. Court of Appeals for the District of Columbia Circuit denied all of the petitions forand is not cost-effective. That rule has not been finalized. The Federal EPA has indicated that it intends to conduct a comprehensive review of the April 2012 final rule. Industry trade groupsexisting standards and, several states filed petitionsif appropriate, amend the emission standards for further reviewnew fossil fuel-fired generating units. A proposed rule is expected in the U.S. Supreme Court2023. 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 the court granted those petitions in November 2014.
In June 2015, the U.S. Supreme Court reversed the decision of the U.S. Court of Appeals for the District of Columbia Circuit. The U.S. Court of Appeals for the District of Columbia Circuit remanded the MATS rule for further proceedings consistent with the U.S. Supreme Court’s decision that the Federal EPA was unreasonable in refusing to consider costs in its determination whether to regulate emissions of HAPs from power plants. The Federal EPA issued notice of a supplemental finding concluding that it is appropriate and necessary to regulate HAPoffset 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 oil-fired units. Management submitted comments onactions taken to diversify the proposal. In April 2016, the Federal EPA affirmed its determination that regulation of HAPs from electric generating unitsgeneration fleet and increase energy efficiency where there is necessary and appropriate. Petitionsregulatory support for review of the Federal EPA’s April 2016 determination have been filed in the U.S. Court of Appeals for the District of Columbia Circuit. Oral argument was scheduled for May 2017, but in April 2017 the Federal EPA requested that oral argument be postponed to facilitate its review of the rule. The rule remains in effect.
Climate Change, CO2 Regulation and Energy Policy
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 (RGGI), 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, andpurchasing renewable power purchases and broadening the AEP System’s portfolio of energy efficiency programs. In early 2022, Virginia’s governor issued an executive order directing his administration to end Virginia’s participation in RGGI. In December 2022, the Virginia Air Pollution Control Board voted in support of the proposed regulations to withdraw Virginia from RGGI. These regulations have not been finalized. Management will continue to monitor these rulemaking activities.
In October 2015,2022, AEP announced new intermediate and long-term CO2 emission reduction goals, based on the Federal EPA publishedoutput of the final standards for new, modifiedcompany’s integrated resource plans, which take into account economics, customer demand, grid reliability and reconstructed fossil fired steam generating unitsresiliency, regulations and combustion turbines,the company’s current business strategy. AEP adjusted its near-term CO2 emission reduction target from a 2000 baseline to a 2005 baseline, upgraded its 80% reduction by 2030 target to include full Scope 1 emissions and final guidelines for the developmentaccelerated its net-zero goal by five years to 2045. AEP’s total Scope 1 greenhouse gas (GHG) emissions in 2022 were approximately 52.5 million metric tons CO2e, approximately a 65% reduction from AEP’s 2005 Scope 1 GHG emissions (inclusive of state plans to regulateemission reductions that result from plants that have been sold). AEP has made significant progress in reducing CO2 emissions from existing sources. The final standardits 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 new combustion turbines is 1,000 pounds of CO2 per MWh and the final standard for new fossil steam units is 1,400 pounds of CO2 per MWh. Reconstructed turbines are subjectcustomers.
Excessive costs to comply with future legislation or regulations have led to the same standard as new unitsannouncement of early plant closures and no standard for modified combustion turbines was issued. Reconstructed fossil steam units are subjectcould force AEP to a standardclose additional coal-fired generation facilities earlier than their estimated useful life. If AEP is unable to recover the costs of 1,800 pounds of CO2 per MWh for larger unitsits investments, it would reduce future net income and 2,000 pounds of CO2 per MWh for smaller units. Modified fossil steam units will be subject to a site specific standard no lower than the standards that would be applied if the units were reconstructed.cash flows and impact financial condition.
The final emissions guidelines for existing sources, known as the Clean Power Plan (CPP), are based on a series of declining emission rates that are implemented beginning in 2022 through 2029. The final emission rate is 771 pounds of CO2 per MWh for existing natural gas combined cycle unitsMercury and 1,305 pounds of CO2 per MWh for existing fossil steam units in 2030 and thereafter. The Federal EPA also developed a set of rate-based and mass-based state goals.Air Toxics Standards (MATS) Rule
The Federal EPA also published proposed “model” rules that can be adopted by the states that would allow sources within “trading ready” state programs to trade, bank or sell allowances or credits issued by the states. These rules would also be the basis for any federal plan issued by the Federal EPA in a state that fails to submit or receive approval for a state plan. In June 2016,April 2023, the Federal EPA issued a separate proposalproposed rule that would revise the MATS for power plants. The proposed rule includes a more stringent standard for emissions of filterable PM for coal-fired electric generating units, as well as a new mercury standard for lignite-fired electric generating units. The proposed rule also requires the Clean Energy Incentive Program (CEIP) that was included ininstallation and operation of continuous emissions monitors for PM. Management is evaluating the model rules.impacts of the rule as proposed. Management will continue to monitor the rulemaking.
Coal Combustion Residual (CCR) Rule
The final rules are being challenged inFederal EPA’s CCR rule regulates the courts. 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 February 2016, the U.S. Supreme Court issued a stay on the final CPP, including all of the deadlines for submission of initial or final state plans. The stay will remain in effect until a final decision is issued by the U.S. Court of Appeals for the District of Columbia Circuit and the U.S. Supreme Court considers any petition for review. In April 2017,2020, the Federal EPA withdrew its previously issued proposalsrevised 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 model trading rulesmost units, and October 15, 2024 for a CEIP.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 and Unit | | Generating
Capacity | | | | Net Book Value (a) | | Projected
Retirement Date | | | | | | |
| | | | | | | | (in MWs) | | | | (in millions) | | | | | | | | |
| AEGCo | | | | | | Rockport Plant | | 1,310 | | | | $ | 304.6 | | | 2028 | | | | | | |
| APCo | | | | | | Amos Plant | | 2,930 | | | | 2,133.4 | | | 2040 | | | | | | |
| APCo | | | | | | Mountaineer Plant | | 1,320 | | | | 976.3 | | | 2040 | | | | | | |
| I&M | | | | | | Rockport Plant | | 1,310 | | | | 585.9 | | (b) | 2028 | | | | | | |
| KPCo | | | | | | Mitchell Plant | | 780 | | | | 571.6 | | | 2040 | | | | | | |
| SWEPCo | | | | | | Flint Creek Plant | | 258 | | | | 262.3 | | | 2038 | | | | | | |
| WPCo | | | | | | Mitchell Plant | | 780 | | | | 652.0 | | | 2040 | | | | | | |
(a)Net book value as of March 31, 2023, before cost of removal including CWIP and inventory.
(b)Amount includes a $141 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 March 2017,January 2022, the Federal EPA proposed to deny several extension requests filed by the other utilities based on allegations that those utilities are not in compliance with the CCR Rule (the January Actions). In November 2022, the Federal EPA finalized one of these denials. The Federal EPA’s allegations of noncompliance rely on new interpretations of the CCR Rule requirements. The January Actions of the Federal EPA have been challenged in the U.S. Court of Appeals for the District of Columbia Circuit as unlawful rulemaking that revises the existing CCR Rule requirements without proper notice of: (a) an Executive Order fromand without opportunity for comment. Management is unable to predict the Presidentoutcome of the United States titled “Promoting Energy Independence and Economic Growth” directingthat litigation.
In July 2022, the Federal EPA to review the CPP and related rules; (b) the Federal EPA’s initiation of a reviewproposed conditional approval of the CPP and (c) a forthcoming rulemaking related topending extension request for the CPP consistentMountaineer Plant. The Federal EPA alleged that the Mountaineer Plant was not fully compliant with the Executive Order, ifCCR Rule. In December 2022, AEP withdrew the Federal EPA determines appropriate. In this same filing,pending extension request for the Federal EPA also presented a motionMountaineer Plant as work to holdconstruct new CCR disposal facilities was completed and the litigation in abeyance until 30 days after the conclusion of review and any resulting rulemaking. The District of Columbia Circuit granted the Federal EPA’s motion in part and has requested periodic status reports. In October 2017, the Federal EPA issued a proposed rule repealing the CPP and withdrawing the legal memoranda issued in connection with the rule.extension was no longer needed. The Federal EPA has re-examined its legal interpretation of the “best system of emission reduction” and found that basednot yet proposed any action on the statutory text, legislative history, use of similar terms elsewhere in the CAA and its own historic implementation of Section 111 that a narrower interpretation of the term limits it to those designs, processes, control technologies and other systems that can be applied directly to or at the source. Since the primary systems relied on in the CPP are not consistent with that interpretation,pending extension requests submitted by AEP. However, statements made by the Federal EPA proposes thatin the rule be withdrawn. Management does not expect a change in AEP’s overall strategy as a resultcontext of the proposed repeal.
Federal and state legislation or regulationsfinal decisions on extension requests issued to date indicate that mandate limits on the emission of CO2 could result in significant increases in capital expenditures and operating costs, which in turn, could lead to increased liquidity needs and higher financing costs. Excessive costs to comply with future legislation or regulations might force AEP to close some coal-fired facilities and could lead to possible impairment of assets.
Coal Combustion Residual Rule
In April 2015,there is a risk that the Federal EPA published a final rulemay conclude that AEP is not eligible for an extension of time to regulatecease use of those CCR impoundments for which extension requests are pending and/or that one or more of AEP’s facilities is not in compliance with the disposal and beneficial re-useCCR 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 coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The final rule has been challenged inone or more facilities until an acceptable compliance alternative can be implemented. Such temporary cessation of operation could materially impact the courts.
The final rule became effective in October 2015. The Federal EPA regulates CCR as a non-hazardous solid wastecost of serving customers of the affected utility. Further actions by its issuance of new minimum federal solid waste management standards. The rule applies to new and existing active CCR landfills and CCR surface impoundments at operating electric utility or independent power production facilities. The rule imposes new and additional construction and operating obligations, including location restrictions, liner criteria, structural integrity requirements for impoundments, operating criteria and additional groundwater monitoring requirements to be implemented on a schedule spanning an approximate four year implementation period.
In December 2016, the U.S. Congress passed legislation authorizing states to submit programs to regulate CCR facilities, and the Federal EPA could require AEP to approve suchremove coal ash from CCR units that have already been closed in accordance with state law programs if they are no less stringent than the minimum federal standards. The Federal EPA may also enforce complianceor could require AEP to incur costs related to CCR units at various active and legacy facilities.
Closure and post-closure costs have been included in ARO in accordance with the minimum standards until a state program is approved or if states fail to adopt their own programs. In September 2017,requirements in the Federal EPA granted industry petitionsEPA’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 reconsidermitigate groundwater impacts. AEP may incur significant additional costs complying with the Federal EPA’s CCR rule and asked that litigation regarding the rule be held in abeyance. The court has ordered oral argument to proceed in November 2017 and that the motion for abeyance be addressed during oral argument.
Because AEP currently uses surface impoundments and landfills to manage CCR materials at generating facilities, significantRule, including costs will be incurred to upgrade or close and replace these existing facilities at some point in thesurface impoundments and landfills used to manage CCR and to conduct any required remedial actions including removal of coal ash. If additional costs are incurred and AEP is unable to obtain cost recovery, it would reduce future as the new rule is implemented. Management recorded a $95 million increase in asset retirement obligations in the second quarter of 2015 primarily due to the publication of the final rule.net income and cash flows and impact financial condition. Management will continue to evaluateparticipate in rulemaking activities and make adjustments based on new federal and state requirements affecting its ash disposal units.
The second option to obtain an extension of the rule’sApril 11, 2021 deadline to cease operation of unlined impoundments allows a generating facility to continue operating its existing impoundments without developing alternative CCR disposal, provided the facility commits to cease combustion of coal by a date certain. Under this option, a generating facility would have until October 17, 2023 to cease coal-fired operations and to close CCR storage ponds 40 acres or less in size, or through October 17, 2028 for facilities with CCR storage ponds greater than 40 acres in size. Pursuant to this option, AEP informed the Federal EPA of its intent to retire the Pirkey Plant and cease using coal at the Welsh Plant. In March 2023, the Pirkey Plant was retired. The table below summarizes the net book value of Welsh Plant, Units 1 and 3 as of March 31, 2023.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Company | | | | | | Plant Name and Unit | | Generating
Capacity | | | | Net Investment (a) | | Accelerated Depreciation Regulatory Asset | | Projected
Retirement Date | | | | | | |
| | | | | | | | (in MWs) | | | | (in millions) | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| SWEPCo | | | | | | Welsh Plant, Units 1 and 3 | | 1,053 | | | | $ | 399.6 | | | $ | 95.5 | | | 2028 | (b)(c) | | | | | | |
(a)Net book value as of March 31, 2023, including CWIP excluding cost of removal and materials and supplies.
(b)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028.
(c)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.
To date, the Federal EPA has not taken any action on these pending extension requests. Under the second option above, AEP may need to recover remaining depreciation and estimated closure costs associated with these 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 these plants in a timely manner, it would reduce future net income and cash flows and impact on operations.financial condition.
Clean Water Act (CWA) Regulations
In 2014, theThe Federal EPA issued a finalEPA’s ELG rule setting forth standards for existing power plants that is intended to reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water. Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress. The final rule affects all plants withdrawing more than two million gallons of cooling water per day. The rule offers seven technology options to comply with the impingement standard and requires site-specific studies to determine appropriate entrainment compliance measures atgenerating facilities withdrawing more than
125 million gallons per day. Additional requirements may be imposed as a result of consultation with other federal agencies to protect threatened and endangered species and their habitats. Facilities with existing closed cycle recirculating cooling systems, as defined in the rule, are not expected to require any technology changes. Facilities subject to both the impingement standard and site-specific entrainment studies will typically be given at least three years to conduct and submit the results of those studies to the permit agency. Compliance timeframes will then be established by the permit agency through each facility’s National Pollutant Discharge Elimination System (NPDES) permit for installation of any required technology changes, as those permits are renewed over the next five to eight years. Petitions for review of the final rule were filed by industry and environmental groups and are currently pending in the U.S. Court of Appeals for the Second Circuit.
In addition, the Federal EPA developed revised effluent limitation guidelines for electricity generating facilities. A final rule was issued in November 2015. The final rule establishes limits onfor FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater, as soon as possible after November 2018 and no later than December 2023. These new requirements willwhich are to be implemented through each facility’s wastewater discharge permit. TheA revision to the ELG rule, has been challengedpublished in the U.S. CourtOctober 2020, established additional options for reusing and discharging small volumes of Appeals for the Fifth Circuit. In March 2017, industry associations filed a petition for reconsideration of the rule with the Federal EPA. In April 2017, the Federal EPA granted reconsideration of the rule and issued a stay of the rule’s future compliance deadlines, which has now expired. In April 2017, the U.S. Court of Appeals for the Fifth Circuit granted a stay of the litigation for 120 days. In June 2017, the Federal EPA also issued a proposal to temporarily postpone certain compliance deadlines in the rule. A final rule revising the compliance deadlines for FGD wastewater and bottom ash transport water, provided an exception for retiring units and extended the compliance deadline to bea date as soon as possible beginning one year after the rule was published but no earlierlater than 2020 was issued in September 2017.December 2025. Management submitted comments supporting the proposed postponement. Management continues to assesshas assessed technology additions and retrofits to comply with the rule and the impacts of the Federal EPA’s recent actions on facilities’ wastewater discharge permitting.
permitting for FGD wastewater and bottom ash transport water. For affected facilities that must install additional technologies to meet the ELG rule limits, permit modifications were filed in January 2021 that reflect the outcome of that assessment. AEP continues to work with state agencies to finalize permit terms and conditions. Other facilities opted to file Notices of Planned Participation (NOPP), pursuant to which the facilities are not required to install additional controls to meet ELG limits provided they make commitments to cease coal combustion by a date certain. In June 2015,March 2023, the Federal EPA proposed further revisions to the ELG rule which, if finalized, would establish a zero discharge standard for FGD wastewater and bottom ash transport water, and more stringent discharge limits for combustion residual leachate. Management is evaluating the U.S. Army Corpsimpacts of Engineers jointly issued a finalthe proposed rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases. The CWA provides for federal jurisdiction over “navigable waters” defined as “the waters of the United States.” This jurisdictional definition applies to all CWA programs, potentially impacting generation, transmission and distribution permitting and compliance requirements. Among those programs are permits for wastewater and storm water discharges, permits for impacts to wetlands and water bodies and oil spill prevention planning. The final definition continues to recognize traditional navigable waters of the U.S. as jurisdictional as well as certain exclusions. The rule also contains a number of new specific definitions and criteria for determiningoperations. Management cannot predict whether certain other waters are jurisdictional because of a “significant nexus.” Management believes that clarity and efficiency in the permitting process is needed. Management remains concerned that the rule introduces new concepts and could subject more of AEP’s operations to CWA jurisdiction, thereby increasing the time and complexity of permitting. The final rule is being challenged in both courts of appeal and district courts. Challengers include industry associations of which AEP is a member. The U.S. Court of Appeals for the Sixth Circuit granted a nationwide stay of the rule pending jurisdictional determinations. In February 2016, the U.S. Court of Appeals for the Sixth Circuit issued a decision holding that it has exclusive jurisdiction to decide the challenges to the “waters of the United States” rule. Industry, state and related associations have filed petitions for a rehearing of the jurisdictional decision. In April 2016, the U.S. Court of Appeals for the Sixth Circuit denied the petitions. In January 2017, the decision was appealed to the U.S. Supreme Court, which granted certiorari to review the jurisdictional issue. The U.S. Supreme Court denied the Federal EPA’s motion to hold briefing in abeyance pending further Federal EPA actions on the rule and the appeal on the jurisdictional issue continues.
In March 2017, the Federal EPA published a notice of intentwill actually finalize further revisions, but will continue to review the rulemonitor this issue and provide an advanced notice of a proposedwill participate in further rulemaking consistent with the Executive Order of the President of the United States directingactivities as they arise.
In January 2023, the Federal EPA and U.S. Army Corps of Engineers to review and rescind or revise the rule. In June 2017, the agencies signedfinalized a notice of proposednew rule to rescindrevising the definition of “waters of the United States” that was adoptedStates,” which became effective in June 2015, and to re-codifyMarch 2023. The new rule expands the scope of the definition, which means that permits may be necessary where none were previously required and issued permits may need to be reopened to impose additional obligations. A number of legal challenges in courts across the country have resulted in the rule being stayed in more than half of the states. Management is evaluating what impacts the revised rule will have on operations.
In October 2022, the United States Supreme Court heard an appeal related to the scope of “waters of the United States,” specifically which wetlands can be regulated as waters of the United States. Management cannot predict the outcome of that phraselitigation.
Impact of Environmental Regulation on Coal-Fired Generation
Compliance with extensive environmental regulations requires significant capital investment in environmental monitoring, installation of pollution control equipment, emission fees, disposal, remediation and permits. Management continuously evaluates cost estimates of complying with these regulations which may result in a decision to retire coal-fired generating facilities earlier than their currently estimated useful lives.
The table below summarizes the net book value, as of March 31, 2023, 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 | | | | | | $ | 128.5 | | | $ | 150.3 | | | | | | | 2026 | | | (c) | | $ | 14.9 | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| SWEPCo | | Pirkey Plant | | | | | | — | | | 111.8 | | (d) | | | | | 2023 | | | (e) | | — | | | |
| SWEPCo | | Welsh Plant, Units 1 and 3 | | | | | | 399.6 | | | 95.5 | | | | | | | 2028 | (f) | | (g) | | 38.3 | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
(a)Net book value including CWIP excluding cost of removal and materials and supplies.
(b)These amounts represent the amount of annual depreciation that has been collected from customers over the prior 12-month period.
(c)Northeastern Plant, Unit 3 is currently being recovered through 2040.
(d)Represents Arkansas and Texas jurisdictional share.
(e)As part of the 2021 Arkansas Base Rate Case, the APSC granted SWEPCo regulatory asset treatment. SWEPCo will request recovery including a weighted average cost of capital carrying charge through a future proceeding. The Texas share of the Pirkey Plant will be addressed in SWEPCo’s next base rate case.
(f)In November 2020, management announced it existed immediately prior to that action. This action would effectively retainwill cease using coal at the status quo until a new ruleWelsh Plant in 2028.
(g)Welsh Plant, Unit 1 is adopted bybeing recovered through 2027 in the agencies.Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Welsh Plant, Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.
Management is seeking or will seek regulatory recovery, as necessary, for any net book value remaining when the plants are retired. To the extent the net book value of these generation assets is not deemed recoverable, it could materially reduce future net income, cash flows and impact financial condition.
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 OPCoAEP Texas and AEP Texas.OPCo.
•OPCo purchases energy and capacity at auction to serve SSOstandard service offer customers and provides transmission and distribution services for all connected load.
With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other.
AEP Transmission Holdco
•Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved returns on equity.ROEs.
•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.ROEs.
Generation & Marketing
Competitive generation in ERCOT•Contracted renewable energy investments and PJM.management services.
•Marketing, risk management and retail activities in ERCOT, MISO, PJM SPP and MISO.SPP.
Contracted renewable energy investments and management services.•Competitive generation in PJM.
The remainder of AEP’s activities isare presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
The following discussion of AEP’s results of operations by operating segment includes an analysis of Gross Margin, which is a non-GAAP financial measure. Gross Margin includes Total Revenues less the costs of Fuel and Other Consumables Used for Electric Generation, as well as Purchased Electricity for Resale, Generation Deferrals and Amortization of Generation Deferrals as presented in the RegistrantsRegistrants’ statements of income as applicable. Under the various state utility rate making processes, these expenses are generally reimbursable directly from and billed to customers. As a result, they do not typically impact Operating Income or Earnings Attributable to AEP Common Shareholders. Management believes that Gross Margin provides a useful measure for investors and other financial statement users to analyze AEP’s financial performance in that it excludes the effect on Total Revenues caused by volatility in these expenses. Operating income,Income, which is presented in accordance with GAAP in AEP’s statements of income, is the most directly comparable GAAP financial measure to the presentation of Gross Margin. AEP’s definition of Gross Margin may not be directly comparable to similarly titled financial measures used by other companies.
The following table presents Earnings (Loss) Attributable to AEP Common Shareholders by segment:
| | | | | | | | | | | | | | | |
| | | Three Months Ended March 31, |
| | | | | | 2023 | | 2022 |
| | | | | | (in millions) |
| Vertically Integrated Utilities | | | | | $ | 261.0 | | | $ | 298.2 | |
| Transmission and Distribution Utilities | | | | | 125.7 | | | 152.8 | |
| AEP Transmission Holdco | | | | | 181.5 | | | 173.1 | |
| Generation & Marketing | | | | | (157.7) | | | 114.2 | |
| Corporate and Other | | | | | (13.5) | | | (23.6) | |
| Earnings Attributable to AEP Common Shareholders | | | | | $ | 397.0 | | | $ | 714.7 | |
|
| | | | | | | | | | | | | | | |
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) |
| Vertically Integrated Utilities | $ | 286.3 |
| | $ | 342.3 |
| | $ | 626.6 |
| | $ | 829.3 |
|
| Transmission and Distribution Utilities | 144.0 |
| | 155.7 |
| | 374.3 |
| | 387.8 |
|
| AEP Transmission Holdco | 75.5 |
| | 69.0 |
| | 275.7 |
| | 207.5 |
|
| Generation & Marketing | 33.7 |
| | (1,369.2 | ) | | 246.3 |
| | (1,248.8 | ) |
| Corporate and Other | 5.2 |
| | 36.4 |
| | (11.0 | ) | | 61.7 |
|
| Earnings (Loss) Attributable to AEP Common Shareholders | $ | 544.7 |
| | $ | (765.8 | ) | | $ | 1,511.9 |
| | $ | 237.5 |
|
AEP CONSOLIDATED
ThirdFirst Quarter of 20172023 Compared to ThirdFirst Quarter of 20162022
Earnings (Loss) Attributable to AEP Common Shareholders increased from a loss of $766 million in 2016 to income of $545 million in 2017 primarily due to:
An increase due to the impairment of certain merchant generation assets in 2016.
An increase in transmission investment primarily at AEP Transmission Holdco which resulted in higher revenues and income.
These increases were partially offset by:
A decrease in generation revenues associated with the sale of certain merchant generation assets.
A decrease in weather-related usage.
The prior year reversal of income tax expense for an unrealized capital loss valuation allowance. AEP effectively settled a 2011 audit issue with the IRS resulting in a change in the valuation allowance.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
Earnings Attributable to AEP Common Shareholders increaseddecreased from income of $238$715 million in 20162022 to income of $1.5 billion$397 million in 20172023 primarily due to:
An increase due to the impairment of certain merchant generation assets in 2016.
An increase due to the current year gain•A loss on the expected sale of certain merchant generation assets.the competitive contracted renewable portfolio.
•An increase in transmission investment primarily at AEP Transmission Holdco which resultedinterest expense due to higher interest rates and debt balances.
•A decrease in higher revenues and income.weather-related sales volumes.
•Unfavorable mark-to-market economic hedge activity driven by a decrease in commodity prices.
These decreases were partially offset by:
•Favorable rate proceedings in AEP’s various jurisdictions.
•Increased weather-normalized sales volumes.
These increases were partially offset by:
A decrease in generation revenues associated with the sale of certain merchant generation assets.
A decrease in weather-related usage.
A decrease in weather-normalized sales.
A decrease in FERC wholesale municipal and cooperative revenues.
The prior year reversal of income tax expense for an unrealized capital loss valuation allowance. AEP effectively settled a 2011 audit issue with the IRS resulting in a change in the valuation allowance.
AEP’s results of operations by operating segment are discussed below.
VERTICALLY INTEGRATED UTILITIES
| | | | | | | | | | | | | | | | | | |
| | | | Three Months Ended March 31, |
| Vertically Integrated Utilities | | | | | | 2023 | | 2022 |
| | | | | | | (in millions) |
| Revenues | | | | | | $ | 2,857.8 | | | $ | 2,687.4 | |
| Fuel and Purchased Electricity | | | | | | 976.2 | | | 866.1 | |
| | | | | | | | |
| Gross Margin | | | | | | 1,881.6 | | | 1,821.3 | |
| Other Operation and Maintenance | | | | | | 832.2 | | | 769.2 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Depreciation and Amortization | | | | | | 473.5 | | | 500.0 | |
| Taxes Other Than Income Taxes | | | | | | 132.4 | | | 125.2 | |
| Operating Income | | | | | | 443.5 | | | 426.9 | |
| | | | | | | | |
| | | | | | | | |
| Other Income | | | | | | 7.2 | | | 5.2 | |
| Allowance for Equity Funds Used During Construction | | | | | | 5.8 | | | 8.1 | |
| Non-Service Cost Components of Net Periodic Benefit Cost | | | | | | 31.8 | | | 27.6 | |
| Interest Expense | | | | | | (172.9) | | | (151.0) | |
| Income Before Income Tax Expense and Equity Earnings | | | | | | 315.4 | | | 316.8 | |
| Income Tax Expense | | | | | | 53.5 | | | 17.9 | |
| Equity Earnings of Unconsolidated Subsidiary | | | | | | 0.3 | | | 0.3 | |
| Net Income | | | | | | 262.2 | | | 299.2 | |
| Net Income Attributable to Noncontrolling Interests | | | | | | 1.2 | | | 1.0 | |
| Earnings Attributable to AEP Common Shareholders | | | | | | $ | 261.0 | | | $ | 298.2 | |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| Vertically Integrated Utilities | | 2017 | | 2016 | | 2017 | | 2016 |
| | | (in millions) |
| Revenues | | $ | 2,482.2 |
| | $ | 2,556.3 |
| | $ | 6,893.1 |
| | $ | 6,927.8 |
|
| Fuel and Purchased Electricity | | 868.6 |
| | 858.3 |
| | 2,368.9 |
| | 2,299.8 |
|
| Gross Margin | | 1,613.6 |
| | 1,698.0 |
| | 4,524.2 |
| | 4,628.0 |
|
| Other Operation and Maintenance | | 659.1 |
| | 673.0 |
| | 2,024.5 |
| | 1,926.9 |
|
| Asset Impairments and Other Related Charges | | — |
| | 10.5 |
| | — |
| | 10.5 |
|
| Depreciation and Amortization | | 288.8 |
| | 277.7 |
| | 845.1 |
| | 815.5 |
|
| Taxes Other Than Income Taxes | | 105.7 |
| | 99.0 |
| | 306.2 |
| | 295.0 |
|
| Operating Income | | 560.0 |
| | 637.8 |
| | 1,348.4 |
| | 1,580.1 |
|
| Interest and Investment Income | | 1.3 |
| | 0.8 |
| | 5.4 |
| | 2.4 |
|
| Carrying Costs Income | | 2.1 |
| | 0.8 |
| | 11.3 |
| | 8.1 |
|
| Allowance for Equity Funds Used During Construction | | 7.5 |
| | 10.0 |
| | 20.0 |
| | 35.4 |
|
| Interest Expense | | (134.9 | ) | | (136.7 | ) | | (406.5 | ) | | (399.9 | ) |
| Income Before Income Tax Expense and Equity Earnings (Loss) | | 436.0 |
| | 512.7 |
| | 978.6 |
| | 1,226.1 |
|
| Income Tax Expense | | 139.1 |
| | 172.0 |
| | 334.9 |
| | 398.4 |
|
| Equity Earnings (Loss) of Unconsolidated Subsidiaries | | 0.4 |
| | 2.7 |
| | (4.5 | ) | | 4.9 |
|
| Net Income | | 297.3 |
| | 343.4 |
| | 639.2 |
| | 832.6 |
|
| Net Income Attributable to Noncontrolling Interests | | 11.0 |
| | 1.1 |
| | 12.6 |
| | 3.3 |
|
| Earnings Attributable to AEP Common Shareholders | | $ | 286.3 |
| | $ | 342.3 |
| | $ | 626.6 |
| | $ | 829.3 |
|
Summary of KWh Energy Sales for Vertically Integrated Utilities
| | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | | |
| | Three Months Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| | | (in millions of KWhs) |
| Retail: | | | | | | | | |
| Residential | | 8,099 | | | 9,225 | | | | | |
| Commercial | | 5,372 | | | 5,518 | | | | | |
| Industrial | | 8,295 | | | 8,162 | | | | | |
| Miscellaneous | | 521 | | | 544 | | | | | |
| Total Retail | | 22,287 | | | 23,449 | | | | | |
| | | | | | | | |
| Wholesale (a) | | 3,260 | | | 4,474 | | | | | |
| | | | | | | | |
| Total KWhs | | 25,547 | | | 27,923 | | | | | |
(a)Includes Off-system Sales, municipalities and cooperatives, unit power and other wholesale customers.
|
| | | | | | | | | | | |
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions of KWhs) |
| Retail: | |
| | |
| | |
| | |
|
| Residential | 8,488 |
| | 9,575 |
| | 23,226 |
| | 25,373 |
|
| Commercial | 6,701 |
| | 7,137 |
| | 18,386 |
| | 19,207 |
|
| Industrial | 8,839 |
| | 8,655 |
| | 25,792 |
| | 25,576 |
|
| Miscellaneous | 603 |
| | 634 |
| | 1,701 |
| | 1,740 |
|
| Total Retail | 24,631 |
| | 26,001 |
| | 69,105 |
| | 71,896 |
|
| | | | | | | | |
| Wholesale (a) | 6,837 |
| | 6,765 |
| | 19,262 |
| | 17,253 |
|
| | | | | | | | |
| Total KWhs | 31,468 |
| | 32,766 |
| | 88,367 |
| | 89,149 |
|
| |
(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
| | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | | |
| | Three Months Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| | | (in degree days) |
| Eastern Region | | | | | | | | |
Actual – Heating (a) | | 1,131 | | | 1,590 | | | | | |
Normal – Heating (b) | | 1,608 | | | 1,604 | | | | | |
| | | | | | | | |
Actual – Cooling (c) | | 5 | | | 2 | | | | | |
Normal – Cooling (b) | | 4 | | | 4 | | | | | |
| | | | | | | | |
| Western Region | | | | | | | | |
Actual – Heating (a) | | 637 | | | 915 | | | | | |
Normal – Heating (b) | | 881 | | | 871 | | | | | |
| | | | | | | | |
Actual – Cooling (c) | | 58 | | | 20 | | | | | |
Normal – Cooling (b) | | 28 | | | 28 | | | | | |
(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.
|
| | | | | | | | | | | |
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in degree days) |
| Eastern Region | |
| | |
| | |
| | |
|
Actual – Heating (a) | — |
| | — |
| | 1,266 |
| | 1,684 |
|
Normal – Heating (b) | 4 |
| | 5 |
| | 1,757 |
| | 1,775 |
|
| | | | | | | | |
Actual – Cooling (c) | 698 |
| | 954 |
| | 1,034 |
| | 1,306 |
|
Normal – Cooling (b) | 731 |
| | 726 |
| | 1,060 |
| | 1,058 |
|
| | | | | | | | |
| Western Region | |
| | |
| | |
| | |
|
Actual – Heating (a) | — |
| | — |
| | 539 |
| | 685 |
|
Normal – Heating (b) | 1 |
| | 1 |
| | 926 |
| | 927 |
|
| | | | | | | | |
Actual – Cooling (c) | 1,281 |
| | 1,519 |
| | 2,000 |
| | 2,262 |
|
Normal – Cooling (b) | 1,404 |
| | 1,400 |
| | 2,124 |
| | 2,116 |
|
| | | | | | | | |
(a) | Heating degree days are calculated on a 55 degree temperature base.Reconciliation of First Quarter of 2022 to First Quarter of 2023 |
| Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities |
| (in millions) |
| | |
(b)First Quarter of 2022 | Normal Heating/Cooling represents the thirty-year average of degree days. | $ | 298.2 | |
| | |
| Changes in Gross Margin: | | |
| Retail Margins | | 36.5 | |
| Margins from Off-system Sales | | 26.5 | |
| Transmission Revenues | | 4.5 | |
| Other Revenues | | (7.2) | |
| Total Change in Gross Margin | | 60.3 | |
| | |
| Changes in Expenses and Other: | | |
| Other Operation and Maintenance | | (63.0) | |
| | |
(c) | Cooling degree days are calculated on a 65 degree temperature base. | |
| Depreciation and Amortization | | 26.5 | |
| Taxes Other Than Income Taxes | | (7.2) | |
| | |
| | |
| Other Income | | 2.0 | |
| Allowance for Equity Funds Used During Construction | | (2.3) | |
| Non-Service Cost Components of Net Periodic Pension Cost | | 4.2 | |
| Interest Expense | | (21.9) | |
| Total Change in Expenses and Other | | (61.7) | |
| | |
| Income Tax Expense | | (35.6) | |
| | |
| Net Income Attributable to Noncontrolling Interests | | (0.2) | |
| | |
| First Quarter of 2023 | | $ | 261.0 | |
Third Quarter of 2017 Compared to Third Quarter of 2016
|
| | | | |
| Reconciliation of Third Quarter of 2016 to Third Quarter of 2017 |
| Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities |
| (in millions) |
| | | |
| Third Quarter of 2016 | | $ | 342.3 |
|
| | | |
|
| Changes in Gross Margin: | | |
|
| Retail Margins | | (74.1 | ) |
| Off-system Sales | | (0.8 | ) |
| Transmission Revenues | | (7.6 | ) |
| Other Revenues | | (1.9 | ) |
| Total Change in Gross Margin | | (84.4 | ) |
| | | |
|
| Changes in Expenses and Other: | | |
|
| Other Operation and Maintenance | | 13.9 |
|
| Asset Impairments and Other Related Charges | | 10.5 |
|
| Depreciation and Amortization | | (11.1 | ) |
| Taxes Other Than Income Taxes | | (6.7 | ) |
| Interest and Investment Income | | 0.5 |
|
| Carrying Costs Income | | 1.3 |
|
| Allowance for Equity Funds Used During Construction | | (2.5 | ) |
| Interest Expense | | 1.8 |
|
| Total Change in Expenses and Other | | 7.7 |
|
| | | |
|
| Income Tax Expense | | 32.9 |
|
| Equity Earnings (Loss) of Unconsolidated Subsidiary | | (2.3 | ) |
| Net Income Attributable to Noncontrolling Interest | | (9.9 | ) |
| | | |
| Third Quarter of 2017 | | $ | 286.3 |
|
The major components of the decreaseincrease 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 decreased $74 increased $37 million primarily due to the following:
An $80 million decrease in weather-related usage in the eastern and western regions.
The effect of rate proceedings in AEP’s service territories which included:
•A $17 million decrease for PSO primarily due to higher rates implemented in 2016 associated with interim rates.
A $6 million decrease primarily due to a decrease in rates in West Virginia and Virginia.
For the rate decreases described above, $4 million relate to riders/trackers which have corresponding decreases in expense items below.
These decreases were partially offset by:
•The effect of rate proceedings in AEP’s service territories which included:
An $11 million increase from rate proceedings in the Indiana service territory.
An $11 million increase primarily due to rider revenue increases in Louisiana, partially offset in expense items below.
For the rate increases described above, $8 millionrelate to riders/trackers which have corresponding increases in expense items below.
An $11$33 million increase in weather-normalized margins.retail margins primarily in the residential and commercial classes.
•A $4$22 million increase at SWEPCo primarily due to reducedbase rate revenue increases in Arkansas and Louisiana and rider increases in all retail jurisdictions. These increases were partially offset in other expense items below.
•An $18 million increase at I&M due to a base rate revenue increase in Indiana and rider increases.
•A $15 million increase at APCo due to a base rate increase in Virginia implemented in October 2022 following the Virginia Supreme Court remand. This increase was partially offset in Other Operation and Maintenance expense below.
•A $14 million increase in deferred fuel and other variable production costs not recovered through fuel clauses or other trackers.
Transmission Revenues decreased $8 millionat APCo primarily due to the following:
timing of recoverable expenses. This increase was offset in other expense items below.A $6 million decrease primarily due to I&M’s annual formula rate true-up and reduced net PJM Network Integration Transmission Service revenues resulting from increased affiliated transmission-related charges.
A $5 million decrease due to a net favorable accrual for SPP sponsor-funded transmission upgrades in third quarter 2016.
Expenses and Other, Income Tax Expense and Net Income Attributable to Noncontrolling Interest changed between years as follows:
Other Operation and Maintenance expenses decreased $14 million primarily due to the following:
A $15 million decrease in employee-related expenses.
•A $10 million decreaseincrease in PJM and SPP transmission services expense not recovered through riders/trackers.
A $6 million decrease in storm expenses, primarily in the APCo region.
These decreases wererider revenues at PSO. This increase was partially offset by:in other expense items below.
•A $5$9 million increase due to the Wind Catcher Projecta reduction in a provision for PSO and SWEPCo.
A $5 million increase in nuclear expensesrefund at Cook Plant.
A $3 million increase in vegetation management expenses, primarily at PSO and SWEPCo.
Asset Impairments and Other Related Charges decreased $11 million due to the impairment of I&M’s Price River Coal reserves in 2016.
Depreciation and Amortization expenses increased $11 millionprimarily due to the following:
A $15 million increase primarily due to higher depreciable base.
A $6 million increase due to amortization of capitalized software costs.&M.
These increases were partially offset by:
A $9•An $83 million decrease in weather-related usage primarily in the residential class.
•Margins from Off-system Sales increased $27 million primarily due to Rockport Plant, Unit 2 merchant activity and estimated PJM performance incentives for Rockport Plant, Unit 2 merchant operations related to prior year higher estimated depreciation expense associated with interim rates at PSO.winter storm Elliott in December 2022.
Taxes •Other Than Income Taxes increasedRevenues decreased $7 million primarily due to higher property taxes.
the following:Income TaxExpense decreased $33•A $4 million decrease at APCo primarily due to apole attachment revenue. This decrease in pretax book income and income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine.
Net Income Attributable to Noncontrolling Interest increased $10 million primarily due to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine. This increase is offset by a decrease in Income Tax Expense.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
|
| | | | |
| Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017 |
| Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities |
| (in millions) |
| | | |
| Nine Months Ended September 30, 2016 | | $ | 829.3 |
|
| | | |
|
| Changes in Gross Margin: | | |
|
| Retail Margins | | (123.9 | ) |
| Off-system Sales | | 7.4 |
|
| Transmission Revenues | | 11.0 |
|
| Other Revenues | | 1.7 |
|
| Total Change in Gross Margin | | (103.8 | ) |
| | | |
|
| Changes in Expenses and Other: | | |
|
| Other Operation and Maintenance | | (97.6 | ) |
| Asset Impairments and Other Related Charges | | 10.5 |
|
| Depreciation and Amortization | | (29.6 | ) |
| Taxes Other Than Income Taxes | | (11.2 | ) |
| Interest and Investment Income | | 3.0 |
|
| Carrying Costs Income | | 3.2 |
|
| Allowance for Equity Funds Used During Construction | | (15.4 | ) |
| Interest Expense | | (6.6 | ) |
| Total Change in Expenses and Other | | (143.7 | ) |
| | | |
|
| Income Tax Expense | | 63.5 |
|
| Equity Earnings (Loss) of Unconsolidated Subsidiary | | (9.4 | ) |
| Net Income Attributable to Noncontrolling Interest | | (9.3 | ) |
| | | |
| Nine Months Ended September 30, 2017 | | $ | 626.6 |
|
The major components of the decrease 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 decreased $124 million primarily due to the following:
A $164 million decrease in weather-related usage in the eastern and western regions.
A $42 million decrease in FERC generation wholesale municipal and cooperative revenues primarily due to an annual formula rate true-up and adjustments at I&M and SWEPCo.
The effect of rate proceedings in AEP’s service territories which included:
A $14 million decrease primarily due to prior year recognition of deferred billing in West Virginia as approved by the WVPSC.
A $9 million net decrease for PSO primarily due to revenue decreases associated with interim base rates implemented in 2016.
For the rate decreases described above, $1 million relate to riders/trackers which have corresponding decreases in expense items below.
A $5 million decrease in weather-normalized margins.
These decreases were partially offset by:
The effect of rate proceedings in AEP’s service territories which included:
A $42 million increase from rate proceedings in the Indiana service territory.
A $33 million increase due to rider revenue increases in Louisiana, Texas and Arkansas, partially offset in expense items below.
A $6 million increase for KGPCo due to revenue increases from rate riders/trackers.
For the rate increases described above, $37 million relate to riders/trackers which have corresponding increases in expense items below.
A $19 million increase primarily due to reduced fuel and other variable production costs not recovered through fuel clauses or other trackers.
Margins from Off-system Sales increased $7 million primarily due to higher market prices.
Transmission Revenues increased $11 million primarily due the following:
A $35 million increase primarily due to increases in formula rates driven by continued investment in transmission assets. This increase iswas partially offset in Other Operation and Maintenance expenses below.
These increases were•A $4 million decrease at I&M due to the sale of allowances. This decrease was partially offset by:in Retail Margins above.
A $23 million decrease primarily due to I&M’s annual formula rate true-up and reduced net PJM Network Integration Transmission Service revenues resulting from increased affiliated transmission-related charges.
A $5 million net decrease due to a net favorable accrual for SPP sponsor-funded transmission upgrades in third quarter 2016.
Expenses and Other and Income Tax Expense Equity Earnings (Loss) of Unconsolidated Subsidiary and Net Income Attributable to Noncontrolling Interest changed between years as follows:
•Other Operation and Maintenance expenses increased $98$63 million primarily due to the following:
•A $103$32 million increase in recoverablegeneration expenses primarily PJM expensesdue to plant outages and energy efficiency expenses fully recovered in rate recovery riders/trackers within Gross Margin above.maintenance at I&M and APCo.
A $22•An $11 million increase in vegetation managementaccounts receivable factoring expenses primarily at PSO and I&M.due to increased interest rates.
•A $6$10 million increase in distribution expenses.
•A $9 million increase due to a favorable land saledecreased Nuclear Electric Insurance Limited distribution at I&M in 2016 in the APCo region.2023.
These increases were partially offset by:
A $27 million decrease in employee-related expenses.
Asset Impairments and Other Related Charges decreased $11 million primarily due to the impairment of I&M’s Price River Coal reserves in 2016.
•Depreciation and Amortization expenses increased $30decreased $27 millionprimarily due to the following:
•A $46$38 million increasedecrease at AEGCo and I&M primarily due to higher depreciable base.
A $15 millionthe expiration of the Rockport Plant, Unit 2 lease in December 2022, partially offset by an increase in depreciation expense at I&M due to amortizationthe acquisition of capitalized software costs.Rockport Plant, Unit 2 at the end of the lease.
These increases wereThis decrease was partially offset by:
A $24•An $8 million decrease increase at PSO primarily relateddue to prior yeara higher estimated depreciation expense associated with interimdepreciable base, implementation of new rates at PSO.and the timing of refunds to customers under rate rider mechanisms.
•Taxes Other Than Income Taxes increased $11 million primarily due to higher property taxes.
Allowance for Equity Funds Used During Construction decreased $15 millionprimarily due to completed environmental projects.
Interest Expense increased $7 million primarily due to increased property taxes at SWEPCo and PSO driven by the following:
investment in the NCWF.A $7•Interest Expense increased $22 million increase due to lower AFUDC borrowed funds resulting from completed environmental projects.
A $7 million increase primarily due to higher long-term debt balances and higher interest rates primarily at I&M.
These increases wereAPCo and PSO, partially offset by:
A $4by a settlement agreement in Louisiana which provided for $12 million decrease primarily due to the deferral of the debt component of carrying charges on environmental control costsstorm-related regulatory assets at PSO.SWEPCo.
•Income TaxExpense decreased $64 increased $36 million primarily due to a decrease in pretax book income and income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine, partially offset by the recordingamortization of favorable state and federal income tax adjustments in 2016.Excess ADIT.
Equity Earnings (Loss) of Unconsolidated Subsidiary decreased $9 million primarily due to a prior period income tax adjustment for DHLC, a SWEPCo unconsolidated subsidiary.
Net Income Attributable to Noncontrolling Interest increased $9 million primarily due to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine. This increase is offset by a decrease in Income Tax Expense.
TRANSMISSION AND DISTRIBUTION UTILITIES
| | | | | | | | | | | | | | | | | | |
| | | | Three Months Ended March 31, |
| Transmission and Distribution Utilities | | | | | | 2023 | | 2022 |
| | | | | | | (in millions) |
| Revenues | | | | | | $ | 1,464.2 | | | $ | 1,246.8 | |
| Purchased Electricity | | | | | | 392.7 | | | 232.6 | |
| | | | | | | | |
| Gross Margin | | | | | | 1,071.5 | | | 1,014.2 | |
| Other Operation and Maintenance | | | | | | 491.9 | | | 428.5 | |
| | | | | | | | |
| | | | | | | | |
| Depreciation and Amortization | | | | | | 186.2 | | | 183.6 | |
| Taxes Other Than Income Taxes | | | | | | 178.8 | | | 164.4 | |
| Operating Income | | | | | | 214.6 | | | 237.7 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Other Income | | | | | | 0.5 | | | 0.3 | |
| Allowance for Equity Funds Used During Construction | | | | | | 9.1 | | | 7.3 | |
| Non-Service Cost Components of Net Periodic Benefit Cost | | | | | | 14.0 | | | 11.9 | |
| Interest Expense | | | | | | (88.1) | | | (74.8) | |
| Income Before Income Tax Expense | | | | | | 150.1 | | | 182.4 | |
| Income Tax Expense | | | | | | 24.4 | | | 29.6 | |
| | | | | | | | |
| Net Income | | | | | | 125.7 | | | 152.8 | |
| Net Income Attributable to Noncontrolling Interests | | | | | | — | | | — | |
| Earnings Attributable to AEP Common Shareholders | | | | | | $ | 125.7 | | | $ | 152.8 | |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| Transmission and Distribution Utilities | | 2017 | | 2016 | | 2017 | | 2016 |
| | | (in millions) |
| Revenues | | $ | 1,173.3 |
| | $ | 1,275.6 |
| | $ | 3,313.2 |
| | $ | 3,468.5 |
|
| Purchased Electricity | | 215.7 |
| | 253.6 |
| | 626.0 |
| | 662.2 |
|
| Amortization of Generation Deferrals | | 58.7 |
| | 66.1 |
| | 172.9 |
| | 173.0 |
|
| Gross Margin | | 898.9 |
| | 955.9 |
| | 2,514.3 |
| | 2,633.3 |
|
| Other Operation and Maintenance | | 303.2 |
| | 358.2 |
| | 882.5 |
| | 1,009.5 |
|
| Depreciation and Amortization | | 182.3 |
| | 181.4 |
| | 502.4 |
| | 505.0 |
|
| Taxes Other Than Income Taxes | | 133.6 |
| | 132.0 |
| | 387.1 |
| | 373.0 |
|
| Operating Income | | 279.8 |
| | 284.3 |
| | 742.3 |
| | 745.8 |
|
| Interest and Investment Income | | 1.2 |
| | 1.5 |
| | 5.6 |
| | 5.5 |
|
| Carrying Costs Income | | 0.5 |
| | 0.9 |
| | 3.0 |
| | 4.0 |
|
| Allowance for Equity Funds Used During Construction | | 0.9 |
| | 2.2 |
| | 6.3 |
| | 10.6 |
|
| Interest Expense | | (61.0 | ) | | (63.2 | ) | | (182.5 | ) | | (196.0 | ) |
| Income Before Income Tax Expense | | 221.4 |
| | 225.7 |
| | 574.7 |
| | 569.9 |
|
| Income Tax Expense | | 77.4 |
| | 70.0 |
| | 200.4 |
| | 182.1 |
|
| Net Income | | 144.0 |
| | 155.7 |
| | 374.3 |
| | 387.8 |
|
| Net Income Attributable to Noncontrolling Interests | | — |
| | — |
| | — |
| | — |
|
| Earnings Attributable to AEP Common Shareholders | | $ | 144.0 |
| | $ | 155.7 |
| | $ | 374.3 |
| | $ | 387.8 |
|
Summary of KWh Energy Sales for Transmission and Distribution Utilities
| | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | | |
| | Three Months Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| | | (in millions of KWhs) |
| Retail: | | | | | | | | |
| Residential | | 6,266 | | | 6,977 | | | | | |
| Commercial | | 6,744 | | | 5,999 | | | | | |
| Industrial | | 6,526 | | | 5,930 | | | | | |
| Miscellaneous | | 168 | | | 171 | | | | | |
| Total Retail (a) | | 19,704 | | | 19,077 | | | | | |
| | | | | | | | |
| Wholesale (b) | | 453 | | | 571 | | | | | |
| | | | | | | | |
| Total KWhs | | 20,157 | | | 19,648 | | | | | |
(a)Represents energy delivered to distribution customers.
(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold to PJM.
|
| | | | | | | | | | | |
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions of KWhs) |
| Retail: | |
| | |
| | |
| | |
|
| Residential | 7,511 |
| | 8,325 |
| | 19,361 |
| | 20,575 |
|
| Commercial | 6,941 |
| | 7,287 |
| | 19,184 |
| | 19,676 |
|
| Industrial | 5,575 |
| | 5,518 |
| | 16,992 |
| | 16,522 |
|
| Miscellaneous | 185 |
| | 187 |
| | 516 |
| | 528 |
|
| Total Retail (a) | 20,212 |
| | 21,317 |
| | 56,053 |
| | 57,301 |
|
| | | | | | | | |
| Wholesale (b) | 585 |
| | 654 |
| | 1,749 |
| | 1,389 |
|
| | | | | | | | |
| Total KWhs | 20,797 |
| | 21,971 |
| | 57,802 |
| | 58,690 |
|
| |
(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
| | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | | |
| | Three Months Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| | | (in degree days) |
| Eastern Region | | | | | | | | |
Actual – Heating (a) | | 1,344 | | | 1,864 | | | | | |
Normal – Heating (b) | | 1,891 | | | 1,886 | | | | | |
| | | | | | | | |
Actual – Cooling (c) | | — | | | 1 | | | | | |
Normal – Cooling (b) | | 3 | | | 3 | | | | | |
| | | | | | | | |
| Western Region | | | | | | | | |
Actual – Heating (a) | | 141 | | | 278 | | | | | |
Normal – Heating (b) | | 194 | | | 190 | | | | | |
| | | | | | | | |
Actual – Cooling (d) | | 271 | | | 88 | | | | | |
Normal – Cooling (b) | | 127 | | | 126 | | | | | |
(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.
|
| | | | | | | | | | | |
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in degree days) |
| Eastern Region | |
| | |
| | |
| | |
|
Actual – Heating (a) | — |
| | — |
| | 1,500 |
| | 1,929 |
|
Normal – Heating (b) | 6 |
| | 7 |
| | 2,091 |
| | 2,110 |
|
| | | | | | | | |
Actual – Cooling (c) | 642 |
| | 900 |
| | 957 |
| | 1,209 |
|
Normal – Cooling (b) | 670 |
| | 664 |
| | 960 |
| | 956 |
|
| | | | | | | | |
| Western Region | |
| | |
| | |
| | |
|
Actual – Heating (a) | — |
| | — |
| | 103 |
| | 123 |
|
Normal – Heating (b) | — |
| | — |
| | 199 |
| | 198 |
|
| | | | | | | | |
Actual – Cooling (d) | 1,393 |
| | 1,534 |
| | 2,640 |
| | 2,619 |
|
Normal – Cooling (b) | 1,364 |
| | 1,358 |
| | 2,396 |
| | 2,384 |
|
| | | | | | | | |
(a)Reconciliation of First Quarter of 2022 to First Quarter of 2023 |
| Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities |
| (in millions) |
| Heating degree days are calculated on a 55 degree temperature base. | |
| First Quarter of 2022 | | $ | 152.8 | |
| | |
| Changes in Gross Margin: | | |
| Retail Margins | | 22.0 | |
| Margins from Off-system Sales | | 24.1 | |
| Transmission Revenues | | 11.5 | |
| Other Revenues | | (0.3) | |
| Total Change in Gross Margin | | 57.3 | |
| | |
| Changes in Expenses and Other: | | |
| Other Operation and Maintenance | | (63.4) | |
| Depreciation and Amortization | | (2.6) | |
| | |
(b)Taxes Other Than Income Taxes | Normal Heating/Cooling represents the thirty-year average of degree days. | (14.4) | |
| | |
(c) | Eastern Region cooling degree days are calculated on a 65 degree temperature base. |
| |
(d)Other Income | Western Region cooling degree days are calculated on a 70 degree temperature base. | 0.2 | |
| Allowance for Equity Funds Used During Construction | | 1.8 | |
| Non-Service Cost Components of Net Periodic Benefit Cost | | 2.1 | |
| Interest Expense | | (13.3) | |
| Total Change in Expenses and Other | | (89.6) | |
| | |
| Income Tax Expense | | 5.2 | |
| | |
| | |
| First Quarter of 2023 | | $ | 125.7 | |
Third Quarter of 2017 Compared to Third Quarter of 2016
|
| | | | |
| Reconciliation of Third Quarter of 2016 to Third Quarter of 2017 |
| Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities |
| (in millions) |
| | | |
| Third Quarter of 2016 | | $ | 155.7 |
|
| | | |
|
| Changes in Gross Margin: | | |
|
| Retail Margins | | (58.7 | ) |
| Off-system Sales | | (11.6 | ) |
| Transmission Revenues | | 7.6 |
|
| Other Revenues | | 5.7 |
|
| Total Change in Gross Margin | | (57.0 | ) |
| | | |
|
| Changes in Expenses and Other: | | |
|
| Other Operation and Maintenance | | 55.0 |
|
| Depreciation and Amortization | | (0.9 | ) |
| Taxes Other Than Income Taxes | | (1.6 | ) |
| Interest and Investment Income | | (0.3 | ) |
| Carrying Costs Income | | (0.4 | ) |
| Allowance for Equity Funds Used During Construction | | (1.3 | ) |
| Interest Expense | | 2.2 |
|
| Total Change in Expenses and Other | | 52.7 |
|
| | | |
|
| Income Tax Expense | | (7.4 | ) |
| | | |
|
| Third Quarter of 2017 | | $ | 144.0 |
|
The major components of the decreaseincrease in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:
•Retail Margins decreased $59 increased $22 million primarily due to the following:
•A $52$29 million decreaseincrease due to various rider revenues in Ohio. This increase was partially offset in Margins from Off-system Sales and other expense items below.
•An $18 million increase due to interim rate increases driven by increased investment in Texas.
•A $15 million net increase in Ohio Basic Transmission Cost Rider revenues associated with the Universal Service Fund (USF) surcharge rate decrease.and recoverable PJM expenses. This decreaseincrease was partially offset by a corresponding decrease in Other OperatingOperation and Maintenance expenses below.
An $18 million net decrease in recovery of equity carrying charges related to the Ohio Phase-In Recovery Rider (PIRR), net of associated amortizations.These increases were partially offset by:
An $8 million decrease in revenues associated with smart grid riders in Ohio. This decrease was offset in expense items below.
•A $7$25 million decrease in weather-related usage in Texas.Ohio due to a 28% decrease in heating degree days.
•A $5$13 million decrease in state excise taxesweather-normalized revenues in the residential and commercial classes, partially offset by the industrial class.
•Margins from Off-system Sales increased $24 million primarily due to athe following:
•A $34 million increase in deferrals of OVEC costs in Ohio. This increase was offset in Retail Margins above.
This increase was partially offset by:
•A $10 million decrease in metered KWhoff-system sales at OVEC in Ohio.Ohio due to lower market prices and volume. This decrease was offset by a corresponding decrease in Taxes Other Than Income Taxes below.
These decreases were partially offset by:
A $14 million increase in AEP Texas revenues associated with the Distribution Cost Recovery Factor revenue rider.
A $12 million favorable impact in Ohio due to the recovery of losses from a power contract with OVEC. The PUCO approved a PPA rider beginning in January 2017 to recover any net margin related to the deferral of OVEC losses starting in June 2016. This increase was offset by a corresponding decrease in Margins from Off-System Sales below.
Margins from Off-system Sales decreased $12 million due to current year losses from a power contract with OVEC which is deferred in Retail Margins above as a result of the OVEC PPA rider beginning in January 2017.
above.•Transmission Revenues increased $8$12 million primarily due to recovery ofinterim rate increases driven by increased transmission investment in ERCOT.Texas.
Other Revenues increased $6 million primarily due to an increase in Texas securitization revenue, offset in other expense items below.28
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses decreased $55increased $63 million primarily due to the following:
•A $52$29 million decrease in remitted USF surcharge paymentsincrease related to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This decrease was offset by a corresponding decrease in Retail Margins above.
A $5 million decrease in employee-related expenses.
A $3 million decrease in recoverable smart grid expenses in Ohio. This decreaseincrease was offset in Retail Margins above.
These decreases were partially offset by:
•A $6$14 million increase in stormERCOT transmission expenses. This increase was partially offset in Retail Margins and Transmission Revenues above.
•A $9 million increase in distribution-related expenses primarily in the Texas region.Texas.
Depreciation and Amortization•A $5 million increase in transmission expenses increased $1 millionin Ohio primarily due to the following:
An $11 millionan increase primarily due to securitization amortizations related to transition funding, offset in Other Revenues above.
A $2 million increase due to amortization of capitalized software costs.
These increases were partially offset by:
A $5 million decrease in recoverable DIR depreciation expense in Ohio.
A $4 million decrease in amortization expenses for the collection of carrying costs on Ohio deferred capacity charges beginning June 2015.
A $4 million decrease in recoverable smart grid rider depreciation expenses in Ohio.PJM expenses. This decreaseincrease was offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $2$14 million primarily due to the following:
A $7 million increase in property taxes due to additional investmentsas a result of increased distribution and transmission investment in transmissionOhio and distribution assetsTexas and higher tax rates.rates in Ohio.
This increase was partially offset by:
A $5•Interest Expense increased $13 million decrease in state excise taxesprimarily due to a decrease in metered KWh in Ohio.higher long-term debt balances and higher interest rates.
Interest•Income Tax Expense decreased $2$5 million primarily due to a decrease in the Texas securitization transition assets as a result of the final maturity of the first Texas securitization bond. This decrease was offset by a corresponding decrease in Other Revenues above.pretax book income.
Income TaxExpense increased $7 million primarily due to the recording of favorable federal income tax adjustments in 2016 and other book/tax differences which are accounted for on a flow-through basis.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
|
| | | | |
| Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017 |
| Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities |
| (in millions) |
| | | |
| Nine Months Ended September 30, 2016 | | $ | 387.8 |
|
| | | |
|
| Changes in Gross Margin: | | |
|
| Retail Margins | | (123.0 | ) |
| Off-system Sales | | (26.8 | ) |
| Transmission Revenues | | 24.2 |
|
| Other Revenues | | 6.6 |
|
| Total Change in Gross Margin | | (119.0 | ) |
| | | |
|
| Changes in Expenses and Other: | | |
|
| Other Operation and Maintenance | | 127.0 |
|
| Depreciation and Amortization | | 2.6 |
|
| Taxes Other Than Income Taxes | | (14.1 | ) |
| Interest and Investment Income | | 0.1 |
|
| Carrying Costs Income | | (1.0 | ) |
| Allowance for Equity Funds Used During Construction | | (4.3 | ) |
| Interest Expense | | 13.5 |
|
| Total Change in Expenses and Other | | 123.8 |
|
| | | |
|
| Income Tax Expense | | (18.3 | ) |
| | | |
|
| Nine Months Ended September 30, 2017 | | $ | 374.3 |
|
The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:
Retail Margins decreased $123 million primarily due to the following:
A $140 million decrease in Ohio revenues associated with the USF surcharge rate decrease. This decrease was offset by a corresponding decrease in Other Operating and Maintenance expenses below.
A $14 million decrease in weather-normalized margins, primarily in the residential class.
A $21 million decrease due to a prior year reversal of a regulatory provision resulting from a favorable court decision in Ohio.
A $13 million decrease in revenues associated with smart grid riders in Ohio. This decrease was offset in expense items below.
A $9 million net decrease in recovery of equity carrying charges related to the PIRR, net of associated amortizations.
A $7 million decrease in state excise taxes due to a decrease in metered KWh in Ohio. This decrease was offset by a corresponding decrease in Taxes Other Than Income Taxes.
These decreases were partially offset by:
A $46 million favorable impact in Ohio due to the recovery of losses from a power contract with OVEC. The PUCO approved a PPA rider beginning in January 2017 to recover any net margin related to the deferral of OVEC losses starting in June 2016. This increase was offset by a corresponding decrease in Margins from Off-System Sales below.
A $40 million increase in AEP Texas revenues associated with the Distribution Cost Recovery Factor revenue rider.
A $6 million increase in rider revenues associated with the DIR. This increase is partially offset in other expense items below.
Margins from Off-system Sales decreased $27 million primarily due to the following:
A $46 million decrease in Ohio due to current year losses from a power contract with OVEC, which is deferred in Retail Margins above as a result of the OVEC PPA rider beginning in January 2017.
This decrease was partially offset by:
An $18 million increase in Ohio primarily due to the impact of prior year losses from a power contract with OVEC which was not included in the OVEC PPA rider.
Transmission Revenues increased $24 million primarily due to recovery of increased transmission investment in ERCOT.
Other Revenues increased $7 million primarily due to an increase in Texas securitization revenue, offset in other expense items below.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses decreased $127 million primarily due to the following:
A $140 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 by a corresponding decrease in Retail Margins above.
A $10 million decrease in employee-related expenses.
These decreases were partially offset by:
A $12 million increase in PJM expenses related to the annual formula rate true-up that will be recovered in future periods.
A $6 million increase in storm expenses, primarily in the Texas region.
A $5 million increase in vegetation management expenses.
Depreciation and Amortization expenses decreased $3 million primarily due to the following:
An $11 million decrease in amortization expenses for the collection of carrying costs on Ohio deferred capacity charges beginning June 2015.
An $8 million decrease due to recoveries of transmission cost rider carrying costs in Ohio. This decrease was partially offset in Retail Margins above.
A $7 million decrease in recoverable DIR depreciation expense in Ohio.
A $5 million decrease in recoverable smart grid rider depreciation expenses in Ohio. This decrease was offset in Retail Margins above.
These decreases were partially offset by:
A $16 million increase due to securitization amortizations related to transition funding, offset in Other Revenues above.
A $9 million increase in depreciation expense primarily due to an increase in depreciable base of transmission and distribution assets.
A $6 million increase due to amortization of capitalized software costs.
Taxes Other Than Income Taxes increased $14 million primarily due to the following:
A $20 million increase in property taxes due to additional investments in transmission and distribution assets and higher tax rates.
This increase were partially offset by:
A $7 million decrease in state excise taxes due to a decrease in metered KWh in Ohio.
Allowance for Equity Funds Used During Construction decreased $4 millionprimarily due to larger short-term debt balances.
Interest Expense decreased $14 million primarily due to the following:
A $9 million decrease due to the maturity of a senior unsecured note in June 2016 in Ohio.
A $7 million decrease in the Texas securitization transition assets due to the final maturity of the first Texas securitization bond. This decrease was offset by a corresponding decrease in Other Revenues above.
Income TaxExpense increased $18 million primarily due to the recording of favorable state and federal income tax adjustments in 2016 and other book/tax differences which are accounted for on a flow-through basis.
AEP TRANSMISSION HOLDCO
| | | | | | | | | | | | | | | | | | |
| | | | Three Months Ended March 31, |
| AEP Transmission Holdco | | | | | | 2023 | | 2022 |
| | | | | | | (in millions) |
| Transmission Revenues | | | | | | $ | 455.5 | | | $ | 411.4 | |
| Other Operation and Maintenance | | | | | | 36.7 | | | 31.7 | |
| Depreciation and Amortization | | | | | | 97.5 | | | 85.3 | |
| Taxes Other Than Income Taxes | | | | | | 76.8 | | | 67.3 | |
| Operating Income | | | | | | 244.5 | | | 227.1 | |
| Interest and Investment Income | | | | | | 1.9 | | | 0.1 | |
| | | | | | | | |
| | | | | | | | |
| Allowance for Equity Funds Used During Construction | | | | | | 16.4 | | | 15.6 | |
| Non-Service Cost Components of Net Periodic Benefit Cost | | | | | | 1.6 | | | 1.3 | |
| Interest Expense | | | | | | (47.2) | | | (39.1) | |
| Income Before Income Tax Expense and Equity Earnings | | | | | | 217.2 | | | 205.0 | |
| Income Tax Expense | | | | | | 52.3 | | | 50.4 | |
| Equity Earnings of Unconsolidated Subsidiary | | | | | | 17.5 | | | 19.1 | |
| Net Income | | | | | | 182.4 | | | 173.7 | |
| Net Income Attributable to Noncontrolling Interests | | | | | | 0.9 | | | 0.6 | |
| Earnings Attributable to AEP Common Shareholders | | | | | | $ | 181.5 | | | $ | 173.1 | |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| AEP Transmission Holdco | | 2017 | | 2016 | | 2017 | | 2016 |
| | | (in millions) |
| Transmission Revenues | | $ | 178.5 |
| | $ | 132.4 |
| | $ | 581.9 |
| | $ | 382.7 |
|
| Other Operation and Maintenance | | 23.1 |
| | 12.2 |
| | 54.5 |
| | 32.7 |
|
| Depreciation and Amortization | | 26.1 |
| | 17.1 |
| | 74.7 |
| | 48.4 |
|
| Taxes Other Than Income Taxes | | 28.6 |
| | 22.7 |
| | 85.0 |
| | 65.7 |
|
| Operating Income | | 100.7 |
| | 80.4 |
| | 367.7 |
| | 235.9 |
|
| Interest and Investment Income | | 0.1 |
| | — |
| | 0.5 |
| | — |
|
| Carrying Costs Expense | | — |
| | — |
| | (0.1 | ) | | (0.2 | ) |
| Allowance for Equity Funds Used During Construction | | 11.6 |
| | 13.5 |
| | 35.9 |
| | 39.8 |
|
| Interest Expense | | (17.9 | ) | | (12.2 | ) | | (52.3 | ) | | (35.4 | ) |
| Income Before Income Tax Expense and Equity Earnings | | 94.5 |
| | 81.7 |
| | 351.7 |
| | 240.1 |
|
| Income Tax Expense | | 38.6 |
| | 35.2 |
| | 142.1 |
| | 103.2 |
|
| Equity Earnings of Unconsolidated Subsidiaries | | 20.6 |
| | 23.0 |
| | 68.7 |
| | 72.6 |
|
| Net Income | | 76.5 |
| | 69.5 |
| | 278.3 |
| | 209.5 |
|
| Net Income Attributable to Noncontrolling Interests | | 1.0 |
| | 0.5 |
| | 2.6 |
| | 2.0 |
|
| Earnings Attributable to AEP Common Shareholders | | $ | 75.5 |
| | $ | 69.0 |
| | $ | 275.7 |
| | $ | 207.5 |
|
Summary of Investment in Transmission Assets for AEP Transmission Holdco
| | | | | | | | | | | | | | |
| | March 31, |
| | 2023 | | 2022 |
| | (in millions) |
| Plant in Service | | $ | 13,376.3 | | | $ | 12,042.4 | |
| Construction Work in Progress | | 1,959.1 | | | 1,640.4 | |
| Accumulated Depreciation and Amortization | | 1,128.2 | | | 873.3 | |
| Total Transmission Property, Net | | $ | 14,207.2 | | | $ | 12,809.5 | |
|
| | | | | | | | |
| | | September 30, |
| | | 2017 | | 2016 |
| | | (in millions) |
| Plant in Service | | $ | 5,001.4 |
| | $ | 3,330.5 |
|
| CWIP | | 1,392.8 |
| | 1,565.8 |
|
| Accumulated Depreciation | | 156.6 |
| | 88.1 |
|
| Total Transmission Property, Net | | $ | 6,237.6 |
| | $ | 4,808.2 |
|
ThirdFirst Quarter of 20172023 Compared to ThirdFirst Quarter of 20162022
Reconciliation of ThirdFirst Quarter of 20162022 to ThirdFirst Quarter of 20172023
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
| | | | | | | | |
| First Quarter of 2022 | | $ | 173.1 | |
| | |
| Changes in Transmission Revenues: | | |
| Transmission Revenues | | 44.1 | |
| Total Change in Transmission Revenues | | 44.1 | |
| | |
| Changes in Expenses and Other: | | |
| Other Operation and Maintenance | | (5.0) | |
| Depreciation and Amortization | | (12.2) | |
| Taxes Other Than Income Taxes | | (9.5) | |
| Interest and Investment Income | | 1.8 | |
| | |
| Allowance for Equity Funds Used During Construction | | 0.8 | |
| Non-Service Cost Components of Net Periodic Pension Cost | | 0.3 | |
| Interest Expense | | (8.1) | |
| Total Change in Expenses and Other | | (31.9) | |
| | |
| Income Tax Expense | | (1.9) | |
| Equity Earnings of Unconsolidated Subsidiary | | (1.6) | |
| Net Income Attributable to Noncontrolling Interests | | (0.3) | |
| | |
| First Quarter of 2023 | | $ | 181.5 | |
|
| | | | |
| Third Quarter of 2016 | | $ | 69.0 |
|
| | | |
| Changes in Transmission Revenues: | | |
| Transmission Revenues | | 46.1 |
|
| Total Change in Transmission Revenues | | 46.1 |
|
| | | |
| Changes in Expenses and Other: | | |
| Other Operation and Maintenance | | (10.9 | ) |
| Depreciation and Amortization | | (9.0 | ) |
| Taxes Other Than Income Taxes | | (5.9 | ) |
| Interest and Investment Income | | 0.1 |
|
| Allowance for Equity Funds Used During Construction | | (1.9 | ) |
| Interest Expense | | (5.7 | ) |
| Total Change in Expenses and Other | | (33.3 | ) |
| | | |
| Income Tax Expense | | (3.4 | ) |
| Equity Earnings | | (2.4 | ) |
| Net Income Attributable to Noncontrolling Interests | | (0.5 | ) |
| | | |
| Third Quarter of 2017 | | $ | 75.5 |
|
The major componentscomponent of the increase in transmission revenues, which consists of wholesale sales to affiliates and non-affiliates, werenonaffiliates, was as follows:
•Transmission Revenuesincreased $46$44 million primarily due to an increase in formula rates driven by continued investment in transmission assets.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $11 million primarily due to increased transmission investment.
Depreciation and Amortization expenses increased $9$5 million primarily due to higher vegetation management expenses, affiliated rent expense and other miscellaneous expenses.
•Depreciation and Amortization expenses increased $12 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $6$10 million primarily due to increasedhigher property taxes as a result of additionalincreased transmission investment.
•Interest Expenseincreased $6$8 million primarily due to higher outstanding long-term debt balances.
Income Tax Expense increased $3 million primarily due to an increase in pretax book income.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
|
| | | | |
| Nine Months Ended September 30, 2016 | | $ | 207.5 |
|
| | | |
| Changes in Transmission Revenues: | | |
| Transmission Revenues | | 199.2 |
|
| Total Change in Transmission Revenues | | 199.2 |
|
| | | |
| Changes in Expenses and Other: | | |
| Other Operation and Maintenance | | (21.8 | ) |
| Depreciation and Amortization | | (26.3 | ) |
| Taxes Other Than Income Taxes | | (19.3 | ) |
| Interest and Investment Income | | 0.5 |
|
| Carrying Costs Expense | | 0.1 |
|
| Allowance for Equity Funds Used During Construction | | (3.9 | ) |
| Interest Expense | | (16.9 | ) |
| Total Change in Expenses and Other | | (87.6 | ) |
| | | |
| Income Tax Expense | | (38.9 | ) |
| Equity Earnings | | (3.9 | ) |
| Net Income Attributable to Noncontrolling Interests | | (0.6 | ) |
| | | |
| Nine Months Ended September 30, 2017 | | $ | 275.7 |
|
The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and non-affiliates, were as follows:
Transmission Revenues increased $199 million primarily due to the current year favorable impact of the modification of the PJM OATT formula rates combined with an increase driven by continued investment in transmission assets.
Expenses and Other, Income Tax Expense and Equity Earnings changed between years as follows:
Other Operation and Maintenance expenses increased $22 million primarily due to increased transmission investment.
Depreciation and Amortization expenses increased $26 million primarily due to higher depreciable base.
Taxes Other Than Income Taxes increased $19 million primarily due to increased property taxes as a result of additional transmission investment.
Allowance for Equity Funds Used During Construction decreased $4 million primarily due to the FERC transmission complaint and an increase in the amount of short-term debt, offset by an increase in the CWIP balance.
Interest Expense increased $17 million primarily due to higher outstanding long-term debt balances.
Income Tax Expense increased $39 million primarily due to an increase in pretax book income.
Equity Earnings decreased $4 million primarily due to lower earnings at ETT resulting from increased property taxes, depreciation expense, and decreased AFUDC, partially offset by increased revenues. The revenue increase is primarily due to interim rate increases in the third quarter of 2016balances and higher loads, partially offset by an ETT rate reduction that went into effect in March 2017.interest rates.
GENERATION & MARKETING
| | | | | | | | | | | | | | | | | | |
| | | | Three Months Ended March 31, |
| Generation & Marketing | | | | | | 2023 | | 2022 |
| | | | | | | (in millions) |
| Revenues | | | | | | $ | 327.0 | | | $ | 619.3 | |
| Fuel, Purchased Electricity and Other | | | | | | 382.3 | | | 448.1 | |
| | | | | | | | |
| Gross Margin | | | | | | (55.3) | | | 171.2 | |
| Other Operation and Maintenance | | | | | | 43.0 | | | 32.5 | |
| Loss on the Expected Sale of the Competitive Contracted Renewable Portfolio | | | | | | 112.0 | | | — | |
| | | | | | | | |
| Depreciation and Amortization | | | | | | 18.2 | | | 23.3 | |
| Taxes Other Than Income Taxes | | | | | | 2.8 | | | 3.1 | |
| Operating Income (Loss) | | | | | | (231.3) | | | 112.3 | |
| Interest and Investment Income | | | | | | 9.0 | | | 2.1 | |
| | | | | | | | |
| Non-Service Cost Components of Net Periodic Benefit Cost | | | | | | 6.6 | | | 5.1 | |
| Interest Expense | | | | | | (24.3) | | | (5.0) | |
| Income (Loss) Before Income Tax Benefit and Equity Earnings (Loss) | | | | | | (240.0) | | | 114.5 | |
| Income Tax Benefit | | | | | | (78.1) | | | (6.7) | |
| Equity Earnings (Loss) of Unconsolidated Subsidiaries | | | | | | 5.5 | | | (5.2) | |
| Net Income (Loss) | | | | | | (156.4) | | | 116.0 | |
| Net Income Attributable to Noncontrolling Interests | | | | | | 1.3 | | | 1.8 | |
| Earnings (Loss) Attributable to AEP Common Shareholders | | | | | | $ | (157.7) | | | $ | 114.2 | |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| Generation & Marketing | | 2017 | | 2016 | | 2017 | | 2016 |
| | | (in millions) |
| Revenues | | $ | 465.5 |
| | $ | 859.4 |
| | $ | 1,467.5 |
| | $ | 2,291.2 |
|
| Fuel, Purchased Electricity and Other | | 354.6 |
| | 567.4 |
| | 1,062.7 |
| | 1,490.6 |
|
| Gross Margin | | 110.9 |
| | 292.0 |
| | 404.8 |
| | 800.6 |
|
| Other Operation and Maintenance | | 56.5 |
| | 95.8 |
| | 211.4 |
| | 290.2 |
|
| Asset Impairments and Other Related Charges | | (2.5 | ) | | 2,254.4 |
| | 10.6 |
| | 2,254.4 |
|
| Gain on Sale of Merchant Generation Assets | | — |
| | — |
| | (226.4 | ) | | — |
|
| Depreciation and Amortization | | 6.2 |
| | 50.5 |
| | 17.5 |
| | 149.8 |
|
| Taxes Other Than Income Taxes | | 3.2 |
| | 8.7 |
| | 8.9 |
| | 29.0 |
|
| Operating Income (Loss) | | 47.5 |
| | (2,117.4 | ) | | 382.8 |
| | (1,922.8 | ) |
| Interest and Investment Income | | 2.7 |
| | 0.3 |
| | 7.9 |
| | 1.2 |
|
| Interest Expense | | (4.0 | ) | | (9.5 | ) | | (14.7 | ) | | (27.1 | ) |
| Income (Loss) Before Income Tax Expense | | 46.2 |
| | (2,126.6 | ) | | 376.0 |
| | (1,948.7 | ) |
| Income Tax Expense (Credit) | | 12.5 |
| | (757.4 | ) | | 129.7 |
| | (699.9 | ) |
| Net Income (Loss) | | 33.7 |
| | (1,369.2 | ) | | 246.3 |
| | (1,248.8 | ) |
| Net Income Attributable to Noncontrolling Interests | | — |
| | — |
| | — |
| | — |
|
| Earnings (Loss) Attributable to AEP Common Shareholders | | $ | 33.7 |
| | $ | (1,369.2 | ) | | $ | 246.3 |
| | $ | (1,248.8 | ) |
Summary of MWhs Generated for Generation & Marketing
| | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | | |
| | Three Months Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| | | (in millions of MWhs) |
| Fuel Type: | | | | | | | | |
| Coal | | 1 | | | 1 | | | | | |
| Renewables | | 1 | | | 1 | | | | | |
| | | | | | | | |
| Total MWhs | | 2 | | | 2 | | | | | |
|
| | | | | | | | | | | |
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions of MWhs) |
| Fuel Type: | |
| | |
| | |
| | |
|
| Coal | 2 |
| | 8 |
| | 10 |
| | 19 |
|
| Natural Gas | — |
| | 4 |
| | 2 |
| | 11 |
|
| Total MWhs | 2 |
| | 12 |
| | 12 |
| | 30 |
|
ThirdFirst Quarter of 20172023 Compared to ThirdFirst Quarter of 20162022
| | | | | | | | |
| Reconciliation of First Quarter of 2022 to First Quarter of 2023 |
| Earnings Attributable to AEP Common Shareholders from Generation & Marketing |
| (in millions) |
| | |
| First Quarter of 2022 | | $ | 114.2 | |
| | |
| Changes in Gross Margin: | | |
| Merchant Generation | | 0.1 | |
| Renewable Generation | | (1.9) | |
| Retail, Trading and Marketing | | (224.7) | |
| Total Change in Gross Margin | | (226.5) | |
| | |
| Changes in Expenses and Other: | | |
| Other Operation and Maintenance | | (10.5) | |
| Loss on the Expected Sale of the Competitive Contracted Renewable Portfolio | | (112.0) | |
| | |
| Depreciation and Amortization | | 5.1 | |
| Taxes Other Than Income Taxes | | 0.3 | |
| Interest and Investment Income | | 6.9 | |
| | |
| | |
| Non-Service Cost Components of Net Periodic Benefit Cost | | 1.5 | |
| Interest Expense | | (19.3) | |
| Total Change in Expenses and Other | | (128.0) | |
| | |
| Income Tax Benefit | | 71.4 | |
| Equity Earnings (Loss) of Unconsolidated Subsidiaries | | 10.7 | |
| Net Income Attributable to Noncontrolling Interests | | 0.5 | |
| | |
| First Quarter of 2023 | | $ | (157.7) | |
|
| | | | |
| Reconciliation of Third Quarter of 2016 to Third Quarter of 2017 |
| Earnings Attributable to AEP Common Shareholders from Generation & Marketing |
| (in millions) |
| | | |
| Third Quarter of 2016 | | $ | (1,369.2 | ) |
| | | |
|
| Changes in Gross Margin: | | |
|
| Generation | | (175.4 | ) |
| Retail, Trading and Marketing | | (10.1 | ) |
| Other | | 4.4 |
|
| Total Change in Gross Margin | | (181.1 | ) |
| | | |
|
| Changes in Expenses and Other: | | |
|
| Other Operation and Maintenance | | 39.3 |
|
| Asset Impairments and Other Related Charges | | 2,256.9 |
|
| Depreciation and Amortization | | 44.3 |
|
| Taxes Other Than Income Taxes | | 5.5 |
|
| Interest and Investment Income | | 2.4 |
|
| Interest Expense | | 5.5 |
|
| Total Change in Expenses and Other | | 2,353.9 |
|
| | | |
|
| Income Tax Expense | | (769.9 | ) |
| | | |
|
| Third Quarter of 2017 | | $ | 33.7 |
|
The major components of the decrease 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:
Generation •Retail, Trading and Marketing decreased $175$225 million primarily due to a $145 million unrealized loss on economic hedge activity in 2023 and a $126 million unrealized gain on economic hedge activity in 2022 driven by changes in commodity prices.
Expenses and Other, Income Tax Benefit and Equity Earnings (Loss) of Unconsolidated Subsidiaries changed between years as follows:
•Other Operation and Maintenance expenses increased $11 million primarily due to a decrease in land sales.
•Loss on the Expected Sale of the Competitive Contracted Renewable Portfolio increased $112 million due to the pre-tax loss on the expected sale recorded in 2023.
•Depreciation and Amortization decreased $5 million primarily due to the reductionceasing of revenues associated withdepreciation on the sale of certain merchant generation assets.
Retail, Trading and Marketing decreased $10 million due to lower retail margins in 2017 partially offset by favorable wholesale trading and marketing performance in 2017.
Other increased $4 million primarily due tocompetitive contracted renewable projects placed in service.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses decreased $39 million primarily due to decreased plant expensesportfolio assets as a result of theheld for sale of certain merchant generation assets.
classification in 2023.Asset Impairments and Other Related Charges decreased $2.3 billion due to the asset impairment of certain merchant generation assets in 2016.
Depreciation and Amortization expenses decreased $44 million primarily due to the sale and impairment of certain merchant generation assets.
Taxes Other Than Income Taxes decreased $6 million primarily due to the sale of certain merchant generation assets.
Interest Expense decreased $6 million primarily due to reduced debt as a result of the sale of certain merchant generation assets.
Income Tax Expense increased $770 million primarily due to an increase in pretax book income resulting primarily from the impairment of certain merchant generation assets in 2016.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
|
| | | | |
| Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017 |
| Earnings Attributable to AEP Common Shareholders from Generation & Marketing |
| (in millions) |
| | | |
| Nine Months Ended September 30, 2016 | | $ | (1,248.8 | ) |
| | | |
|
| Changes in Gross Margin: | | |
|
| Generation | | (376.2 | ) |
| Retail, Trading and Marketing | | (33.6 | ) |
| Other | | 14.0 |
|
| Total Change in Gross Margin | | (395.8 | ) |
| | | |
|
| Changes in Expenses and Other: | | |
|
| Other Operation and Maintenance | | 78.8 |
|
| Asset Impairments and Other Related Charges | | 2,243.8 |
|
| Gain on Sale of Merchant Generation Assets | | 226.4 |
|
| Depreciation and Amortization | | 132.3 |
|
| Taxes Other Than Income Taxes | | 20.1 |
|
| Interest and Investment Income | | 6.7 |
|
| Interest Expense | | 12.4 |
|
| Total Change in Expenses and Other | | 2,720.5 |
|
| | | |
|
| Income Tax Expense | | (829.6 | ) |
| | | |
|
| Nine Months Ended September 30, 2017 | | $ | 246.3 |
|
The major components of the decrease 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:
Generation decreased $376 million primarily due to the reduction of revenues associated with the sale of certain merchant generation assets.
Retail, Trading and Marketing decreased $34 million primarily due to lower margins in 2017 combined with the impact of favorable wholesale trading and marketing performance in 2016.
Other increased $14 million primarily due to renewable projects placed in service.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses decreased $79 million primarily due to decreased plant expenses as a result of the sale of certain merchant generation assets.
Asset Impairments and Other Related Charges decreased $2.2 billion due to the asset impairment of certain merchant generation assets in 2016.
Gain on Sale of Merchant Generation Assets increased $226 million due to the sale of certain merchant generation assets.
Depreciation and Amortization expenses decreased $132 million primarily due to the sale and impairment of certain merchant generation assets.
Taxes Other Than Income Taxes decreased $20 million primarily due to the sale of certain merchant generation assets.
•Interest and Investment Income increased $7 million primarily due to increased cash invested as a result of the sale of certain merchant generation assets.
higher interest rates on advances to affiliates.•Interest Expense decreased $12increased $19 million due to higher borrowing costs in 2023.
•Income Tax Benefit increased $71 million primarily due to reduced debt as a resultdecrease in pretax book income.
•Equity Earnings (Loss) of the sale of certain merchant generation assets.
Income Tax ExpenseUnconsolidated Subsidiaries increased $830$11 million primarily due to an increase in pretax book income and state income taxes resulting primarilyincreased production from the impairment of certain merchant generation assets in 2016.renewable assets.
CORPORATE AND OTHER
ThirdFirst Quarter of 20172023 Compared to ThirdFirst Quarter of 20162022
Earnings Attributable to AEP Common Shareholders from Corporate and Other decreasedincreased from $36a loss of $24 million in 2016 to $5 million in 2017 primarily due to the prior year reversal of a capital loss valuation allowance related to the pending sale of certain merchant generation assets as well as tax return adjustments related to the prior year disposition of AEP’s commercial barging operations, partially offset by the gain recognized on the sale of a cost-based investment in the third quarter of 2017.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from income of $62 million in 20162022 to a loss of $11$14 million in 20172023 primarily due to:
•A $44 million increase in interest income, primarily due to the prior year reversal of capital loss valuation allowances relatedhigher interest income from affiliates.
•A $36 million decrease in corporate expenses, primarily due to effectively settling a 2011 audit issue with the IRS and the impact of the pending sale of certain merchant generation assets as well as 2015 tax return adjustments related to the disposition of AEP’s commercial barging operations, partially offsetdriven by the gain recognized ontermination of the sale of Kentucky operations.
•A $17 million increase at EIS, primarily due to higher returns on investments and a cost-based investmentdecrease in the third quarter of 2017.reserves.
These items were partially offset by:
•A $91 million increase in interest expense due to higher interest rates, and an increase in short-term and long-term debt outstanding.
AEP SYSTEM INCOME TAXES
ThirdFirst Quarter of 20172023 Compared to ThirdFirst Quarter of 20162022
Income Tax Expense increased $799decreased $42 million primarily due to an increasea decrease in pretax book income, drivenpartially offset by the impairmenta decrease in benefit from PTCs and a decrease in amortization of certain merchant generation assets in the third quarter of 2016. The increase in Income Tax Expense is also due to the third quarter of 2016 reversal of a $66 million capital loss valuation allowance related to the pending sale of certain merchant generation assets as well as prior year tax return adjustments related to the disposition of AEP’s commercial barging operations.Excess ADIT.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
Income Tax Expense increased $932 million primarily due to an increase in pretax book income driven by the impairment of certain merchant generation assets in the third quarter of 2016. The increase in Income Tax Expense is also due to the prior year reversal of a $56 million unrealized capital loss valuation allowance where AEP effectively settled a 2011 audit issue with the IRS, the prior year reversal of a $66 million capital loss valuation allowance related to the pending sale of certain merchant generation assets as well as prior year tax return adjustments related to the disposition of AEP’s commercial barging operations.
FINANCIAL CONDITION
AEP measures financial condition by the strength of its balance sheetsheets and the liquidity provided by its cash flows.
LIQUIDITY AND CAPITAL RESOURCES
Debt and Equity Capitalization
| | | | | | | | | | | | | | | | | | | | | | | |
| | March 31, 2023 | | December 31, 2022 |
| | (dollars in millions) |
| Long-term Debt, including amounts due within one year | $ | 39,144.2 | | | 58.7 | % | | $ | 36,801.0 | | | 56.6 | % |
| Short-term Debt | 3,622.1 | | | 5.4 | | | 4,112.2 | | | 6.3 | |
| Total Debt | 42,766.3 | | | 64.1 | | | 40,913.2 | | | 62.9 | |
| AEP Common Equity | 23,738.2 | | | 35.6 | | | 23,893.4 | | | 36.7 | |
| Noncontrolling Interests | 229.6 | | | 0.3 | | | 229.0 | | | 0.4 | |
| Total Debt and Equity Capitalization | $ | 66,734.1 | | | 100.0 | % | | $ | 65,035.6 | | | 100.0 | % |
|
| | | | | | | | | | | | | |
| | September 30, 2017 | | December 31, 2016 |
| | (dollars in millions) |
| Long-term Debt, including amounts due within one year | $ | 20,721.7 |
| | 51.9 | % | | $ | 20,391.2 |
| (a) | 51.6 | % |
| Short-term Debt | 1,059.3 |
| | 2.7 |
| | 1,713.0 |
| | 4.3 |
|
| Total Debt | 21,781.0 |
| | 54.6 |
| | 22,104.2 |
| (a) | 55.9 |
|
| AEP Common Equity | 18,069.1 |
| | 45.3 |
| | 17,397.0 |
| | 44.0 |
|
| Noncontrolling Interests | 36.4 |
| | 0.1 |
| | 23.1 |
| | 0.1 |
|
| Total Debt and Equity Capitalization | $ | 39,886.5 |
| | 100.0 | % | | $ | 39,524.3 |
| | 100.0 | % |
| |
(a) | Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. |
AEP’s ratio of debt-to-total capital decreasedincreased from 55.9%62.9% as of December 31, 20162022 to 54.6%64.1% as of September 30, 2017March 31, 2023 primarily due to a decreasean increase in short-term debt due to the use of proceeds from the sale of Merchant Generation Assetssupport distribution, transmission and renewable investment growth in addition to pay down debt. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information.working capital needs.
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.liquidity. As of September 30, 2017,March 31, 2023, AEP had a $3$5 billion of revolving credit facility commitmentfacilities to support its operations. In May 2017, the $500 million revolving credit facility due in June 2018 was terminated.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, sale-leaseback or leasing agreements, hybrid securities or common stock. AEP and its utilities finance its operations with commercial paper and other variable rate instruments that are subject to fluctuations in interest rates. To the extent that the Federal Reserve continues to raise short-term interest rates, it could reduce future net income and cash flows and impact financial condition. Market volatility and reduced liquidity in the financial markets could affect AEP’s ability to raise capital on reasonable terms to fund capital needs, including construction costs and refinancing maturing indebtedness. AEP is also monitoring the current bank environment and any impacts thereof. AEP was not materially impacted by these conditions during the three months ended March 31, 2023. AEP continues to address the cash flow implications of increased fuel and purchased power costs, see “Deferred Fuel Costs” section of Executive Overview for additional information. In February 2023, AEP entered into a $500 million term loan. Additionally, in April 2023, AEP made a $125 million capital contribution to AEP Texas and a $125 million capital contribution to OPCo. In May 2023, AEP made an additional $50 million capital contribution to AEP Texas. These contributions were made to address short-term liquidity needs.
Commercial Paper Credit Facilities
Net Available Liquidity
AEP manages liquidity by maintaining adequate external financing commitments. As of September 30, 2017,March 31, 2023, available liquidity was approximately $3$3.4 billion as illustrated in the table below:
| | | | | | | | | | | | | | | | | |
| | Amount | | Maturity | |
| Commercial Paper Backup: | (in millions) | | | |
| Revolving Credit Facility | $ | 4,000.0 | | | March 2027 | |
| Revolving Credit Facility | 1,000.0 | | | March 2025 | (a) |
| | | | | |
| | | | | |
| Cash and Cash Equivalents | 343.5 | | | | |
| Total Liquidity Sources | 5,343.5 | | | | |
| Less: | AEP Commercial Paper Outstanding | 1,981.1 | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Net Available Liquidity | $ | 3,362.4 | | | | |
|
| | | | | | |
| | | Amount | | Maturity |
| | | (in millions) | | |
| Commercial Paper Backup: | |
| | |
| | Revolving Credit Facility | $ | 3,000.0 |
| | June 2021 |
| Total | 3,000.0 |
| | |
| Cash and Cash Equivalents | 343.9 |
| | |
| Total Liquidity Sources | 3,343.9 |
| | |
| Less: | AEP Commercial Paper Outstanding | 295.0 |
| | |
| | | | | |
| Net Available Liquidity | $ | 3,048.9 |
| | |
(a)In March 2023, AEP has a $3extended the maturity date of the $1 billion revolving credit facilityRevolving Credit Facility from March 2024 to support its commercial paper program.
March 2025.
AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program is used to fund bothfunds a Utility Money Pool, which funds theAEP’s utility subsidiaries, andsubsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries. In addition, the program also funds, as direct borrowers,subsidiaries; and the short-term debt requirements of other subsidiaries that are not participantsparticipating in either money pool for regulatory or operational reasons.reasons, as direct borrowers. The maximum amount of commercial paper outstanding during the first ninethree months of 20172023 was $1.6$3.2 billion. The weighted-average interest rate for AEP’s commercial paper during 20172023 was 1.19%5.06%.
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 fivesix uncommitted facilities totaling $445$450 million. In August 2017, AEP executed a $75 million uncommitted letter of credit facility due in August 2018. As of September 30, 2017, theThe Registrants’ maximum future paymentpayments for letters of credit issued under the uncommitted facilities as of March 31, 2023 was $123$299 million with maturities ranging from October 2017April 2023 to September 2018.March 2024.
Securitized Accounts ReceivableReceivables
AEP’sAEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and includes a $125 million and a $625 million facility, both of which expire in September 2024. As of March 31, 2023, the affiliated utility subsidiaries were in compliance with all requirements under the agreement. SWEPCo temporarily eased credit policies from August 2022 through October 2022 to assist customers with higher than normal bills driven by increased fuel costs and, in turn, experienced higher than normal aged receivables. TheIn response, in January 2023, AEP Credit amended its receivables securitization agreement expiresto increase the eligibility criteria related to their aged receivables requirements to ensure SWEPCo remains in June 2019.compliance.
Debt Covenants and Borrowing Limitations
AEP’s credit agreements contain certain covenants and require it to maintain a percentage of debt to totaldebt-to-total capitalization at a level that does not exceed 67.5%. The method for calculating outstanding debt and capitalization is contractually definedcontractually-defined in AEP’s credit agreements. Debt as defined in the revolving credit agreementsagreement excludes securitization bonds and debt of AEP Credit. As of September 30, 2017,March 31, 2023,this contractually-defined percentage was 52.4%61.2%. NonperformanceNon-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 tradednon-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 tradednon-exchange-traded commodity contracts would not cause an event of default under its credit agreements.
The revolving credit facility doesfacilities do not permit the lenders to refuse a draw on theany 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. There were no issuances under the ATM program for the three months ended March 31, 2023. As of March 31, 2023, approximately $511 million of equity is available for issuance under the ATM offering program. See Note 12 - 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 August 2023. The proceeds were used to support AEP’s overall capital expenditure plans. See Note 12 - Financing Activities for additional information.
Dividend Policy and Restrictions
The Board of Directors declared a quarterly dividend of $0.62$0.83 per share in October 2017.April 2023. 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 related to AEP’s various financing arrangements and regulatory requirements 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 12 for additional information.
Credit Ratings
AEP doesand 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 theirits 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.
|
| | | | | | | |
| | Nine Months Ended
September 30, |
| | 2017 | | 2016 |
| | (in millions) |
| Cash and Cash Equivalents at Beginning of Period | $ | 210.5 |
| | $ | 176.4 |
|
| Net Cash Flows from Continuing Operating Activities | 3,124.2 |
| | 3,421.0 |
|
| Net Cash Flows Used for Continuing Investing Activities | (1,676.6 | ) | | (3,428.7 | ) |
| Net Cash Flows from (Used for) Continuing Financing Activities | (1,314.2 | ) | | 46.0 |
|
| Net Cash Flows Used for Discontinued Operations | — |
| | (2.5 | ) |
| Net Increase in Cash and Cash Equivalents | 133.4 |
| | 35.8 |
|
| Cash and Cash Equivalents at End of Period | $ | 343.9 |
| | $ | 212.2 |
|
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.
| | | | | | | | | | | |
| Three Months Ended
March 31, |
| | 2023 | | 2022 |
| | (in millions) |
| Cash, Cash Equivalents and Restricted Cash at Beginning of Period | $ | 556.5 | | | $ | 451.4 | |
| Net Cash Flows from Operating Activities | 717.8 | | | 1,622.2 | |
| Net Cash Flows Used for Investing Activities | (2,245.2) | | | (2,893.2) | |
| Net Cash Flows from Financing Activities | 1,364.4 | | | 1,545.1 | |
| | | |
| Net Increase (Decrease) in Cash and Cash Equivalents | (163.0) | | | 274.1 | |
| Cash, Cash Equivalents and Restricted Cash at End of Period | $ | 393.5 | | | $ | 725.5 | |
Operating Activities
| | | | | | | | | | | |
| Three Months Ended
March 31, |
| 2023 | | 2022 |
| (in millions) |
| Net Income | $ | 400.4 | | | $ | 718.1 | |
| Non-Cash Adjustments to Net Income (a) | 924.2 | | | 743.7 | |
| Mark-to-Market of Risk Management Contracts | (82.0) | | | 282.3 | |
| | | |
| Property Taxes | (101.6) | | | (82.0) | |
| Deferred Fuel Over/Under-Recovery, Net | 128.0 | | | (148.8) | |
| | | |
| | | |
| Change in Other Noncurrent Assets | (96.0) | | | 49.4 | |
| Change in Other Noncurrent Liabilities | (58.7) | | | 36.9 | |
| Change in Certain Components of Working Capital | (396.5) | | | 22.6 | |
| Net Cash Flows from Operating Activities | $ | 717.8 | | | $ | 1,622.2 | |
|
| | | | | | | |
| | Nine Months Ended
September 30, |
| | 2017 | | 2016 |
| | (in millions) |
| Income from Continuing Operations | $ | 1,527.1 |
| | $ | 245.3 |
|
| Depreciation and Amortization | 1,485.9 |
| | 1,550.2 |
|
| Deferred Income Taxes | 740.9 |
| | (47.0 | ) |
| Asset Impairments and Other Related Charges | 10.6 |
| | 2,264.9 |
|
| Gain on Sale of Merchant Generation Assets | (226.4 | ) | | — |
|
| Provision for Refund – Global Settlement, Net | (93.3 | ) | | — |
|
| Accrued Taxes, Net | (310.1 | ) | | (393.0 | ) |
| Other | (10.5 | ) | | (199.4 | ) |
| Net Cash Flows from Continuing Operating Activities | $ | 3,124.2 |
| | $ | 3,421.0 |
|
(a)Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Deferred Income Taxes, Loss on the Expected Sale of the Competitive Contracted Renewable Portfolio and AFUDC.
Net Cash Flows from Continuing Operating Activities were $3.1 billion in 2017 consisting primarily of Income from Continuing Operations of $1.5 billion and $1.5 billion of noncash Depreciation and Amortization. In addition, AEP recorded a gain of $226 decreased by $904 million on the sale of certain merchant generation assets. AEP also recorded asset impairments of $11 million. See Note 6 - Impairment, Disposition and Assets and Liabilities Held for Sale for a complete discussion of this sale and these impairments. Deferred and Accrued Taxes changed primarily due to the income tax impacts associated withfollowing:
•A $419 million decrease in cash from the saleChange in Certain Components of certain merchant generation assets and the receipt of a tax refund related to the U.K. Windfall Tax. AEP refunded $93 million to customers as part of the Ohio Global Settlement reached in 2016. Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.
Net Cash Flows from Continuing Operating Activities were $3.4 billion in 2016 consisting primarily of Income from Continuing Operations of $245 million and $1.6 billion of noncash Depreciation and Amortization. AEP also had asset impairments of $2.3 billion during the third quarter of 2016. See Note 6 - Impairment, Disposition and Assets and Liabilities Held for Sale and Impairments for a complete discussion of asset impairments and other related charges. Accrued Taxes decreasedWorking Capital. The decrease is primarily due to the impactstiming of bonus depreciation relatedaccounts payable, increases in fuel, material and supplies driven by coal inventory on hand as a result of the mild winter weather and a decrease in margin deposits due to unfavorable current year pricing variances and the Protecting Americansreturn of deposits from Tax Hikes ActPJM received in the prior year. These decreases were partially offset by the timing of 2015. Deferredaccounts receivable.
•A $364 million decrease primarily due to a reduction in collateral held associated with risk management contracts driven by the reduction in commodity prices.
•A $241 million decrease in cash from Changes in Other Noncurrent Assets and Liabilities. This decrease is primarily due to changes in regulatory assets and liabilities driven by timing differences between collections from and refunds to customers under rate rider mechanisms.
•A $137 million decrease in cash from Net Income, Taxes decreasedafter non-cash adjustments. See Results of Operations for further detail.
These decreases in cash were partially offset by:
•A $277 million increase in cash primarily due to the tax effecttiming of fuel and purchase power revenues and expenses. See the asset impairment partially offset by an increase in tax versus book temporary differences from operations, which includes provisions related to the Protecting Americans from Tax Hikes Act“Deferred Fuel Costs” section of 2015. Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.Executive Overview for additional information.
Investing Activities
| | | | | | | | | | | |
| Three Months Ended
March 31, |
| | 2023 | | 2022 |
| | (in millions) |
| Construction Expenditures | $ | (2,090.1) | | | $ | (1,686.6) | |
| Acquisitions of Nuclear Fuel | (1.7) | | | (31.1) | |
| Acquisitions of Renewable Energy Facilities | (145.7) | | | (1,207.3) | |
| | | |
| | | |
| Other | (7.7) | | | 31.8 | |
| Net Cash Flows Used for Investing Activities | $ | (2,245.2) | | | $ | (2,893.2) | |
|
| | | | | | | |
| | Nine Months Ended
September 30, |
| | 2017 | | 2016 |
| | (in millions) |
| Construction Expenditures | $ | (3,778.2 | ) | | $ | (3,387.0 | ) |
| Acquisitions of Nuclear Fuel | (73.2 | ) | | (127.6 | ) |
| Proceeds from Sale of Merchant Generation Assets | 2,159.6 |
| | — |
|
| Other | 15.2 |
| | 85.9 |
|
| Net Cash Flows Used for Continuing Investing Activities | $ | (1,676.6 | ) | | $ | (3,428.7 | ) |
Net Cash Flows Used for Continuing Investing Activities were $1.7 billion in 2017 decreased by $648 million primarily due to Construction Expenditures for environmental, distribution and transmission investments,the following:
•A $1.1 billion decrease due to the 2022 acquisition of Traverse, partially offset by the proceeds received from2023 acquisition of the saleRock Falls Wind Facility. See “Acquisitions” section of certain merchant generation assets. See Note 6 - Impairment, Disposition and Assets and Liabilities Held for Sale for a complete discussion of this sale.additional information.
This decrease in cash used was partially offset by:
Net Cash Flows Used for Continuing Investing Activities were $3.4 billion•A $404 million increase in 2016Construction Expenditures, primarily due to Construction Expenditures for environmental, distributionincreases in Vertically Integrated Utilities of $218 million and transmission investments.Transmission and Distribution Utilities of $167 million.
Financing Activities
| | | | | | | | | | | |
| Three Months Ended
March 31, |
| | 2023 | | 2022 |
| | (in millions) |
| Issuance of Common Stock | $ | 41.1 | | | $ | 809.5 | |
| Issuance/Retirement of Debt, Net | 1,837.7 | | | 1,214.9 | |
| | | |
| Dividends Paid on Common Stock | (431.8) | | | (398.8) | |
| Other | (82.6) | | | (80.5) | |
| Net Cash Flows from Financing Activities | $ | 1,364.4 | | | $ | 1,545.1 | |
|
| | | | | | | |
| | Nine Months Ended
September 30, |
| | 2017 | | 2016 |
| | (in millions) |
| Issuance of Common Stock, Net | $ | — |
| | $ | 34.2 |
|
| Issuance/Retirement of Debt, Net | (338.2 | ) | | 930.3 |
|
| Make Whole Premium on Extinguishment of Long-term Debt | (46.1 | ) | | — |
|
| Dividends Paid on Common Stock | (875.0 | ) | | (829.8 | ) |
| Other | (54.9 | ) | | (88.7 | ) |
| Net Cash Flows from (Used for) Continuing Financing Activities | $ | (1,314.2 | ) | | $ | 46.0 |
|
Net Cash Flows Used for Continuing Financing Activities in 2017 were $1.3 billion. AEP’s net debt retirements were $338 million. The net retirements include retirements of $978 million of senior unsecured notes, $356 million of pollution control bonds, $258 million of securitization bonds, $835 million of other debt notes and repayments of $654 million of short term debt offset by issuances of $2.3 billion of senior unsecured notes, $242 million of pollution control bonds and $254 million of other debt notes. AEP also paid $46 million for a make whole premium on the early extinguishment of debt related to the sale of certain merchant generation assets. See Note 6 - Impairment, Disposition and Assets and Liabilities Held for Sale for a complete discussion of this sale. AEP paid common stock dividends of $875 million. See Note 12 - Financing Activities for a complete discussion of long-term debt issuances and retirements.
Net Cash Flows from Continuing Financing Activities in 2016 were $46 million. AEP’s net debt issuances were $930 million. The net issuances included an increase decreased by $181 million primarily due to the following:
•A $1.3 billion decrease due to changes in short-term borrowing of $678 million, issuances of $950 million of senior unsecured notes, $191 million of pollution control bonds and $430 million of other debt notes offset by retirements of $507 million of senior unsecured notes, $289 million of securitization bonds, $251 million of pollution control bonds and $261 million of other debt notes. AEP paid common stock dividends of $830 million.debt. See Note 12 - Financing Activities for a complete discussionadditional information.
•A $768 million decrease in issuances of common stock primarily due to the prior year settlement of the 2019 equity units.
•A $469 million increase in retirements of long-term debt. See Note 12 - Financing Activities for additional information.
These decreases in cash were partially offset by:
•A $2.3 billion increase in issuances of long-term debt. See Note 12 - Financing Activities for additional information.
See the “Long-term Debt Subsequent Events” section of Note 12 for Long-term debt issuances and retirements.other securities issued, retired and principal payments made after March 31, 2023 through May 4, 2023, the date that the first quarter 10-Q was filed.
In October 2017, I&M retired $1 million of Notes Payable related to DCC Fuel.
In October 2017, AEP Texas retired $41 million of 5.625% Pollution Control Bonds due in 2017.
OFF-BALANCE SHEET ARRANGEMENTS
AEP’s current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements that AEP enters in the normal course of business. The following identifies significant off-balance sheet arrangements:
|
| | | | | | | |
| | September 30,
2017 | | December 31,
2016 |
| | (in millions) |
| Rockport Plant, Unit 2 Future Minimum Lease Payments | $ | 812.4 |
| | $ | 886.2 |
|
| Railcars Maximum Potential Loss from Lease Agreement | 16.9 |
| | 18.4 |
|
Management forecasts approximately $6.8 billion of capital expenditures in 2023. For the four year period, 2024 through 2027, management forecasts capital expenditures of $32.9 billion. The expenditures are generally for transmission, generation, distribution, regulated renewables and required environmental investment to comply with the Federal EPA rules. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, supply chain issues, weather, legal reviews, inflation and the ability to access capital. Management expects to fund these capital expenditures through cash flows from operations, proceeds from the sale of competitive contracted renewables 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. For complete information on each of these off-balance sheet arrangements,forecasted capital expenditures, see the “Off-balance Sheet Arrangements”“Budgeted Capital Expenditures” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 20162022 Annual Report.
CONTRACTUAL OBLIGATION INFORMATIONSIGNIFICANT CASH REQUIREMENTS
A summary of contractual obligationssignificant cash requirements is included in the 20162022 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING PRONOUNCEMENTSSTANDARDS
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
See the “Critical Accounting Policies and Estimates” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 20162022 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.standards.
ACCOUNTING PRONOUNCEMENTSSTANDARDS
See Note 2 - New Accounting Pronouncements Adopted During 2017
The FASB issued ASU 2015-11 “Simplifying the Measurement of Inventory” simplifying the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first-out or the retail inventory method. Under theStandards for information related to accounting standards. There are no new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management adopted ASU 2015-11 prospectively, effective January 1, 2017. There was no impact on results of operations, financial position or cash flows at adoption.
The FASB issued ASU 2016-09 “Compensation – Stock Compensation” simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities
and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offsetstandards expected to accumulated excess tax benefits, if any, or on the statements of income. Management adopted ASU 2016-09 effective January 1, 2017. As a result of the adoption of this guidance, management made an accounting policy election to recognize the effect of forfeitures in compensation cost when they occur. There was an immaterial impact on results of operations and financial position and no impact on cash flows at adoption.
Pronouncements Effective in the Future
The FASB issued ASU 2014-09 “Revenue from Contracts with Customers” clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. Management continues to analyze the impact of the new revenue standard and related ASUs.
During 2016 and 2017, revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expecthave a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption.
The evaluation of revenue streams, new contracts and the new revenue standard’s disclosure requirements continues during the fourth quarter of 2017, in particular with respect to various ongoing industry implementation issues. Management will continue to analyze the related impacts to revenue recognition and monitor any new industry implementation issues that arise. Further, given industry conclusions related to implementation issues, including contributions in aid of construction and collectability, management does not anticipate changes to current accounting systems. Management plans to adopt ASU 2014-09 effective January 1, 2018.
The FASB issued ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheets or the accompanying notes to theRegistrants’ financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018.
The FASB issued ASU 2016-02 “Accounting for Leases” increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheets and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine
lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. Management continues to analyze the impact of the new lease standard. During 2016 and 2017, lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Multiple lease system options were also evaluated. Management plans to elect certain of the following practical expedients upon adoption:
|
| | |
Practical Expedient | | Description |
Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) | | Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases. |
Lease and Non-lease Components (elect by class of underlying asset) | | Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component. |
Short-term Lease (elect by class of underlying asset) | | Elect as an accounting policy to not apply the recognition requirements to short-term leases. |
Lease term | | Elect to use hindsight to determine the lease term. |
Evaluation of new lease contracts continues and the process of implementing a compliant lease system solution began in the third quarter of 2017. Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019.
The FASB issued ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020.
The FASB issued ASU 2016-18 “Restricted Cash” clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows. The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report.
The FASB issued ASU 2017-07 “Compensation - Retirement Benefits” requiring that an employer report the service cost component of pension and postretirement benefits in the same line item or items as other compensation costs. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. For 2016, AEP’s actual non-service cost components were a credit of $66 million, of which approximately 37% was capitalized. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Management plans to adopt ASU 2017-07 effective January 1, 2018.
The FASB issued ASU 2017-12 “Derivatives and Hedging” amending the recognition and presentation requirements for hedge accounting activities. The objectives are to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and reduce the complexity of applying hedge accounting. Under the new standard, the concept of recognizing hedge ineffectiveness within the statements of income for cash flow hedges, which has historically been immaterial to AEP, will be eliminated. In addition, certain required tabular disclosures relating to fair value and cash flow hedges will be modified. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted for any interim or annual period after August 2017. Management is analyzing the impact of this new standard, including the possibility of early adoption, and at this time, cannot estimate the impact of adoption on net income.
Future Accounting Changes
The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, management cannot determine the impact on the reporting of operations and financial position that may result from any such future changes. Future pronouncements issued by the FASB could have an impact on future net income and financial position.
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. In addition, this segment is exposed to foreign currency exchange risk from occasionally procuring various services and materials used in its energy business from foreign suppliers. 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 OperationsRegulated 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 Commercial Officer, Executive Vice President of Generation,Utilities, Senior Vice President of Regulated Commercial Operations, 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, Chief Commercial Officer, Senior Vice President of Treasury and Risk, Senior Vice President of Competitive Commercial Operations and Chief Risk Officer in addition to Energy Supply’s President and Vice President.Officer. 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 following table summarizes the reasons for changes in total MTM value as compared to December 31, 2016:2022:
| | | | | | | | | | | | | | | | | | | | | | | |
| MTM Risk Management Contract Net Assets (Liabilities) |
| Three Months Ended March 31, 2023 |
| | | | | | | |
| Vertically
Integrated
Utilities | | Transmission
and
Distribution
Utilities | | Generation
&
Marketing | | Total |
| | (in millions) |
| Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2022 | $ | 134.7 | | | $ | (40.0) | | | $ | 360.5 | | | $ | 455.2 | |
| Gain from Contracts Realized/Settled During the Period and Entered in a Prior Period | (131.5) | | | (0.3) | | | (88.7) | | | (220.5) | |
| Fair Value of New Contracts at Inception When Entered During the Period (a) | — | | | — | | | 0.4 | | | 0.4 | |
| | | | | | | |
| Changes in Fair Value Due to Market Fluctuations During the Period (b) | (5.3) | | | — | | | (101.1) | | | (106.4) | |
| Changes in Fair Value Allocated to Regulated Jurisdictions (c) | 28.8 | | | (7.2) | | | — | | | 21.6 | |
| | | | | | | |
| Total MTM Risk Management Contract Net Assets (Liabilities) as of March 31, 2023 | $ | 26.7 | | | $ | (47.5) | | | $ | 171.1 | | | 150.3 | |
Commodity Cash Flow Hedge Contracts | | | | | | | 83.1 | |
Interest Rate Cash Flow Hedge Contracts | | | | | | | 7.2 | |
| Fair Value Hedge Contracts | | | | | | | (120.5) | |
| Collateral Deposits | | | | | | | (92.7) | |
| | | | | | | |
| Total MTM Derivative Contract Net Assets as of March 31, 2023 | | | | | | | $ | 27.4 | |
|
| | | | | | | | | | | | | | | |
| MTM Risk Management Contract Net Assets (Liabilities) |
| Nine Months Ended September 30, 2017 |
| | | | | | | | |
| | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | Generation & Marketing | | Total |
| | (in millions) |
| Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2016 | $ | 5.2 |
| | $ | (118.2 | ) | | $ | 164.2 |
| | $ | 51.2 |
|
| (Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period | (7.0 | ) | | 3.4 |
| | (32.8 | ) | | (36.4 | ) |
| Fair Value of New Contracts at Inception When Entered During the Period (a) | — |
| | — |
| | 26.7 |
| | 26.7 |
|
| Changes in Fair Value Due to Market Fluctuations During the Period (b) | — |
| | — |
| | 10.5 |
| | 10.5 |
|
| Changes in Fair Value Allocated to Regulated Jurisdictions (c) | 64.9 |
| | (23.2 | ) | | — |
| | 41.7 |
|
| Total MTM Risk Management Contract Net Assets (Liabilities) as of September 30, 2017 | $ | 63.1 |
| | $ | (138.0 | ) | | $ | 168.6 |
| | 93.7 |
|
Commodity Cash Flow Hedge Contracts | | | |
| | |
| | (75.6 | ) |
Interest Rate and Foreign Currency Cash Flow Hedge Contracts | | | |
| | |
| | 4.2 |
|
| Fair Value Hedge Contracts | | | |
| | |
| | (1.4 | ) |
| Collateral Deposits | | | |
| | |
| | 13.5 |
|
| Total MTM Derivative Contract Net Assets as of September 30, 2017 | | | |
| | |
| | $ | 34.4 |
|
(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.
| |
(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. |
(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 on the balance sheet.
See Note 9 – Derivatives and Hedging and Note 10 – 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 Moody’s Investors Service Inc., S&P Global Inc.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 September 30, 2017,March 31, 2023, credit exposure net of collateral to sub investment grade counterparties was approximately 7.9%0.6%, 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 September 30, 2017,March 31, 2023, 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 | | $ | 490.2 | | | $ | 108.3 | | | $ | 381.9 | | | 2 | | | $ | 120.4 | |
| Split Rating | | 10.4 | | | — | | | 10.4 | | | 1 | | | 10.4 | |
| Noninvestment Grade | | 1.3 | | | 1.3 | | | — | | | — | | | — | |
| No External Ratings: | | | | | | | | | | |
| Internal Investment Grade | | 40.7 | | | — | | | 40.7 | | | 3 | | | 25.1 | |
| Internal Noninvestment Grade | | 3.4 | | | 1.0 | | | 2.4 | | | 4 | | | 2.3 | |
| Total as of March 31, 2023 | | $ | 546.0 | | | $ | 110.6 | | | $ | 435.4 | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| 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 | | $ | 619.6 |
| | $ | 2.2 |
| | $ | 617.4 |
| | 3 |
| | $ | 352.2 |
|
| Split Rating | | 5.6 |
| | — |
| | 5.6 |
| | 2 |
| | 5.6 |
|
| Noninvestment Grade | | — |
| | — |
| | — |
| | — |
| | — |
|
| No External Ratings: | | |
| | |
| |
|
| | |
| | |
|
| Internal Investment Grade | | 119.2 |
| | — |
| | 119.2 |
| | 3 |
| | 78.7 |
|
| Internal Noninvestment Grade | | 75.4 |
| | 11.5 |
| | 63.9 |
| | 3 |
| | 40.5 |
|
| Total as of September 30, 2017 | | $ | 819.8 |
| | $ | 13.7 |
| | $ | 806.1 |
| |
|
| |
|
|
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 September 30, 2017,March 31, 2023, 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
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended | | Twelve Months Ended |
| March 31, 2023 | | December 31, 2022 |
| End | | High | | Average | | Low | | End | | High | | Average | | Low |
| (in millions) | | (in millions) |
| $ | 0.2 | | | $ | 0.9 | | | $ | 0.3 | | | $ | 0.1 | | | $ | 0.5 | | | $ | 4.5 | | | $ | 0.7 | | | $ | 0.1 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended | | Twelve Months Ended |
| September 30, 2017 | | December 31, 2016 |
| End | | High | | Average | | Low | | End | | High | | Average | | Low |
| (in millions) | | (in millions) |
| $ | 0.2 |
| | $ | 0.4 |
| | $ | 0.1 |
| | $ | 0.1 |
| | $ | 0.2 |
| | $ | 1.1 |
| | $ | 0.2 |
| | $ | 0.1 |
|
VaR Model
Non-Trading Portfolio
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended | | Twelve Months Ended |
| March 31, 2023 | | December 31, 2022 |
| End | | High | | Average | | Low | | End | | High | | Average | | Low |
| (in millions) | | (in millions) |
| $ | 8.7 | | | $ | 24.4 | | | $ | 14.9 | | | $ | 7.9 | | | $ | 17.7 | | | $ | 76.9 | | | $ | 24.7 | | | $ | 6.7 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended | | Twelve Months Ended |
| September 30, 2017 | | December 31, 2016 |
| End | | High | | Average | | Low | | End | | High | | Average | | Low |
| (in millions) | | (in millions) |
| $ | 0.7 |
| | $ | 6.5 |
| | $ | 0.9 |
| | $ | 0.3 |
| | $ | 5.6 |
| | $ | 8.4 |
| | $ | 1.5 |
| | $ | 0.4 |
|
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
Management utilizes an Earnings at Risk (EaR) modelAEP is exposed to measure interest rate market fluctuations in the normal course of business operations. Prior to 2022, interest rates remained at low levels and the Federal Reserve maintained the federal funds target range at 0.0% to 0.25% for much of 2021. However, during 2022, the Federal Reserve approved several rate increases for a cumulative total of a 4.25% increase. In the first quarter of 2023, the Federal Reserve approved another two rate increases for a cumulative total of a 0.5% rate increase and further increases in interest rates may be authorized during 2023. AEP has outstanding short and long-term debt which is subject to variable rates. AEP manages interest rate risk exposure. EaR statistically quantifiesby limiting variable-rate exposures to a percentage of total debt, by entering into interest rate derivative instruments and by monitoring the extent to whicheffects of market changes in interest rates. For the three months ended March 31, 2023 and 2022, a 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pretax interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense. The resulting EaR is interpreted as the dollar amountannually by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence. The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months. As calculated on debt outstanding as of September 30, 2017 and December 31, 2016, the estimated EaR on AEP’s debt portfolio for the following twelve months was $30$43 million and $29$37 million, respectively.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONSINCOME
For the Three and Nine Months Ended September 30, 2017March 31, 2023 and 20162022
(in millions, except per-share and share amounts)
(Unaudited)
| | | | | | | | | | | | | | | | | | |
| | | | |
| | | | |
| | | | Three Months Ended March 31, |
| | | | | | 2023 | | 2022 |
| REVENUES | | | | | | | | |
| Vertically Integrated Utilities | | | | | | $ | 2,816.3 | | | $ | 2,646.8 | |
| Transmission and Distribution Utilities | | | | | | 1,455.3 | | | 1,242.2 | |
| Generation & Marketing | | | | | | 326.9 | | | 609.5 | |
| Other Revenues | | | | | | 92.4 | | | 94.1 | |
| TOTAL REVENUES | | | | | | 4,690.9 | | | 4,592.6 | |
| | | | | | | | |
| EXPENSES | | | | | | | | |
| Purchased Electricity, Fuel and Other Consumables Used for Electric Generation | | | | | | 1,706.4 | | | 1,500.7 | |
| | | | | | | | |
| Other Operation | | | | | | 680.0 | | | 662.2 | |
| Maintenance | | | | | | 317.3 | | | 285.0 | |
| | | | | | | | |
| Loss on the Expected Sale of the Competitive Contracted Renewable Portfolio | | | | | | 112.0 | | | — | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Depreciation and Amortization | | | | | | 775.5 | | | 792.4 | |
| Taxes Other Than Income Taxes | | | | | | 394.9 | | | 364.2 | |
| TOTAL EXPENSES | | | | | | 3,986.1 | | | 3,604.5 | |
| | | | | | | | |
| OPERATING INCOME | | | | | | 704.8 | | | 988.1 | |
| | | | | | | | |
| Other Income (Expense): | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Other Income | | | | | | 14.7 | | | 2.3 | |
| Allowance for Equity Funds Used During Construction | | | | | | 31.3 | | | 31.0 | |
| Non-Service Cost Components of Net Periodic Benefit Cost | | | | | | 55.5 | | | 47.2 | |
| | | | | | | | |
| Interest Expense | | | | | | (415.7) | | | (313.4) | |
| | | | | | | | |
| INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS | | | | | | 390.6 | | | 755.2 | |
| | | | | | | | |
| Income Tax Expense | | | | | | 10.4 | | | 52.8 | |
| Equity Earnings of Unconsolidated Subsidiaries | | | | | | 20.2 | | | 15.7 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| NET INCOME | | | | | | 400.4 | | | 718.1 | |
| | | | | | | | |
| Net Income Attributable to Noncontrolling Interests | | | | | | 3.4 | | | 3.4 | |
| | | | | | | | |
| EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | | | | | $ | 397.0 | | | $ | 714.7 | |
| | | | | | | | |
| WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING | | | | | | 514,176,648 | | | 506,050,147 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | | | | | $ | 0.77 | | | $ | 1.41 | |
| | | | | | | | |
| WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING | | | | | | 515,598,090 | | | 507,658,522 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | | | | | $ | 0.77 | | | $ | 1.41 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended | | Nine Months Ended |
| | | September 30, | | September 30, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| REVENUES | | | | | | | | |
| Vertically Integrated Utilities | | $ | 2,453.8 |
| | $ | 2,538.3 |
| | $ | 6,819.3 |
| | $ | 6,864.6 |
|
| Transmission and Distribution Utilities | | 1,149.7 |
| | 1,245.4 |
| | 3,242.7 |
| | 3,398.9 |
|
| Generation & Marketing | | 441.5 |
| | 823.3 |
| | 1,386.8 |
| | 2,192.5 |
|
| Other Revenues | | 59.7 |
| | 45.2 |
| | 165.7 |
| | 134.0 |
|
| TOTAL REVENUES | | 4,104.7 |
| | 4,652.2 |
| | 11,614.5 |
| | 12,590.0 |
|
| | | | | | | | | |
| EXPENSES | | |
| | |
| | |
| | |
|
| Fuel and Other Consumables Used for Electric Generation | | 707.4 |
| | 880.1 |
| | 1,865.3 |
| | 2,236.1 |
|
| Purchased Electricity for Resale | | 718.1 |
| | 774.0 |
| | 2,156.9 |
| | 2,134.6 |
|
| Other Operation | | 636.1 |
| | 771.1 |
| | 1,842.5 |
| | 2,150.7 |
|
| Maintenance | | 268.0 |
| | 286.3 |
| | 859.4 |
| | 854.4 |
|
| Asset Impairments and Other Related Charges | | (2.5 | ) | | 2,264.9 |
| | 10.6 |
| | 2,264.9 |
|
| Gain on Sale of Merchant Generation Assets | | — |
| | — |
| | (226.4 | ) | | — |
|
| Depreciation and Amortization | | 518.5 |
| | 539.3 |
| | 1,485.9 |
| | 1,550.2 |
|
| Taxes Other Than Income Taxes | | 272.6 |
| | 264.4 |
| | 792.0 |
| | 767.9 |
|
| TOTAL EXPENSES | | 3,118.2 |
| | 5,780.1 |
| | 8,786.2 |
| | 11,958.8 |
|
| | | | | | | | | |
| OPERATING INCOME (LOSS) | | 986.5 |
| | (1,127.9 | ) | | 2,828.3 |
| | 631.2 |
|
| | | | | | | | | |
| Other Income (Expense): | | |
| | |
| | |
| | |
|
| Interest and Investment Income | | 2.4 |
| | 2.0 |
| | 12.7 |
| | 6.5 |
|
| Carrying Costs Income | | 2.6 |
| | 1.7 |
| | 14.2 |
| | 11.9 |
|
| Allowance for Equity Funds Used During Construction | | 20.0 |
| | 25.6 |
| | 62.2 |
| | 86.1 |
|
| Gain on Sale of Equity Investment | | 12.4 |
| | — |
| | 12.4 |
| | — |
|
| Interest Expense | | (223.3 | ) | | (225.3 | ) | | (668.0 | ) | | (667.2 | ) |
| | | | | | | | | |
| INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS | | 800.6 |
| | (1,323.9 | ) | | 2,261.8 |
| | 68.5 |
|
| | | | | | | | | |
| Income Tax Expense (Credit) | | 264.0 |
| | (534.5 | ) | | 797.8 |
| | (134.0 | ) |
| Equity Earnings of Unconsolidated Subsidiaries | | 20.1 |
| | 25.2 |
| | 63.1 |
| | 42.8 |
|
| | | | | | | | | |
| INCOME (LOSS) FROM CONTINUING OPERATIONS | | 556.7 |
| | (764.2 | ) | | 1,527.1 |
| | 245.3 |
|
| | | | | | | | | |
| LOSS FROM DISCONTINUED OPERATIONS, NET OF TAX | | — |
| | — |
| | — |
| | (2.5 | ) |
| | | | | | | | | |
| NET INCOME (LOSS) | | 556.7 |
| | (764.2 | ) | | 1,527.1 |
| | 242.8 |
|
| | | | | | | | | |
| Net Income Attributable to Noncontrolling Interests | | 12.0 |
| | 1.6 |
| | 15.2 |
| | 5.3 |
|
| | | | | | | | | |
| EARNINGS (LOSS) ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 544.7 |
| | $ | (765.8 | ) | | $ | 1,511.9 |
| | $ | 237.5 |
|
| | | | | | | | | |
| WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING | | 491,840,722 |
| | 491,697,809 |
| | 491,781,643 |
| | 491,422,921 |
|
| | | | | | | | | |
| BASIC EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS | | $ | 1.11 |
| | $ | (1.56 | ) | | $ | 3.07 |
| | $ | 0.49 |
|
| BASIC LOSS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS | | — |
| | — |
| | — |
| | (0.01 | ) |
| TOTAL BASIC EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 1.11 |
| | $ | (1.56 | ) | | $ | 3.07 |
| | $ | 0.48 |
|
| | | | | | | | | |
| WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING | | 492,986,307 |
| | 491,813,858 |
| | 492,428,586 |
| | 491,596,861 |
|
| | | | | | | | | |
| DILUTED EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS | | $ | 1.10 |
| | $ | (1.56 | ) | | $ | 3.07 |
| | $ | 0.49 |
|
| DILUTED LOSS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS | | — |
| | — |
| | — |
| | (0.01 | ) |
| TOTAL DILUTED EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 1.10 |
| | $ | (1.56 | ) | | $ | 3.07 |
| | $ | 0.48 |
|
| | | | | | | | | |
| CASH DIVIDENDS DECLARED PER SHARE | | $ | 0.59 |
| | $ | 0.56 |
| | $ | 1.77 |
| | $ | 1.68 |
|
|
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2017March 31, 2023 and 20162022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | |
| | | | |
| | Three Months Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| Net Income | | $ | 400.4 | | | $ | 718.1 | | | | | |
| | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | | | | | | | | |
| Cash Flow Hedges, Net of Tax of $(40.5) and $65.9 in 2023 and 2022, Respectively | | (152.4) | | | 248.0 | | | | | |
| | | | | | | | |
| Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(4.3) and $(0.6) in 2023 and 2022, Respectively | | (16.1) | | | (2.2) | | | | | |
| Reclassifications of KPCo Pension and OPEB Regulatory Assets, Net of Tax of $4.4 and $0 in 2023 and 2022, Respectively | | 16.7 | | | — | | | | | |
| | | | | | | | |
| TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | | (151.8) | | | 245.8 | | | | | |
| | | | | | | | |
| TOTAL COMPREHENSIVE INCOME | | 248.6 | | | 963.9 | | | | | |
| | | | | | | | |
| Total Comprehensive Income Attributable To Noncontrolling Interests | | 3.4 | | | 3.4 | | | | | |
| | | | | | | | |
| TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 245.2 | | | $ | 960.5 | | | | | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended | | Nine Months Ended |
| | | September 30, | | September 30, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| Net Income (Loss) | | $ | 556.7 |
| | $ | (764.2 | ) | | $ | 1,527.1 |
| | $ | 242.8 |
|
| | | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | | |
| | |
| | |
| | |
|
| Cash Flow Hedges, Net of Tax of $(8.1) and $(15.4) for the Three Months Ended September 30, 2017 and 2016, Respectively, and $(12.2) and $(11.2) for the Nine Months Ended September 30, 2017 and 2016, Respectively | | (15.0 | ) | | (28.6 | ) | | (22.6 | ) | | (20.8 | ) |
| Securities Available for Sale, Net of Tax of $0.5 and $0.3 for the Three Months Ended September 30, 2017 and 2016, Respectively, and $1.5 and $1 for the Nine Months Ended September 30, 2017 and 2016, Respectively | | 0.9 |
| | 0.5 |
| | 2.7 |
| | 1.7 |
|
| Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0.1 and $0.1 for the Three Months Ended September 30, 2017 and 2016, Respectively, and $0.4 and $0.2 for the Nine Months Ended September 30, 2017 and 2016, Respectively | | 0.3 |
| | 0.2 |
| | 0.8 |
| | 0.4 |
|
| | | | | | | | | |
| TOTAL OTHER COMPREHENSIVE LOSS | | (13.8 | ) | | (27.9 | ) | | (19.1 | ) | | (18.7 | ) |
| | | | | | | | | |
| TOTAL COMPREHENSIVE INCOME (LOSS) | | 542.9 |
| | (792.1 | ) | | 1,508.0 |
| | 224.1 |
|
| | | | | | | | | |
| Total Comprehensive Income Attributable to Noncontrolling Interests | | 12.0 |
| | 1.6 |
| | 15.2 |
| | 5.3 |
|
| | | | | | | | | |
| TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 530.9 |
| | $ | (793.7 | ) | | $ | 1,492.8 |
| | $ | 218.8 |
|
|
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the NineThree Months Ended September 30, 2017March 31, 2023 and 20162022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| AEP Common Shareholders | | | | |
| Common Stock | | | | | | Accumulated
Other
Comprehensive
Income (Loss) | | | | |
| Shares | | Amount | | Paid-in
Capital | | Retained
Earnings | | | Noncontrolling
Interests | | Total |
| TOTAL EQUITY – DECEMBER 31, 2021 | 524.4 | | | $ | 3,408.7 | | | $ | 7,172.6 | | | $ | 11,667.1 | | | $ | 184.8 | | | $ | 247.0 | | | $ | 22,680.2 | |
| | | | | | | | | | | | | |
| Issuance of Common Stock | 0.4 | | | 2.4 | | | 807.1 | | | | | | | | | 809.5 | |
| Common Stock Dividends | | | | | | | (395.2) | | (a) | | | (3.6) | | | (398.8) | |
| Other Changes in Equity | | | | | (15.2) | | | (1.5) | | | | | | | (16.7) | |
| Net Income | | | | | | | 714.7 | | | | | 3.4 | | | 718.1 | |
| Other Comprehensive Income | | | | | | | | | 245.8 | | | | | 245.8 | |
| TOTAL EQUITY – MARCH 31, 2022 | 524.8 | | | $ | 3,411.1 | | | $ | 7,964.5 | | | $ | 11,985.1 | | | $ | 430.6 | | | $ | 246.8 | | | $ | 24,038.1 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| TOTAL EQUITY – DECEMBER 31, 2022 | 525.1 | | | $ | 3,413.1 | | | $ | 8,051.0 | | | $ | 12,345.6 | | | $ | 83.7 | | | $ | 229.0 | | | $ | 24,122.4 | |
| | | | | | | | | | | | | |
| Issuance of Common Stock | 0.8 | | | 5.1 | | | 36.0 | | | | | | | | | 41.1 | |
| Common Stock Dividends | | | | | | | (428.8) | | (b) | | | (3.0) | | | (431.8) | |
| Other Changes in Equity | | | | | (12.7) | | | | | | | 0.2 | | | (12.5) | |
| | | | | | | | | | | | | |
| Net Income | | | | | | | 397.0 | | | | | 3.4 | | | 400.4 | |
| Other Comprehensive Loss | | | | | | | | | (151.8) | | | | | (151.8) | |
| TOTAL EQUITY – MARCH 31, 2023 | 525.9 | | | $ | 3,418.2 | | | $ | 8,074.3 | | | $ | 12,313.8 | | | $ | (68.1) | | | $ | 229.6 | | | $ | 23,967.8 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | AEP Common Shareholders | | | | |
| | Common Stock | | | | | | Accumulated Other Comprehensive Income (Loss) | | | | |
| | Shares | | Amount | | Paid-in Capital | | Retained Earnings | | | Noncontrolling Interests | | Total |
| TOTAL EQUITY - DECEMBER 31, 2015 | 511.4 |
| | $ | 3,324.0 |
| | $ | 6,296.5 |
| | $ | 8,398.3 |
| | $ | (127.1 | ) | | $ | 13.2 |
| | $ | 17,904.9 |
|
| | | | | | | | | | | | | | |
| Issuance of Common Stock | 0.6 |
| | 4.3 |
| | 29.9 |
| | |
| | |
| | |
| | 34.2 |
|
| Common Stock Dividends | |
| | |
| | |
| | (826.4 | ) | | |
| | (3.4 | ) | | (829.8 | ) |
| Other Changes in Equity | |
| | |
| | 3.6 |
| | | | |
| | 6.0 |
| | 9.6 |
|
| Net Income | | | | | | | 237.5 |
| | |
| | 5.3 |
| | 242.8 |
|
| Other Comprehensive Loss | |
| | |
| | |
| | |
| | (18.7 | ) | | |
| | (18.7 | ) |
| TOTAL EQUITY - SEPTEMBER 30, 2016 | 512.0 |
| | $ | 3,328.3 |
| | $ | 6,330.0 |
| | $ | 7,809.4 |
| | $ | (145.8 | ) | | $ | 21.1 |
| | $ | 17,343.0 |
|
| | | | | | | | | | | | | | |
| TOTAL EQUITY - DECEMBER 31, 2016 | 512.0 |
| | $ | 3,328.3 |
| | $ | 6,332.6 |
| | $ | 7,892.4 |
| | $ | (156.3 | ) | | $ | 23.1 |
| | $ | 17,420.1 |
|
| | | | | | | | | | | | | | |
| Common Stock Dividends | |
| | |
| | |
| | (872.3 | ) | | |
| | (2.7 | ) | | (875.0 | ) |
| Other Changes in Equity | |
| | |
| | 51.6 |
| | | | |
| | 0.8 |
| | 52.4 |
|
| Net Income | | | | | | | 1,511.9 |
| | |
| | 15.2 |
| | 1,527.1 |
|
| Other Comprehensive Loss | |
| | |
| | |
| | |
| | (19.1 | ) | | |
| | (19.1 | ) |
| TOTAL EQUITY - SEPTEMBER 30, 2017 | 512.0 |
| | $ | 3,328.3 |
| | $ | 6,384.2 |
| | $ | 8,532.0 |
| | $ | (175.4 | ) | | $ | 36.4 |
| | $ | 18,105.5 |
|
(a) Cash dividends declared per AEP common share were $0.78.
(b) Cash dividends declared per AEP common share were $0.83. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118114. |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2017March 31, 2023 and December 31, 20162022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | | March 31, | | December 31, |
| | | 2023 | | 2022 |
| CURRENT ASSETS | | | | |
| Cash and Cash Equivalents | | $ | 343.5 | | | $ | 509.4 | |
Restricted Cash (March 31, 2023 and December 31, 2022 Amounts Include $50 and $47.1, Respectively, Related to Transition Funding, Restoration Funding and Appalachian Consumer Rate Relief Funding) | | 50.0 | | | 47.1 | |
Other Temporary Investments (March 31, 2023 and December 31, 2022 Amounts Include $187.5 and $182.9, Respectively, Related to EIS and Transource Energy) | | 194.6 | | | 187.6 | |
| Accounts Receivable: | | | | |
| Customers | | 949.8 | | | 1,145.1 | |
| Accrued Unbilled Revenues | | 239.7 | | | 322.9 | |
| Pledged Accounts Receivable – AEP Credit | | 1,133.0 | | | 1,207.4 | |
| Miscellaneous | | 39.3 | | | 49.7 | |
| Allowance for Uncollectible Accounts | | (58.0) | | | (57.1) | |
| Total Accounts Receivable | | 2,303.8 | | | 2,668.0 | |
| Fuel | | 554.7 | | | 435.1 | |
| Materials and Supplies | | 902.5 | | | 915.1 | |
| Risk Management Assets | | 190.6 | | | 348.8 | |
| Accrued Tax Benefits | | 141.2 | | | 99.4 | |
| Regulatory Asset for Under-Recovered Fuel Costs | | 1,380.1 | | | 1,310.0 | |
| | | | |
| Assets Held for Sale | | 1,396.3 | | | — | |
| Prepayments and Other Current Assets | | 340.9 | | | 255.0 | |
| TOTAL CURRENT ASSETS | | 7,798.2 | | | 6,775.5 | |
| | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | |
| Electric: | | | | |
| Generation | | 24,034.3 | | | 25,834.2 | |
| Transmission | | 33,570.2 | | | 33,266.9 | |
| Distribution | | 27,521.1 | | | 27,138.8 | |
| Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) | | 6,056.3 | | | 5,971.8 | |
| Construction Work in Progress | | 5,526.2 | | | 4,809.7 | |
| Total Property, Plant and Equipment | | 96,708.1 | | | 97,021.4 | |
| Accumulated Depreciation and Amortization | | 23,361.1 | | | 23,682.3 | |
| TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 73,347.0 | | | 73,339.1 | |
| | | | |
| OTHER NONCURRENT ASSETS | | | | |
| Regulatory Assets | | 4,578.0 | | | 4,762.0 | |
| Securitized Assets | | 420.1 | | | 446.0 | |
| Spent Nuclear Fuel and Decommissioning Trusts | | 3,501.1 | | | 3,341.2 | |
| Goodwill | | 52.5 | | | 52.5 | |
| Long-term Risk Management Assets | | 318.2 | | | 284.1 | |
| Operating Lease Assets | | 631.5 | | | 645.5 | |
| Deferred Charges and Other Noncurrent Assets | | 3,871.3 | | | 3,757.4 | |
| TOTAL OTHER NONCURRENT ASSETS | | 13,372.7 | | | 13,288.7 | |
| | | | |
| TOTAL ASSETS | | $ | 94,517.9 | | | $ | 93,403.3 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
|
| | | | | | | | |
| | | September 30, | | December 31, |
| | | 2017 | | 2016 |
| CURRENT ASSETS | | |
| | |
|
| Cash and Cash Equivalents | | $ | 343.9 |
| | $ | 210.5 |
|
Other Temporary Investments (September 30, 2017 and December 31, 2016 Amounts Include $300.5 and $322.5, Respectively, Related to Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, EIS, Transource Energy and Sabine) | | 310.7 |
| | 331.7 |
|
| Accounts Receivable: | | |
| | |
|
| Customers | | 522.7 |
| | 705.1 |
|
| Accrued Unbilled Revenues | | 187.3 |
| | 158.7 |
|
| Pledged Accounts Receivable – AEP Credit | | 967.6 |
| | 972.7 |
|
| Miscellaneous | | 99.9 |
| | 118.1 |
|
| Allowance for Uncollectible Accounts | | (36.6 | ) | | (37.9 | ) |
| Total Accounts Receivable | | 1,740.9 |
| | 1,916.7 |
|
| Fuel | | 354.2 |
| | 423.8 |
|
| Materials and Supplies | | 562.3 |
| | 543.5 |
|
| Risk Management Assets | | 146.1 |
| | 94.5 |
|
| Regulatory Asset for Under-Recovered Fuel Costs | | 153.5 |
| | 156.6 |
|
| Margin Deposits | | 105.7 |
| | 79.9 |
|
| Assets Held for Sale | | — |
| | 1,951.2 |
|
| Prepayments and Other Current Assets | | 350.5 |
| | 325.5 |
|
| TOTAL CURRENT ASSETS | | 4,067.8 |
| | 6,033.9 |
|
| | | | | |
| PROPERTY, PLANT AND EQUIPMENT | | |
| | |
|
| Electric: | | |
| | |
|
| Generation | | 20,739.3 |
| | 19,848.9 |
|
| Transmission | | 17,785.4 |
| | 16,658.7 |
|
| Distribution | | 19,589.4 |
| | 18,900.8 |
|
| Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) | | 3,614.1 |
| | 3,444.3 |
|
| Construction Work in Progress | | 3,710.0 |
| | 3,183.9 |
|
| Total Property, Plant and Equipment | | 65,438.2 |
| | 62,036.6 |
|
| Accumulated Depreciation and Amortization | | 17,121.7 |
| | 16,397.3 |
|
| TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 48,316.5 |
| | 45,639.3 |
|
| | | | | |
| OTHER NONCURRENT ASSETS | | |
| | |
|
| Regulatory Assets | | 5,640.0 |
| | 5,625.5 |
|
| Securitized Assets | | 1,287.8 |
| | 1,486.1 |
|
| Spent Nuclear Fuel and Decommissioning Trusts | | 2,433.0 |
| | 2,256.2 |
|
| Goodwill | | 52.5 |
| | 52.5 |
|
| Long-term Risk Management Assets | | 310.4 |
| | 289.1 |
|
| Deferred Charges and Other Noncurrent Assets | | 1,856.9 |
| | 2,085.1 |
|
| TOTAL OTHER NONCURRENT ASSETS | | 11,580.6 |
| | 11,794.5 |
|
| | | | | |
| TOTAL ASSETS | | $ | 63,964.9 |
| | $ | 63,467.7 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 2017March 31, 2023 and December 31, 20162022
(dollars in millions)millions, except per-share and share amounts)
(Unaudited) |
| | | | | | | | | | | | | |
| | | | | | | | September 30, | | December 31, |
| | | | | | | | 2017 | | 2016 |
| CURRENT LIABILITIES | | | | |
| Accounts Payable | | | | | | | $ | 1,537.0 |
| | $ | 1,688.5 |
|
| Short-term Debt: | | | | | | | | | |
| Securitized Debt for Receivables – AEP Credit | | | | | | | 750.0 |
| | 673.0 |
|
| Other Short-term Debt | | | | | | | 309.3 |
| | 1,040.0 |
|
| Total Short-term Debt | | | | | | | 1,059.3 |
| | 1,713.0 |
|
Long-term Debt Due Within One Year (September 30, 2017 and December 31, 2016 Amounts Include $393.7 and $427.5, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and Sabine) | | | 2,359.3 |
| | 2,878.0 |
|
| Risk Management Liabilities | | | | | | | 69.4 |
| | 53.4 |
|
| Customer Deposits | | | | | | | 346.6 |
| | 343.2 |
|
| Accrued Taxes | | | | | | | 716.5 |
| | 1,048.0 |
|
| Accrued Interest | | | | | | | 260.3 |
| | 227.2 |
|
| Regulatory Liability for Over-Recovered Fuel Costs | | | | | 19.7 |
| | 8.0 |
|
| Liabilities Held for Sale | | | | | | | — |
| | 235.9 |
|
| Other Current Liabilities | | | | | | | 953.9 |
| | 1,302.8 |
|
| TOTAL CURRENT LIABILITIES | | | | | | | 7,322.0 |
| | 9,498.0 |
|
| | | | | | | | |
| NONCURRENT LIABILITIES | | | | |
Long-term Debt (September 30, 2017 and December 31, 2016 Amounts Include $1421.5 and $1,737.5, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy, and Sabine) | | | 18,362.4 |
| | 17,378.4 |
|
| Long-term Risk Management Liabilities | | | | | | | 352.7 |
| | 316.2 |
|
| Deferred Income Taxes | | | | | | | 12,628.2 |
| | 11,884.4 |
|
| Regulatory Liabilities and Deferred Investment Tax Credits | | | 3,959.6 |
| | 3,751.3 |
|
| Asset Retirement Obligations | | | | | | | 1,919.3 |
| | 1,830.6 |
|
| Employee Benefits and Pension Obligations | | | | | | | 468.9 |
| | 614.1 |
|
| Deferred Credits and Other Noncurrent Liabilities | | | 837.0 |
| | 774.6 |
|
| TOTAL NONCURRENT LIABILITIES | | | | | | | 38,528.1 |
| | 36,549.6 |
|
| | | | | | | | | | |
| TOTAL LIABILITIES | | | | | | | 45,850.1 |
| | 46,047.6 |
|
| | | | | | | | | | |
| Rate Matters (Note 4) | | | | | | |
| |
|
| Commitments and Contingencies (Note 5) | | | | | | |
| |
|
| | | | | | | | | | |
| MEZZANINE EQUITY | | | | |
| Contingently Redeemable Performance Share Awards | | | | | | | 9.3 |
| | — |
|
| | | | | | | | | | |
| EQUITY | | | | |
| Common Stock – Par Value – $6.50 Per Share: | | | | | | | | | |
| | | 2017 | | 2016 | | | | | |
| Shares Authorized | | 600,000,000 | | 600,000,000 | | | | | |
| Shares Issued | | 512,048,663 | | 512,048,520 | | | | | |
| (20,206,368 and 20,336,592 Shares were Held in Treasury as of September 30, 2017 and December 31, 2016, Respectively) | | | 3,328.3 |
| | 3,328.3 |
|
| Paid-in Capital | | | | | | | 6,384.2 |
| | 6,332.6 |
|
| Retained Earnings | | | | | | | 8,532.0 |
| | 7,892.4 |
|
| Accumulated Other Comprehensive Income (Loss) | | | (175.4 | ) | | (156.3 | ) |
| TOTAL AEP COMMON SHAREHOLDERS’ EQUITY | | | 18,069.1 |
| | 17,397.0 |
|
| | | | | | | | | | |
| Noncontrolling Interests | | | | | | | 36.4 |
| | 23.1 |
|
| | | | | | | | | | |
| TOTAL EQUITY | | | | | | | 18,105.5 |
| | 17,420.1 |
|
| | | | | | | | | | |
| TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY | | $ | 63,964.9 |
| | $ | 63,467.7 |
|
|
| | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | March 31, | | December 31, |
| | | | | | | | 2023 | | 2022 |
| CURRENT LIABILITIES | | | | |
| Accounts Payable | | | | | | | $ | 2,269.3 | | | $ | 2,670.8 | |
| Short-term Debt: | | | | | | | | | |
| Securitized Debt for Receivables – AEP Credit | | | | | | | 750.0 | | | 750.0 | |
| Other Short-term Debt | | | | | | | 2,872.1 | | | 3,362.2 | |
| Total Short-term Debt | | | | | | | 3,622.1 | | | 4,112.2 | |
Long-term Debt Due Within One Year (March 31, 2023 and December 31, 2022 Amounts Include $206.9 and $218.2, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy) | | | 2,905.1 | | | 2,486.4 | |
| Risk Management Liabilities | | | | | | | 166.0 | | | 145.2 | |
| Customer Deposits | | | | | | | 390.0 | | | 408.8 | |
| Accrued Taxes | | | | | | | 1,599.9 | | | 1,714.6 | |
| Accrued Interest | | | | | | | 440.5 | | | 336.5 | |
| Obligations Under Operating Leases | | | | | | | 116.4 | | | 113.6 | |
| | | | | | | |
| Liabilities Held for Sale | | | | | | | 67.2 | | | — | |
| Other Current Liabilities | | | | | | | 1,045.2 | | | 1,278.2 | |
| TOTAL CURRENT LIABILITIES | | | | | | | 12,621.7 | | | 13,266.3 | |
| | | | | | | |
| NONCURRENT LIABILITIES | | | | |
Long-term Debt (March 31, 2023 and December 31, 2022 Amounts Include $624.2 and $755.3, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy) | | | 36,239.1 | | | 34,314.6 | |
| Long-term Risk Management Liabilities | | | | | | | 315.4 | | | 345.2 | |
| Deferred Income Taxes | | | | | | | 8,989.0 | | | 8,896.9 | |
| Regulatory Liabilities and Deferred Investment Tax Credits | | | 8,095.3 | | | 8,115.6 | |
| Asset Retirement Obligations | | | | | | | 2,877.5 | | | 2,879.3 | |
| Employee Benefits and Pension Obligations | | | | | | | 246.5 | | | 257.3 | |
| Obligations Under Operating Leases | | | | | | | 535.9 | | | 552.5 | |
| Deferred Credits and Other Noncurrent Liabilities | | | 573.1 | | | 607.3 | |
| TOTAL NONCURRENT LIABILITIES | | | | | | | 57,871.8 | | | 55,968.7 | |
| | | | | | | | | |
| TOTAL LIABILITIES | | | | | | | 70,493.5 | | | 69,235.0 | |
| | | | | | | | | |
| Rate Matters (Note 4) | | | | | | | | | |
| Commitments and Contingencies (Note 5) | | | | | | | | | |
| | | | | | | | | |
| MEZZANINE EQUITY | | | | |
| | | | | | | | | |
| Contingently Redeemable Performance Share Awards | | | | | | | 56.6 | | | 45.9 | |
| TOTAL MEZZANINE EQUITY | | | | | | | 56.6 | | | 45.9 | |
| | | | | | | | | |
| EQUITY | | | | |
| Common Stock – Par Value – $6.50 Per Share: | | | | | | | | | |
| | 2023 | | 2022 | | | | | |
| Shares Authorized | | 600,000,000 | | 600,000,000 | | | | | |
| Shares Issued | | 525,883,990 | | 525,099,321 | | | | | |
| (11,233,240 Shares were Held in Treasury as of March 31, 2023 and December 31, 2022, Respectively) | | | 3,418.2 | | | 3,413.1 | |
| Paid-in Capital | | | | | | | 8,074.3 | | | 8,051.0 | |
| Retained Earnings | | | | | | | 12,313.8 | | | 12,345.6 | |
| Accumulated Other Comprehensive Income (Loss) | | | (68.1) | | | 83.7 | |
| TOTAL AEP COMMON SHAREHOLDERS’ EQUITY | | | 23,738.2 | | | 23,893.4 | |
| | | | | | | | | |
| Noncontrolling Interests | | | | | | | 229.6 | | | 229.0 | |
| | | | | | | | | |
| TOTAL EQUITY | | | | | | | 23,967.8 | | | 24,122.4 | |
| | | | | | | | | |
| TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY | | $ | 94,517.9 | | | $ | 93,403.3 | |
| | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the NineThree Months Ended September 30, 2017March 31, 2023 and 20162022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | | Three Months Ended March 31, |
| | | 2023 | | 2022 |
| OPERATING ACTIVITIES | | | | |
| Net Income | | $ | 400.4 | | | $ | 718.1 | |
| | | | |
| | | | |
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | |
| Depreciation and Amortization | | 775.5 | | | 792.4 | |
| | | | |
| Deferred Income Taxes | | 68.0 | | | (17.7) | |
| | | | |
| Loss on the Expected Sale of the Competitive Contracted Renewable Portfolio | | 112.0 | | | — | |
| | | | |
| | | | |
| Allowance for Equity Funds Used During Construction | | (31.3) | | | (31.0) | |
| Mark-to-Market of Risk Management Contracts | | (82.0) | | | 282.3 | |
| | | | |
| | | | |
| Property Taxes | | (101.6) | | | (82.0) | |
| Deferred Fuel Over/Under-Recovery, Net | | 128.0 | | | (148.8) | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Change in Other Noncurrent Assets | | (96.0) | | | 49.4 | |
| Change in Other Noncurrent Liabilities | | (58.7) | | | 36.9 | |
| Changes in Certain Components of Working Capital: | | | | |
| Accounts Receivable, Net | | 348.4 | | | (24.3) | |
| Fuel, Materials and Supplies | | (115.9) | | | 27.6 | |
| Accounts Payable | | (255.9) | | | (1.0) | |
| Accrued Taxes, Net | | (150.9) | | | (51.8) | |
| | | | |
| Other Current Assets | | (94.6) | | | 133.9 | |
| Other Current Liabilities | | (127.6) | | | (61.8) | |
| Net Cash Flows from Operating Activities | | 717.8 | | | 1,622.2 | |
| | | | |
| INVESTING ACTIVITIES | | | | |
| Construction Expenditures | | (2,090.1) | | | (1,686.6) | |
| | | | |
| Purchases of Investment Securities | | (537.3) | | | (508.5) | |
| Sales of Investment Securities | | 517.6 | | | 497.4 | |
| Acquisitions of Nuclear Fuel | | (1.7) | | | (31.1) | |
| | | | |
| Acquisitions of Renewable Energy Facilities | | (145.7) | | | (1,207.3) | |
| | | | |
| | | | |
| Other Investing Activities | | 12.0 | | | 42.9 | |
| Net Cash Flows Used for Investing Activities | | (2,245.2) | | | (2,893.2) | |
| | | | |
| FINANCING ACTIVITIES | | | | |
| Issuance of Common Stock | | 41.1 | | | 809.5 | |
| Issuance of Long-term Debt | | 2,847.3 | | | 499.6 | |
| Issuance of Short-term Debt with Original Maturities greater than 90 Days | | 97.4 | | | 271.0 | |
| Change in Short-term Debt with Original Maturities less than 90 Days, Net | | (433.7) | | | 710.3 | |
| Retirement of Long-term Debt | | (519.5) | | | (51.0) | |
| | | | |
| Redemption of Short-term Debt with Original Maturities Greater than 90 Days | | (153.8) | | | (215.0) | |
| Principal Payments for Finance Lease Obligations | | (26.8) | | | (14.7) | |
| Dividends Paid on Common Stock | | (431.8) | | | (398.8) | |
| | | | |
| Other Financing Activities | | (55.8) | | | (65.8) | |
| Net Cash Flows from Financing Activities | | 1,364.4 | | | 1,545.1 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Net Increase (Decrease) in Cash and Cash Equivalents | | (163.0) | | | 274.1 | |
| Cash, Cash Equivalents and Restricted Cash at Beginning of Period | | 556.5 | | | 451.4 | |
| Cash, Cash Equivalents and Restricted Cash at End of Period | | $ | 393.5 | | | $ | 725.5 | |
| | | | |
| SUPPLEMENTARY INFORMATION | | | | |
| Cash Paid for Interest, Net of Capitalized Amounts | | $ | 311.9 | | | $ | 233.9 | |
| Net Cash Paid for Income Taxes | | 15.8 | | | 6.9 | |
| Noncash Acquisitions Under Finance Leases | | 12.5 | | | 7.2 | |
| Construction Expenditures Included in Current Liabilities as of March 31, | | 1,076.1 | | | 758.6 | |
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
|
| | | | | | | | |
| | | Nine Months Ended September 30, |
| | | 2017 | | 2016 |
| OPERATING ACTIVITIES | | |
| | |
|
| Net Income | | $ | 1,527.1 |
| | $ | 242.8 |
|
| Loss from Discontinued Operations, Net of Tax | | — |
| | (2.5 | ) |
| Income from Continuing Operations | | 1,527.1 |
| | 245.3 |
|
| Adjustments to Reconcile Income from Continuing Operations to Net Cash Flows from Continuing Operating Activities: | | | | |
| Depreciation and Amortization | | 1,485.9 |
| | 1,550.2 |
|
| Deferred Income Taxes | | 740.9 |
| | (47.0 | ) |
| Asset Impairments and Other Related Charges | | 10.6 |
| | 2,264.9 |
|
| Allowance for Equity Funds Used During Construction | | (62.2 | ) | | (86.1 | ) |
| Mark-to-Market of Risk Management Contracts | | (56.2 | ) | | 56.6 |
|
| Amortization of Nuclear Fuel | | 104.8 |
| | 109.7 |
|
| Pension Contributions to Qualified Plan Trust | | (93.3 | ) | | (84.8 | ) |
| Property Taxes | | 291.4 |
| | 288.3 |
|
| Deferred Fuel Over/Under-Recovery, Net | | 81.0 |
| | (28.5 | ) |
| Gain on Sale of Merchant Generation Assets | | (226.4 | ) | | — |
|
| Gain on Sale of Equity Investment | | (12.4 | ) | | — |
|
| Recovery of Ohio Capacity Costs | | 65.6 |
| | 108.8 |
|
Provision for Refund – Global Settlement, Net
| | (93.3 | ) | | — |
|
| Change in Other Noncurrent Assets | | (345.2 | ) | | (243.4 | ) |
| Change in Other Noncurrent Liabilities | | 205.7 |
| | 41.3 |
|
| Changes in Certain Components of Continuing Working Capital: | | | | |
| Accounts Receivable, Net | | 201.3 |
| | (240.8 | ) |
| Fuel, Materials and Supplies | | 58.5 |
| | 11.6 |
|
| Accounts Payable | | (91.0 | ) | | 47.8 |
|
| Accrued Taxes, Net | | (310.1 | ) | | (393.0 | ) |
| Other Current Assets | | (98.2 | ) | | 31.5 |
|
| Other Current Liabilities | | (260.3 | ) | | (211.4 | ) |
| Net Cash Flows from Continuing Operating Activities | | 3,124.2 |
| | 3,421.0 |
|
| | | | | |
| INVESTING ACTIVITIES | | | | |
| Construction Expenditures | | (3,778.2 | ) | | (3,387.0 | ) |
| Change in Other Temporary Investments, Net | | 34.5 |
| | 109.2 |
|
| Purchases of Investment Securities | | (1,855.8 | ) | | (2,454.5 | ) |
| Sales of Investment Securities | | 1,808.6 |
| | 2,427.0 |
|
| Acquisitions of Nuclear Fuel | | (73.2 | ) | | (127.6 | ) |
| Proceeds from Sale of Merchant Generation Assets | | 2,159.6 |
| | — |
|
| Other Investing Activities | | 27.9 |
| | 4.2 |
|
| Net Cash Flows Used for Continuing Investing Activities | | (1,676.6 | ) | | (3,428.7 | ) |
| | | | | |
| FINANCING ACTIVITIES | | | | |
| Issuance of Common Stock | | — |
| | 34.2 |
|
| Issuance of Long-term Debt | | 2,742.7 |
| | 1,559.6 |
|
| Change in Short-term Debt, Net | | (653.7 | ) | | 678.3 |
|
| Retirement of Long-term Debt | | (2,427.2 | ) | | (1,307.6 | ) |
| Make Whole Premium on Extinguishment of Long-term Debt | | (46.1 | ) | | — |
|
| Principal Payments for Capital Lease Obligations | | (50.5 | ) | | (81.9 | ) |
| Dividends Paid on Common Stock | | (875.0 | ) | | (829.8 | ) |
| Other Financing Activities | | (4.4 | ) | | (6.8 | ) |
| Net Cash Flows from (Used for) Continuing Financing Activities | | (1,314.2 | ) | | 46.0 |
|
| | | | | |
| Net Cash Flows Used for Discontinued Operating Activities | | — |
| | (2.5 | ) |
| Net Cash Flows from Discontinued Investing Activities | | — |
| | — |
|
| Net Cash Flows from Discontinued Financing Activities | | — |
| | — |
|
| | | | | |
| Net Increase in Cash and Cash Equivalents | | 133.4 |
| | 35.8 |
|
| Cash and Cash Equivalents at Beginning of Period | | 210.5 |
| | 176.4 |
|
| Cash and Cash Equivalents at End of Period | | $ | 343.9 |
| | $ | 212.2 |
|
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
| | | | | | | | | | | | | | | |
| | | |
| Three Months Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| | (in millions of KWhs) |
| Retail: | | | | | | | |
| Residential | 2,532 | | | 2,843 | | | | | |
| Commercial | 2,744 | | | 2,148 | | | | | |
| Industrial | 3,108 | | | 2,427 | | | | | |
| Miscellaneous | 138 | | | 141 | | | | | |
| Total Retail | 8,522 | | | 7,559 | | | | | |
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
| | | | | | | | | | | | | | | |
| | | |
| Three Months Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| | (in degree days) |
| Actual – Heating (a) | 141 | | | 278 | | | | | |
| Normal – Heating (b) | 194 | | | 190 | | | | | |
| | | | | | | |
| Actual – Cooling (c) | 271 | | | 88 | | | | | |
| Normal – Cooling (b) | 127 | | | 126 | | | | | |
(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.
First Quarter of 2023 Compared to First Quarter of 2022
|
| | | | | | | |
See Condensed NotesAEP Texas Inc. and Subsidiaries
|
Reconciliation of First Quarter of 2022 to Condensed Financial StatementsFirst Quarter of Registrants beginning on page 118.2023 |
| Net Income |
| (in millions) |
|
| First Quarter of 2022 | | $ | 69.6 | |
| | |
| Changes in Revenues: | | |
| Retail Revenues | | 1.5 | |
| | |
| Transmission Revenues | | 12.4 | |
| Other Revenues | | (1.1) | |
| Total Change in Revenues | | 12.8 | |
| | |
| Changes in Expenses and Other: | | |
| Other Operation and Maintenance | | (22.9) | |
| Depreciation and Amortization | | (2.2) | |
| Taxes Other Than Income Taxes | | (6.2) | |
| | |
| Interest Income | | 0.3 | |
| | |
| Allowance for Equity Funds Used During Construction | | 2.0 | |
| Non-Service Cost Components of Net Periodic Benefit Cost | | 0.6 | |
| Interest Expense | | (11.4) | |
| Total Change in Expenses and Other | | (39.8) | |
| | |
| Income Tax Expense | | 5.0 | |
| | |
| First Quarter of 2023 | | $ | 47.6 | |
The major components of the increase in revenues were as follows:
•Retail Revenues increased $2 million primarily due to the following:
•An $18 million increase due to interim rate increases driven by increased investment.
This increase was partially offset by:
•A $13 million decrease in weather-normalized revenues primarily in the residential class.
•A $3 million decrease in revenue from rate riders. This decrease was partially offset in other expense items below.
•Transmission Revenues increased $12 million primarily due to interim rate increases driven by increased transmission investment.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $23 million primarily due to the following:
•A $14 million increase in ERCOT transmission expenses. This increase was offset in Retail Revenues above.
•A $9 million increase in distribution-related expenses.
•Taxes Other Than Income Taxes increased $6 million primarily due to higher property taxes as a result of increased distribution and transmission investment.
•Interest Expense increased $11 million due to higher long-term debt balances and higher interest rates.
•Income Tax Expense decreased $5 million primarily due to a decrease in pretax book income.
AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2023 and 2022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | |
| | | | |
| | Three Months Ended March 31, | | |
| | | 2023 | | 2022 | | | | |
| REVENUES | | | | | | | | |
| Electric Transmission and Distribution | | $ | 427.7 | | | $ | 414.7 | | | | | |
| Sales to AEP Affiliates | | 1.2 | | | 0.9 | | | | | |
| Other Revenues | | 0.6 | | | 1.1 | | | | | |
| TOTAL REVENUES | | 429.5 | | | 416.7 | | | | | |
| | | | | | | | |
| EXPENSES | | | | | | | | |
| | | | | | | | |
| Other Operation | | 146.9 | | | 125.8 | | | | | |
| Maintenance | | 24.4 | | | 22.6 | | | | | |
| Depreciation and Amortization | | 111.0 | | | 108.8 | | | | | |
| Taxes Other Than Income Taxes | | 43.5 | | | 37.3 | | | | | |
| TOTAL EXPENSES | | 325.8 | | | 294.5 | | | | | |
| | | | | | | | |
| OPERATING INCOME | | 103.7 | | | 122.2 | | | | | |
| | | | | | | | |
| Other Income (Expense): | | | | | | | | |
| Interest Income | | 0.4 | | | 0.1 | | | | | |
| | | | | | | | |
| Allowance for Equity Funds Used During Construction | | 6.3 | | | 4.3 | | | | | |
| | | | | | | | |
| Non-Service Cost Components of Net Periodic Benefit Cost | | 4.8 | | | 4.2 | | | | | |
| Interest Expense | | (56.9) | | | (45.5) | | | | | |
| | | | | | | | |
| INCOME BEFORE INCOME TAX EXPENSE | | 58.3 | | | 85.3 | | | | | |
| | | | | | | | |
| Income Tax Expense | | 10.7 | | | 15.7 | | | | | |
| | | | | | | | |
| NET INCOME | | $ | 47.6 | | | $ | 69.6 | | | | | |
| | | | | | | | |
| The common stock of AEP Texas is wholly-owned by Parent. |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2023 and 2022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | |
| | | | |
| | Three Months Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| Net Income | | $ | 47.6 | | | $ | 69.6 | | | | | |
| | | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | | | | | | | | |
| Cash Flow Hedges, Net of Tax of $0 and $0.1 in 2023 and 2022, Respectively | | — | | | 0.3 | | | | | |
| Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $0 in 2023 and 2022, Respectively | | (0.6) | | | — | | | | | |
| | | | | | | | |
| TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | | (0.6) | | | 0.3 | | | | | |
| | | | | | | | |
| TOTAL COMPREHENSIVE INCOME | | $ | 47.0 | | | $ | 69.9 | | | | | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Three Months Ended March 31, 2023 and 2022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Paid-in
Capital | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income (Loss) | | Total |
| TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2021 | | $ | 1,553.9 | | | $ | 2,046.8 | | | $ | (6.5) | | | $ | 3,594.2 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Net Income | | | | 69.6 | | | | | 69.6 | |
| Other Comprehensive Income | | | | | | 0.3 | | | 0.3 | |
| TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2022 | | $ | 1,553.9 | | | $ | 2,116.4 | | | $ | (6.2) | | | $ | 3,664.1 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2022 | | $ | 1,558.2 | | | $ | 2,354.7 | | | $ | (8.6) | | | $ | 3,904.3 | |
| | | | | | | | |
| Capital Contribution from Parent | | 100.0 | | | | | | | 100.0 | |
| Net Income | | | | 47.6 | | | | | 47.6 | |
| Other Comprehensive Loss | | | | | | (0.6) | | | (0.6) | |
| TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2023 | | $ | 1,658.2 | | | $ | 2,402.3 | | | $ | (9.2) | | | $ | 4,051.3 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2023 and December 31, 2022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | | March 31, | | December 31, |
| | | 2023 | | 2022 |
| CURRENT ASSETS | | | | |
| Cash and Cash Equivalents | | $ | 0.1 | | | $ | 0.1 | |
Restricted Cash
(March 31, 2023 and December 31, 2022 Amounts Include $42.5 and $32.7, Respectively, Related to Transition Funding and Restoration Funding) | | 42.5 | | | 32.7 | |
| Advances to Affiliates | | 6.8 | | | 6.9 | |
| Accounts Receivable: | | | | |
| Customers | | 141.3 | | | 150.9 | |
| Affiliated Companies | | 13.5 | | | 11.9 | |
| Accrued Unbilled Revenues | | 74.7 | | | 91.4 | |
| Miscellaneous | | 0.2 | | | 0.2 | |
| Allowance for Uncollectible Accounts | | (4.1) | | | (4.2) | |
| Total Accounts Receivable | | 225.6 | | | 250.2 | |
| | | | |
| Materials and Supplies | | 139.9 | | | 138.8 | |
| | | | |
| Accrued Tax Benefits | | 8.3 | | | 12.2 | |
| Prepayments and Other Current Assets | | 5.9 | | | 6.0 | |
| TOTAL CURRENT ASSETS | | 429.1 | | | 446.9 | |
| | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | |
| Electric: | | | | |
| | | | |
| Transmission | | 6,373.2 | | | 6,301.5 | |
| Distribution | | 5,419.5 | | | 5,312.8 | |
| Other Property, Plant and Equipment | | 1,078.7 | | | 1,022.8 | |
| Construction Work in Progress | | 934.8 | | | 805.2 | |
| Total Property, Plant and Equipment | | 13,806.2 | | | 13,442.3 | |
| Accumulated Depreciation and Amortization | | 1,798.2 | | | 1,760.7 | |
| TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 12,008.0 | | | 11,681.6 | |
| | | | |
| OTHER NONCURRENT ASSETS | | | | |
| Regulatory Assets | | 299.3 | | | 298.3 | |
Securitized Assets (March 31, 2023 and December 31, 2022 Amounts Include $267.1 and $286.4, Respectively, Related to Transition Funding and Restoration Funding) | | 267.1 | | | 286.4 | |
| | | | |
| Deferred Charges and Other Noncurrent Assets | | 268.7 | | | 179.0 | |
| TOTAL OTHER NONCURRENT ASSETS | | 835.1 | | | 763.7 | |
| | | | |
| TOTAL ASSETS | | $ | 13,272.2 | | | $ | 12,892.2 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
March 31, 2023 and December 31, 2022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | | March 31, | | December 31, |
| | | 2023 | | 2022 |
| CURRENT LIABILITIES | | | | |
| Advances from Affiliates | | $ | 450.8 | | | $ | 96.5 | |
| Accounts Payable: | | | | |
| General | | 288.4 | | | 331.0 | |
| Affiliated Companies | | 26.7 | | | 34.7 | |
| | | | |
Long-term Debt Due Within One Year – Nonaffiliated (March 31, 2023 and December 31, 2022 Amounts Include $93.7 and $93.5, Respectively, Related to Transition Funding and Restoration Funding) | | 153.7 | | | 278.5 | |
| | | | |
| | | | |
| Accrued Taxes | | 136.1 | | | 95.5 | |
Accrued Interest (March 31, 2023 and December 31, 2022 Amounts Include $2.2 and $2.2, Respectively, Related to Transition Funding and Restoration Funding) | | 72.2 | | | 48.3 | |
| | | | |
| Obligations Under Operating Leases | | 29.4 | | | 28.6 | |
| | | | |
| Other Current Liabilities | | 122.8 | | | 130.7 | |
| TOTAL CURRENT LIABILITIES | | 1,280.1 | | | 1,043.8 | |
| | | | |
| NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated (March 31, 2023 and December 31, 2022 Amounts Include $209.3 and $221, Respectively, Related to Transition Funding and Restoration Funding) | | 5,368.3 | | | 5,379.3 | |
| | | | |
| Deferred Income Taxes | | 1,153.2 | | | 1,144.2 | |
| Regulatory Liabilities and Deferred Investment Tax Credits | | 1,258.0 | | | 1,259.6 | |
| | | | |
| Obligations Under Operating Leases | | 64.8 | | | 67.8 | |
| Deferred Credits and Other Noncurrent Liabilities | | 96.5 | | | 93.2 | |
| TOTAL NONCURRENT LIABILITIES | | 7,940.8 | | | 7,944.1 | |
| | | | |
| TOTAL LIABILITIES | | 9,220.9 | | | 8,987.9 | |
| | | | |
| Rate Matters (Note 4) | | | | |
| Commitments and Contingencies (Note 5) | | | | |
| | | | |
| COMMON SHAREHOLDER’S EQUITY | | | | |
| Paid-in Capital | | 1,658.2 | | | 1,558.2 | |
| Retained Earnings | | 2,402.3 | | | 2,354.7 | |
| Accumulated Other Comprehensive Income (Loss) | | (9.2) | | | (8.6) | |
| TOTAL COMMON SHAREHOLDER’S EQUITY | | 4,051.3 | | | 3,904.3 | |
| | | | |
| TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 13,272.2 | | | $ | 12,892.2 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2023 and 2022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | | Three Months Ended March 31, |
| | | 2023 | | 2022 |
| OPERATING ACTIVITIES | | | | |
| Net Income | | $ | 47.6 | | | $ | 69.6 | |
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | |
| Depreciation and Amortization | | 111.0 | | | 108.8 | |
| Deferred Income Taxes | | 6.4 | | | 7.0 | |
| Allowance for Equity Funds Used During Construction | | (6.3) | | | (4.3) | |
| Mark-to-Market of Risk Management Contracts | | 0.4 | | | (0.2) | |
| | | | |
| Property Taxes | | (88.8) | | | (79.5) | |
| | | | |
| Change in Other Noncurrent Assets | | (18.3) | | | (17.0) | |
| Change in Other Noncurrent Liabilities | | (0.8) | | | 5.8 | |
| Changes in Certain Components of Working Capital: | | | | |
| Accounts Receivable, Net | | 24.6 | | | (20.2) | |
| Materials and Supplies | | (1.1) | | | (4.9) | |
| Accounts Payable | | 3.6 | | | 9.6 | |
| | | | |
| Accrued Taxes, Net | | 44.5 | | | 37.9 | |
| | | | |
| Other Current Assets | | 0.9 | | | 0.8 | |
| Other Current Liabilities | | 13.0 | | | 16.5 | |
| Net Cash Flows from Operating Activities | | 136.7 | | | 129.9 | |
| | | | |
| INVESTING ACTIVITIES | | | | |
| Construction Expenditures | | (450.4) | | | (356.6) | |
| Change in Advances to Affiliates, Net | | 0.1 | | | 0.1 | |
| | | | |
| Other Investing Activities | | 7.3 | | | 13.7 | |
| Net Cash Flows Used for Investing Activities | | (443.0) | | | (342.8) | |
| | | | |
| FINANCING ACTIVITIES | | | | |
| Capital Contribution from Parent | | 100.0 | | | — | |
| | | | |
| | | | |
| Change in Advances from Affiliates, Net | | 354.3 | | | 235.3 | |
| Retirement of Long-term Debt – Nonaffiliated | | (136.7) | | | (11.4) | |
| Principal Payments for Finance Lease Obligations | | (1.8) | | | (1.7) | |
| | | | |
| Other Financing Activities | | 0.3 | | | 0.2 | |
| Net Cash Flows from Financing Activities | | 316.1 | | | 222.4 | |
| | | | |
| Net Increase in Cash, Cash Equivalents and Restricted | | 9.8 | | | 9.5 | |
| Cash, Cash Equivalents and Restricted Cash at Beginning of Period | | 32.8 | | | 30.5 | |
| Cash, Cash Equivalents and Restricted Cash at End of Period | | $ | 42.6 | | | $ | 40.0 | |
| | | | |
| SUPPLEMENTARY INFORMATION | | | | |
| Cash Paid for Interest, Net of Capitalized Amounts | | $ | 31.6 | | | $ | 29.9 | |
| | | | |
| Noncash Acquisitions Under Finance Leases | | 1.8 | | | 0.6 | |
| Construction Expenditures Included in Current Liabilities as of March 31, | | 177.5 | | | 147.6 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
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 March 31, |
| | 2023 | | 2022 |
| | (in millions) |
| Plant In Service | | $ | 12,971.3 | | | $ | 11,637.9 | |
| Construction Work in Progress | | 1,831.9 | | | 1,534.3 | |
| Accumulated Depreciation and Amortization | | 1,091.2 | | | 842.6 | |
| Total Transmission Property, Net | | $ | 13,712.0 | | | $ | 12,329.6 | |
|
| | | | | | | | |
| | | As of September 30, |
| | | 2017 | | 2016 |
| | | (in millions) |
| Plant In Service | | $ | 4,684.4 |
| | $ | 3,260.7 |
|
| CWIP | | 1,383.1 |
| | 1,328.6 |
|
| Accumulated Depreciation | | 151.5 |
| | 86.6 |
|
| Total Transmission Property, Net | | $ | 5,916.0 |
| | $ | 4,502.7 |
|
ThirdFirst Quarter of 20172023 Compared to ThirdFirst Quarter of 20162022
| | | | | | | | |
| AEP Transmission Company, LLC and Subsidiaries |
| Reconciliation of First Quarter of 2022 to First Quarter of 2023 |
| Net Income |
| (in millions) |
| | |
| First Quarter of 2022 | | $ | 155.4 | |
| Changes in Transmission Revenues: | | |
| Transmission Revenues | | 41.2 | |
| Total Change in Transmission Revenues | | 41.2 | |
| | |
| Changes in Expenses and Other: | | |
| Other Operation and Maintenance | | (5.1) | |
| Depreciation and Amortization | | (12.1) | |
| Taxes Other Than Income Taxes | | (9.2) | |
| Interest Income | | 1.4 | |
| Allowance for Equity Funds Used During Construction | | 0.8 | |
| Interest Expense | | (7.5) | |
| Total Change in Expenses and Other | | (31.7) | |
| | |
| Income Tax Expense | | (2.2) | |
| | |
| | |
| First Quarter of 2023 | | $ | 162.7 | |
|
| | | | |
| Reconciliation of Third Quarter of 2016 to Third Quarter of 2017 |
| Net Income |
| (in millions) |
| | | |
| Third Quarter of 2016 | | $ | 52.4 |
|
| | | |
| Changes in Transmission Revenues: | | |
| Transmission Revenues | | 42.0 |
|
| Total Change in Transmission Revenues | | 42.0 |
|
| | | |
| Changes in Expenses and Other: | | |
| Other Operation and Maintenance | | (10.4 | ) |
| Depreciation and Amortization | | (8.0 | ) |
| Taxes Other Than Income Taxes | | (4.9 | ) |
| Interest Income | | 0.1 |
|
| Allowance for Equity Funds Used During Construction | | (1.6 | ) |
| Interest Expense | | (5.9 | ) |
| Total Change in Expenses and Other | | (30.7 | ) |
| | | |
| Income Tax Expense | | (3.8 | ) |
| | | |
| Third Quarter of 2017 | | $ | 59.9 |
|
The major componentscomponent of the increase in transmission revenues, which consists of wholesale sales to affiliates and non-affiliates werenonaffiliates was as follows:
•Transmission Revenues increased $42$41 million primarily due to continued investment in transmission assets.
Expenses and Other changed between years as follows:
•Other Operation and Maintenance expenses increased $5 million primarily due to higher vegetation management expenses, affiliated rent expense and other miscellaneous expenses.
•Depreciation and Amortization expenses increased $12 million primarily due to a $40 million increase in formula rates driven by continued investment in transmission assets.
higher depreciable base.
Expenses and•Taxes Other andThan Income Tax Expense changed between years as follows:
Other Operation and Maintenance expensesTaxes increased $10$9 million primarily due to higher property taxes as a result of increased transmission investment.
Depreciation and Amortization expenses•Interest Expense increased $8 million primarily due to higher depreciable base.
Taxes Other Than Income Taxes increased $5 million primarily due to increased property taxes as a result of additional transmission investment.
Interest Expense increased $6 million primarily due to higher outstanding long-term debt balances.balances and higher interest rates.
Income Tax Expense increased $4 million primarily due to an increase in pretax book income.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
|
| | | | |
| Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017 |
| Net Income |
| (in millions) |
| |
| Nine Months Ended September 30, 2016 | | $ | 153.0 |
|
| | | |
|
| Changes in Transmission Revenues: | | |
|
| Transmission Revenues | | 191.4 |
|
| Total Change in Transmission Revenues | | 191.4 |
|
| | | |
|
| Changes in Expenses and Other: | | |
|
| Other Operation and Maintenance | | (19.8 | ) |
| Depreciation and Amortization | | (23.4 | ) |
| Taxes Other Than Income Taxes | | (16.6 | ) |
| Interest Income | | 0.3 |
|
| Allowance for Equity Funds Used During Construction | | (3.7 | ) |
| Interest Expense | | (16.3 | ) |
| Total Change in Expenses and Other | | (79.5 | ) |
| | | |
|
| Income Tax Expense | | (40.6 | ) |
| | | |
|
| Nine Months Ended September 30, 2017 | | $ | 224.3 |
|
The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and non-affiliates were as follows:
Transmission Revenues increased $191 million primarily due to the current year favorable impact of the modification of the PJM OATT formula rates combined with an increase driven by continued investment in transmission assets.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $20 million primarily due to increased transmission investment.
Depreciation and Amortization expenses increased $23 million primarily due to higher depreciable base.
Taxes Other Than Income Taxes increased $17 million primarily due to increased property taxes as a result of additional transmission investment.
Allowance for Equity Funds Used During Construction decreased $4 millionprimarily due to the FERC transmission complaint and an increase in the amount of short term debt, offset by an increase in the CWIP balance.
Interest Expense increased $16 million primarily due to higher outstanding long-term debt balances.
Income Tax Expense increased $41 million primarily due to an increase in pretax book income.
AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2017March 31, 2023 and 20162022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | |
| | | | |
| | Three Months Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| REVENUES | | | | | | | | |
| Transmission Revenues | | $ | 90.0 | | | $ | 87.0 | | | | | |
| Sales to AEP Affiliates | | 357.4 | | | 325.0 | | | | | |
| Provision for Refund – Affiliated | | (4.8) | | | (0.3) | | | | | |
| Provision for Refund – Nonaffiliated | | (1.0) | | | (11.3) | | | | | |
| | | | | | | | |
| TOTAL REVENUES | | 441.6 | | | 400.4 | | | | | |
| | | | | | | | |
| EXPENSES | | | | | | | | |
| Other Operation | | 29.0 | | | 25.5 | | | | | |
| Maintenance | | 4.9 | | | 3.3 | | | | | |
| Depreciation and Amortization | | 95.2 | | | 83.1 | | | | | |
| Taxes Other Than Income Taxes | | 74.8 | | | 65.6 | | | | | |
| TOTAL EXPENSES | | 203.9 | | | 177.5 | | | | | |
| | | | | | | | |
| OPERATING INCOME | | 237.7 | | | 222.9 | | | | | |
| | | | | | | | |
| Other Income (Expense): | | | | | | | | |
| Interest Income - Affiliated | | 1.5 | | | 0.1 | | | | | |
| Allowance for Equity Funds Used During Construction | | 16.4 | | | 15.6 | | | | | |
| | | | | | | | |
| Interest Expense | | (45.2) | | | (37.7) | | | | | |
| | | | | | | | |
| INCOME BEFORE INCOME TAX EXPENSE | | 210.4 | | | 200.9 | | | | | |
| | | | | | | | |
| Income Tax Expense | | 47.7 | | | 45.5 | | | | | |
| | | | | | | | |
| NET INCOME | | $ | 162.7 | | | $ | 155.4 | | | | | |
| | | | | | | | |
| AEPTCo is wholly-owned by AEP Transmission Holdco. |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended | | Nine Months Ended |
| | | September 30, | | September 30, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| REVENUES | | | | | | | | |
| Transmission Revenues | | $ | 35.9 |
| | $ | 33.5 |
| | $ | 99.2 |
| | $ | 89.6 |
|
| Sales to AEP Affiliates | | 131.4 |
| | 91.8 |
| | 450.2 |
| | 268.4 |
|
| TOTAL REVENUES | | 167.3 |
| | 125.3 |
| | 549.4 |
| | 358.0 |
|
| | | | | | | | | |
| EXPENSES | | |
| | | | |
| | |
|
| Other Operation | | 18.4 |
| | 7.5 |
| | 38.8 |
| | 21.0 |
|
| Maintenance | | 1.4 |
| | 1.9 |
| | 6.8 |
| | 4.8 |
|
| Depreciation and Amortization | | 24.8 |
| | 16.8 |
| | 70.9 |
| | 47.5 |
|
| Taxes Other Than Income Taxes | | 27.6 |
| | 22.7 |
| | 82.0 |
| | 65.4 |
|
| TOTAL EXPENSES | | 72.2 |
| | 48.9 |
| | 198.5 |
| | 138.7 |
|
| | | | | | | | | |
| OPERATING INCOME | | 95.1 |
| | 76.4 |
| | 350.9 |
| | 219.3 |
|
| | | | | | | | | |
| Other Income (Expense): | | |
| | | | |
| | |
|
| Interest Income | | 0.2 |
| | 0.1 |
| | 0.5 |
| | 0.2 |
|
| Allowance for Equity Funds Used During Construction | | 11.7 |
| | 13.3 |
| | 36.0 |
| | 39.7 |
|
| Interest Expense | | (16.9 | ) | | (11.0 | ) | | (48.6 | ) | | (32.3 | ) |
| | | | | | | | | |
| INCOME BEFORE INCOME TAX EXPENSE | | 90.1 |
| | 78.8 |
| | 338.8 |
| | 226.9 |
|
| | | | | | | | | |
| Income Tax Expense | | 30.2 |
| | 26.4 |
| | 114.5 |
| | 73.9 |
|
| | | | | | | | | |
| NET INCOME | | $ | 59.9 |
| | $ | 52.4 |
| | $ | 224.3 |
| | $ | 153.0 |
|
|
|
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 118. |
AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY
For the NineThree Months Ended September 30, 2017March 31, 2023 and 20162022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | |
| | | Paid-in
Capital | | Retained
Earnings | | Total |
| TOTAL MEMBER'S EQUITY – DECEMBER 31, 2021 | | $ | 2,949.6 | | | $ | 2,426.5 | | | $ | 5,376.1 | |
| | | | | | | |
| | | | | | |
| Dividends Paid to Member | | | | (40.0) | | | (40.0) | |
| Net Income | | | | 155.4 | | | 155.4 | |
| TOTAL MEMBER'S EQUITY – MARCH 31, 2022 | | $ | 2,949.6 | | | $ | 2,541.9 | | | $ | 5,491.5 | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | | |
| TOTAL MEMBER'S EQUITY – DECEMBER 31, 2022 | | $ | 3,022.3 | | | $ | 2,850.7 | | | $ | 5,873.0 | |
| | | | | | |
| Capital Contribution from Member | | 25.0 | | | | | 25.0 | |
| Dividends Paid to Member | | | | (55.0) | | | (55.0) | |
| Net Income | | | | 162.7 | | | 162.7 | |
| TOTAL MEMBER'S EQUITY – MARCH 31, 2023 | | $ | 3,047.3 | | | $ | 2,958.4 | | | $ | 6,005.7 | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
|
| | | | | | | | | | | | |
| | | Paid-in
Capital | | Retained
Earnings | | Total Member’s Equity |
| TOTAL MEMBER'S EQUITY – DECEMBER 31, 2015 | | $ | 1,243.0 |
| | $ | 309.9 |
| | $ | 1,552.9 |
|
| | | | | | | |
| Capital Contributions from Member | | 116.0 |
| | | | 116.0 |
|
| Net Income | | |
| | 153.0 |
| | 153.0 |
|
| TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2016 | | $ | 1,359.0 |
| | $ | 462.9 |
| | $ | 1,821.9 |
|
| | | | | | | |
| TOTAL MEMBER'S EQUITY – DECEMBER 31, 2016 | | $ | 1,455.0 |
| | $ | 502.6 |
| | $ | 1,957.6 |
|
| | | | | | | |
| Capital Contributions from Member | | 185.5 |
| | | | 185.5 |
|
| Net Income | | |
| | 224.3 |
| | 224.3 |
|
| TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2017 | | $ | 1,640.5 |
| | $ | 726.9 |
| | $ | 2,367.4 |
|
|
|
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 118. |
AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2017March 31, 2023 and December 31, 20162022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | | March 31, | | December 31, |
| | | 2023 | | 2022 |
| CURRENT ASSETS | | | | |
| Advances to Affiliates | | $ | 297.5 | | | $ | 4.4 | |
| Accounts Receivable: | | | | |
| Customers | | 51.9 | | | 46.9 | |
| Affiliated Companies | | 127.0 | | | 119.5 | |
| | | | |
| Total Accounts Receivable | | 178.9 | | | 166.4 | |
| Materials and Supplies | | 14.8 | | | 10.7 | |
| | | | |
| | | | |
| Prepayments and Other Current Assets | | 2.1 | | | 7.2 | |
| TOTAL CURRENT ASSETS | | 493.3 | | | 188.7 | |
| | | | |
| TRANSMISSION PROPERTY | | | | |
| Transmission Property | | 12,486.7 | | | 12,335.4 | |
| Other Property, Plant and Equipment | | 484.6 | | | 476.8 | |
| Construction Work in Progress | | 1,831.9 | | | 1,554.7 | |
| Total Transmission Property | | 14,803.2 | | | 14,366.9 | |
| Accumulated Depreciation and Amortization | | 1,091.2 | | | 1,027.0 | |
| TOTAL TRANSMISSION PROPERTY – NET | | 13,712.0 | | | 13,339.9 | |
| | | | |
| OTHER NONCURRENT ASSETS | | | | |
| | | | |
| Regulatory Assets | | 5.8 | | | 7.2 | |
| Deferred Property Taxes | | 232.0 | | | 266.6 | |
| Deferred Charges and Other Noncurrent Assets | | 11.6 | | | 11.8 | |
| TOTAL OTHER NONCURRENT ASSETS | | 249.4 | | | 285.6 | |
| | | | |
| TOTAL ASSETS | | $ | 14,454.7 | | | $ | 13,814.2 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
|
| | | | | | | | |
| | | September 30, | | December 31, |
| | | 2017 | | 2016 |
| CURRENT ASSETS | | | | |
| Advances to Affiliates | | $ | 290.9 |
| | $ | 67.1 |
|
| Accounts Receivable: | | | | |
| Customers | | 19.5 |
| | 11.3 |
|
| Affiliated Companies | | 102.8 |
| | 66.6 |
|
| Total Accounts Receivable | | 122.3 |
| | 77.9 |
|
| Materials and Supplies | | 16.0 |
| | 5.0 |
|
| Accrued Tax Benefits | | 12.7 |
| | 26.0 |
|
| Prepayments and Other Current Assets | | 8.1 |
| | 2.8 |
|
| TOTAL CURRENT ASSETS | | 450.0 |
| | 178.8 |
|
| | | | | |
| TRANSMISSION PROPERTY | | | | |
| Transmission Property | | 4,570.9 |
| | 3,973.5 |
|
| Other Property, Plant and Equipment | | 113.5 |
| | 99.4 |
|
| Construction Work in Progress | | 1,383.1 |
| | 981.3 |
|
| Total Transmission Property | | 6,067.5 |
| | 5,054.2 |
|
| Accumulated Depreciation and Amortization | | 151.5 |
| | 99.6 |
|
TOTAL TRANSMISSION PROPERTY – NET | | 5,916.0 |
| | 4,954.6 |
|
| | | | | |
| OTHER NONCURRENT ASSETS | | | | |
| Accounts Receivable - Affiliated Companies | | 13.8 |
| | — |
|
| Regulatory Assets | | 138.0 |
| | 112.3 |
|
| Deferred Property Taxes | | 29.8 |
| | 102.2 |
|
| Deferred Charges and Other Noncurrent Assets | | 1.3 |
| | 1.9 |
|
| TOTAL OTHER NONCURRENT ASSETS | | 182.9 |
| | 216.4 |
|
| | | | | |
| TOTAL ASSETS | | $ | 6,548.9 |
| | $ | 5,349.8 |
|
|
|
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 118. |
AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND MEMBER’S EQUITY
September 30, 2017March 31, 2023 and December 31, 20162022
(in millions)(Unaudited)
(Unaudited) | | | | | | | | | | | | | | |
| | | March 31, | | December 31, |
| | | 2023 | | 2022 |
| | (in millions) |
| CURRENT LIABILITIES | | | | |
| Advances from Affiliates | | $ | 4.4 | | | $ | 229.3 | |
| Accounts Payable: | | | | |
| General | | 421.7 | | | 427.8 | |
| Affiliated Companies | | 110.8 | | | 82.7 | |
| | | | |
| Long-term Debt Due Within One Year – Nonaffiliated | | 60.0 | | | 60.0 | |
| Accrued Taxes | | 465.7 | | | 529.8 | |
| Accrued Interest | | 56.8 | | | 28.8 | |
| Obligations Under Operating Leases | | 1.3 | | | 1.3 | |
| | | | |
| Other Current Liabilities | | 14.1 | | | 8.3 | |
| TOTAL CURRENT LIABILITIES | | 1,134.8 | | | 1,368.0 | |
| | | | |
| NONCURRENT LIABILITIES | | | | |
| Long-term Debt – Nonaffiliated | | 5,412.1 | | | 4,722.8 | |
| Deferred Income Taxes | | 1,079.1 | | | 1,056.5 | |
| Regulatory Liabilities | | 746.4 | | | 723.3 | |
| Obligations Under Operating Leases | | 1.2 | | | 1.5 | |
| Deferred Credits and Other Noncurrent Liabilities | | 75.4 | | | 69.1 | |
| TOTAL NONCURRENT LIABILITIES | | 7,314.2 | | | 6,573.2 | |
| | | | |
| TOTAL LIABILITIES | | 8,449.0 | | | 7,941.2 | |
| | | | |
| Rate Matters (Note 4) | | | | |
| Commitments and Contingencies (Note 5) | | | | |
| | | | |
| MEMBER’S EQUITY | | | | |
| Paid-in Capital | | 3,047.3 | | | 3,022.3 | |
| Retained Earnings | | 2,958.4 | | | 2,850.7 | |
| TOTAL MEMBER’S EQUITY | | 6,005.7 | | | 5,873.0 | |
| | | | |
| TOTAL LIABILITIES AND MEMBER’S EQUITY | | $ | 14,454.7 | | | $ | 13,814.2 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
|
| | | | | | | | |
| | | September 30, | | December 31, |
| | | 2017 | | 2016 |
| CURRENT LIABILITIES | | | | |
| Advances from Affiliates | | $ | 32.8 |
| | $ | 4.1 |
|
| Accounts Payable: | | | | |
| General | | 233.2 |
| | 289.7 |
|
| Affiliated Companies | | 50.0 |
| | 43.1 |
|
| Accrued Taxes | | 112.5 |
| | 191.8 |
|
| Accrued Interest | | 28.9 |
| | 10.5 |
|
| Other Current Liabilities | | 10.4 |
| | 10.9 |
|
| TOTAL CURRENT LIABILITIES | | 467.8 |
| | 550.1 |
|
| | | | | |
| NONCURRENT LIABILITIES | | | | |
| Long-term Debt – Nonaffiliated | | 2,550.0 |
| | 1,932.0 |
|
| Deferred Income Taxes | | 1,073.1 |
| | 862.1 |
|
| Regulatory Liabilities | | 60.5 |
| | 44.0 |
|
| Deferred Credits and Other Noncurrent Liabilities | | 30.1 |
| | 4.0 |
|
| TOTAL NONCURRENT LIABILITIES | | 3,713.7 |
| | 2,842.1 |
|
| | | | | |
| TOTAL LIABILITIES | | 4,181.5 |
| | 3,392.2 |
|
| | | | | |
| Rate Matters (Note 4) | |
| |
|
| Commitments and Contingencies (Note 5) | |
| |
|
| | | | | |
| MEMBER’S EQUITY | | | | |
| Paid-in Capital | | 1,640.5 |
| | 1,455.0 |
|
| Retained Earnings | | 726.9 |
| | 502.6 |
|
| TOTAL MEMBER’S EQUITY | | 2,367.4 |
| | 1,957.6 |
|
| | | | | |
| TOTAL LIABILITIES AND MEMBER’S EQUITY | | $ | 6,548.9 |
| | $ | 5,349.8 |
|
|
|
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 118. |
AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the NineThree Months Ended September 30, 2017March 31, 2023 and 20162022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | | Three Months Ended March 31, |
| | | 2023 | | 2022 |
| OPERATING ACTIVITIES | | | | |
| Net Income | | $ | 162.7 | | | $ | 155.4 | |
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | |
| Depreciation and Amortization | | 95.2 | | | 83.1 | |
| Deferred Income Taxes | | 20.6 | | | 23.1 | |
| Allowance for Equity Funds Used During Construction | | (16.4) | | | (15.6) | |
| Property Taxes | | 34.6 | | | 31.3 | |
| | | | |
| Change in Other Noncurrent Assets | | 0.9 | | | 2.1 | |
| Change in Other Noncurrent Liabilities | | 6.6 | | | 11.8 | |
| Changes in Certain Components of Working Capital: | | | | |
| Accounts Receivable, Net | | (12.5) | | | (21.8) | |
| Materials and Supplies | | (4.1) | | | (0.8) | |
| Accounts Payable | | 41.0 | | | 3.6 | |
| Accrued Taxes, Net | | (59.9) | | | (53.7) | |
| | | | |
| Other Current Assets | | 1.0 | | | 0.5 | |
| Other Current Liabilities | | 29.6 | | | 19.8 | |
| Net Cash Flows from Operating Activities | | 299.3 | | | 238.8 | |
| | | | |
| INVESTING ACTIVITIES | | | | |
| Construction Expenditures | | (439.7) | | | (417.1) | |
| Change in Advances to Affiliates, Net | | (293.1) | | | 22.6 | |
| | | | |
| | | | |
| Other Investing Activities | | (0.8) | | | (1.7) | |
| Net Cash Flows Used for Investing Activities | | (733.6) | | | (396.2) | |
| | | | |
| FINANCING ACTIVITIES | | | | |
| Capital Contribution from Member | | 25.0 | | | — | |
| Issuance of Long-term Debt – Nonaffiliated | | 689.2 | | | — | |
| Change in Advances from Affiliates, Net | | (224.9) | | | 197.4 | |
| Dividends Paid to Member | | (55.0) | | | (40.0) | |
| | | | |
| Net Cash Flows from Financing Activities | | 434.3 | | | 157.4 | |
| | | | |
| 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 | | $ | 16.2 | | | $ | 16.4 | |
| | | | |
| Construction Expenditures Included in Current Liabilities as of March 31, | | 305.4 | | | 214.6 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
|
| | | | | | | | |
| | | Nine Months Ended September 30, |
| | | 2017 | | 2016 |
| OPERATING ACTIVITIES | | | | |
| Net Income | | $ | 224.3 |
| | $ | 153.0 |
|
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | |
| Depreciation and Amortization | | 70.9 |
| | 47.5 |
|
| Deferred Income Taxes | | 193.0 |
| | 161.2 |
|
| Allowance for Equity Funds Used During Construction | | (36.0 | ) | | (39.7 | ) |
| Property Taxes | | 72.4 |
| | 63.5 |
|
| Long-term Accounts Receivable - Affiliated | | (13.8 | ) | | — |
|
| Change in Other Noncurrent Assets | | 7.6 |
| | (6.4 | ) |
| Change in Other Noncurrent Liabilities | | 25.7 |
| | 0.6 |
|
| Changes in Certain Components of Working Capital: | | | | |
|
| Accounts Receivable, Net | | (44.4 | ) | | (43.3 | ) |
| Materials and Supplies | | (11.0 | ) | | (1.5 | ) |
| Accounts Payable | | 8.6 |
| | (1.7 | ) |
| Accrued Taxes, Net | | (66.0 | ) | | 61.2 |
|
| Accrued Interest | | 18.4 |
| | 11.3 |
|
| Other Current Assets | | (5.3 | ) | | (0.1 | ) |
| Other Current Liabilities | | 0.5 |
| | 0.1 |
|
| Net Cash Flows from Operating Activities | | 444.9 |
| | 405.7 |
|
| | | | | |
| INVESTING ACTIVITIES | | |
| | |
|
| Construction Expenditures | | (1,050.7 | ) | | (799.8 | ) |
| Change in Advances to Affiliates, Net | | (223.8 | ) | | 83.7 |
|
| Other Investing Activities | | (2.9 | ) | | (4.6 | ) |
| Net Cash Flows Used for Investing Activities | | (1,277.4 | ) | | (720.7 | ) |
| | | | | |
| FINANCING ACTIVITIES | | | | |
|
| Capital Contributions from Member | | 185.5 |
| | 116.0 |
|
| Issuance of Long-term Debt - Nonaffiliated | | 618.3 |
| | — |
|
| Change in Advances from Affiliates, Net | | 28.7 |
| | 199.0 |
|
| Net Cash Flows from Financing Activities | | 832.5 |
| | 315.0 |
|
| | | | | |
| 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 | | $ | 28.6 |
| | $ | 20.0 |
|
| Net Cash Paid (Received) for Income Taxes | | (93.4 | ) | | (209.8 | ) |
| Construction Expenditures Included in Current Liabilities as of September 30, | | 239.0 |
| | 204.8 |
|
|
|
See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 118. |
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
| | | | | | | | | | | | | | | |
| | | |
| | Three Months Ended March 31, | | |
| 2023 | | 2022 | | | | |
| | (in millions of KWhs) |
| Retail: | | | | | | | |
| Residential | 3,059 | | | 3,532 | | | | | |
| Commercial | 1,403 | | | 1,519 | | | | | |
| Industrial | 2,109 | | | 2,219 | | | | | |
| Miscellaneous | 200 | | | 213 | | | | | |
| Total Retail | 6,771 | | | 7,483 | | | | | |
| | | | | | | |
| Wholesale | 489 | | | 363 | | | | | |
| | | | | | | |
| Total KWhs | 7,260 | | | 7,846 | | | | | |
|
| | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions of KWhs) |
| Retail: | |
| | |
| | |
| | |
|
| Residential | 2,488 |
| | 2,845 |
| | 7,829 |
| | 8,743 |
|
| Commercial | 1,673 |
| | 1,823 |
| | 4,805 |
| | 5,125 |
|
| Industrial | 2,431 |
| | 2,391 |
| | 7,106 |
| | 7,022 |
|
| Miscellaneous | 202 |
| | 217 |
| | 613 |
| | 637 |
|
| Total Retail | 6,794 |
| | 7,276 |
| | 20,353 |
| | 21,527 |
|
| | | | | | | | |
| Wholesale | 994 |
| | 1,029 |
| | 2,684 |
| | 2,413 |
|
| | | | | | | | |
| Total KWhs | 7,788 |
| | 8,305 |
| | 23,037 |
| | 23,940 |
|
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
| | | | | | | | | | | | | | | |
| | | |
| | Three Months Ended March 31, | | |
| 2023 | | 2022 | | | | |
| | (in degree days) |
| Actual – Heating (a) | 859 | | | 1,274 | | | | | |
| Normal – Heating (b) | 1,321 | | | 1,319 | | | | | |
| | | | | | | |
| Actual – Cooling (c) | 8 | | | 2 | | | | | |
| Normal – Cooling (b) | 6 | | | 6 | | | | | |
(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.
|
| | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in degree days) |
| Actual - Heating (a) | — |
| | — |
| | 1,000 |
| | 1,433 |
|
| Normal - Heating (b) | 2 |
| | 2 |
| | 1,420 |
| | 1,437 |
|
| | | | | | | | |
| Actual - Cooling (c) | 805 |
| | 1,049 |
| | 1,180 |
| | 1,437 |
|
| Normal - Cooling (b) | 812 |
| | 808 |
| | 1,179 |
| | 1,177 |
|
| | | | | | | | |
(a)Appalachian Power Company and Subsidiaries |
| Reconciliation of First Quarter of 2022 to First Quarter of 2023 |
| Net Income |
| (in millions) |
|
| First Quarter of 2022 | Heating degree days are calculated on a 55 degree temperature base. | $ | 120.2 | |
| | |
| Changes in Gross Margin: | | |
| Retail Margins | | 13.1 | |
| Margins from Off-system Sales | | 2.2 | |
| Transmission Revenues | | 0.1 | |
| Other Revenues | | (4.2) | |
| Total Change in Gross Margin | | 11.2 | |
| | |
| Changes in Expenses and Other: | | |
| Other Operation and Maintenance | | (5.9) | |
| | |
(b) | Normal Heating/Cooling represents the thirty-year average of degree days. |
| |
(c)Depreciation and Amortization | Cooling degree days are calculated on a 65 degree temperature base. | 2.2 | |
| Taxes Other Than Income Taxes | | (1.6) | |
| Interest Income | | 0.5 | |
| | |
| Allowance for Equity Funds Used During Construction | | 0.4 | |
| Non-Service Cost Components of Net Periodic Benefit Cost | | 0.8 | |
| Interest Expense | | (11.0) | |
| Total Change in Expenses and Other | | (14.6) | |
| | |
| Income Tax Expense | | (4.3) | |
| | |
| First Quarter of 2023 | | $ | 112.5 | |
Third Quarter of 2017 Compared to Third Quarter of 2016
|
| | | | |
| Reconciliation of Third Quarter of 2016 to Third Quarter of 2017 |
| Net Income |
| (in millions) |
| |
| Third Quarter of 2016 | | $ | 104.1 |
|
| | | |
|
| Changes in Gross Margin: | | |
|
| Retail Margins | | (40.6 | ) |
| Off-system Sales | | (1.0 | ) |
| Transmission Revenues | | 1.8 |
|
| Other Revenues | | 0.5 |
|
| Total Change in Gross Margin | | (39.3 | ) |
| | | |
|
| Changes in Expenses and Other: | | |
|
| Other Operation and Maintenance | | 12.9 |
|
| Depreciation and Amortization | | (4.7 | ) |
| Taxes Other Than Income Taxes | | (0.3 | ) |
| Carrying Costs Income | | 0.4 |
|
| Allowance for Equity Funds Used During Construction | | (1.8 | ) |
| Interest Expense | | (0.8 | ) |
| Total Change in Expenses and Other | | 5.7 |
|
| | | |
|
| Income Tax Expense | | 15.5 |
|
| | | |
|
| Third Quarter of 2017 | | $ | 86.0 |
|
The major components of the decreaseincrease 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 decreased $41 increased $13 million primarily due to the following:
•A $25$16 million increase in weather-normalized margins primarily driven by an increase in the residential class.
•A $15 million increase due to a base rate increase in Virginia implemented in October 2022 following the Virginia Supreme Court remand. This increase was partially offset in Other Operation and Maintenance expense below.
•A $10 million increase driven by sales of renewable energy credits and lower fuel handling costs in Virginia.
•A $9 million increase due to lower customer refunds related to Tax Reform. This increase was offset in Income Tax Expense below.
•A $4 million increase due to lower amortization expenses related to the Virginia CCR. This increase was offset in other expense items below.
These increases were partially offset by:
•A $43 million decrease in weather-related usage primarily driven by a 23%33% decrease in coolingheating degree days.
An $8•Other Revenues decreased $4 million decrease in weather-normalized margin occurring across all retail classes.
A $6 million decrease primarily due to a decrease in rates in West Virginia and Virginia.pole attachment revenue. This decrease iswas partially offset by a corresponding decrease in Other Operation and Maintenance expensesExpense below.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses decreased $13increased $6 million primarily due to the following:
amortization of the regulatory asset in accordance with the August 2022 Virginia Supreme Court opinion related to under-earnings during the 2017-2019 Triennial Review. This increase was offset in Retail Margins above.A $7 million decrease in storm-related expenses.
A $4 million decrease in generation plant maintenance expenses.
Depreciation and Amortization expenses•Interest Expense increased $5$11 million primarily due to a higher depreciable base.
debt balances and higher interest rates.•Income Tax Expensedecreased $16 increased $4 million primarily due to a decreasean increase in pretax book income andunfavorable discrete tax adjustments in 2023.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the recording of federal income tax adjustments.
NineThree Months Ended September 30, 2017March 31, 2023 and 2022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | |
| | | | | Three Months Ended March 31, |
| | | | |
| | | | | | | 2023 | | 2022 |
| REVENUES | | | | | | | | |
| Electric Generation, Transmission and Distribution | | | | | | $ | 914.5 | | | $ | 847.1 | |
| Sales to AEP Affiliates | | | | | | 69.6 | | | 56.9 | |
| Other Revenues | | | | | | 3.6 | | | 3.3 | |
| TOTAL REVENUES | | | | | | 987.7 | | | 907.3 | |
| | | | | | | | |
| EXPENSES | | | | | | | | |
| Purchased Electricity, Fuel and Other Consumables Used for Electric Generation | | | | | | 339.7 | | | 270.5 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Other Operation | | | | | | 191.8 | | | 184.9 | |
| Maintenance | | | | | | 73.1 | | | 74.1 | |
| | | | | | | | |
| | | | | | | | |
| Depreciation and Amortization | | | | | | 143.0 | | | 145.2 | |
| Taxes Other Than Income Taxes | | | | | | 41.8 | | | 40.2 | |
| TOTAL EXPENSES | | | | | | 789.4 | | | 714.9 | |
| | | | | | | | |
| OPERATING INCOME | | | | | | 198.3 | | | 192.4 | |
| | | | | | | | |
| Other Income (Expense): | | | | | | | | |
| Interest Income | | | | | | 0.6 | | | 0.1 | |
| | | | | | | | |
| Allowance for Equity Funds Used During Construction | | | | | | 2.4 | | | 2.0 | |
| Non-Service Cost Components of Net Periodic Benefit Cost | | | | | | 8.1 | | | 7.3 | |
| Interest Expense | | | | | | (65.3) | | | (54.3) | |
| | | | | | | | |
| INCOME BEFORE INCOME TAX EXPENSE | | | | | | 144.1 | | | 147.5 | |
| | | | | | | | |
| Income Tax Expense | | | | | | 31.6 | | | 27.3 | |
| | | | | | | | |
| NET INCOME | | | | | | $ | 112.5 | | | $ | 120.2 | |
| | | | | | | | |
| The common stock of APCo is wholly-owned by Parent. |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2023 and 2022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | | | Three Months Ended March 31, |
| | | | | | 2023 | | 2022 |
| Net Income | | | | | | $ | 112.5 | | | $ | 120.2 | |
| | | | | | | | |
| OTHER COMPREHENSIVE LOSS, NET OF TAXES | | | | | | | | |
| Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) in 2023 and 2022, Respectively | | | | | | (0.2) | | | (0.2) | |
| Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.2) and $(0.3) in 2023 and 2022, Respectively | | | | | | (0.8) | | | (1.1) | |
| | | | | | | | |
| TOTAL OTHER COMPREHENSIVE LOSS | | | | | | (1.0) | | | (1.3) | |
| | | | | | | | |
| TOTAL COMPREHENSIVE INCOME | | | | | | $ | 111.5 | | | $ | 118.9 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Three Months Ended March 31, 2023 and 2022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common
Stock | | Paid-in
Capital | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income (Loss) | | Total |
| TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2021 | | $ | 260.4 | | | $ | 1,828.7 | | | $ | 2,534.4 | | | $ | 24.4 | | | $ | 4,647.9 | |
| | | | | | | | | | |
| Common Stock Dividends | | | | | | (18.8) | | | | | (18.8) | |
| | | | | | | | | | |
| Net Income | | | | | | 120.2 | | | | | 120.2 | |
| Other Comprehensive Loss | | | | | | | | (1.3) | | | (1.3) | |
| TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2022 | | $ | 260.4 | | | $ | 1,828.7 | | | $ | 2,635.8 | | | $ | 23.1 | | | $ | 4,748.0 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2022 | | $ | 260.4 | | | $ | 1,828.7 | | | $ | 2,891.1 | | | $ | (4.8) | | | $ | 4,975.4 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Net Income | | | | | | 112.5 | | | | | 112.5 | |
| Other Comprehensive Loss | | | | | | | | (1.0) | | | (1.0) | |
| TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2023 | | $ | 260.4 | | | $ | 1,828.7 | | | $ | 3,003.6 | | | $ | (5.8) | | | $ | 5,086.9 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2023 and December 31, 2022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | March 31, | | December 31, |
| | 2023 | | 2022 |
| CURRENT ASSETS | | | | |
| Cash and Cash Equivalents | | $ | 7.1 | | | $ | 7.5 | |
| Restricted Cash for Securitized Funding | | 7.5 | | | 14.4 | |
| Advances to Affiliates | | 18.7 | | | 19.8 | |
| Accounts Receivable: | | | | |
| Customers | | 154.0 | | | 168.9 | |
| Affiliated Companies | | 91.5 | | | 94.0 | |
| Accrued Unbilled Revenues | | 55.4 | | | 91.3 | |
| Miscellaneous | | 0.2 | | | 0.3 | |
| Allowance for Uncollectible Accounts | | (2.0) | | | (1.7) | |
| Total Accounts Receivable | | 299.1 | | | 352.8 | |
| Fuel | | 220.5 | | | 158.9 | |
| Materials and Supplies | | 128.4 | | | 130.6 | |
| Risk Management Assets | | 12.4 | | | 69.1 | |
| | | | |
| Regulatory Asset for Under-Recovered Fuel Costs | | 574.5 | | | 473.1 | |
| | | | |
| Prepayments and Other Current Assets | | 30.8 | | | 33.4 | |
| TOTAL CURRENT ASSETS | | 1,299.0 | | | 1,259.6 | |
| | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | |
| Electric: | | | | |
| Generation | | 6,886.9 | | | 6,776.8 | |
| Transmission | | 4,510.3 | | | 4,482.8 | |
| Distribution | | 4,992.6 | | | 4,933.0 | |
| Other Property, Plant and Equipment | | 890.3 | | | 883.3 | |
| Construction Work in Progress | | 689.4 | | | 705.3 | |
| Total Property, Plant and Equipment | | 17,969.5 | | | 17,781.2 | |
| Accumulated Depreciation and Amortization | | 5,463.4 | | | 5,402.0 | |
| TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 12,506.1 | | | 12,379.2 | |
| | | | |
| OTHER NONCURRENT ASSETS | | | | |
| Regulatory Assets | | 920.4 | | | 1,058.6 | |
| Securitized Assets | | 153.1 | | | 159.6 | |
| Employee Benefits and Pension Assets | | 157.4 | | | 152.9 | |
| | | | |
| Operating Lease Assets | | 71.2 | | | 73.6 | |
| Deferred Charges and Other Noncurrent Assets | | 149.2 | | | 138.7 | |
| TOTAL OTHER NONCURRENT ASSETS | | 1,451.3 | | | 1,583.4 | |
| | | | |
| TOTAL ASSETS | | $ | 15,256.4 | | | $ | 15,222.2 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
March 31, 2023 and December 31, 2022
(Unaudited)
| | | | | | | | | | | | | | |
| | | March 31, | | December 31, |
| | | 2023 | | 2022 |
| | | (in millions) |
| CURRENT LIABILITIES | | | | |
| Advances from Affiliates | | $ | 310.2 | | | $ | 182.2 | |
| Accounts Payable: | | | | |
| General | | 297.6 | | | 451.2 | |
| Affiliated Companies | | 101.0 | | | 142.7 | |
| Long-term Debt Due Within One Year – Nonaffiliated | | 252.3 | | | 251.8 | |
| | | | |
| Risk Management Liabilities | | 7.0 | | | 3.6 | |
| Customer Deposits | | 74.2 | | | 75.1 | |
| | | | |
| Accrued Taxes | | 112.3 | | | 101.0 | |
| Accrued Interest | | 83.2 | | | 57.9 | |
| Obligations Under Operating Leases | | 14.8 | | | 15.0 | |
| | | | |
| Other Current Liabilities | | 97.5 | | | 109.7 | |
| TOTAL CURRENT LIABILITIES | | 1,350.1 | | | 1,390.2 | |
| | | | |
| NONCURRENT LIABILITIES | | | | |
| Long-term Debt – Nonaffiliated | | 5,146.4 | | | 5,158.7 | |
| | | | |
| | | | |
| | | | |
| Deferred Income Taxes | | 2,006.8 | | | 1,992.2 | |
| Regulatory Liabilities and Deferred Investment Tax Credits | | 1,109.5 | | | 1,143.6 | |
| Asset Retirement Obligations | | 422.5 | | | 419.2 | |
| Employee Benefits and Pension Obligations | | 33.1 | | | 34.2 | |
| Obligations Under Operating Leases | | 56.9 | | | 59.1 | |
| Deferred Credits and Other Noncurrent Liabilities | | 44.2 | | | 49.6 | |
| TOTAL NONCURRENT LIABILITIES | | 8,819.4 | | | 8,856.6 | |
| | | | |
| TOTAL LIABILITIES | | 10,169.5 | | | 10,246.8 | |
| | | | |
| Rate Matters (Note 4) | | | | |
| Commitments and Contingencies (Note 5) | | | | |
| | | | |
| 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 | | 3,003.6 | | | 2,891.1 | |
| Accumulated Other Comprehensive Income (Loss) | | (5.8) | | | (4.8) | |
| TOTAL COMMON SHAREHOLDER’S EQUITY | | 5,086.9 | | | 4,975.4 | |
| | | | |
| TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 15,256.4 | | | $ | 15,222.2 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2023 and 2022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | | Three Months Ended March 31, |
| | | 2023 | | 2022 |
| OPERATING ACTIVITIES | | | | |
| Net Income | | $ | 112.5 | | | $ | 120.2 | |
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | |
| Depreciation and Amortization | | 143.0 | | | 145.2 | |
| Deferred Income Taxes | | 10.3 | | | 4.1 | |
| | | | |
| | | | |
| | | | |
| Allowance for Equity Funds Used During Construction | | (2.4) | | | (2.0) | |
| Mark-to-Market of Risk Management Contracts | | 60.1 | | | 34.3 | |
| | | | |
| | | | |
| Deferred Fuel Over/Under-Recovery, Net | | 26.0 | | | (100.3) | |
| | | | |
| Change in Other Noncurrent Assets | | (5.5) | | | 1.4 | |
| Change in Other Noncurrent Liabilities | | (33.0) | | | (20.4) | |
| Changes in Certain Components of Working Capital: | | | | |
| Accounts Receivable, Net | | 54.5 | | | 72.4 | |
| Fuel, Materials and Supplies | | (59.3) | | | 19.5 | |
| Margin Deposits | | (11.1) | | | 61.4 | |
| Accounts Payable | | (156.1) | | | 33.6 | |
| Accrued Taxes, Net | | 23.6 | | | 26.1 | |
| Other Current Assets | | 2.9 | | | 2.3 | |
| Other Current Liabilities | | (1.2) | | | 18.3 | |
| Net Cash Flows from Operating Activities | | 164.3 | | | 416.1 | |
| | | | |
| INVESTING ACTIVITIES | | | | |
| Construction Expenditures | | (287.4) | | | (233.9) | |
| | | | |
| Change in Advances to Affiliates, Net | | 1.1 | | | 1.1 | |
| | | | |
| Other Investing Activities | | 1.5 | | | 9.7 | |
| Net Cash Flows Used for Investing Activities | | (284.8) | | | (223.1) | |
| | | | |
| FINANCING ACTIVITIES | | | | |
| | | | |
| | | | |
| Change in Advances from Affiliates, Net | | 128.0 | | | (163.8) | |
| Retirement of Long-term Debt – Nonaffiliated | | (13.0) | | | (12.7) | |
| | | | |
| | | | |
| Principal Payments for Finance Lease Obligations | | (2.0) | | | (2.0) | |
| Dividends Paid on Common Stock | | — | | | (18.8) | |
| Other Financing Activities | | 0.2 | | | 0.2 | |
| Net Cash Flows from (Used for) Financing Activities | | 113.2 | | | (197.1) | |
| | | | |
| Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding | | (7.3) | | | (4.1) | |
| Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period | | 21.9 | | | 20.1 | |
| Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period | | $ | 14.6 | | | $ | 16.0 | |
| | | | |
| SUPPLEMENTARY INFORMATION | | | | |
| Cash Paid for Interest, Net of Capitalized Amounts | | $ | 37.9 | | | $ | 21.0 | |
| | | | |
| Noncash Acquisitions Under Finance Leases | | 0.6 | | | 0.3 | |
| Construction Expenditures Included in Current Liabilities as of March 31, | | 122.6 | | | 94.9 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
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
| | | | | | | | | | | | | | | |
| | | |
| | Three Months Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| | (in millions of KWhs) |
| Retail: | | | | | | | |
| Residential | 1,463 | | | 1,539 | | | | | |
| Commercial | 1,189 | | | 1,119 | | | | | |
| Industrial | 1,804 | | | 1,790 | | | | | |
| Miscellaneous | 16 | | | 16 | | | | | |
| Total Retail | 4,472 | | | 4,464 | | | | | |
| | | | | | | |
| Wholesale | 1,417 | | | 1,957 | | | | | |
| | | | | | | |
| Total KWhs | 5,889 | | | 6,421 | | | | | |
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
| | | | | | | | | | | | | | | |
| | | |
| | Three Months Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| | (in degree days) |
| Actual – Heating (a) | 1,687 | | | 2,240 | | | | | |
| Normal – Heating (b) | 2,182 | | | 2,171 | | | | | |
| | | | | | | |
| Actual – Cooling (c) | — | | | — | | | | | |
| Normal – Cooling (b) | 1 | | | 1 | | | | | |
(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.
First Quarter of 2023 Compared to Nine Months Ended September 30, 2016First Quarter of 2022
| | | | | | | | |
| Indiana Michigan Power Company and Subsidiaries |
| Reconciliation of First Quarter of 2022 to First Quarter of 2023 |
| Net Income |
| (in millions) |
| | |
| First Quarter of 2022 | | $ | 89.5 | |
| | |
| Changes in Gross Margin: | | |
| Retail Margins | | 40.3 | |
| | |
| Margins from Off-system Sales | | 14.8 | |
| Transmission Revenues | | (3.6) | |
| Other Revenues | | 4.8 | |
| Total Change in Gross Margin | | 56.3 | |
| | |
| Changes in Expenses and Other: | | |
| Other Operation and Maintenance | | (38.0) | |
| | |
| Depreciation and Amortization | | 9.7 | |
| Taxes Other Than Income Taxes | | 5.7 | |
| Other Income | | (2.0) | |
| | |
| | |
| Non-Service Cost Components of Net Periodic Benefit Cost | | 1.7 | |
| Interest Expense | | (2.9) | |
| Total Change in Expenses and Other | | (25.8) | |
| | |
| Income Tax Expense | | (17.2) | |
| | |
| First Quarter of 2023 | | $ | 102.8 | |
|
| | | | |
| Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017 |
| Net Income |
| (in millions) |
| |
| Nine Months Ended September 30, 2016 | | $ | 303.8 |
|
| | | |
| Changes in Gross Margin: | | |
|
| Retail Margins | | (93.7 | ) |
| Off-system Sales | | (0.1 | ) |
| Transmission Revenues | | 25.9 |
|
| Other Revenues | | 3.2 |
|
| Total Change in Gross Margin | | (64.7 | ) |
| | | |
|
| Changes in Expenses and Other: | | |
|
| Other Operation and Maintenance | | (8.3 | ) |
| Depreciation and Amortization | | (14.1 | ) |
| Taxes Other Than Income Taxes | | 0.6 |
|
| Interest Income | | 0.3 |
|
| Carrying Costs Income | | 0.8 |
|
| Allowance for Equity Funds Used During Construction | | (2.9 | ) |
| Interest Expense | | (2.8 | ) |
| Total Change in Expenses and Other | | (26.4 | ) |
| | | |
|
| Income Tax Expense | | 36.0 |
|
| | | |
|
| Nine Months Ended September 30, 2017 | | $ | 248.7 |
|
The major components of the decreaseincrease 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 decreased $94 increased $40 million primarily due to the following:
•A $72$25 million increase in weather-normalized retail margins primarily in the residential and commercial classes.
•An $18 million increase due to a base rate revenue increase in Indiana and rider increases.
•A $9 million increase due to a reduction in a provision for refund.
These increases were partially offset by:
•An $18 million decrease in weather-related usage primarily driven bydue to a 30%25% decrease in heating degree days and an 18% decrease in cooling degree days.
A $14 million decrease primarily due to prior year recognition of deferred billing in West Virginia as approved by the WVPSC.
A $3 million decrease in weather-normalized margin primarily driven by the commercial class.
Transmission Revenues•Margins from Off-system Sales increased $26$15 million primarily due to estimated PJM performance incentives for Rockport Plant, Unit 2 merchant operations related to winter storm Elliott in December 2022.
•Transmission Revenues decreased $4 million primarily due to lower PJM rates for certain point-to-point transmission service resulting from a December 2022 FERC approved settlement agreement.
•Other Revenues increased $5 million primarily due to an $8 million increase in formula rates drivenbarging revenues by continued investmentRiver Transportation Division (RTD), partially offset by a $4 million decrease in transmission assets. Thisthe sale of allowances. The increase isin RTD barging revenues was partially offset in Other Operation and Maintenance expenses below.below and the decrease due to the sale of allowances was partially offset in Retail Margins above.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $8$38 million primarily due to the following:
•A $13$9 million increase due to a decreased Nuclear Electric Insurance Limited distribution in 2023.
•A $9 million increase in recoverable PJM transmissionDemand Side Management Rider expenses primarily due to an increase in revenues collected from customers. This increase was partially offset in Retail Margins above.
•An $8 million increase in nuclear expenses at Cook Plant primarily due to refueling outage expenses.
•An $8 million increase in nonutility operation expense primarily due to an increase in RTD expenses. This increase was offset in expense is offset within Gross MarginOther Revenues above.
A $6 million gain on the sale of property in 2016.
These increases were partially offset by:
An $8 million decrease in storm-related expenses.
A $5 million decrease in employee-related expenses.
•Depreciation and Amortizationexpenses increased $14decreased $10 million primarily due to a higher depreciable base.
the expiration of the Rockport Plant, Unit 2 lease in December 2022, partially offset by an increase in depreciation expense due to the acquisition of Rockport Plant, Unit 2 at the end of the lease.•Taxes Other Than Income Tax ExpenseTaxes decreased $36$6 million primarily due to athe repeal of the Indiana Utility Receipts Tax in July 2022. This decrease was partially offset in Retail Margins above.
•Income Tax Expense increased $17 million primarily due to the following:
•A $6 million increase due to higher pretax book income.
•A $6 million decrease in pretax book income and the recordingamortization of federal income tax adjustments.Excess ADIT.
•A $3 million increase in state taxes.
APPALACHIAN
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2017March 31, 2023 and 20162022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | |
| | | Three Months Ended March 31, | | |
| | | | |
| | | 2023 | | 2022 | | | | |
| REVENUES | | | | | | | | |
| Electric Generation, Transmission and Distribution | | $ | 642.8 | | | $ | 612.0 | | | | | |
| Sales to AEP Affiliates | | 1.2 | | | 2.0 | | | | | |
| Other Revenues – Affiliated | | 15.9 | | | 8.4 | | | | | |
| Other Revenues – Nonaffiliated | | 3.1 | | | 2.8 | | | | | |
| TOTAL REVENUES | | 663.0 | | | 625.2 | | | | | |
| | | | | | | | |
| EXPENSES | | | | | | | | |
| Purchased Electricity, Fuel and Other Consumables Used for Electric Generation | | 99.2 | | | 105.7 | | | | | |
| | | | | | | | |
| Purchased Electricity from AEP Affiliates | | 45.1 | | | 57.1 | | | | | |
| Other Operation | | 169.7 | | | 139.3 | | | | | |
| Maintenance | | 58.6 | | | 51.0 | | | | | |
| | | | | | | | |
| Depreciation and Amortization | | 125.2 | | | 134.9 | | | | | |
| Taxes Other Than Income Taxes | | 19.5 | | | 25.2 | | | | | |
| TOTAL EXPENSES | | 517.3 | | | 513.2 | | | | | |
| | | | | | | | |
| OPERATING INCOME | | 145.7 | | | 112.0 | | | | | |
| | | | | | | | |
| Other Income (Expense): | | | | | | | | |
| Other Income | | 0.6 | | | 2.6 | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Non-Service Cost Components of Net Periodic Benefit Cost | | 8.0 | | | 6.3 | | | | | |
| Interest Expense | | (33.2) | | | (30.3) | | | | | |
| | | | | | | | |
| INCOME BEFORE INCOME TAX EXPENSE | | 121.1 | | | 90.6 | | | | | |
| | | | | | | | |
| Income Tax Expense | | 18.3 | | | 1.1 | | | | | |
| | | | | | | | |
| NET INCOME | | $ | 102.8 | | | $ | 89.5 | | | | | |
| | | | | | | | |
| The common stock of I&M is wholly-owned by Parent. |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended | | Nine Months Ended |
| | | September 30, | | September 30, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| REVENUES | | | | | | | | |
|
| Electric Generation, Transmission and Distribution | | $ | 674.4 |
| | $ | 739.0 |
| | $ | 2,045.0 |
| | $ | 2,153.3 |
|
| Sales to AEP Affiliates | | 41.9 |
| | 36.4 |
| | 130.6 |
| | 109.0 |
|
| Other Revenues | | 3.0 |
| | 2.8 |
| | 11.8 |
| | 9.4 |
|
| TOTAL REVENUES | | 719.3 |
| | 778.2 |
| | 2,187.4 |
| | 2,271.7 |
|
| | | | | | | | | |
| EXPENSES | | |
| | | | |
| | |
|
| Fuel and Other Consumables Used for Electric Generation | | 178.6 |
| | 190.1 |
| | 498.3 |
| | 494.1 |
|
| Purchased Electricity for Resale | | 61.1 |
| | 69.2 |
| | 217.1 |
| | 240.9 |
|
| Other Operation | | 115.7 |
| | 117.6 |
| | 366.2 |
| | 349.4 |
|
| Maintenance | | 55.8 |
| | 66.8 |
| | 187.8 |
| | 196.3 |
|
| Depreciation and Amortization | | 102.8 |
| | 98.1 |
| | 304.1 |
| | 290.0 |
|
| Taxes Other Than Income Taxes | | 32.3 |
| | 32.0 |
| | 93.3 |
| | 93.9 |
|
| TOTAL EXPENSES | | 546.3 |
| | 573.8 |
| | 1,666.8 |
| | 1,664.6 |
|
| | | | | | | | | |
| OPERATING INCOME | | 173.0 |
| | 204.4 |
| | 520.6 |
| | 607.1 |
|
| | | | | | | | | |
| Other Income (Expense): | | |
| | | | |
| | |
|
| Interest Income | | 0.3 |
| | 0.3 |
| | 1.1 |
| | 0.8 |
|
| Carrying Costs Income | | 0.4 |
| | — |
| | 1.0 |
| | 0.2 |
|
| Allowance for Equity Funds Used During Construction | | 2.7 |
| | 4.5 |
| | 6.2 |
| | 9.1 |
|
| Interest Expense | | (47.2 | ) | | (46.4 | ) | | (143.5 | ) | | (140.7 | ) |
| | | | | | | | | |
| INCOME BEFORE INCOME TAX EXPENSE | | 129.2 |
| | 162.8 |
| | 385.4 |
| | 476.5 |
|
| | | | | | | | | |
| Income Tax Expense | | 43.2 |
| | 58.7 |
| | 136.7 |
| | 172.7 |
|
| | | | | | | | | |
| NET INCOME | | $ | 86.0 |
| | $ | 104.1 |
| | $ | 248.7 |
| | $ | 303.8 |
|
|
| | | | |
The common stock of APCo is wholly-owned by Parent. | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
APPALACHIANINDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2017March 31, 2023 and 20162022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | |
| | | | |
| | | Three Months Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| Net Income | | $ | 102.8 | | | $ | 89.5 | | | | | |
| | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | | | | | | | | |
| Cash Flow Hedges, Net of Tax of $(0.2) and $0.1 for 2023 and 2022, Respectively | | (0.7) | | | 0.4 | | | | | |
| Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.5) and $0 for 2023 and 2022, Respectively | | (1.9) | | | (0.1) | | | | | |
| | | | | | | | |
| TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | | (2.6) | | | 0.3 | | | | | |
| | | | | | | | |
| TOTAL COMPREHENSIVE INCOME | | $ | 100.2 | | | $ | 89.8 | | | | | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended | | Nine Months Ended |
| | | September 30, | | September 30, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| Net Income | | $ | 86.0 |
| | $ | 104.1 |
| | $ | 248.7 |
| | $ | 303.8 |
|
| | | | | | | | | |
| OTHER COMPREHENSIVE LOSS, NET OF TAXES | | | | |
| | |
| | |
| Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2017 and 2016, Respectively, and $(0.3) and $(0.3) for the Nine Months Ended September 30, 2017 and 2016, Respectively | | (0.1 | ) | | (0.2 | ) | | (0.5 | ) | | (0.6 | ) |
| Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2017 and 2016, Respectively, and $(0.4) and $(0.5) for the Nine Months Ended September 30, 2017 and 2016, Respectively | | (0.3 | ) | | (0.3 | ) | | (0.9 | ) | | (1.0 | ) |
| | | | | | | | | |
| TOTAL OTHER COMPREHENSIVE LOSS | | (0.4 | ) | | (0.5 | ) | | (1.4 | ) | | (1.6 | ) |
| | | | | | | | | |
| TOTAL COMPREHENSIVE INCOME | | $ | 85.6 |
| | $ | 103.6 |
| | $ | 247.3 |
| | $ | 302.2 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
APPALACHIANINDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the NineThree Months Ended September 30, 2017March 31, 2023 and 20162022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common
Stock | | Paid-in
Capital | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income (Loss) | | Total |
| TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2021 | | $ | 56.6 | | | $ | 980.9 | | | $ | 1,748.5 | | | $ | (1.3) | | | $ | 2,784.7 | |
| | | | | | | | | | |
| | | | | | | | | | |
| Common Stock Dividends | | | | | | (25.0) | | | | | (25.0) | |
| Net Income | | | | | | 89.5 | | | | | 89.5 | |
| Other Comprehensive Income | | | | | | | | 0.3 | | | 0.3 | |
| TOTAL COMMON SHAREHOLDER'S EQUITY -MARCH 31, 2022 | | $ | 56.6 | | | $ | 980.9 | | | $ | 1,813.0 | | | $ | (1.0) | | | $ | 2,849.5 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2022 | | $ | 56.6 | | | $ | 988.8 | | | $ | 1,963.2 | | | $ | (0.3) | | | $ | 3,008.3 | |
| | | | | | | | | | |
| | | | | | | | | | |
| Common Stock Dividends | | | | | | (31.2) | | | | | (31.2) | |
| Net Income | | | | | | 102.8 | | | | | 102.8 | |
| Other Comprehensive Loss | | | | | | | | (2.6) | | | (2.6) | |
| TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2023 | | $ | 56.6 | | | $ | 988.8 | | | $ | 2,034.8 | | | $ | (2.9) | | | $ | 3,077.3 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
| TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2015 | | $ | 260.4 |
| | $ | 1,828.7 |
| | $ | 1,388.7 |
| | $ | (2.8 | ) | | $ | 3,475.0 |
|
| | | | | | | | | | | |
| Common Stock Dividends | | |
| | |
| | (225.0 | ) | | |
| | (225.0 | ) |
| Net Income | | |
| | |
| | 303.8 |
| | |
| | 303.8 |
|
| Other Comprehensive Loss | | |
| | |
| | |
| | (1.6 | ) | | (1.6 | ) |
| TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2016 | | $ | 260.4 |
| | $ | 1,828.7 |
| | $ | 1,467.5 |
| | $ | (4.4 | ) | | $ | 3,552.2 |
|
| | | | | | | | | | | |
| TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2016 | | $ | 260.4 |
| | $ | 1,828.7 |
| | $ | 1,502.8 |
| | $ | (8.4 | ) | | $ | 3,583.5 |
|
| | | | | | | | | | | |
| Common Stock Dividends | | |
| | |
| | (90.0 | ) | | |
| | (90.0 | ) |
| Net Income | | |
| | |
| | 248.7 |
| | |
| | 248.7 |
|
| Other Comprehensive Loss | | |
| | |
| | |
| | (1.4 | ) | | (1.4 | ) |
| TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2017 | | $ | 260.4 |
| | $ | 1,828.7 |
| | $ | 1,661.5 |
| | $ | (9.8 | ) | | $ | 3,740.8 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
APPALACHIANINDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2017March 31, 2023 and December 31, 20162022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | March 31, | | December 31, |
| | | 2023 | | 2022 |
| CURRENT ASSETS | | | | |
| Cash and Cash Equivalents | | $ | 8.5 | | | $ | 4.2 | |
| Advances to Affiliates | | 60.0 | | | 23.0 | |
| Accounts Receivable: | | | | |
| Customers | | 62.4 | | | 96.6 | |
| Affiliated Companies | | 86.6 | | | 104.0 | |
| Accrued Unbilled Revenues | | — | | | 0.6 | |
| Miscellaneous | | 4.6 | | | 4.7 | |
| Allowance for Uncollectible Accounts | | — | | | (0.1) | |
| Total Accounts Receivable | | 153.6 | | | 205.8 | |
| Fuel | | 66.5 | | | 46.5 | |
| Materials and Supplies | | 192.2 | | | 188.1 | |
| Risk Management Assets | | 5.9 | | | 15.2 | |
| | | | |
| Regulatory Asset for Under-Recovered Fuel Costs | | 43.3 | | | 47.1 | |
| | | | |
| | | | |
| Prepayments and Other Current Assets | | 41.4 | | | 41.9 | |
| TOTAL CURRENT ASSETS | | 571.4 | | | 571.8 | |
| | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | |
| Electric: | | | | |
| Generation | | 5,590.1 | | | 5,585.1 | |
| Transmission | | 1,861.0 | | | 1,842.2 | |
| Distribution | | 3,054.8 | | | 3,024.7 | |
| Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) | | 813.6 | | | 839.3 | |
| Construction Work in Progress | | 288.2 | | | 253.0 | |
| Total Property, Plant and Equipment | | 11,607.7 | | | 11,544.3 | |
| Accumulated Depreciation, Depletion and Amortization | | 4,190.8 | | | 4,132.8 | |
| TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 7,416.9 | | | 7,411.5 | |
| | | | |
| OTHER NONCURRENT ASSETS | | | | |
| Regulatory Assets | | 420.8 | | | 459.6 | |
| Spent Nuclear Fuel and Decommissioning Trusts | | 3,501.1 | | | 3,341.2 | |
| | | | |
| Operating Lease Assets | | 60.9 | | | 64.3 | |
| Deferred Charges and Other Noncurrent Assets | | 271.2 | | | 270.5 | |
| TOTAL OTHER NONCURRENT ASSETS | | 4,254.0 | | | 4,135.6 | |
| | | | |
| TOTAL ASSETS | | $ | 12,242.3 | | | $ | 12,118.9 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
|
| | | | | | | | |
| | | September 30, | | December 31, |
| | | 2017 | | 2016 |
| CURRENT ASSETS | | | | |
| Cash and Cash Equivalents | | $ | 2.9 |
| | $ | 2.7 |
|
| Restricted Cash for Securitized Funding | | 8.3 |
| | 15.8 |
|
| Advances to Affiliates | | 23.6 |
| | 24.1 |
|
| Accounts Receivable: | | | | |
| Customers | | 96.8 |
| | 131.4 |
|
| Affiliated Companies | | 59.5 |
| | 54.4 |
|
| Accrued Unbilled Revenues | | 41.1 |
| | 52.7 |
|
| Miscellaneous | | 1.3 |
| | 0.9 |
|
| Allowance for Uncollectible Accounts | | (2.7 | ) | | (3.5 | ) |
| Total Accounts Receivable | | 196.0 |
| | 235.9 |
|
| Fuel | | 96.3 |
| | 112.0 |
|
| Materials and Supplies | | 100.8 |
| | 98.8 |
|
| Risk Management Assets | | 30.3 |
| | 2.6 |
|
| Accrued Tax Benefits | | 0.4 |
| | 4.2 |
|
| Regulatory Asset for Under-Recovered Fuel Costs | | 63.5 |
| | 68.4 |
|
| Margin Deposits | | 11.8 |
| | 17.5 |
|
| Prepayments and Other Current Assets | | 18.2 |
| | 9.7 |
|
| TOTAL CURRENT ASSETS | | 552.1 |
| | 591.7 |
|
| | | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | |
| Electric: | | | | |
| Generation | | 6,393.7 |
| | 6,332.8 |
|
| Transmission | | 2,904.4 |
| | 2,796.9 |
|
| Distribution | | 3,703.5 |
| | 3,569.1 |
|
| Other Property, Plant and Equipment | | 409.8 |
| | 373.5 |
|
| Construction Work in Progress | | 493.5 |
| | 390.3 |
|
| Total Property, Plant and Equipment | | 13,904.9 |
| | 13,462.6 |
|
| Accumulated Depreciation and Amortization | | 3,836.7 |
| | 3,636.8 |
|
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 10,068.2 |
| | 9,825.8 |
|
| | | | | |
| OTHER NONCURRENT ASSETS | | | | |
| Regulatory Assets | | 1,100.1 |
| | 1,121.1 |
|
| Securitized Assets | | 288.0 |
| | 305.3 |
|
| Long-term Risk Management Assets | | 0.6 |
| | — |
|
| Deferred Charges and Other Noncurrent Assets | | 113.6 |
| | 133.3 |
|
| TOTAL OTHER NONCURRENT ASSETS | | 1,502.3 |
| | 1,559.7 |
|
| | | | | |
| TOTAL ASSETS | | $ | 12,122.6 |
| | $ | 11,977.2 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
APPALACHIANINDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2017March 31, 2023 and December 31, 20162022
(dollars in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | | March 31, | | December 31, |
| | | 2023 | | 2022 |
| CURRENT LIABILITIES | | | | |
| Advances from Affiliates | | $ | — | | | $ | 249.9 | |
| Accounts Payable: | | | | |
| General | | 165.4 | | | 173.4 | |
| Affiliated Companies | | 91.8 | | | 121.5 | |
Long-term Debt Due Within One Year – Nonaffiliated (March 31, 2023 and December 31, 2022 Amounts Include $83.8 and $89.6, Respectively, Related to DCC Fuel) | | 86.0 | | | 341.8 | |
| | | | |
| Customer Deposits | | 46.3 | | | 48.6 | |
| Accrued Taxes | | 124.3 | | | 103.2 | |
| Accrued Interest | | 24.8 | | | 36.9 | |
| | | | |
| Obligations Under Operating Leases | | 16.7 | | | 16.0 | |
| | | | |
| Other Current Liabilities | | 79.5 | | | 105.8 | |
| TOTAL CURRENT LIABILITIES | | 634.8 | | | 1,197.1 | |
| | | | |
| NONCURRENT LIABILITIES | | | | |
| Long-term Debt – Nonaffiliated | | 3,403.0 | | | 2,919.0 | |
| | | | |
| Deferred Income Taxes | | 1,162.5 | | | 1,157.0 | |
| Regulatory Liabilities and Deferred Investment Tax Credits | | 1,824.0 | | | 1,702.2 | |
| Asset Retirement Obligations | | 2,046.2 | | | 2,027.6 | |
| Obligations Under Operating Leases | | 45.2 | | | 48.9 | |
| Deferred Credits and Other Noncurrent Liabilities | | 49.3 | | | 58.8 | |
| TOTAL NONCURRENT LIABILITIES | | 8,530.2 | | | 7,913.5 | |
| | | | |
| TOTAL LIABILITIES | | 9,165.0 | | | 9,110.6 | |
| | | | |
| Rate Matters (Note 4) | | | | |
| Commitments and Contingencies (Note 5) | | | | |
| | | | |
| 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 | | 988.8 | | | 988.8 | |
| Retained Earnings | | 2,034.8 | | | 1,963.2 | |
| Accumulated Other Comprehensive Income (Loss) | | (2.9) | | | (0.3) | |
| TOTAL COMMON SHAREHOLDER’S EQUITY | | 3,077.3 | | | 3,008.3 | |
| | | | |
| TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 12,242.3 | | | $ | 12,118.9 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
|
| | | | | | | | |
| | | September 30, | | December 31, |
| | | 2017 | | 2016 |
| | | (in millions) |
| CURRENT LIABILITIES | | | | |
| Advances from Affiliates | | $ | 69.5 |
| | $ | 79.6 |
|
| Accounts Payable: | | |
| | |
|
| General | | 235.4 |
| | 253.7 |
|
| Affiliated Companies | | 75.5 |
| | 82.6 |
|
| Long-term Debt Due Within One Year - Nonaffiliated | | 149.2 |
| | 503.1 |
|
| Risk Management Liabilities | | 0.9 |
| | 0.3 |
|
| Customer Deposits | | 84.0 |
| | 83.1 |
|
| Accrued Taxes | | 64.0 |
| | 107.6 |
|
| Accrued Interest | | 71.4 |
| | 40.6 |
|
| Other Current Liabilities | | 99.2 |
| | 129.5 |
|
| TOTAL CURRENT LIABILITIES | | 849.1 |
| | 1,280.1 |
|
| | | | | |
| NONCURRENT LIABILITIES | | | | |
| Long-term Debt - Nonaffiliated | | 3,830.1 |
| | 3,530.8 |
|
| Long-term Risk Management Liabilities | | 0.3 |
| | 0.9 |
|
| Deferred Income Taxes | | 2,796.7 |
| | 2,672.3 |
|
| Regulatory Liabilities and Deferred Investment Tax Credits | | 634.4 |
| | 627.8 |
|
| Asset Retirement Obligations | | 101.2 |
| | 108.8 |
|
| Employee Benefits and Pension Obligations | | 92.2 |
| | 108.5 |
|
| Deferred Credits and Other Noncurrent Liabilities | | 77.8 |
| | 64.5 |
|
| TOTAL NONCURRENT LIABILITIES | | 7,532.7 |
| | 7,113.6 |
|
| | | | | |
| TOTAL LIABILITIES | | 8,381.8 |
| | 8,393.7 |
|
| | | | | |
| Rate Matters (Note 4) | |
| |
|
| Commitments and Contingencies (Note 5) | |
| |
|
| | | | | |
| 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 | | 1,661.5 |
| | 1,502.8 |
|
| Accumulated Other Comprehensive Income (Loss) | | (9.8 | ) | | (8.4 | ) |
| TOTAL COMMON SHAREHOLDER’S EQUITY | | 3,740.8 |
| | 3,583.5 |
|
| | | | | |
| TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 12,122.6 |
| | $ | 11,977.2 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
APPALACHIANINDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the NineThree Months Ended September 30, 2017March 31, 2023 and 20162022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | | Three Months Ended March 31, |
| | | 2023 | | 2022 |
| OPERATING ACTIVITIES | | | | |
| Net Income | | $ | 102.8 | | | $ | 89.5 | |
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | |
| Depreciation and Amortization | | 125.2 | | | 134.9 | |
| | | | |
| Deferred Income Taxes | | (3.3) | | | (11.5) | |
| Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net | | 18.1 | | | (6.5) | |
| | | | |
| | | | |
| Allowance for Equity Funds Used During Construction | | (0.5) | | | (2.9) | |
| Mark-to-Market of Risk Management Contracts | | 8.8 | | | (2.8) | |
| Amortization of Nuclear Fuel | | 25.0 | | | 22.9 | |
| | | | |
| Deferred Fuel Over/Under-Recovery, Net | | 3.8 | | | 6.1 | |
| Change in Other Noncurrent Assets | | (4.3) | | | (5.2) | |
| Change in Other Noncurrent Liabilities | | 3.7 | | | 2.4 | |
| Changes in Certain Components of Working Capital: | | | | |
| Accounts Receivable, Net | | 52.7 | | | 25.9 | |
| Fuel, Materials and Supplies | | (24.1) | | | 6.3 | |
| | | | |
| Accounts Payable | | (27.8) | | | 3.8 | |
| | | | |
| Accrued Taxes, Net | | 21.1 | | | 22.3 | |
| | | | |
| | | | |
| Other Current Assets | | (1.9) | | | 15.3 | |
| Other Current Liabilities | | (41.8) | | | (53.6) | |
| Net Cash Flows from Operating Activities | | 257.5 | | | 246.9 | |
| | | | |
| INVESTING ACTIVITIES | | | | |
| Construction Expenditures | | (141.7) | | | (129.9) | |
| Change in Advances to Affiliates, Net | | (37.0) | | | — | |
| Purchases of Investment Securities | | (536.3) | | | (507.7) | |
| Sales of Investment Securities | | 517.6 | | | 493.5 | |
| Acquisitions of Nuclear Fuel | | (1.7) | | | (31.1) | |
| | | | |
| Other Investing Activities | | 3.3 | | | 0.3 | |
| Net Cash Flows Used for Investing Activities | | (195.8) | | | (174.9) | |
| | | | |
| FINANCING ACTIVITIES | | | | |
| | | | |
| | | | |
| Issuance of Long-term Debt – Nonaffiliated | | 499.8 | | | — | |
| Change in Advances from Affiliates, Net | | (249.9) | | | (19.7) | |
| Retirement of Long-term Debt – Nonaffiliated | | (274.3) | | | (23.8) | |
| Principal Payments for Finance Lease Obligations | | (1.9) | | | (1.6) | |
| Dividends Paid on Common Stock | | (31.2) | | | (25.0) | |
| Other Financing Activities | | 0.1 | | | 0.1 | |
| Net Cash Flows Used for Financing Activities | | (57.4) | | | (70.0) | |
| | | | |
| Net Increase in Cash and Cash Equivalents | | 4.3 | | | 2.0 | |
| Cash and Cash Equivalents at Beginning of Period | | 4.2 | | | 1.3 | |
| Cash and Cash Equivalents at End of Period | | $ | 8.5 | | | $ | 3.3 | |
| | | | |
| SUPPLEMENTARY INFORMATION | | | | |
| Cash Paid for Interest, Net of Capitalized Amounts | | $ | 44.4 | | | $ | 41.6 | |
| Net Cash Paid for Income Taxes | | 2.4 | | | — | |
| Noncash Acquisitions Under Finance Leases | | 2.2 | | | 0.3 | |
| Construction Expenditures Included in Current Liabilities as of March 31, | | 61.3 | | | 60.7 | |
| | | | |
| | | | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
|
| | | | | | | | |
| | | Nine Months Ended September 30, |
| | | 2017 | | 2016 |
| OPERATING ACTIVITIES | | |
| | |
|
| Net Income | | $ | 248.7 |
| | $ | 303.8 |
|
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | |
| | |
|
| Depreciation and Amortization | | 304.1 |
| | 290.0 |
|
| Deferred Income Taxes | | 121.7 |
| | 100.9 |
|
| Carrying Costs Income | | (1.0 | ) | | (0.2 | ) |
| Allowance for Equity Funds Used During Construction | | (6.2 | ) | | (9.1 | ) |
| Mark-to-Market of Risk Management Contracts | | (28.3 | ) | | 18.4 |
|
| Pension Contributions to Qualified Plan Trust | | (10.2 | ) | | (8.8 | ) |
| Property Taxes | | 29.8 |
| | 29.2 |
|
| Deferred Fuel Over/Under-Recovery, Net | | 4.9 |
| | 19.0 |
|
| Change in Other Noncurrent Assets | | 8.3 |
| | (5.1 | ) |
| Change in Other Noncurrent Liabilities | | 7.9 |
| | (23.0 | ) |
| Changes in Certain Components of Working Capital: | | |
| | |
|
| Accounts Receivable, Net | | 39.9 |
| | (20.5 | ) |
| Fuel, Materials and Supplies | | 14.0 |
| | (1.2 | ) |
| Accounts Payable | | 6.2 |
| | 4.9 |
|
| Accrued Taxes, Net | | (44.2 | ) | | (13.9 | ) |
| Other Current Assets | | (2.5 | ) | | (0.2 | ) |
| Other Current Liabilities | | 9.1 |
| | (4.1 | ) |
| Net Cash Flows from Operating Activities | | 702.2 |
| | 680.1 |
|
| | | | | |
| INVESTING ACTIVITIES | | |
| | |
|
| Construction Expenditures | | (560.0 | ) | | (472.7 | ) |
| Change in Restricted Cash for Securitized Funding | | 7.5 |
| | 7.0 |
|
| Change in Advances to Affiliates, Net | | 0.5 |
| | 1.2 |
|
| Other Investing Activities | | 11.8 |
| | 10.6 |
|
| Net Cash Flows Used for Investing Activities | | (540.2 | ) | | (453.9 | ) |
| | | | | |
| FINANCING ACTIVITIES | | |
| | |
|
| Issuance of Long-term Debt - Nonaffiliated | | 320.9 |
| | 314.1 |
|
| Change in Advances from Affiliates, Net | | (10.1 | ) | | (96.9 | ) |
| Retirement of Long-term Debt - Nonaffiliated | | (377.9 | ) | | (213.6 | ) |
| Principal Payments for Capital Lease Obligations | | (5.2 | ) | | (4.7 | ) |
| Dividends Paid on Common Stock | | (90.0 | ) | | (225.0 | ) |
| Other Financing Activities | | 0.5 |
| | 0.4 |
|
| Net Cash Flows Used for Financing Activities | | (161.8 | ) | | (225.7 | ) |
| | | | | |
| Net Increase in Cash and Cash Equivalents | | 0.2 |
| | 0.5 |
|
| Cash and Cash Equivalents at Beginning of Period | | 2.7 |
| | 2.8 |
|
| Cash and Cash Equivalents at End of Period | | $ | 2.9 |
| | $ | 3.3 |
|
| | | | | |
| SUPPLEMENTARY INFORMATION | | |
| | |
|
| Cash Paid for Interest, Net of Capitalized Amounts | | $ | 107.1 |
| | $ | 113.2 |
|
| Net Cash Paid for Income Taxes | | 24.4 |
| | 55.8 |
|
| Noncash Acquisitions Under Capital Leases | | 2.9 |
| | 2.1 |
|
| Construction Expenditures Included in Current Liabilities as of September 30, | | 107.2 |
| | 66.8 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
INDIANA MICHIGANOHIO POWER COMPANY
AND SUBSIDIARIES
INDIANA MICHIGAN
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
| | | | | | | | | | | | | | | |
| | | |
| | Three Months Ended March 31, | | |
| 2023 | | 2022 | | | | |
| | (in millions of KWhs) |
| Retail: | | | | | | | |
| Residential | 3,734 | | | 4,134 | | | | | |
| Commercial | 4,000 | | | 3,851 | | | | | |
| Industrial | 3,418 | | | 3,503 | | | | | |
| Miscellaneous | 30 | | | 30 | | | | | |
| Total Retail (a) | 11,182 | | | 11,518 | | | | | |
| | | | | | | |
| Wholesale (b) | 453 | | | 571 | | | | | |
| | | | | | | |
| Total KWhs | 11,635 | | | 12,089 | | | | | |
|
| | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions of KWhs) |
| Retail: | |
| | |
| | |
| | |
|
| Residential | 1,404 |
| | 1,619 |
| | 4,015 |
| | 4,344 |
|
| Commercial | 1,313 |
| | 1,405 |
| | 3,640 |
| | 3,780 |
|
| Industrial | 1,978 |
| | 1,996 |
| | 5,793 |
| | 5,876 |
|
| Miscellaneous | 16 |
| | 15 |
| | 50 |
| | 50 |
|
| Total Retail | 4,711 |
| | 5,035 |
| | 13,498 |
| | 14,050 |
|
| | | | | | | | |
| Wholesale | 2,807 |
| | 2,613 |
| | 8,567 |
| | 7,038 |
|
| | | | | | | | |
| Total KWhs | 7,518 |
| | 7,648 |
| | 22,065 |
| | 21,088 |
|
(a)Represents energy delivered to distribution customers.
(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold to 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
| | | | | | | | | | | | | | | |
| | | |
| | Three Months Ended March 31, | | |
| 2023 | | 2022 | | | | |
| | (in degree days) |
| Actual – Heating (a) | 1,344 | | | 1,864 | | | | | |
| Normal – Heating (b) | 1,891 | | | 1,886 | | | | | |
| | | | | | | |
| Actual – Cooling (c) | — | | | 1 | | | | | |
| Normal – Cooling (b) | 3 | | | 3 | | | | | |
(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.
|
| | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in degree days) |
| Actual - Heating (a) | — |
| | — |
| | 1,816 |
| | 2,196 |
|
| Normal - Heating (b) | 11 |
| | 10 |
| | 2,430 |
| | 2,449 |
|
| | | | | | | | |
| Actual - Cooling (c) | 504 |
| | 741 |
| | 764 |
| | 1,011 |
|
| Normal - Cooling (b) | 574 |
| | 571 |
| | 835 |
| | 835 |
|
| | | | | | | | |
(a) | Heating degree days are calculated on a 55 degree temperature base.Ohio Power Company and Subsidiaries |
| Reconciliation of First Quarter of 2022 to First Quarter of 2023 |
| Net Income |
| (in millions) |
| | |
(b)First Quarter of 2022 | Normal Heating/Cooling represents the thirty-year average of degree days. | $ | 83.2 | |
| | |
| Changes in Gross Margin: | | |
| Retail Margins | | 20.6 | |
| Margins from Off-system Sales | | 24.1 | |
| Transmission Revenues | | (0.9) | |
| Other Revenues | | 0.8 | |
| Total Change in Gross Margin | | 44.6 | |
| | |
| Changes in Expenses and Other: | | |
| Other Operation and Maintenance | | (40.1) | |
| Depreciation and Amortization | | (0.3) | |
| Taxes Other Than Income Taxes | | (8.3) | |
| | |
(c)Carrying Costs Income | Cooling degree days are calculated on a 65 degree temperature base. | (0.1) | |
Third Quarter of 2017 Compared to Third Quarter of 2016
|
| | | | |
| Reconciliation of Third Quarter of 2016 to Third Quarter of 2017 |
| Net Income |
| (in millions) |
| | | |
| Third Quarter of 2016 | | $ | 75.4 |
|
| | | |
|
| Changes in Gross Margin: | | |
|
| Retail Margins (a) | | (4.4 | ) |
| Transmission Revenues | | (6.2 | ) |
| Other Revenues | | (1.5 | ) |
| Total Change in Gross Margin | | (12.1 | ) |
| | | |
|
| Changes in Expenses and Other: | | |
|
| Other Operation and Maintenance | | (7.4 | ) |
| Asset Impairments and Other Related Charges | | 10.5 |
|
| Depreciation and Amortization | | (5.9 | ) |
| Taxes Other Than Income Taxes | | (1.4 | ) |
| Other Income | | 0.1 |
|
| Interest Expense | | (0.8 | ) |
| Total Change in Expenses and Other | | (4.9 | ) |
| | | |
|
| Income Tax Expense | | 6.5 |
|
| | | |
|
| Third Quarter of 2017 | | $ | 64.9 |
|
| Allowance for Equity Funds Used During Construction | | (0.2) | |
| Non-Service Cost Components of Net Periodic Benefit Cost | | 1.0 | |
| Interest Expense | | (1.9) | |
| Total Change in Expenses and Other | | (49.9) | |
| | |
| Income Tax Expense | | 0.1 | |
| | |
(a) | Includes firm wholesale sales to municipals and cooperatives. | |
| First Quarter of 2023 | | $ | 78.0 | |
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 $21 million primarily due to the following:
•A $29 million increase due to various rider revenues. This increase was partially offset in Margins from Off-system Sales and other expense items below.
•A $15 million net increase in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Transmission Revenues and Other Operation and Maintenance expenses below.
These increases were partially offset by:
•A $25 million decrease in weather-related usage due to a 28% decrease in heating degree days.
•Margins from Off-system Sales increased $24 million primarily due to the following:
•A $34 million increase in deferrals of OVEC costs. This increase was offset in Retail Margins above.
This increase was partially offset by:
•A $10 million decrease in off-system sales at OVEC due to lower market prices and volume. This decrease was offset in Retail Margins above.
Expenses and Other changed between years as follows:
•Other Operation and Maintenance expenses increased $40 million primarily due to the following:
•A $29 million increase related to an energy assistance program for qualified Ohio customers. This increase was offset in Retail Margins above.
•A $5 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses. This increase was offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $8 million primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2023 and 2022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | |
| | | | | Three Months Ended March 31, |
| | | | | | | 2023 | | 2022 |
| REVENUES | | | | | | | | |
| Electricity, Transmission and Distribution | | | | | | $ | 1,021.8 | | | $ | 824.2 | |
| Sales to AEP Affiliates | | | | | | 7.6 | | | 3.7 | |
| Other Revenues | | | | | | 5.2 | | | 2.1 | |
| TOTAL REVENUES | | | | | | 1,034.6 | | | 830.0 | |
| | | | | | | | |
| EXPENSES | | | | | | | | |
| Purchased Electricity for Resale | | | | | | 392.6 | | | 226.3 | |
| Purchased Electricity from AEP Affiliates | | | | | | — | | | 6.3 | |
| | | | | | | | |
| Other Operation | | | | | | 273.8 | | | 237.6 | |
| Maintenance | | | | | | 44.3 | | | 40.4 | |
| Depreciation and Amortization | | | | | | 75.2 | | | 74.9 | |
| Taxes Other Than Income Taxes | | | | | | 135.3 | | | 127.0 | |
| TOTAL EXPENSES | | | | | | 921.2 | | | 712.5 | |
| | | | | | | | |
| OPERATING INCOME | | | | | | 113.4 | | | 117.5 | |
| | | | | | | | |
| Other Income (Expense): | | | | | | | | |
| Interest Income | | | | | | 0.1 | | | 0.1 | |
| Carrying Costs Income | | | | | | — | | | 0.1 | |
| Allowance for Equity Funds Used During Construction | | | | | | 2.8 | | | 3.0 | |
| Non-Service Cost Components of Net Periodic Benefit Cost | | | | | | 6.5 | | | 5.5 | |
| Interest Expense | | | | | | (31.1) | | | (29.2) | |
| | | | | | | | |
| INCOME BEFORE INCOME TAX EXPENSE | | | | | | 91.7 | | | 97.0 | |
| | | | | | | | |
| Income Tax Expense | | | | | | 13.7 | | | 13.8 | |
| | | | | | | | |
| | | | | | | | |
| NET INCOME | | | | | | $ | 78.0 | | | $ | 83.2 | |
| | | | | | | | |
| The common stock of OPCo is wholly-owned by Parent. |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Three Months Ended March 31, 2023 and 2022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common
Stock | | Paid-in
Capital | | Retained
Earnings | | | | Total |
| TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2021 | | $ | 321.2 | | | $ | 838.8 | | | $ | 1,686.3 | | | | | $ | 2,846.3 | |
| | | | | | | | | | |
| Common Stock Dividends | | | | | | (15.0) | | | | | (15.0) | |
| Net Income | | | | | | 83.2 | | | | | 83.2 | |
| | | | | | | | | | |
| TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2022 | | $ | 321.2 | | | $ | 838.8 | | | $ | 1,754.5 | | | | | $ | 2,914.5 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2022 | | $ | 321.2 | | | $ | 837.8 | | | $ | 1,929.1 | | | | | $ | 3,088.1 | |
| | | | | | | | | | |
| Capital Contribution from Parent | | | | 50.0 | | | | | | 50.0 |
| | | | | | | | | | |
| Net Income | | | | | | 78.0 | | | | | 78.0 | |
| | | | | | | | | | |
| TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2023 | | $ | 321.2 | | | $ | 887.8 | | | $ | 2,007.1 | | | | | $ | 3,216.1 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2023 and December 31, 2022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | | March 31, | | December 31, |
| | | 2023 | | 2022 |
| CURRENT ASSETS | | | | |
| Cash and Cash Equivalents | | $ | 9.1 | | | $ | 9.6 | |
| | | | |
| Accounts Receivable: | | | | |
| Customers | | 104.9 | | | 119.9 | |
| Affiliated Companies | | 113.9 | | | 100.9 | |
| Accrued Unbilled Revenues | | 30.0 | | | 17.8 | |
| Miscellaneous | | 0.1 | | | 0.1 | |
| Allowance for Uncollectible Accounts | | (0.1) | | | (0.1) | |
| Total Accounts Receivable | | 248.8 | | | 238.6 | |
| Materials and Supplies | | 110.0 | | | 109.5 | |
| Renewable Energy Credits | | 36.7 | | | 35.0 | |
| | | | |
| | | | |
| | | | |
| Prepayments and Other Current Assets | | 25.6 | | | 21.7 | |
| TOTAL CURRENT ASSETS | | 430.2 | | | 414.4 | |
| | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | |
| Electric: | | | | |
| Transmission | | 3,218.7 | | | 3,198.6 | |
| Distribution | | 6,535.9 | | | 6,450.3 | |
| Other Property, Plant and Equipment | | 1,066.5 | | | 1,051.4 | |
| Construction Work in Progress | | 589.1 | | | 474.3 | |
| Total Property, Plant and Equipment | | 11,410.2 | | | 11,174.6 | |
| Accumulated Depreciation and Amortization | | 2,602.9 | | | 2,565.3 | |
| TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 8,807.3 | | | 8,609.3 | |
| | | | |
| OTHER NONCURRENT ASSETS | | | | |
| Regulatory Assets | | 352.8 | | | 327.3 | |
| | | | |
| Operating Lease Assets | | 72.5 | | | 73.8 | |
| Deferred Charges and Other Noncurrent Assets | | 489.9 | | | 578.3 | |
| TOTAL OTHER NONCURRENT ASSETS | | 915.2 | | | 979.4 | |
| | | | |
| TOTAL ASSETS | | $ | 10,152.7 | | | $ | 10,003.1 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
March 31, 2023 and December 31, 2022
(Unaudited)
| | | | | | | | | | | | | | |
| | | March 31, | | December 31, |
| | | 2023 | | 2022 |
| | (in millions) |
| CURRENT LIABILITIES | | | | |
| Advances from Affiliates | | $ | 414.6 | | | $ | 172.9 | |
| Accounts Payable: | | | | |
| General | | 333.5 | | | 337.3 | |
| Affiliated Companies | | 130.0 | | | 126.1 | |
| Long-term Debt Due Within One Year – Nonaffiliated | | 0.1 | | | 0.1 | |
| Risk Management Liabilities | | 6.0 | | | 1.8 | |
| Customer Deposits | | 73.8 | | | 96.5 | |
| Accrued Taxes | | 573.4 | | | 733.1 | |
| | | | |
| Obligations Under Operating Leases | | 13.4 | | | 13.5 | |
| Other Current Liabilities | | 145.5 | | | 154.2 | |
| TOTAL CURRENT LIABILITIES | | 1,690.3 | | | 1,635.5 | |
| | | | |
| NONCURRENT LIABILITIES | | | | |
| Long-term Debt – Nonaffiliated | | 2,970.7 | | | 2,970.2 | |
| Long-term Risk Management Liabilities | | 40.9 | | | 37.9 | |
| Deferred Income Taxes | | 1,109.1 | | | 1,101.1 | |
| Regulatory Liabilities and Deferred Investment Tax Credits | | 1,014.6 | | | 1,044.0 | |
| | | | |
| Obligations Under Operating Leases | | 59.2 | | | 60.3 | |
| Deferred Credits and Other Noncurrent Liabilities | | 51.8 | | | 66.0 | |
| TOTAL NONCURRENT LIABILITIES | | 5,246.3 | | | 5,279.5 | |
| | | | |
| TOTAL LIABILITIES | | 6,936.6 | | | 6,915.0 | |
| | | | |
| Rate Matters (Note 4) | | | | |
| Commitments and Contingencies (Note 5) | | | | |
| | | | |
| 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 | | 887.8 | | | 837.8 | |
| Retained Earnings | | 2,007.1 | | | 1,929.1 | |
| | | | |
| TOTAL COMMON SHAREHOLDER’S EQUITY | | 3,216.1 | | | 3,088.1 | |
| | | | |
| TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 10,152.7 | | | $ | 10,003.1 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2023 and 2022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | | Three Months Ended March 31, |
| | | 2023 | | 2022 |
| OPERATING ACTIVITIES | | | | |
| Net Income | | $ | 78.0 | | | $ | 83.2 | |
| Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | | | | |
| Depreciation and Amortization | | 75.2 | | | 74.9 | |
| Deferred Income Taxes | | 2.1 | | | 9.5 | |
| | | | |
| Allowance for Equity Funds Used During Construction | | (2.8) | | | (3.0) | |
| Mark-to-Market of Risk Management Contracts | | 7.2 | | | (24.0) | |
| | | | |
| Property Taxes | | 92.0 | | | 87.0 | |
| | | | |
| Change in Other Noncurrent Assets | | (43.2) | | | (1.2) | |
| Change in Other Noncurrent Liabilities | | (21.7) | | | 11.0 | |
| Changes in Certain Components of Working Capital: | | | | |
| Accounts Receivable, Net | | (20.3) | | | (28.8) | |
| Materials and Supplies | | (4.8) | | | (5.0) | |
| Accounts Payable | | (5.5) | | | 4.0 | |
| Customer Deposits | | (22.7) | | | 24.1 | |
| Accrued Taxes, Net | | (157.9) | | | (158.3) | |
| Other Current Assets | | (2.2) | | | 13.5 | |
| Other Current Liabilities | | (7.7) | | | 20.3 | |
| Net Cash Flows from (Used for) Operating Activities | | (34.3) | | | 107.2 | |
| | | | |
| INVESTING ACTIVITIES | | | | |
| Construction Expenditures | | (262.0) | | | (188.7) | |
| Change in Advances to Affiliates, Net | | — | | | 42.0 | |
| Other Investing Activities | | 4.9 | | | 4.2 | |
| Net Cash Flows Used for Investing Activities | | (257.1) | | | (142.5) | |
| | | | |
| FINANCING ACTIVITIES | | | | |
| Capital Contribution from Parent | | 50.0 | | | — | |
| | | | |
| Change in Advances from Affiliates, Net | | 241.7 | | | 55.7 | |
| | | | |
| Principal Payments for Finance Lease Obligations | | (1.2) | | | (1.2) | |
| Dividends Paid on Common Stock | | — | | | (15.0) | |
| Other Financing Activities | | 0.4 | | | 0.2 | |
| Net Cash Flows from Financing Activities | | 290.9 | | | 39.7 | |
| | | | |
| Net Increase (Decrease) in Cash and Cash Equivalents | | (0.5) | | | 4.4 | |
| Cash and Cash Equivalents at Beginning of Period | | 9.6 | | | 3.0 | |
| Cash and Cash Equivalents at End of Period | | $ | 9.1 | | | $ | 7.4 | |
| | | | |
| SUPPLEMENTARY INFORMATION | | | | |
| Cash Paid for Interest, Net of Capitalized Amounts | | $ | 20.9 | | | $ | 19.5 | |
| | | | |
| Noncash Acquisitions Under Finance Leases | | 0.6 | | | 0.6 | |
| Construction Expenditures Included in Current Liabilities as of March 31, | | 109.9 | | | 67.0 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
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
| | | | | | | | | | | | | | | |
| | | |
| | Three Months Ended March 31, | | |
| 2023 | | 2022 | | | | |
| | (in millions of KWhs) |
| Retail: | | | | | | | |
| Residential | 1,388 | | | 1,558 | | | | | |
| Commercial | 1,104 | | | 1,120 | | | | | |
| Industrial | 1,439 | | | 1,386 | | | | | |
| Miscellaneous | 275 | | | 283 | | | | | |
| Total Retail | 4,206 | | | 4,347 | | | | | |
| | | | | | | |
| Wholesale | 27 | | | 343 | | | | | |
| | | | | | | |
| Total KWhs | 4,233 | | | 4,690 | | | | | |
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
| | | | | | | | | | | | | | | |
| | | |
| | Three Months Ended March 31, | | |
| 2023 | | 2022 | | | | |
| | (in degree days) |
| Actual – Heating (a) | 871 | | | 1,134 | | | | | |
| Normal – Heating (b) | 1,055 | | | 1,040 | | | | | |
| | | | | | | |
| Actual – Cooling (c) | 10 | | | 11 | | | | | |
| Normal – Cooling (b) | 17 | | | 17 | | | | | |
(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.
First Quarter of 2023 Compared to First Quarter of 2022
| | | | | | | | |
| Public Service Company of Oklahoma |
| Reconciliation of First Quarter of 2022 to First Quarter of 2023 |
| Net Income (Loss) |
| (in millions) |
| | |
| First Quarter of 2022 | | $ | 5.8 | |
| | |
| Changes in Gross Margin: | | |
| Retail Margins (a) | | 15.3 | |
| | |
| Transmission Revenues | | 1.6 | |
| Other Revenues | | 1.1 | |
| Total Change in Gross Margin | | 18.0 | |
| | |
| Changes in Expenses and Other: | | |
| Other Operation and Maintenance | | (6.7) | |
| Depreciation and Amortization | | (8.4) | |
| Taxes Other Than Income Taxes | | (3.1) | |
| Interest Income | | (0.7) | |
| | |
| Allowance for Equity Funds Used During Construction | | 0.4 | |
| | |
| Non-Service Cost Components of Net Periodic Benefit Cost | | 0.5 | |
| Interest Expense | | (6.3) | |
| Total Change in Expenses and Other | | (24.3) | |
| | |
| Income Tax Expense | | (1.8) | |
| | |
| First Quarter of 2023 | | $ | (2.3) | |
(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 decreased $4 increased $15 million primarily due to the following:
An $18•A $10 million decreaseincrease in weather-related usage primarily due to a 32% decreaserider revenues. This increase was partially offset in cooling degree days.other expense items below.
•A $6$4 million decreaseincrease in weather-normalized margins.
A $5 million decrease in FERC generation wholesale municipal and cooperativefuel revenues primarily due to formula rate adjustments.
A $2 million decrease due to increased costs for power acquired under the Unit Power Agreement between AEGCo and I&M.
These decreases were partially offset by:
A $13 million increase from rate proceedings in the I&M service territory. The increase in retail margins relating to riders has corresponding increases in other items below.
A $9 million increase related to over/carrying charges on fuel under recovery of riders.balances.
A $2 million decrease in PJM related expenses primarily due to reduced FTRs.
Transmission Revenues decreased $6 million primarily due to an annual formula rate true-up and reduced net PJM Network Integration Transmission Service revenues resulting from increased affiliated transmission-related charges.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $7 million primarily due to the following:
A $9 millionan increase in transmissiongenerating maintenance expenses driven by the Northeastern Plant and the NCWF.
•Depreciation and Amortization expenses increased $8 million primarily due to an increase in recoverable PJM expenses. This increase in expense is offset within Retail Margins above.a higher depreciable base, implementation of new rates and the timing of refunds to customers under rate rider mechanisms.
A•Taxes Other Than Income Taxes increased $3 million increase in nuclear expenses primarily due to anincreased property taxes driven by the investment in the NCWF and a new infrastructure fee implemented by the City of Tulsa in March 2022. This increase in refueling outage amortization and refueling outage expenses not deferred,was partially offset by a decrease in employee-related expenses.Retail Margins above.
These increases were partially offset by:
A $3 million decrease in distribution expenses primarily due to decreased vegetation management.
Asset Impairments and Other Related Charges decreased $11 million due to the impairment of I&M’s Price River coal reserves in 2016.
Depreciation and Amortization expenses•Interest Expenseincreased $6 million primarily due to higher depreciable base.long-term debt balances.
Income Tax Expense decreased $7 million primarily due to a decrease in pretax book income and
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF OPERATIONS
For the regulatory accounting treatment of state income taxes.
NineThree Months Ended September 30, 2017March 31, 2023 and 2022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | |
| | | | | Three Months Ended March 31, |
| | | | | | |
| | | | | | | 2023 | | 2022 |
| REVENUES | | | | | | | | |
| Electric Generation, Transmission and Distribution | | | | | | $ | 414.8 | | | $ | 386.4 | |
| Sales to AEP Affiliates | | | | | | 0.7 | | | 0.6 | |
| Other Revenues | | | | | | 1.5 | | | 0.6 | |
| TOTAL REVENUES | | | | | | 417.0 | | | 387.6 | |
| | | | | | | | |
| EXPENSES | | | | | | | | |
| Purchased Electricity, Fuel and Other Consumables Used for Electric Generation | | | | | | 200.1 | | | 188.7 | |
| | | | | | | | |
| | | | | | | | |
| Other Operation | | | | | | 92.1 | | | 88.8 | |
| Maintenance | | | | | | 28.8 | | | 25.4 | |
| Depreciation and Amortization | | | | | | 61.1 | | | 52.7 | |
| Taxes Other Than Income Taxes | | | | | | 17.3 | | | 14.2 | |
| TOTAL EXPENSES | | | | | | 399.4 | | | 369.8 | |
| | | | | | | | |
| OPERATING INCOME | | | | | | 17.6 | | | 17.8 | |
| | | | | | | | |
| Other Income (Expense): | | | | | | | | |
| Interest Income | | | | | | 1.0 | | | 1.7 | |
| | | | | | | | |
| Allowance for Equity Funds Used During Construction | | | | | | 1.5 | | | 1.1 | |
| | | | | | | | |
| Non-Service Cost Components of Net Periodic Benefit Cost | | | | | | 3.6 | | | 3.1 | |
| Interest Expense | | | | | | (25.2) | | | (18.9) | |
| | | | | | | | |
| INCOME (LOSS) BEFORE INCOME TAX EXPENSE (BENEFIT) | | | | | | (1.5) | | | 4.8 | |
| | | | | | | | |
| Income Tax Expense (Benefit) | | | | | | 0.8 | | | (1.0) | |
| | | | | | | | |
| NET INCOME (LOSS) | | | | | | $ | (2.3) | | | $ | 5.8 | |
| | | | | | | | |
| The common stock of PSO is wholly-owned by Parent. |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2023 and 2022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | |
| | | | | Three Months Ended March 31, |
| | | | | | |
| | | | | | 2023 | | 2022 |
| Net Income (Loss) | | | | | | $ | (2.3) | | | $ | 5.8 | |
| | | | | | | | |
| OTHER COMPREHENSIVE LOSS, NET OF TAXES | | | | | | | | |
| Cash Flow Hedges, Net of Tax of $(0.4) and $0 in 2023 and 2022, Respectively | | | | | | (1.5) | | | — | |
| | | | | | | | |
| TOTAL COMPREHENSIVE INCOME (LOSS) | | | | | | $ | (3.8) | | | $ | 5.8 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Three Months Ended March 31, 2023 and 2022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common
Stock | | Paid-in
Capital | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income (Loss) | | Total |
| TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2021 | | $ | 157.2 | | | $ | 1,039.0 | | | $ | 1,095.4 | | | $ | — | | | $ | 2,291.6 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Net Income | | | | | | 5.8 | | | | | 5.8 | |
| | | | | | | | | | |
| TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2022 | | $ | 157.2 | | | $ | 1,039.0 | | | $ | 1,101.2 | | | $ | — | | | $ | 2,297.4 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2022 | | $ | 157.2 | | | $ | 1,042.6 | | | $ | 1,218.0 | | | $ | 1.3 | | | $ | 2,419.1 | |
| | | | | | | | | | |
| Common Stock Dividends | | | | | | (17.5) | | | | | (17.5) | |
| | | | | | | | | | |
| | | | | | | | | | |
| Net Loss | | | | | | (2.3) | | | | | (2.3) | |
| Other Comprehensive Loss | | | | | | | | (1.5) | | | (1.5) | |
| TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2023 | | $ | 157.2 | | | $ | 1,042.6 | | | $ | 1,198.2 | | | $ | (0.2) | | | $ | 2,397.8 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
March 31, 2023 and December 31, 2022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | | March 31, | | December 31, |
| | | 2023 | | 2022 |
| CURRENT ASSETS | | | | |
| Cash and Cash Equivalents | | $ | 3.8 | | | $ | 4.0 | |
| | | | |
| Accounts Receivable: | | | | |
| Customers | | 61.4 | | | 70.1 | |
| Affiliated Companies | | 33.5 | | | 52.2 | |
| Miscellaneous | | 1.0 | | | 0.8 | |
| | | | |
| Total Accounts Receivable | | 95.9 | | | 123.1 | |
| Fuel | | 14.9 | | | 11.6 | |
| Materials and Supplies | | 95.9 | | | 111.1 | |
| Risk Management Assets | | 9.4 | | | 25.3 | |
| | | | |
| Accrued Tax Benefits | | 27.4 | | | 16.1 | |
| Regulatory Asset for Under-Recovered Fuel Costs | | 178.7 | | | 178.7 | |
| Prepayments and Other Current Assets | | 23.3 | | | 21.6 | |
| TOTAL CURRENT ASSETS | | 449.3 | | | 491.5 | |
| | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | |
| Electric: | | | | |
| Generation | | 2,658.9 | | | 2,394.8 | |
| Transmission | | 1,171.8 | | | 1,164.4 | |
| Distribution | | 3,264.4 | | | 3,216.4 | |
| Other Property, Plant and Equipment | | 478.5 | | | 469.3 | |
| Construction Work in Progress | | 263.8 | | | 219.3 | |
| Total Property, Plant and Equipment | | 7,837.4 | | | 7,464.2 | |
| Accumulated Depreciation and Amortization | | 1,973.1 | | | 1,837.7 | |
| TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 5,864.3 | | | 5,626.5 | |
| | | | |
| OTHER NONCURRENT ASSETS | | | | |
| Regulatory Assets | | 609.8 | | | 653.7 | |
| | | | |
| Employee Benefits and Pension Assets | | 68.7 | | | 67.3 | |
| Operating Lease Assets | | 106.1 | | | 106.1 | |
| Deferred Charges and Other Noncurrent Assets | | 66.4 | | | 20.8 | |
| TOTAL OTHER NONCURRENT ASSETS | | 851.0 | | | 847.9 | |
| | | | |
| TOTAL ASSETS | | $ | 7,164.6 | | | $ | 6,965.9 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
March 31, 2023 and December 31, 2022
(Unaudited)
| | | | | | | | | | | | | | |
| | | March 31, | | December 31, |
| | | 2023 | | 2022 |
| | | (in millions) |
| CURRENT LIABILITIES | | | | |
| Advances from Affiliates | | $ | 130.7 | | | $ | 364.2 | |
| Accounts Payable: | | | | |
| General | | 155.7 | | | 202.9 | |
| Affiliated Companies | | 56.3 | | | 76.7 | |
| Long-term Debt Due Within One Year – Nonaffiliated | | 0.5 | | | 0.5 | |
| | | | |
| Customer Deposits | | 59.4 | | | 59.0 | |
| Accrued Taxes | | 64.9 | | | 28.7 | |
| | | | |
| Obligations Under Operating Leases | | 9.2 | | | 8.9 | |
| | | | |
| | | | |
| Other Current Liabilities | | 93.7 | | | 101.8 | |
| TOTAL CURRENT LIABILITIES | | 570.4 | | | 842.7 | |
| | | | |
| NONCURRENT LIABILITIES | | | | |
| Long-term Debt – Nonaffiliated | | 2,383.1 | | | 1,912.3 | |
| | | | |
| Deferred Income Taxes | | 805.9 | | | 788.6 | |
| Regulatory Liabilities and Deferred Investment Tax Credits | | 808.4 | | | 809.1 | |
| Asset Retirement Obligations | | 80.3 | | | 73.5 | |
| | | | |
| Obligations Under Operating Leases | | 99.1 | | | 99.3 | |
| Deferred Credits and Other Noncurrent Liabilities | | 19.6 | | | 21.3 | |
| TOTAL NONCURRENT LIABILITIES | | 4,196.4 | | | 3,704.1 | |
| | | | |
| TOTAL LIABILITIES | | 4,766.8 | | | 4,546.8 | |
| | | | |
| Rate Matters (Note 4) | | | | |
| Commitments and Contingencies (Note 5) | | | | |
| | | | |
| 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 | | 1,042.6 | | | 1,042.6 | |
| Retained Earnings | | 1,198.2 | | | 1,218.0 | |
| Accumulated Other Comprehensive Income (Loss) | | (0.2) | | | 1.3 | |
| TOTAL COMMON SHAREHOLDER’S EQUITY | | 2,397.8 | | | 2,419.1 | |
| | | | |
| TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 7,164.6 | | | $ | 6,965.9 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2023 and 2022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | | Three Months Ended March 31, |
| | | 2023 | | 2022 |
| OPERATING ACTIVITIES | | | | |
| Net Income (Loss) | | $ | (2.3) | | | $ | 5.8 | |
| Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities: | | | | |
| Depreciation and Amortization | | 61.1 | | | 52.7 | |
| Deferred Income Taxes | | 12.2 | | | (17.4) | |
| | | | |
| Allowance for Equity Funds Used During Construction | | (1.5) | | | (1.1) | |
| Mark-to-Market of Risk Management Contracts | | 13.9 | | | 1.8 | |
| | | | |
| Property Taxes | | (45.6) | | | (37.8) | |
| Deferred Fuel Over/Under-Recovery, Net | | 49.4 | | | (26.4) | |
| | | | |
| Change in Other Noncurrent Assets | | (9.7) | | | (3.9) | |
| Change in Other Noncurrent Liabilities | | 1.4 | | | 6.2 | |
| Changes in Certain Components of Working Capital: | | | | |
| Accounts Receivable, Net | | 27.2 | | | 11.5 | |
| Fuel, Materials and Supplies | | 12.9 | | | — | |
| Accounts Payable | | (62.8) | | | (20.8) | |
| Accrued Taxes, Net | | 24.9 | | | 45.2 | |
| Other Current Assets | | 0.4 | | | 1.9 | |
| Other Current Liabilities | | (7.5) | | | (1.8) | |
| Net Cash Flows from Operating Activities | | 74.0 | | | 15.9 | |
| | | | |
| INVESTING ACTIVITIES | | | | |
| Construction Expenditures | | (146.8) | | | (104.1) | |
| | | | |
| Acquisitions of Renewable Energy Facilities | | (145.7) | | | (549.3) | |
| Other Investing Activities | | 0.4 | | | 0.4 | |
| Net Cash Flows Used for Investing Activities | | (292.1) | | | (653.0) | |
| | | | |
| FINANCING ACTIVITIES | | | | |
| | | | |
| Issuance of Long-term Debt – Nonaffiliated | | 469.9 | | | 500.0 | |
| Change in Advances from Affiliates, Net | | (233.5) | | | 139.5 | |
| Retirement of Long-term Debt – Nonaffiliated | | (0.1) | | | (0.1) | |
| | | | |
| Principal Payments for Finance Lease Obligations | | (0.8) | | | (0.8) | |
| Dividends Paid on Common Stock | | (17.5) | | | — | |
| Other Financing Activities | | (0.1) | | | 0.1 | |
| Net Cash Flows from Financing Activities | | 217.9 | | | 638.7 | |
| | | | |
| Net Increase (Decrease) in Cash and Cash Equivalents | | (0.2) | | | 1.6 | |
| Cash and Cash Equivalents at Beginning of Period | | 4.0 | | | 1.3 | |
| Cash and Cash Equivalents at End of Period | | $ | 3.8 | | | $ | 2.9 | |
| | | | |
| SUPPLEMENTARY INFORMATION | | | | |
| Cash Paid for Interest, Net of Capitalized Amounts | | $ | 22.3 | | | $ | 21.3 | |
| | | | |
| Noncash Acquisitions Under Finance Leases | | 0.2 | | | 0.3 | |
| Construction Expenditures Included in Current Liabilities as of March 31, | | 63.4 | | | 37.1 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
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
| | | | | | | | | | | | | | | |
| | | |
| | Three Months Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| | (in millions of KWhs) |
| Retail: | | | | | | | |
| Residential | 1,351 | | | 1,636 | | | | | |
| Commercial | 1,168 | | | 1,266 | | | | | |
| Industrial | 1,203 | | | 1,115 | | | | | |
| Miscellaneous | 17 | | | 18 | | | | | |
| Total Retail | 3,739 | | | 4,035 | | | | | |
| | | | | | | |
| Wholesale | 1,270 | | | 1,759 | | | | | |
| | | | | | | |
| Total KWhs | 5,009 | | | 5,794 | | | | | |
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
| | | | | | | | | | | | | | | |
| | | |
| | Three Months Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| | (in degree days) |
| Actual – Heating (a) | 401 | | | 694 | | | | | |
| Normal – Heating (b) | 705 | | | 700 | | | | | |
| | | | | | | |
| Actual – Cooling (c) | 107 | | | 30 | | | | | |
| Normal – Cooling (b) | 40 | | | 40 | | | | | |
(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.
First Quarter of 2023 Compared to Nine Months Ended September 30, 2016First Quarter of 2022
|
| | | | |
| Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017 |
| Net Income |
| (in millions) |
| | | |
| Nine Months Ended September 30, 2016 | | $ | 201.4 |
|
| | | |
|
| Changes in Gross Margin: | | |
|
| Retail Margins (a) | | (11.2 | ) |
| Off-system Sales | | 0.5 |
|
| Transmission Revenues | | (23.0 | ) |
| Other Revenues | | (2.1 | ) |
| Total Change in Gross Margin | | (35.8 | ) |
| | | |
|
| Changes in Expenses and Other: | | |
|
| Other Operation and Maintenance | | (39.3 | ) |
| Asset Impairments and Other Related Charges | | 10.5 |
|
| Depreciation and Amortization | | (11.6 | ) |
| Taxes Other Than Income Taxes | | 3.2 |
|
| Other Income | | (0.4 | ) |
| Interest Expense | | (6.7 | ) |
| Total Change in Expenses and Other | | (44.3 | ) |
| | | |
|
| Income Tax Expense | | 22.5 |
|
| | | |
|
| Nine Months Ended September 30, 2017 | | $ | 143.8 |
|
| | | | | | | | |
(a)Reconciliation of First Quarter of 2022 to First Quarter of 2023 |
| Earnings Attributable to SWEPCo Common Shareholder |
| (in millions) |
| Includes firm wholesale sales | |
| First Quarter of 2022 | | $ | 44.1 | |
| | |
| Changes in Gross Margin: | | |
| Retail Margins (a) | | 4.4 | |
| Margins from Off-system Sales | | (1.6) | |
| Transmission Revenues | | 7.2 | |
| | |
| Total Change in Gross Margin | | 10.0 | |
| | |
| Changes in Expenses and Other: | | |
| Other Operation and Maintenance | | (15.3) | |
| | |
| Depreciation and Amortization | | (2.6) | |
| Taxes Other Than Income Taxes | | (6.3) | |
| Interest Income | | 1.8 | |
| Allowance for Equity Funds Used During Construction | | (1.1) | |
| Non-Service Cost Components of Net Periodic Benefit Cost | | 0.3 | |
| | |
| Interest Expense | | 8.1 | |
| Total Change in Expenses and Other | | (15.1) | |
| | |
| Income Tax Expense | | 1.8 | |
| | |
Net Income Attributable to municipals and cooperatives.Noncontrolling Interest | | (0.2) | |
| | |
| First Quarter of 2023 | | $ | 40.6 | |
(a)Includes firm wholesale sales to municipals and cooperatives.
The major components of the decreaseincrease 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 decreased $11 increased $4 million primarily due to the following:
•A $33$22 million increase due to base rate revenue increases in Arkansas and Louisiana and rider increases in all retail jurisdictions. These increases were partially offset in other expense items below.
•A $4 million increase in fuel revenues due to increased carrying charges on fuel under-recovery balances.
These increases were partially offset by:
•A $12 million decrease in FERC generation wholesale municipalweather-normalized margins primarily in the residential and cooperative revenues primarily due to an annual formula rate true-up and other rate adjustments.commercial classes.
•A $29$9 million decrease in weather-related usage primarily due to a 24% decrease in cooling degree days and a 17%42% decrease in heating degree days.
An $11 million decrease in weather-normalized margins.
A $5 million decrease due to increased costs for power acquired under the Unit Power Agreement between AEGCo and I&M.
These decreases were partially offset by:
A $47 million increase from rate proceedings in the I&M service territory. The increase in retail margins relating to riders has corresponding increases in other items below.
A $19 million increase related to over/under recovery of riders.
A $2 million decrease in PJM related expenses primarily due to reduced FTRs.
•Transmission Revenues decreased $23 million primarily due to an annual formula rate true-up and reduced net PJM Network Integration Transmission Service revenues resulting from increased affiliated transmission-related charges.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $39 million primarily due to the following:
A $38 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses. This increase in expense was offset within Retail Margins above.
A $7 million increase in nuclear expenses primarily due to an increase in refueling outage amortization, partially offset by refueling outage expenses not deferred, a decrease in employee-related expenses and material write-off.
A $3 million increase in distribution expenses primarily due to increased vegetation management.
These increases were partially offset by:
An $8 million decrease primarily due to employee-related expenses.
Asset Impairments and Other Related Charges decreased $11 million due to the impairment of I&M’s Price River coal reserves in 2016.
Depreciation and Amortization expensesincreased $12 million primarily due to higher depreciable base.
Taxes Other Than Income Taxes decreased $3 million primarily due to property taxes.
Interest Expense increased $7 million primarily due to higher long-term debt balances.
the reversal of a prior period provision for refund.Income Tax Expense decreased $23 million primarily due to a decrease in pretax book income, partially offset by the recording of favorable federal income tax adjustments in 2016.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended | | Nine Months Ended |
| | | September 30, | | September 30, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| REVENUES | | | | | | | | |
|
| Electric Generation, Transmission and Distribution | | $ | 537.0 |
| | $ | 574.7 |
| | $ | 1,527.4 |
| | $ | 1,570.8 |
|
| Other Revenues – Affiliated | | 17.1 |
| | 19.5 |
| | 48.2 |
| | 68.7 |
|
| Other Revenues – Nonaffiliated | | 3.6 |
| | 3.4 |
| | 9.9 |
| | 13.2 |
|
| TOTAL REVENUES | | 557.7 |
| | 597.6 |
| | 1,585.5 |
| | 1,652.7 |
|
| | | | | | | | | |
| EXPENSES | | |
| | | | |
| | |
|
| Fuel and Other Consumables Used for Electric Generation | | 76.4 |
| | 91.3 |
| | 238.2 |
| | 236.8 |
|
| Purchased Electricity for Resale | | 32.9 |
| | 43.7 |
| | 101.2 |
| | 134.3 |
|
| Purchased Electricity from AEP Affiliates | | 62.4 |
| | 64.5 |
| | 166.2 |
| | 165.9 |
|
| Other Operation | | 140.5 |
| | 138.9 |
| | 434.2 |
| | 413.9 |
|
| Maintenance | | 51.5 |
| | 45.7 |
| | 153.6 |
| | 134.6 |
|
| Asset Impairments and Other Related Charges | | — |
| | 10.5 |
| | — |
| | 10.5 |
|
| Depreciation and Amortization | | 55.0 |
| | 49.1 |
| | 154.8 |
| | 143.2 |
|
| Taxes Other Than Income Taxes | | 23.9 |
| | 22.5 |
| | 68.3 |
| | 71.5 |
|
| TOTAL EXPENSES | | 442.6 |
| | 466.2 |
| | 1,316.5 |
| | 1,310.7 |
|
| | | | | | | | | |
| OPERATING INCOME | | 115.1 |
| | 131.4 |
| | 269.0 |
| | 342.0 |
|
| | | | | | | | | |
| Other Income (Expense): | | |
| | | | |
| | |
|
| Interest Income | | 2.4 |
| | 1.7 |
| | 11.5 |
| | 9.1 |
|
| Allowance for Equity Funds Used During Construction | | 3.5 |
| | 4.1 |
| | 8.1 |
| | 10.9 |
|
| Interest Expense | | (27.5 | ) | | (26.7 | ) | | (83.0 | ) | | (76.3 | ) |
| | | | | | | | | |
| INCOME BEFORE INCOME TAX EXPENSE | | 93.5 |
| | 110.5 |
| | 205.6 |
| | 285.7 |
|
| | | | | | | | | |
| Income Tax Expense | | 28.6 |
| | 35.1 |
| | 61.8 |
| | 84.3 |
|
| | | | | | | | | |
| NET INCOME | | $ | 64.9 |
| | $ | 75.4 |
| | $ | 143.8 |
| | $ | 201.4 |
|
|
|
The common stock of I&M is wholly-owned by Parent. |
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended | | Nine Months Ended |
| | | September 30, | | September 30, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| Net Income | | $ | 64.9 |
| | $ | 75.4 |
| | $ | 143.8 |
| | $ | 201.4 |
|
| | | | | | | | | |
| OTHER COMPREHENSIVE INCOME, NET OF TAXES | | |
| | | | |
| | |
|
| Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended September 30, 2017 and 2016, Respectively, and $0.5 and $0.5 for the Nine Months Ended September 30, 2017 and 2016, Respectively | | 0.3 |
| | 0.3 |
| | 1.0 |
| | 1.0 |
|
| | | | | | | | | |
| TOTAL COMPREHENSIVE INCOME | | $ | 65.2 |
| | $ | 75.7 |
| | $ | 144.8 |
| | $ | 202.4 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| | Common
Stock | | Paid-in
Capital | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income (Loss) | | Total |
| TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2015 | $ | 56.6 |
| | $ | 980.9 |
| | $ | 1,015.6 |
| | $ | (16.7 | ) | | $ | 2,036.4 |
|
| | | | | | | | | | |
| Common Stock Dividends | |
| | |
| | (93.8 | ) | | |
| | (93.8 | ) |
| Net Income | |
| | |
| | 201.4 |
| | |
| | 201.4 |
|
| Other Comprehensive Income | |
| | |
| | |
| | 1.0 |
| | 1.0 |
|
| TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2016 | $ | 56.6 |
| | $ | 980.9 |
| | $ | 1,123.2 |
| | $ | (15.7 | ) | | $ | 2,145.0 |
|
| | |
| | |
| | |
| | |
| | |
|
| TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2016 | $ | 56.6 |
| | $ | 980.9 |
| | $ | 1,130.5 |
| | $ | (16.2 | ) | | $ | 2,151.8 |
|
| | | | | | | | | | |
| Common Stock Dividends | |
| | |
| | (93.7 | ) | | |
| | (93.7 | ) |
| Net Income | |
| | |
| | 143.8 |
| | |
| | 143.8 |
|
| Other Comprehensive Income | |
| | |
| | |
| | 1.0 |
| | 1.0 |
|
| TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2017 | $ | 56.6 |
| | $ | 980.9 |
| | $ | 1,180.6 |
| | $ | (15.2 | ) | | $ | 2,202.9 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2017 and December 31, 2016
(in millions)
(Unaudited)
|
| | | | | | | | |
| | | September 30, | | December 31, |
| | | 2017 | | 2016 |
| CURRENT ASSETS | | | | |
| Cash and Cash Equivalents | | $ | 1.3 |
| | $ | 1.2 |
|
| Advances to Affiliates | | 12.6 |
| | 12.5 |
|
| Accounts Receivable: | | | | |
| Customers | | 42.1 |
| | 60.2 |
|
| Affiliated Companies | | 42.8 |
| | 51.0 |
|
| Accrued Unbilled Revenues | | 8.4 |
| | 1.5 |
|
| Miscellaneous | | 1.1 |
| | 0.7 |
|
| Allowance for Uncollectible Accounts | | (0.3 | ) | | — |
|
| Total Accounts Receivable | | 94.1 |
| | 113.4 |
|
| Fuel | | 32.3 |
| | 32.3 |
|
| Materials and Supplies | | 156.5 |
| | 150.8 |
|
| Risk Management Assets | | 11.6 |
| | 3.5 |
|
| Accrued Tax Benefits | | 34.5 |
| | 37.7 |
|
| Regulatory Asset for Under-Recovered Fuel Costs | | 12.3 |
| | 26.1 |
|
| Accrued Reimbursement of Spent Nuclear Fuel Costs | | 11.0 |
| | 22.1 |
|
| Prepayments and Other Current Assets | | 26.9 |
| | 19.9 |
|
| TOTAL CURRENT ASSETS | | 393.1 |
| | 419.5 |
|
| | | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | |
| Electric: | | | | |
| Generation | | 4,399.9 |
| | 4,056.1 |
|
| Transmission | | 1,491.4 |
| | 1,472.8 |
|
| Distribution | | 2,000.1 |
| | 1,899.3 |
|
| Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) | | 555.9 |
| | 550.2 |
|
| Construction Work in Progress | | 478.9 |
| | 654.2 |
|
| Total Property, Plant and Equipment | | 8,926.2 |
| | 8,632.6 |
|
| Accumulated Depreciation, Depletion and Amortization | | 3,022.5 |
| | 3,005.1 |
|
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 5,903.7 |
| | 5,627.5 |
|
| | | | | |
| OTHER NONCURRENT ASSETS | | | | |
| Regulatory Assets | | 941.0 |
| | 916.6 |
|
| Spent Nuclear Fuel and Decommissioning Trusts | | 2,433.0 |
| | 2,256.2 |
|
| Long-term Risk Management Assets | | 0.5 |
| | — |
|
| Deferred Charges and Other Noncurrent Assets | | 95.9 |
| | 121.5 |
|
| TOTAL OTHER NONCURRENT ASSETS | | 3,470.4 |
| | 3,294.3 |
|
| | | | | |
| TOTAL ASSETS | | $ | 9,767.2 |
| | $ | 9,341.3 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2017 and December 31, 2016
(dollars in millions)
(Unaudited)
|
| | | | | | | | |
| | | September 30, | | December 31, |
| | | 2017 | | 2016 |
| CURRENT LIABILITIES | | | | |
| Advances from Affiliates | | $ | 177.5 |
| | $ | 215.2 |
|
| Accounts Payable: | | | | |
| General | | 168.6 |
| | 179.0 |
|
| Affiliated Companies | | 72.2 |
| | 75.6 |
|
Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2017 and December 31, 2016 Amounts Include $83.7 and $130.9, Respectively, Related to DCC Fuel) | | 462.1 |
| | 209.3 |
|
| Risk Management Liabilities | | 2.0 |
| | 0.3 |
|
| Customer Deposits | | 37.3 |
| | 34.3 |
|
| Accrued Taxes | | 43.8 |
| | 77.2 |
|
| Accrued Interest | | 14.3 |
| | 31.7 |
|
| Obligations Under Capital Leases | | 7.3 |
| | 9.4 |
|
| Other Current Liabilities | | 114.3 |
| | 123.4 |
|
| TOTAL CURRENT LIABILITIES | | 1,099.4 |
| | 955.4 |
|
| | | | | |
| NONCURRENT LIABILITIES | | | | |
| Long-term Debt – Nonaffiliated | | 2,196.4 |
| | 2,262.1 |
|
| Long-term Risk Management Liabilities | | 0.2 |
| | 0.8 |
|
| Deferred Income Taxes | | 1,681.8 |
| | 1,527.4 |
|
| Regulatory Liabilities and Deferred Investment Tax Credits | | 1,169.6 |
| | 1,065.5 |
|
| Asset Retirement Obligations | | 1,307.4 |
| | 1,257.9 |
|
| Deferred Credits and Other Noncurrent Liabilities | | 109.5 |
| | 120.4 |
|
| TOTAL NONCURRENT LIABILITIES | | 6,464.9 |
| | 6,234.1 |
|
| | | | | |
| TOTAL LIABILITIES | | 7,564.3 |
| | 7,189.5 |
|
| | | | | |
| Rate Matters (Note 4) | |
| |
|
| Commitments and Contingencies (Note 5) | |
| |
|
| | | | | |
| 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 | | 1,180.6 |
| | 1,130.5 |
|
| Accumulated Other Comprehensive Income (Loss) | | (15.2 | ) | | (16.2 | ) |
| TOTAL COMMON SHAREHOLDER’S EQUITY | | 2,202.9 |
| | 2,151.8 |
|
| | | | | |
| TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 9,767.2 |
| | $ | 9,341.3 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
|
| | | | | | | | |
| | | Nine Months Ended September 30, |
| | | 2017 | | 2016 |
| OPERATING ACTIVITIES | | |
| | |
|
| Net Income | | $ | 143.8 |
| | $ | 201.4 |
|
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | |
| | |
|
| Depreciation and Amortization | | 154.8 |
| | 143.2 |
|
| Deferred Income Taxes | | 132.2 |
| | 116.2 |
|
| Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net | | 15.5 |
| | (17.4 | ) |
| Asset Impairments and Other Related Charges | | — |
| | 10.5 |
|
| Allowance for Equity Funds Used During Construction | | (8.1 | ) | | (10.9 | ) |
| Mark-to-Market of Risk Management Contracts | | (7.5 | ) | | 0.5 |
|
| Amortization of Nuclear Fuel | | 104.8 |
| | 109.7 |
|
| Pension Contribution to Qualified Plan Trust | | (13.0 | ) | | (12.7 | ) |
| Deferred Fuel Over/Under-Recovery, Net | | 22.0 |
| | 6.1 |
|
| Change in Other Noncurrent Assets | | (42.1 | ) | | — |
|
| Change in Other Noncurrent Liabilities | | 40.9 |
| | 30.0 |
|
| Changes in Certain Components of Working Capital: | | |
| | |
|
| Accounts Receivable, Net | | 19.3 |
| | 17.0 |
|
| Fuel, Materials and Supplies | | (4.1 | ) | | (1.1 | ) |
| Accounts Payable | | 16.6 |
| | (17.9 | ) |
| Accrued Taxes, Net | | (30.2 | ) | | (16.5 | ) |
| Other Current Assets | | 8.0 |
| | 6.7 |
|
| Other Current Liabilities | | (28.6 | ) | | (27.8 | ) |
| Net Cash Flows from Operating Activities | | 524.3 |
| | 537.0 |
|
| | | | | |
| INVESTING ACTIVITIES | | |
| | |
|
| Construction Expenditures | | (469.2 | ) | | (405.1 | ) |
| Change in Advances to Affiliates, Net | | (0.1 | ) | | (0.7 | ) |
| Purchases of Investment Securities | | (1,842.2 | ) | | (2,452.9 | ) |
| Sales of Investment Securities | | 1,808.6 |
| | 2,427.0 |
|
| Acquisitions of Nuclear Fuel | | (73.2 | ) | | (127.6 | ) |
| Other Investing Activities | | 7.3 |
| | 7.8 |
|
| Net Cash Flows Used for Investing Activities | | (568.8 | ) | | (551.5 | ) |
| | | | | |
| FINANCING ACTIVITIES | | |
| | |
|
| Issuance of Long-term Debt – Nonaffiliated | | 411.1 |
| | 482.7 |
|
| Change in Advances from Affiliates, Net | | (37.7 | ) | | (268.0 | ) |
| Retirement of Long-term Debt – Nonaffiliated | | (227.1 | ) | | (76.8 | ) |
| Principal Payments for Capital Lease Obligations | | (8.7 | ) | | (29.8 | ) |
| Dividends Paid on Common Stock | | (93.7 | ) | | (93.8 | ) |
| Other Financing Activities | | 0.7 |
| | 0.7 |
|
| Net Cash Flows from Financing Activities | | 44.6 |
| | 15.0 |
|
| | | | | |
| Net Increase in Cash and Cash Equivalents | | 0.1 |
| | 0.5 |
|
| Cash and Cash Equivalents at Beginning of Period | | 1.2 |
| | 1.1 |
|
| Cash and Cash Equivalents at End of Period | | $ | 1.3 |
| | $ | 1.6 |
|
| | | | | |
| SUPPLEMENTARY INFORMATION | | |
| | |
|
| Cash Paid for Interest, Net of Capitalized Amounts | | $ | 92.0 |
| | $ | 85.6 |
|
| Net Cash Paid (Received) for Income Taxes | | (69.6 | ) | | (36.0 | ) |
| Noncash Acquisitions Under Capital Leases | | 5.9 |
| | 16.8 |
|
| Construction Expenditures Included in Current Liabilities as of September 30, | | 74.5 |
| | 83.4 |
|
| Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, | | 0.6 |
| | 0.3 |
|
| Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage | | 2.8 |
| | 0.1 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
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
|
| | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions of KWhs) |
| Retail: | |
| | |
| | |
| | |
|
| Residential | 3,644 |
| | 4,380 |
| | 10,198 |
| | 11,209 |
|
| Commercial | 3,806 |
| | 4,114 |
| | 10,789 |
| | 11,158 |
|
| Industrial | 3,708 |
| | 3,610 |
| | 10,967 |
| | 10,671 |
|
| Miscellaneous | 28 |
| | 27 |
| | 87 |
| | 89 |
|
| Total Retail (a) | 11,186 |
| | 12,131 |
| | 32,041 |
| | 33,127 |
|
| | | | | | | | |
| Wholesale (b) | 585 |
| | 654 |
| | 1,749 |
| | 1,389 |
|
| | | | | | | | |
| Total KWhs | 11,771 |
| | 12,785 |
| | 33,790 |
| | 34,516 |
|
| |
(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
|
| | | | | | | | | | | | |
| | | Three Months Ended | | Nine Months Ended |
| | | September 30, | | September 30, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| | | (in degree days) |
| Actual - Heating (a) | | — |
| | — |
| | 1,500 |
| | 1,929 |
|
| Normal - Heating (b) | | 6 |
| | 7 |
| | 2,091 |
| | 2,110 |
|
| | | | | | | | | |
| Actual - Cooling (c) | | 642 |
| | 900 |
| | 957 |
| | 1,209 |
|
| Normal - Cooling (b) | | 670 |
| | 664 |
| | 960 |
| | 956 |
|
| |
(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. |
Third Quarter of 2017 Compared to Third Quarter of 2016
|
| | | | |
| Reconciliation of Third Quarter of 2016 to Third Quarter of 2017 |
| Net Income |
| (in millions) |
| | | |
| Third Quarter of 2016 | | $ | 99.9 |
|
| | | |
|
| Changes in Gross Margin: | | |
|
| Retail Margins | | (74.1 | ) |
| Off-system Sales | | (12.0 | ) |
| Transmission Revenues | | (1.8 | ) |
| Other Revenues | | (2.1 | ) |
| Total Change in Gross Margin | | (90.0 | ) |
| | | |
|
| Changes in Expenses and Other: | | |
|
| Other Operation and Maintenance | | 59.3 |
|
| Depreciation and Amortization | | 12.1 |
|
| Taxes Other Than Income Taxes | | 1.5 |
|
| Carrying Costs Income | | (0.4 | ) |
| Allowance for Equity Funds Used During Construction | | 0.6 |
|
| Interest Expense | | 1.5 |
|
| Total Change in Expenses and Other | | 74.6 |
|
| | | |
|
| Income Tax Expense | | (1.9 | ) |
| | | |
|
| Third Quarter of 2017 | | $ | 82.6 |
|
The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:
Retail Margins decreased $74 million primarily due to the following:
A $52 million decrease in revenues associated with the Universal Service Fund (USF) surcharge rate decrease. This decrease was offset by a corresponding decrease in Other Operation and Maintenance expenses below.
An $18 million net decrease in recovery of equity carrying charges related to the Phase-In Recovery Rider (PIRR), net of associated amortizations.
An $8 million decrease in revenues associated with smart grid riders. This decrease was offset in various expenses below.
A $5 million decrease in state excise taxes due to a decrease in metered KWh. This decrease was offset by a corresponding decrease in Taxes Other Than Income Taxes below.
These decreases were partially offset by:
A $12 million favorable impact due to the recovery of losses from a power contract with OVEC. The PUCO approved a PPA rider beginning in January 2017 to recover any net expense related to the deferral of OVEC losses starting in June 2016. This increase was offset by a corresponding decrease in Margins from Off-System Sales below.
Margins from Off-system Sales decreased $12 million due to current year losses from a power contract with OVEC which was offset in Retail Margins above as a result of the OVEC PPA rider beginning in January 2017.
Expenses and Other changed between years as follows:
•Other Operation and Maintenance expenses decreased $59increased $15 million primarily due to the following:
•A $52 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 by a corresponding decrease in Retail Margins above.
A $3 million decrease in recoverable smart grid expenses. This decrease was offset in Retail Margins above.
Depreciation and Amortization expensesdecreased $12 million primarily due to the following:
A $5 million decrease in recoverable DIR depreciation expense in Ohio.
A $4 million decrease in amortization expenses for the collection of carrying costs on deferred capacity charges beginning June 2015.
A $4 million decrease in recoverable smart grid depreciation expenses. This decrease was offset in Retail Margins above.
Taxes Other Than Income Taxes decreased $2 million primarily due to the following:
A $5 million decrease in state excise taxes due to a decrease in metered KWh. This decrease was offset by a corresponding decrease in Retail Margins above.
This decrease was partially offset by:
A $3$7 million increase in property taxes due to additional investments in transmission and distribution assets and higher tax rates.generation-related expenses.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
|
| | | | |
| Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017 |
| Net Income |
| (in millions) |
| | | |
| Nine Months Ended September 30, 2016 | | $ | 244.7 |
|
| | | |
|
| Changes in Gross Margin: | | |
|
| Retail Margins | | (153.8 | ) |
| Off-system Sales | | (27.9 | ) |
| Transmission Revenues | | (2.9 | ) |
| Other Revenues | | (0.3 | ) |
| Total Change in Gross Margin | | (184.9 | ) |
| | | |
|
| Changes in Expenses and Other: | | |
|
| Other Operation and Maintenance | | 144.3 |
|
| Depreciation and Amortization | | 23.3 |
|
| Taxes Other Than Income Taxes | | (2.1 | ) |
| Interest Income | | 1.0 |
|
| Carrying Costs Income | | (1.0 | ) |
| Allowance for Equity Funds Used During Construction | | 0.4 |
|
| Interest Expense | | 10.9 |
|
| Total Change in Expenses and Other | | 176.8 |
|
| | | |
|
| Income Tax Expense | | (5.5 | ) |
| | | |
|
| Nine Months Ended September 30, 2017 | | $ | 231.1 |
|
The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:
Retail Margins decreased $154 million primarily due to the following:
A $140 million decrease in revenues associated with the USF surcharge rate decrease. This decrease was offset by a corresponding decrease in Other Operation and Maintenance expenses below.
A $21 million decrease due to a prior year reversal of a regulatory provision resulting from a favorable court decision.
A $13 million decrease in revenues associated with smart grid riders. This decrease was offset in various expenses below.
A $9 million net decrease in recovery of equity carrying charges related to the PIRR, net of associated amortizations.
A $7 million decrease in state excise taxes due to a decrease in metered KWh. This decrease was offset by a corresponding decrease in Taxes Other Than Income Taxes below.
A $3 million decrease in transmission cost recovery rider revenues. This decrease was offset in Depreciation and Amortization below.
These decreases were partially offset by:
A $46 million favorable impact due to the recovery of losses from a power contract with OVEC. The PUCO approved a PPA rider beginning in January 2017 to recover any net expense related to the deferral of OVEC losses starting in June 2016. This increase was offset by a corresponding decrease in Margins from Off-System Sales below.
A $6 million increase in rider revenues associated with the DIR. This increase was partially offset in various expenses below.
Margins from Off-system Sales decreased $28 million primarily due to the following:
A $46 million decrease due to current year losses from a power contract with OVEC which was offset in Retail Margins above as a result of the OVEC PPA rider beginning in January 2017.
This decrease was partially offset by:
An $18 million increase primarily due to the impact of prior year losses from a power contract with OVEC which was not included in the OVEC PPA rider.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses decreased $144 million primarily due to the following:
A $140 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 by a corresponding decrease in Retail Margins above.
An $8 million decrease in recoverable smart grid expenses. This decrease was offset in Retail Margins above.
A $7 million decrease in securitized customer accounts receivable expenses.
A $3 million decrease in employee-related expenses.
These decreases were partially offset by:
A $12 million increase in PJM expenses related to the annual formula rate true-up that will be recovered in future periods.
Depreciation and Amortization expenses decreased $23 million primarily due to the following:
An $11 million decrease in amortization expenses for the collection of carrying costs on deferred capacity charges beginning June 2015.
An $8 million decrease in recoveries of transmission cost rider carrying costs. This decrease was partially offset in Retail Margins above.
A $7 million decrease in recoverable DIR depreciation expense in Ohio.
•A $5 million decrease in recoverable smart grid depreciation expenses. This decrease was offset in Retail Margins above.
These decreases were partially offset by:
A $5 million increase in depreciation expense due to an increase in depreciable base of transmission and distribution assets.
A $3 million increase due to amortization of capitalized software costs.
Taxes Other Than Income Taxes increased $2 million primarily due to the following:
A $9 million increase in property taxes due to additional investments in transmission and distribution assets and higher tax rates.
This increase was partially offset by:
A $7 million decrease in state excise taxes due to a decrease in metered KWh. This decrease was offset by a corresponding decrease in Retail Margins above.
InterestExpense decreased $11 million primarily due to the maturity of a senior unsecured note in June 2016.
Income Tax Expense increased $6 million primarily due to other book/tax differences which are accounted for on a flow-through basis and the recording of federal income tax adjustments, partially offset by a decrease in pretax book income.
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended | | Nine Months Ended |
| | | September 30, | | September 30, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| REVENUES | | | | | | | | |
|
| Electricity, Transmission and Distribution | | $ | 736.0 |
| | $ | 864.4 |
| | $ | 2,127.8 |
| | $ | 2,349.2 |
|
| Sales to AEP Affiliates | | 4.6 |
| | 5.5 |
| | 19.4 |
| | 11.7 |
|
| Other Revenues | | 1.4 |
| | 1.4 |
| | 4.8 |
| | 4.8 |
|
| TOTAL REVENUES | | 742.0 |
| | 871.3 |
| | 2,152.0 |
| | 2,365.7 |
|
| | | | | | | | | |
| EXPENSES | | |
| | |
| | |
| | |
|
| Purchased Electricity for Resale | | 180.7 |
| | 203.4 |
| | 525.4 |
| | 516.1 |
|
| Purchased Electricity from AEP Affiliates | | 26.7 |
| | 35.9 |
| | 83.4 |
| | 121.4 |
|
| Amortization of Generation Deferrals | | 58.7 |
| | 66.1 |
| | 172.9 |
| | 173.0 |
|
| Other Operation | | 125.8 |
| | 184.2 |
| | 377.6 |
| | 525.9 |
|
| Maintenance | | 37.9 |
| | 38.8 |
| | 108.4 |
| | 104.4 |
|
| Depreciation and Amortization | | 57.3 |
| | 69.4 |
| | 165.7 |
| | 189.0 |
|
| Taxes Other Than Income Taxes | | 100.4 |
| | 101.9 |
| | 293.8 |
| | 291.7 |
|
| TOTAL EXPENSES | | 587.5 |
| | 699.7 |
| | 1,727.2 |
| | 1,921.5 |
|
| | | | | | | | | |
| OPERATING INCOME | | 154.5 |
| | 171.6 |
| | 424.8 |
| | 444.2 |
|
| | | | | | | | | |
| Other Income (Expense): | | |
| | |
| | |
| | |
|
| Interest Income | | 0.7 |
| | 0.7 |
| | 4.0 |
| | 3.0 |
|
| Carrying Costs Income | | 0.5 |
| | 0.9 |
| | 3.0 |
| | 4.0 |
|
| Allowance for Equity Funds Used During Construction | | 0.9 |
| | 0.3 |
| | 4.1 |
| | 3.7 |
|
| Interest Expense | | (25.7 | ) | | (27.2 | ) | | (76.8 | ) | | (87.7 | ) |
| | | | | | | | | |
| INCOME BEFORE INCOME TAX EXPENSE | | 130.9 |
| | 146.3 |
| | 359.1 |
| | 367.2 |
|
| | | | | | | | | |
| Income Tax Expense | | 48.3 |
| | 46.4 |
| | 128.0 |
| | 122.5 |
|
| | | | | | | | | |
| NET INCOME | | $ | 82.6 |
| | $ | 99.9 |
| | $ | 231.1 |
| | $ | 244.7 |
|
|
| | | | |
The common stock of OPCo is wholly-owned by Parent. |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended | | Nine Months Ended |
| | | September 30, | | September 30, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| Net Income | | $ | 82.6 |
| | $ | 99.9 |
| | $ | 231.1 |
| | $ | 244.7 |
|
| | | | | | | | | |
| OTHER COMPREHENSIVE LOSS, NET OF TAXES | | |
| | |
| | |
| | |
|
| Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2017 and 2016, Respectively, and $(0.4) and $(0.5) for the Nine Months Ended September 30, 2017 and 2016, Respectively | | (0.3 | ) | | (0.2 | ) | | (0.8 | ) | | (1.0 | ) |
| | | | | | | | | |
| TOTAL COMPREHENSIVE INCOME | | $ | 82.3 |
| | $ | 99.7 |
| | $ | 230.3 |
| | $ | 243.7 |
|
|
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| | Common
Stock | | Paid-in
Capital | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income (Loss) | | Total |
| TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2015 | $ | 321.2 |
| | $ | 838.8 |
| | $ | 822.3 |
| | $ | 4.3 |
| | $ | 1,986.6 |
|
| | | | | | | | | | |
| Common Stock Dividends | |
| | |
| | (150.0 | ) | | |
| | (150.0 | ) |
| Net Income | |
| | |
| | 244.7 |
| | |
| | 244.7 |
|
| Other Comprehensive Loss | |
| | |
| | |
| | (1.0 | ) | | (1.0 | ) |
| TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2016 | $ | 321.2 |
| | $ | 838.8 |
| | $ | 917.0 |
| | $ | 3.3 |
| | $ | 2,080.3 |
|
| | |
| | |
| | |
| | |
| | |
|
| TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2016 | $ | 321.2 |
| | $ | 838.8 |
| | $ | 954.5 |
| | $ | 3.0 |
| | $ | 2,117.5 |
|
| | | | | | | | | | |
| Common Stock Dividends | |
| | |
| | (130.0 | ) | | |
| | (130.0 | ) |
| Net Income | |
| | |
| | 231.1 |
| | |
| | 231.1 |
|
| Other Comprehensive Loss | |
| | |
| | |
| | (0.8 | ) | | (0.8 | ) |
| TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2017 | $ | 321.2 |
| | $ | 838.8 |
| | $ | 1,055.6 |
| | $ | 2.2 |
| | $ | 2,217.8 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2017 and December 31, 2016
(in millions)
(Unaudited)
|
| | | | | | | | |
| | | September 30, | | December 31, |
| | | 2017 | | 2016 |
| CURRENT ASSETS | | | | |
| Cash and Cash Equivalents | | $ | 3.1 |
| | $ | 3.1 |
|
| Restricted Cash for Securitized Funding | | 15.6 |
| | 27.2 |
|
| Advances to Affiliates | | — |
| | 24.2 |
|
| Accounts Receivable: | | | | |
| Customers | | 27.1 |
| | 51.1 |
|
| Affiliated Companies | | 72.0 |
| | 66.3 |
|
| Accrued Unbilled Revenues | | 24.2 |
| | 21.0 |
|
| Miscellaneous | | 1.1 |
| | 0.9 |
|
| Allowance for Uncollectible Accounts | | (0.4 | ) | | (0.4 | ) |
| Total Accounts Receivable | | 124.0 |
| | 138.9 |
|
| Materials and Supplies | | 42.8 |
| | 45.9 |
|
| Emission Allowances | | 23.6 |
| | 20.4 |
|
| Risk Management Assets | | 0.2 |
| | 0.2 |
|
| Accrued Tax Benefits | | 15.4 |
| | 0.1 |
|
| Prepayments and Other Current Assets | | 28.1 |
| | 10.9 |
|
| TOTAL CURRENT ASSETS | | 252.8 |
| | 270.9 |
|
| | | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | |
| Electric: | | | | |
| Transmission | | 2,349.5 |
| | 2,319.2 |
|
| Distribution | | 4,575.0 |
| | 4,457.2 |
|
| Other Property, Plant and Equipment | | 487.9 |
| | 443.7 |
|
| Construction Work in Progress | | 350.7 |
| | 221.5 |
|
| Total Property, Plant and Equipment | | 7,763.1 |
| | 7,441.6 |
|
| Accumulated Depreciation and Amortization | | 2,182.8 |
| | 2,116.0 |
|
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 5,580.3 |
| | 5,325.6 |
|
| | | | | |
| OTHER NONCURRENT ASSETS | | | | |
| Notes Receivable – Affiliated | | 32.3 |
| | 32.3 |
|
| Regulatory Assets | | 1,014.7 |
| | 1,107.5 |
|
| Securitized Assets | | 43.7 |
| | 62.1 |
|
| Deferred Charges and Other Noncurrent Assets | | 131.2 |
| | 295.5 |
|
| TOTAL OTHER NONCURRENT ASSETS | | 1,221.9 |
| | 1,497.4 |
|
| | | | | |
| TOTAL ASSETS | | $ | 7,055.0 |
| | $ | 7,093.9 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2017 and December 31, 2016
(dollars in millions)
(Unaudited)
|
| | | | | | | | |
| | | September 30, | | December 31, |
| | | 2017 | | 2016 |
| CURRENT LIABILITIES | | | | |
| Advances from Affiliates | | $ | 167.6 |
| | $ | — |
|
| Accounts Payable: | | |
| | |
|
| General | | 157.8 |
| | 175.4 |
|
| Affiliated Companies | | 95.3 |
| | 95.6 |
|
Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2017 and December 31, 2016 Amounts Include $47 and $46.3, Respectively, Related to Ohio Phase-in-Recovery Funding) | | 397.0 |
| | 46.4 |
|
| Risk Management Liabilities | | 7.6 |
| | 5.9 |
|
| Customer Deposits | | 62.9 |
| | 71.0 |
|
| Accrued Taxes | | 251.3 |
| | 520.3 |
|
| Accrued Interest | | 38.3 |
| | 31.2 |
|
| Other Current Liabilities | | 166.3 |
| | 236.0 |
|
| TOTAL CURRENT LIABILITIES | | 1,344.1 |
| | 1,181.8 |
|
| | | | | |
| NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated (September 30, 2017 and December 31, 2016 Amounts Include $47.5 and $93.9, Respectively, Related to Ohio Phase-in-Recovery Funding) | | 1,321.9 |
| | 1,717.5 |
|
| Long-term Risk Management Liabilities | | 130.9 |
| | 113.1 |
|
| Deferred Income Taxes | | 1,460.7 |
| | 1,346.1 |
|
| Regulatory Liabilities and Deferred Investment Tax Credits | | 519.3 |
| | 506.2 |
|
| Employee Benefits and Pension Obligations | | 19.3 |
| | 27.8 |
|
| Deferred Credits and Other Noncurrent Liabilities | | 41.0 |
| | 83.9 |
|
| TOTAL NONCURRENT LIABILITIES | | 3,493.1 |
| | 3,794.6 |
|
| | | | | |
| TOTAL LIABILITIES | | 4,837.2 |
| | 4,976.4 |
|
| | | | | |
| Rate Matters (Note 4) | |
| |
|
| Commitments and Contingencies (Note 5) | |
| |
|
| | | | | |
| 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 | | 1,055.6 |
| | 954.5 |
|
| Accumulated Other Comprehensive Income (Loss) | | 2.2 |
| | 3.0 |
|
| TOTAL COMMON SHAREHOLDER’S EQUITY | | 2,217.8 |
| | 2,117.5 |
|
| | | | | |
| TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 7,055.0 |
| | $ | 7,093.9 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
|
| | | | | | | | |
| | | Nine Months Ended September 30, |
| | | 2017 | | 2016 |
| OPERATING ACTIVITIES | | |
| | |
|
| Net Income | | $ | 231.1 |
| | $ | 244.7 |
|
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | |
| | |
|
| Depreciation and Amortization | | 165.7 |
| | 189.0 |
|
| Amortization of Generation Deferrals | | 172.9 |
| | 173.0 |
|
| Deferred Income Taxes | | 117.5 |
| | 28.6 |
|
| Carrying Costs Income | | (3.0 | ) | | (4.0 | ) |
| Allowance for Equity Funds Used During Construction | | (4.1 | ) | | (3.7 | ) |
| Mark-to-Market of Risk Management Contracts | | 19.5 |
| | 124.7 |
|
| Pension Contributions to Qualified Plan Trust | | (8.2 | ) | | (7.1 | ) |
| Property Taxes | | 175.9 |
| | 169.1 |
|
| Provision for Refund – Global Settlement, Net | | (93.3 | ) | | — |
|
| Change in Other Noncurrent Assets | | (126.7 | ) | | (124.9 | ) |
| Change in Other Noncurrent Liabilities | | 43.4 |
| | 17.2 |
|
| Changes in Certain Components of Working Capital: | | |
| | |
|
| Accounts Receivable, Net | | 14.9 |
| | 8.8 |
|
| Materials and Supplies | | (7.1 | ) | | 0.5 |
|
| Accounts Payable | | (31.2 | ) | | 2.0 |
|
| Accrued Taxes, Net | | (284.3 | ) | | (291.1 | ) |
| Other Current Assets | | (17.3 | ) | | (5.7 | ) |
| Other Current Liabilities | | (34.8 | ) | | (46.8 | ) |
| Net Cash Flows from Operating Activities | | 330.9 |
| | 474.3 |
|
| | | | | |
| INVESTING ACTIVITIES | | |
| | |
|
| Construction Expenditures | | (362.5 | ) | | (276.4 | ) |
| Change in Restricted Cash for Securitized Funding | | 11.6 |
| | 11.6 |
|
| Change in Advances to Affiliates, Net | | 24.2 |
| | 330.9 |
|
| Other Investing Activities | | 6.9 |
| | 9.0 |
|
| Net Cash Flows from (Used for) Investing Activities | | (319.8 | ) | | 75.1 |
|
| | | | | |
| FINANCING ACTIVITIES | | |
| | |
|
| Change in Advances from Affiliates, Net | | 167.6 |
| | — |
|
| Retirement of Long-term Debt – Nonaffiliated | | (46.4 | ) | | (395.9 | ) |
| Principal Payments for Capital Lease Obligations | | (3.1 | ) | | (3.1 | ) |
| Dividends Paid on Common Stock | | (130.0 | ) | | (150.0 | ) |
| Other Financing Activities | | 0.8 |
| | 0.5 |
|
| Net Cash Flows Used for Financing Activities | | (11.1 | ) | | (548.5 | ) |
| | | | | |
| Net Increase in Cash and Cash Equivalents | | — |
| | 0.9 |
|
| Cash and Cash Equivalents at Beginning of Period | | 3.1 |
| | 3.1 |
|
| Cash and Cash Equivalents at End of Period | | $ | 3.1 |
| | $ | 4.0 |
|
| | | | | |
| SUPPLEMENTARY INFORMATION | | |
| | |
|
| Cash Paid for Interest, Net of Capitalized Amounts | | $ | 68.1 |
| | $ | 78.2 |
|
| Net Cash Paid for Income Taxes | | 69.6 |
| | 178.0 |
|
| Noncash Acquisitions Under Capital Leases | | 3.6 |
| | 2.4 |
|
| Construction Expenditures Included in Current Liabilities as of September 30, | | 56.8 |
| | 30.0 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
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
|
| | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions of KWhs) |
| Retail: | |
| | |
| | |
| | |
|
| Residential | 1,992 |
| | 2,184 |
| | 4,662 |
| | 4,925 |
|
| Commercial | 1,488 |
| | 1,529 |
| | 3,926 |
| | 4,001 |
|
| Industrial | 1,472 |
| | 1,494 |
| | 4,249 |
| | 4,162 |
|
| Miscellaneous | 353 |
| | 369 |
| | 942 |
| | 955 |
|
| Total Retail | 5,305 |
| | 5,576 |
| | 13,779 |
| | 14,043 |
|
| | | | | | | | |
| Wholesale | 82 |
| | 113 |
| | 309 |
| | 226 |
|
| | | | | | | | |
| Total KWhs | 5,387 |
| | 5,689 |
| | 14,088 |
| | 14,269 |
|
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
|
| | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in degree days) |
| Actual - Heating (a) | — |
| | — |
| | 682 |
| | 782 |
|
| Normal - Heating (b) | 1 |
| | 1 |
| | 1,104 |
| | 1,105 |
|
| | | | | | | | |
| Actual - Cooling (c) | 1,313 |
| | 1,535 |
| | 2,001 |
| | 2,247 |
|
| Normal - Cooling (b) | 1,395 |
| | 1,390 |
| | 2,064 |
| | 2,055 |
|
| |
(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. |
Third Quarter of 2017 Compared to Third Quarter of 2016
|
| | | | |
| Reconciliation of Third Quarter of 2016 to Third Quarter of 2017 |
| Net Income |
| (in millions) |
| | | |
| Third Quarter of 2016 | | $ | 52.8 |
|
| | | |
| Changes in Gross Margin: | | |
| Retail Margins (a) | | (15.6 | ) |
| Off-system Sales | | (0.7 | ) |
| Transmission Revenues | | 4.1 |
|
| Other Revenues | | (2.0 | ) |
| Total Change in Gross Margin | | (14.2 | ) |
| | | |
| Changes in Expenses and Other: | | |
|
| Other Operation and Maintenance | | (2.2 | ) |
| Depreciation and Amortization | | 5.5 |
|
| Taxes Other Than Income Taxes | | (0.7 | ) |
| Interest Income | | (0.2 | ) |
| Allowance for Equity Funds Used During Construction | | (1.1 | ) |
| Interest Expense | | 1.7 |
|
| Total Change in Expenses and Other | | 3.0 |
|
| | | |
|
| Income Tax Expense | | 4.6 |
|
| | | |
|
| Third Quarter of 2017 | | $ | 46.2 |
|
| |
(a) | Includes firm wholesale sales to municipals and cooperatives. |
The major components of the decrease 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 decreased $16 million primarily due to the following:
A $17 million decrease primarily due to higher rates implemented in 2016 associated with interim rates.
An $11 million decrease in weather-related usage primarily due to a 14% decrease in cooling degree days.
These decreases were partially offset by:
A $14 million increase due to weather-normalized margins.
Transmission Revenues increased $4 million primarily due to an accrual for SPP sponsor-funded transmission upgrades in third quarter 2016.
Expenses and Other and Income Tax Expense changed between years as follows:
Depreciation and Amortization expenses decreased $6 million primarily due the following:
A $9 million decrease primarily related to prior year higher estimated depreciation expense associated with interim rates.
This decrease was partially offset by:
A $4 million increase primarily related to new depreciation rates implemented in 2017 and a higher depreciable base.
Income Tax Expense decreased $5 million primarily due to a decrease in pretax book income.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
|
| | | | |
| Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017 |
| Net Income |
| (in millions) |
| | | |
| Nine Months Ended September 30, 2016 | | $ | 97.4 |
|
| | | |
|
| Changes in Gross Margin: | | |
|
| Retail Margins (a) | | (17.6 | ) |
| Off-system Sales | | (0.9 | ) |
| Transmission Revenues | | 4.8 |
|
| Other Revenues | | (4.6 | ) |
| Total Change in Gross Margin | | (18.3 | ) |
| | | |
|
| Changes in Expenses and Other: | | |
|
| Other Operation and Maintenance | | (31.1 | ) |
| Depreciation and Amortization | | 12.1 |
|
| Taxes Other Than Income Taxes | | (2.2 | ) |
| Interest Income | | (0.4 | ) |
| Allowance for Equity Funds Used During Construction | | (4.5 | ) |
| Interest Expense | | 4.4 |
|
| Total Change in Expenses and Other | | (21.7 | ) |
| | | |
|
| Income Tax Expense | | 14.0 |
|
| | | |
|
| Nine Months Ended September 30, 2017 | | $ | 71.4 |
|
| |
(a) | Includes firm wholesale sales to municipals and cooperatives. |
The major components of the decrease 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 decreased $18 million primarily due to the following:
A $15 million decrease in weather-related usage primarily due to an 11% decrease in cooling degree days and a 13% decrease in heating degree days.
A $14 million decrease primarily due to higher rates implemented in 2016 associated with interim rates.
These decreases were partially offset by:
A $9 million increase primarily due to higher weather-normalized margins.
A $5 million increase related to new base rates implemented in January 2017.
Transmission Revenues increased $5 million primarily due to an accrual for SPP sponsor-funded transmission upgrades in third quarter 2016 and additional transmission investments in SPP.
Other Revenues decreased $5 million primarily due to the elimination of connection charges for certain customers with advanced metering, effective with the implementation of new base rates in January 2017.
Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $31 million primarily due to the following:
A $16 million increase in vegetation management expenses. This increase is partially offset by a corresponding increase in Retail Margins as vegetation management expenses recovered in the prior year under the System Reliability Rider are now recovered as a component of base rates in the current year.
A $15 million increase in transmission expenses primarily due to overhead line maintenance.
•Taxes Other Than Income Taxesincreased SPP transmission services.
Depreciation and Amortization expenses decreased $12 million primarily due the following:
A $24 million decrease primarily related to prior year higher estimated depreciation expense associated with interim rates.
This decrease was partially offset by:
A $12 million increase primarily related to new depreciation rates implemented in 2017 and a higher depreciable base.
Allowance for Equity Funds Used During Construction decreased $5$6 million primarily due to increased property taxes driven by the completion of environmental projects.
Interest Expense decreased $4 million primarily due to the deferral of the debt component of carrying charges on environmental control costs for projects at Northeastern Plant, Unit 3 and the Comanche Plant.
Income Tax Expense decreased $14 million primarily due to a decrease in pretax book income.
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended | | Nine Months Ended |
| | | September 30, | | September 30, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| REVENUES | | | | | | | | |
|
| Electric Generation, Transmission and Distribution | | $ | 440.6 |
| | $ | 400.9 |
| | $ | 1,085.1 |
| | $ | 971.3 |
|
| Sales to AEP Affiliates | | 1.1 |
| | 0.1 |
| | 3.2 |
| | 2.0 |
|
| Other Revenues | | 1.1 |
| | 0.7 |
| | 3.3 |
| | 2.9 |
|
| TOTAL REVENUES | | 442.8 |
| | 401.7 |
| | 1,091.6 |
| | 976.2 |
|
| | | | | | | | | |
| EXPENSES | | |
| | |
| | |
| | |
|
| Fuel and Other Consumables Used for Electric Generation | | 77.9 |
| | 16.4 |
| | 115.8 |
| | 43.0 |
|
| Purchased Electricity for Resale | | 127.8 |
| | 130.8 |
| | 379.8 |
| | 315.3 |
|
| Purchased Electricity from AEP Affiliates | | — |
| | 3.2 |
| | — |
| | 3.6 |
|
| Other Operation | | 83.6 |
| | 81.0 |
| | 226.3 |
| | 211.8 |
|
| Maintenance | | 25.2 |
| | 25.6 |
| | 88.2 |
| | 71.6 |
|
| Depreciation and Amortization | | 31.7 |
| | 37.2 |
| | 97.8 |
| | 109.9 |
|
| Taxes Other Than Income Taxes | | 9.8 |
| | 9.1 |
| | 30.0 |
| | 27.8 |
|
| TOTAL EXPENSES | | 356.0 |
| | 303.3 |
| | 937.9 |
| | 783.0 |
|
| | | | | | | | | |
| OPERATING INCOME | | 86.8 |
| | 98.4 |
| | 153.7 |
| | 193.2 |
|
| | | | | | | | | |
| Other Income (Expense): | | |
| | |
| | |
| | |
|
| Interest Income | | — |
| | 0.2 |
| | 0.1 |
| | 0.5 |
|
| Allowance for Equity Funds Used During Construction | | — |
| | 1.1 |
| | 0.4 |
| | 4.9 |
|
| Interest Expense | | (13.2 | ) | | (14.9 | ) | | (40.2 | ) | | (44.6 | ) |
| | | | | | | | | |
| INCOME BEFORE INCOME TAX EXPENSE | | 73.6 |
| | 84.8 |
| | 114.0 |
| | 154.0 |
|
| | | | | | | | | |
| Income Tax Expense | | 27.4 |
| | 32.0 |
| | 42.6 |
| | 56.6 |
|
| | | | | | | | | |
| NET INCOME | | $ | 46.2 |
| | $ | 52.8 |
| | $ | 71.4 |
| | $ | 97.4 |
|
|
| | | | |
The common stock of PSO is wholly-owned by Parent. |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended | | Nine Months Ended |
| | | September 30, | | September 30, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| Net Income | | $ | 46.2 |
| | $ | 52.8 |
| | $ | 71.4 |
| | $ | 97.4 |
|
| | | | | | | | | |
| OTHER COMPREHENSIVE LOSS, NET OF TAXES | | |
| | | | |
| | |
|
| Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2017 and 2016, Respectively, and $(0.3) and $(0.3) for the Nine Months Ended September 30, 2017 and 2016, Respectively | | (0.2 | ) | | (0.2 | ) | | (0.6 | ) | | (0.6 | ) |
| | | |
| | | | |
| | |
|
| TOTAL COMPREHENSIVE INCOME | | $ | 46.0 |
| | $ | 52.6 |
|
| $ | 70.8 |
| | $ | 96.8 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| | Common
Stock | | Paid-in
Capital | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income (Loss) | | Total |
| TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2015 | $ | 157.2 |
| | $ | 364.0 |
| | $ | 594.5 |
| | $ | 4.2 |
| | $ | 1,119.9 |
|
| | | | | | | | | | |
| Net Income | |
| | |
| | 97.4 |
| | |
| | 97.4 |
|
| Other Comprehensive Loss | |
| | |
| | |
| | (0.6 | ) | | (0.6 | ) |
| TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2016 | $ | 157.2 |
| | $ | 364.0 |
| | $ | 691.9 |
| | $ | 3.6 |
| | $ | 1,216.7 |
|
| | |
| | |
| | |
| | |
| | |
|
| TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2016 | $ | 157.2 |
| | $ | 364.0 |
| | $ | 689.5 |
| | $ | 3.4 |
| | $ | 1,214.1 |
|
| | | | | | | | | | |
| Common Stock Dividends | |
| | |
| | (52.5 | ) | | |
| | (52.5 | ) |
| Net Income | |
| | |
| | 71.4 |
| | |
| | 71.4 |
|
| Other Comprehensive Loss | |
| | |
| | |
| | (0.6 | ) | | (0.6 | ) |
| TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2017 | $ | 157.2 |
| | $ | 364.0 |
| | $ | 708.4 |
| | $ | 2.8 |
| | $ | 1,232.4 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
September 30, 2017 and December 31, 2016
(in millions)
(Unaudited)
|
| | | | | | | | |
| | | September 30, | | December 31, |
| | | 2017 | | 2016 |
| CURRENT ASSETS | | | | |
| Cash and Cash Equivalents | | $ | 2.1 |
| | $ | 1.5 |
|
| Accounts Receivable: | | | | |
| Customers | | 17.8 |
| | 27.5 |
|
| Affiliated Companies | | 31.8 |
| | 26.8 |
|
| Miscellaneous | | 3.2 |
| | 4.4 |
|
| Allowance for Uncollectible Accounts | | (0.1 | ) | | (0.2 | ) |
| Total Accounts Receivable | | 52.7 |
| | 58.5 |
|
| Fuel | | 11.9 |
| | 22.9 |
|
| Materials and Supplies | | 42.1 |
| | 44.6 |
|
| Risk Management Assets | | 4.7 |
| | 0.8 |
|
| Accrued Tax Benefits | | 27.0 |
| | 27.3 |
|
| Regulatory Asset for Under-Recovered Fuel Costs | | 36.9 |
| | 33.8 |
|
| Prepayments and Other Current Assets | | 14.4 |
| | 6.0 |
|
| TOTAL CURRENT ASSETS | | 191.8 |
| | 195.4 |
|
| | | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | |
| Electric: | | | | |
| Generation | | 1,573.8 |
| | 1,559.3 |
|
| Transmission | | 852.5 |
| | 832.8 |
|
| Distribution | | 2,414.1 |
| | 2,322.4 |
|
| Other Property, Plant and Equipment | | 286.3 |
| | 233.2 |
|
| Construction Work in Progress | | 114.0 |
| | 148.2 |
|
| Total Property, Plant and Equipment | | 5,240.7 |
| | 5,095.9 |
|
| Accumulated Depreciation and Amortization | | 1,382.8 |
| | 1,272.7 |
|
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 3,857.9 |
| | 3,823.2 |
|
| | | | | |
| OTHER NONCURRENT ASSETS | | | | |
| Regulatory Assets | | 393.6 |
| | 340.2 |
|
| Employee Benefits and Pension Assets | | 16.0 |
| | 10.4 |
|
| Deferred Charges and Other Noncurrent Assets | | 19.2 |
| | 10.0 |
|
| TOTAL OTHER NONCURRENT ASSETS | | 428.8 |
| | 360.6 |
|
| | | | | |
| TOTAL ASSETS | | $ | 4,478.5 |
| | $ | 4,379.2 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2017 and December 31, 2016
(Unaudited)
|
| | | | | | | | |
| | | September 30, | | December 31, |
| | | 2017 | | 2016 |
| | | (in millions) |
| CURRENT LIABILITIES | | | | |
| Advances from Affiliates | | $ | 118.0 |
| | $ | 52.0 |
|
| Accounts Payable: | | |
| | |
|
| General | | 93.8 |
| | 116.3 |
|
| Affiliated Companies | | 43.0 |
| | 56.2 |
|
| Long-term Debt Due Within One Year – Nonaffiliated | | 0.5 |
| | 0.5 |
|
| Customer Deposits | | 53.1 |
| | 49.7 |
|
| Accrued Taxes | | 40.8 |
| | 21.0 |
|
| Accrued Interest | | 19.5 |
| | 13.9 |
|
| Provision for Refund | | 4.1 |
| | 46.1 |
|
| Other Current Liabilities | | 38.5 |
| | 47.8 |
|
| TOTAL CURRENT LIABILITIES | | 411.3 |
| | 403.5 |
|
| | | | | |
| NONCURRENT LIABILITIES | | | | |
| Long-term Debt – Nonaffiliated | | 1,285.9 |
| | 1,285.5 |
|
| Deferred Income Taxes | | 1,152.5 |
| | 1,058.8 |
|
| Regulatory Liabilities and Deferred Investment Tax Credits | | 320.9 |
| | 339.7 |
|
| Asset Retirement Obligations | | 54.5 |
| | 52.8 |
|
| Deferred Credits and Other Noncurrent Liabilities | | 21.0 |
| | 24.8 |
|
| TOTAL NONCURRENT LIABILITIES | | 2,834.8 |
| | 2,761.6 |
|
| | | | | |
| TOTAL LIABILITIES | | 3,246.1 |
| | 3,165.1 |
|
| | | | | |
| Rate Matters (Note 4) | |
| |
|
| Commitments and Contingencies (Note 5) | |
| |
|
| | | | | |
| 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 | | 364.0 |
| | 364.0 |
|
| Retained Earnings | | 708.4 |
| | 689.5 |
|
| Accumulated Other Comprehensive Income (Loss) | | 2.8 |
| | 3.4 |
|
| TOTAL COMMON SHAREHOLDER’S EQUITY | | 1,232.4 |
| | 1,214.1 |
|
| | | | | |
| TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 4,478.5 |
| | $ | 4,379.2 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
|
| | | | | | | | |
| | | Nine Months Ended September 30, |
| | | 2017 | | 2016 |
| OPERATING ACTIVITIES | | |
| | |
|
| Net Income | | $ | 71.4 |
| | $ | 97.4 |
|
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | |
| | |
|
| Depreciation and Amortization | | 97.8 |
| | 109.9 |
|
| Deferred Income Taxes | | 93.7 |
| | 79.5 |
|
| Allowance for Equity Funds Used During Construction | | (0.4 | ) | | (4.9 | ) |
| Mark-to-Market of Risk Management Contracts | | (3.9 | ) | | (0.7 | ) |
| Pension Contributions to Qualified Plan Trust | | (5.3 | ) | | (5.6 | ) |
| Property Taxes | | (9.4 | ) | | (8.0 | ) |
| Deferred Fuel Over/Under-Recovery, Net | | (5.6 | ) | | (80.2 | ) |
| Provision for Refund, Net | | (39.4 | ) | | 13.8 |
|
| Change in Other Noncurrent Assets | | (19.8 | ) | | (18.8 | ) |
| Change in Other Noncurrent Liabilities | | (1.4 | ) | | (3.7 | ) |
| Changes in Certain Components of Working Capital: | | |
| | |
|
| Accounts Receivable, Net | | 5.8 |
| | 4.4 |
|
| Fuel, Materials and Supplies | | 13.5 |
| | (2.4 | ) |
| Accounts Payable | | (18.5 | ) | | 23.1 |
|
| Accrued Taxes, Net | | 20.1 |
| | 45.4 |
|
| Other Current Assets | | (8.2 | ) | | (2.2 | ) |
| Other Current Liabilities | | 1.5 |
| | (14.9 | ) |
| Net Cash Flows from Operating Activities | | 191.9 |
| | 232.1 |
|
| | | | | |
| INVESTING ACTIVITIES | | |
| | |
|
| Construction Expenditures | | (203.1 | ) | | (266.8 | ) |
| Change in Advances to Affiliates, Net | | — |
| | 29.5 |
|
| Other Investing Activities | | 1.5 |
| | 8.7 |
|
| Net Cash Flows Used for Investing Activities | | (201.6 | ) | | (228.6 | ) |
| | | | | |
| FINANCING ACTIVITIES | | |
| | |
|
| Issuance of Long-term Debt – Nonaffiliated | | — |
| | 150.0 |
|
| Change in Advances from Affiliates, Net | | 66.0 |
| | — |
|
| Retirement of Long-term Debt – Nonaffiliated | | (0.3 | ) | | (150.3 | ) |
| Principal Payments for Capital Lease Obligations | | (3.2 | ) | | (3.0 | ) |
| Dividends Paid on Common Stock | | (52.5 | ) | | — |
|
| Other Financing Activities | | 0.3 |
| | 0.4 |
|
| Net Cash Flows from (Used for) Financing Activities | | 10.3 |
| | (2.9 | ) |
| | | | | |
| Net Increase in Cash and Cash Equivalents | | 0.6 |
| | 0.6 |
|
| Cash and Cash Equivalents at Beginning of Period | | 1.5 |
| | 1.4 |
|
| Cash and Cash Equivalents at End of Period | | $ | 2.1 |
| | $ | 2.0 |
|
| | | | | |
| SUPPLEMENTARY INFORMATION | | |
| | |
|
| Cash Paid for Interest, Net of Capitalized Amounts | | $ | 40.9 |
| | $ | 45.0 |
|
| Net Cash Paid (Received) for Income Taxes | | (46.6 | ) | | (50.3 | ) |
| Noncash Acquisitions Under Capital Leases | | 1.0 |
| | 2.2 |
|
| Construction Expenditures Included in Current Liabilities as of September 30, | | 15.1 |
| | 20.2 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
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
|
| | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions of KWhs) |
| Retail: | |
| | |
| | |
| | |
|
| Residential | 1,887 |
| | 2,105 |
| | 4,547 |
| | 4,879 |
|
| Commercial | 1,677 |
| | 1,793 |
| | 4,466 |
| | 4,652 |
|
| Industrial | 1,339 |
| | 1,254 |
| | 3,895 |
| | 3,830 |
|
| Miscellaneous | 19 |
| | 20 |
| | 60 |
| | 61 |
|
| Total Retail | 4,922 |
| | 5,172 |
| | 12,968 |
| | 13,422 |
|
| | | | | | | | |
| Wholesale | 2,105 |
| | 2,326 |
| | 6,286 |
| | 6,056 |
|
| | | | | | | | |
| Total KWhs | 7,027 |
| | 7,498 |
| | 19,254 |
| | 19,478 |
|
Heating degree days and cooling degree days are metrics commonly usedinvestment in the utility industry as a measure of the impact of weather on revenues.NCWF.
Summary of Heating and Cooling Degree Days
|
| | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in degree days) |
| Actual - Heating (a) | — |
| | — |
| | 394 |
| | 586 |
|
| Normal - Heating (b) | 1 |
| | 1 |
| | 747 |
| | 747 |
|
| | | | | | | | |
| Actual - Cooling (c) | 1,248 |
| | 1,502 |
| | 1,999 |
| | 2,277 |
|
| Normal - Cooling (b) | 1,414 |
| | 1,410 |
| | 2,185 |
| | 2,177 |
|
| |
(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. |
Third Quarter of 2017 Compared to Third Quarter of 2016
|
| | | | |
| Reconciliation of Third Quarter of 2016 to Third Quarter of 2017 |
| Earnings Attributable to SWEPCo Common Shareholder |
| (in millions) |
| | | |
| Third Quarter of 2016 | | $ | 83.3 |
|
| | | |
|
| Changes in Gross Margin: | | |
|
| Retail Margins (a) | | (6.9 | ) |
| Off-system Sales | | 0.1 |
|
| Transmission Revenues | | (8.0 | ) |
| Other Revenues | | (0.1 | ) |
| Total Change in Gross Margin | | (14.9 | ) |
| | | |
|
| Changes in Expenses and Other: | | |
|
| Other Operation and Maintenance | | 10.1 |
|
| Depreciation and Amortization | | (4.0 | ) |
| Taxes Other Than Income Taxes | | (1.6 | ) |
| Interest Income | | 0.7 |
|
| Allowance for Equity Funds Used During Construction | | 0.3 |
|
| Interest Expense | | 0.7 |
|
| Total Change in Expenses and Other | | 6.2 |
|
| | | |
|
| Income Tax Expense | | 10.7 |
|
| Equity Earnings (Loss) of Unconsolidated Subsidiary | | (2.3 | ) |
| Net Income Attributable to Noncontrolling Interest | | (9.9 | ) |
| | | |
|
| Third Quarter of 2017 | | $ | 73.1 |
|
| |
(a) | Includes firm wholesale sales to municipals and cooperatives. |
The major components of the decrease 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 decreased $7 million primarily due to the following:
An $18 million decrease in weather-related usage due to a 17% decrease in cooling degree days.
This decrease was partially offset by:
An $11 million increase due to rider revenue increases in Louisiana, partially offset in expense items below.
Transmission Revenues•Interest Expense decreased $8 million primarily due to an accruala settlement agreement in Louisiana which provided for SPP sponsor-funded transmission upgrades in third quarter 2016. This decrease is offset by a corresponding decrease in Other Operation and Maintenance expenses below.
Expenses and Other, Income Tax Expense and Net Income Attributable to Noncontrolling Interest changed between years as follows:
Other Operation and Maintenance expenses decreased $10 million primarily due to a $12 million accrual for SPP sponsor-funded transmission upgrades in third quarter 2016. This decrease is partially offset by a corresponding decrease in Transmission Revenues above.of carrying charges on storm-related regulatory assets.
Depreciation and Amortization expenses increased $4 million primarily due to a higher depreciable base.
Income Tax Expense decreased $11 million primarily due to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine. This decrease is offset by an increase in Net Income Attributable to Noncontrolling Interest below.
Net Income Attributable to Noncontrolling Interest increased $10 million primarily due to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine. This increase is offset by a decrease in Income Tax Expense above.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
|
| | | | |
| Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017 |
| Earnings Attributable to SWEPCo Common Shareholder |
| (in millions) |
| | | |
| Nine Months Ended September 30, 2016 | | $ | 149.9 |
|
| | | |
|
| Changes in Gross Margin: | | |
|
| Retail Margins (a) | | (8.4 | ) |
| Off-system Sales | | 3.8 |
|
| Transmission Revenues | | (5.5 | ) |
| Other Revenues | | 0.3 |
|
| Total Change in Gross Margin | | (9.8 | ) |
| | | |
|
| Changes in Expenses and Other: | | |
|
| Other Operation and Maintenance | | 6.6 |
|
| Depreciation and Amortization | | (10.0 | ) |
| Taxes Other Than Income Taxes | | (5.8 | ) |
| Interest Income | | 2.0 |
|
| Allowance For Equity Funds Used During Construction | | (8.3 | ) |
| Interest Expense | | (0.7 | ) |
| Total Change in Expenses and Other | | (16.2 | ) |
| | | |
|
| Income Tax Expense | | 8.7 |
|
| Equity Earnings (Loss) of Unconsolidated Subsidiary | | (9.4 | ) |
| Net Income Attributable to Noncontrolling Interest | | (9.3 | ) |
| | | |
|
| Nine Months Ended September 30, 2017 | | $ | 113.9 |
|
| |
(a) | Includes firm wholesale sales to municipals and cooperatives. |
The major components of the decrease 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 decreased $8 million primarily due to the following:
A $29 million decrease in weather-related usage primarily due to a 33% decrease in heating degree days and a 12% decrease in cooling degree days.
A $9 million decrease in FERC generation wholesale municipal and cooperative revenues due to an annual formula rate true-up.
A $3 million decrease primarily due to lower fuel cost recovery.
These decreases were partially offset by:
A $33 million increase due to rider revenue increases in Louisiana, Texas and Arkansas, partially offset in various expenses below.
Margins from Off-System Sales increased $4 million primarily due to higher sales prices.
Transmission Revenues decreased $6 million primarily due to an accrual for SPP sponsor-funded transmission upgrades in third quarter 2016. This decrease is offset by a corresponding decrease in Other Operation and Maintenance expenses below.
Expenses and Other, Income Tax Expense, Equity Earnings (Loss) of Unconsolidated Subsidiary and Net Income Attributable to Noncontrolling Interest changed between years as follows:
Other Operation and Maintenance expenses decreased $7 million primarily due to an accrual for SPP sponsor-funded transmission upgrades in third quarter 2016. This decrease is partially offset by a corresponding decrease in Transmission Revenues above.
Depreciation and Amortization expenses increased $10 million primarily due to a higher depreciable base.
Taxes Other than Income Taxes increased $6 million primarily due to an increase in property taxes.
Allowance for Equity Funds Used During Construction decreased $8 million primarily due to the completion of environmental projects.
Income Tax Expense decreased $9 million primarily due to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine. This decrease is offset by an increase in Net Income Attributable to Noncontrolling Interest below.
Equity Earnings (Loss) of Unconsolidated Subsidiary decreased $9 million primarily due to a prior period income tax adjustment for DHLC.
Net Income Attributable to Noncontrolling Interest increased $9 million primarily due to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine. This increase is offset by a decrease in Income Tax Expense above.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2017March 31, 2023 and 20162022
(in millions)
(Unaudited)
| | | | | | | | | | | | | Three Months Ended March 31, |
| | | Three Months Ended | | Nine Months Ended | |
| | | September 30, | | September 30, | |
| | | 2017 | | 2016 | | 2017 | | 2016 | | | | 2023 | | 2022 |
| REVENUES | | | | | | | | |
| REVENUES | | | | | |
| Electric Generation, Transmission and Distribution | | $ | 509.5 |
| | $ | 530.5 |
| | $ | 1,321.8 |
| | $ | 1,324.1 |
| Electric Generation, Transmission and Distribution | | | $ | 503.7 | | | $ | 484.2 | |
| Sales to AEP Affiliates | | 7.7 |
| | 8.6 |
| | 20.4 |
| | 20.0 |
| Sales to AEP Affiliates | | | 11.7 | | | 10.0 | |
| | Other Revenues | | 0.4 |
| | 0.6 |
| | 1.4 |
| | 1.6 |
| Other Revenues | | | 0.5 | | | 0.6 | |
| TOTAL REVENUES | | 517.6 |
| | 539.7 |
| | 1,343.6 |
| | 1,345.7 |
| TOTAL REVENUES | | | 515.9 | | | 494.8 | |
| | | | | | | | | | | | | | |
| EXPENSES | | |
| | |
| | |
| | |
| EXPENSES | | | | | |
| Fuel and Other Consumables Used for Electric Generation | | 147.5 |
| | 158.8 |
| | 389.8 |
| | 403.3 |
| |
| Purchased Electricity for Resale | | 40.0 |
| | 35.9 |
| | 118.7 |
| | 97.5 |
| |
| Purchased Electricity, Fuel and Other Consumables Used for Electric Generation | | Purchased Electricity, Fuel and Other Consumables Used for Electric Generation | | | 209.3 | | | 198.2 | |
| | Other Operation | | 80.3 |
| | 89.2 |
| | 232.2 |
| | 243.3 |
| Other Operation | | | 99.2 | | | 91.5 | |
| Maintenance | | 32.6 |
| | 33.8 |
| | 106.5 |
| | 102.0 |
| Maintenance | | | 37.7 | | | 30.1 | |
| | Depreciation and Amortization | | 55.2 |
| | 51.2 |
| | 158.1 |
| | 148.1 |
| Depreciation and Amortization | | | 80.4 | | | 77.8 | |
| Taxes Other Than Income Taxes | | 25.0 |
| | 23.4 |
| | 72.6 |
| | 66.8 |
| Taxes Other Than Income Taxes | | | 36.1 | | | 29.8 | |
| TOTAL EXPENSES | | 380.6 |
| | 392.3 |
| | 1,077.9 |
| | 1,061.0 |
| TOTAL EXPENSES | | | 462.7 | | | 427.4 | |
| | | | | | | | | | | | | | |
| OPERATING INCOME | | 137.0 |
| | 147.4 |
| | 265.7 |
| | 284.7 |
| OPERATING INCOME | | | 53.2 | | | 67.4 | |
| | | | | | | | | | | | |
| Other Income (Expense): | | |
| | |
| | |
| | |
| Other Income (Expense): | | | | |
| Interest Income | | 0.7 |
| | — |
| | 2.0 |
| | — |
| Interest Income | | | 5.4 | | | 3.6 | |
| Allowance for Equity Funds Used During Construction | | 0.4 |
| | 0.1 |
| | 1.2 |
| | 9.5 |
| Allowance for Equity Funds Used During Construction | | | 0.5 | | | 1.6 | |
| Non-Service Cost Components of Net Periodic Benefit Cost | | Non-Service Cost Components of Net Periodic Benefit Cost | | | 3.4 | | | 3.1 | |
| | Interest Expense | | (31.9 | ) | | (32.6 | ) | | (92.7 | ) | | (92.0 | ) | Interest Expense | | | (25.0) | | | (33.1) | |
| | | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS (LOSS) | | 106.2 |
| | 114.9 |
| | 176.2 |
| | 202.2 |
| |
| INCOME BEFORE INCOME TAX BENEFIT AND EQUITY EARNINGS | | INCOME BEFORE INCOME TAX BENEFIT AND EQUITY EARNINGS | | | 37.5 | | | 42.6 | |
| | | | | | | | | | | | |
| Income Tax Expense | | 22.5 |
| | 33.2 |
| | 45.2 |
| | 53.9 |
| |
| Equity Earnings (Loss) of Unconsolidated Subsidiary | | 0.4 |
| | 2.7 |
| | (4.5 | ) | | 4.9 |
| |
| Income Tax Benefit | | Income Tax Benefit | | | (4.0) | | | (2.2) | |
| Equity Earnings of Unconsolidated Subsidiary | | Equity Earnings of Unconsolidated Subsidiary | | | 0.3 | | | 0.3 | |
| | | | | | | | | | | | | | |
| NET INCOME | | 84.1 |
| | 84.4 |
| | 126.5 |
| | 153.2 |
| NET INCOME | | | 41.8 | | | 45.1 | |
| | | | | | | | | | | | |
| Net Income Attributable to Noncontrolling Interest | | 11.0 |
| | 1.1 |
| | 12.6 |
| | 3.3 |
| Net Income Attributable to Noncontrolling Interest | | | 1.2 | | | 1.0 | |
| | | | | | | | | | | | | | |
| EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER | | $ | 73.1 |
| | $ | 83.3 |
| | $ | 113.9 |
| | $ | 149.9 |
| EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER | | | $ | 40.6 | | | $ | 44.1 | |
| | The common stock of SWEPCo is wholly-owned by Parent. | | The common stock of SWEPCo is wholly-owned by Parent. |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
|
| | | | |
The common stock of SWEPCo is wholly-owned by Parent. |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2017March 31, 2023 and 20162022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | |
| | | | |
| | | | |
| | Three Months Ended March 31, | | | | |
| | | 2023 | | 2022 | | | | |
| Net Income | | $ | 41.8 | | | $ | 45.1 | | | | | |
| | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | | | | | | | | |
| Cash Flow Hedges, Net of Tax of $0.1 and $0 in 2023 and 2022, Respectively | | 0.4 | | | 0.1 | | | | | |
| Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) in 2023 and 2022, Respectively | | (0.3) | | | (0.4) | | | | | |
| | | | | | | | |
| TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | | 0.1 | | | (0.3) | | | | | |
| | | | | | | | |
| TOTAL COMPREHENSIVE INCOME | | 41.9 | | | 44.8 | | | | | |
| | | | | | | | |
| Total Comprehensive Income Attributable to Noncontrolling Interest | | 1.2 | | | 1.0 | | | | | |
| | | | | | | | |
| TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER | | $ | 40.7 | | | $ | 43.8 | | | | | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
|
| | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| Net Income | $ | 84.1 |
| | $ | 84.4 |
| | $ | 126.5 |
| | $ | 153.2 |
|
| | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | |
| | | | |
| | |
|
| Cash Flow Hedges, Net of Tax of $0.2 and $0.2 for the Three Months Ended September 30, 2017 and 2016, Respectively, and $0.6 and $0.7 for the Nine Months Ended September 30, 2017 and 2016, Respectively | 0.4 |
| | 0.4 |
| | 1.1 |
| | 1.3 |
|
| Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2017 and 2016, Respectively, and $(0.3) and $(0.3) for the Nine Months Ended September 30, 2017 and 2016, Respectively | (0.2 | ) | | (0.1 | ) | | (0.5 | ) | | (0.5 | ) |
| | | | | | | | |
| TOTAL OTHER COMPREHENSIVE INCOME | 0.2 |
| | 0.3 |
| | 0.6 |
| | 0.8 |
|
| | | | | | | | |
| TOTAL COMPREHENSIVE INCOME | 84.3 |
| | 84.7 |
| | 127.1 |
| | 154.0 |
|
| | | | | | | | |
| Total Comprehensive Income Attributable to Noncontrolling Interest | 11.0 |
| | 1.1 |
| | 12.6 |
| | 3.3 |
|
| | | | | | | | |
| TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER | $ | 73.3 |
| | $ | 83.6 |
| | $ | 114.5 |
| | $ | 150.7 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the NineThree Months Ended September 30, 2017March 31, 2023 and 20162022
(in millions)
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | SWEPCo Common Shareholder | | | | |
| | Common
Stock | | Paid-in
Capital | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income (Loss) | | Noncontrolling Interest | | Total |
| TOTAL EQUITY - DECEMBER 31, 2015 | $ | 135.7 |
| | $ | 676.6 |
| | $ | 1,366.3 |
| | $ | (9.4 | ) | | $ | 0.5 |
| | $ | 2,169.7 |
|
| | | | | | | | | | | | |
| Common Stock Dividends | | | | | (90.0 | ) | | | | | | (90.0 | ) |
| Common Stock Dividends – Nonaffiliated | |
| | |
| | |
| | |
| | (3.5 | ) | | (3.5 | ) |
| Net Income | |
| | |
| | 149.9 |
| | |
| | 3.3 |
| | 153.2 |
|
| Other Comprehensive Income | |
| | |
| | |
| | 0.8 |
| | |
| | 0.8 |
|
| TOTAL EQUITY - SEPTEMBER 30, 2016 | $ | 135.7 |
| | $ | 676.6 |
| | $ | 1,426.2 |
| | $ | (8.6 | ) | | $ | 0.3 |
| | $ | 2,230.2 |
|
| | | | | | | | | | | | |
| TOTAL EQUITY - DECEMBER 31, 2016 | $ | 135.7 |
| | $ | 676.6 |
| | $ | 1,411.9 |
| | $ | (9.4 | ) | | $ | 0.4 |
| | $ | 2,215.2 |
|
| | | | | | | | | | | | |
| Common Stock Dividends | |
| | |
| | (82.5 | ) | | |
| | |
| | (82.5 | ) |
| Common Stock Dividends – Nonaffiliated | |
| | |
| | |
| | |
| | (2.7 | ) | | (2.7 | ) |
| Net Income | |
| | |
| | 113.9 |
| | |
| | 12.6 |
| | 126.5 |
|
| Other Comprehensive Income | |
| | |
| | |
| | 0.6 |
| | |
| | 0.6 |
|
| TOTAL EQUITY - SEPTEMBER 30, 2017 | $ | 135.7 |
| | $ | 676.6 |
| | $ | 1,443.3 |
| | $ | (8.8 | ) | | $ | 10.3 |
| | $ | 2,257.1 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| SWEPCo Common Shareholder | | | | |
| Common
Stock | | Paid-in
Capital | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income (Loss) | | Noncontrolling
Interest | | Total |
| TOTAL EQUITY – DECEMBER 31, 2021 | $ | 0.1 | | | $ | 1,092.2 | | | $ | 2,050.9 | | | $ | 6.7 | | | $ | (0.1) | | | $ | 3,149.8 | |
| | | | | | | | | | | |
| Capital Contribution from Parent | | | 350.0 | | | | | | | | 350.0 | |
| | | | | | | | | | | |
| Common Stock Dividends – Nonaffiliated | | | | | | | | | (0.8) | | | (0.8) | |
| | | | | | | | | | | |
| Net Income | | | | | 44.1 | | | | | 1.0 | | | 45.1 | |
| Other Comprehensive Loss | | | | | | | (0.3) | | | | | (0.3) | |
| TOTAL EQUITY – MARCH 31, 2022 | $ | 0.1 | | | $ | 1,442.2 | | | $ | 2,095.0 | | | $ | 6.4 | | | $ | 0.1 | | | $ | 3,543.8 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| TOTAL EQUITY – DECEMBER 31, 2022 | $ | 0.1 | | | $ | 1,442.2 | | | $ | 2,236.0 | | | $ | (4.2) | | | $ | 0.7 | | | $ | 3,674.8 | |
| | | | | | | | | | | |
| Capital Contribution from Parent | | | 50.0 | | | | | | | | | 50.0 | |
| | | | | | | | | | | |
| Common Stock Dividends – Nonaffiliated | | | | | | | | | (1.5) | | | (1.5) | |
| | | | | | | | | | | |
| Net Income | | | | | 40.6 | | | | | 1.2 | | | 41.8 | |
| Other Comprehensive Income | | | | | | | 0.1 | | | | | 0.1 | |
| TOTAL EQUITY – MARCH 31, 2023 | $ | 0.1 | | | $ | 1,492.2 | | | $ | 2,276.6 | | | $ | (4.1) | | | $ | 0.4 | | | $ | 3,765.2 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
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| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
|
| | | | |
| |
| |
| |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118114. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2017March 31, 2023 and December 31, 20162022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | | March 31, | | December 31, |
| | | 2023 | | 2022 |
| CURRENT ASSETS | | | | |
Cash and Cash Equivalents (March 31, 2023 and December 31, 2022 Amounts Include $3.9 and $84.2, Respectively, Related to Sabine) | | $ | 8.2 | | | $ | 88.4 | |
| Advances to Affiliates | | 2.1 | | | 2.1 | |
| Accounts Receivable: | | | | |
| Customers | | 33.9 | | | 38.8 | |
| Affiliated Companies | | 38.9 | | | 65.4 | |
| Miscellaneous | | 11.9 | | | 10.4 | |
| | | | |
| Total Accounts Receivable | | 84.7 | | | 114.6 | |
Fuel (March 31, 2023 and December 31, 2022 Amounts Include $0 and $14.2, Respectively, Related to Sabine) | | 90.6 | | | 81.3 | |
Materials and Supplies (March 31, 2023 and December 31, 2022 Amounts Include $4.2 and $4.2, Respectively, Related to Sabine) | | 84.5 | | | 92.1 | |
| Risk Management Assets | | 6.3 | | | 16.4 | |
| | | | |
| Accrued Tax Benefits | | 33.7 | | | 16.5 | |
| Regulatory Asset for Under-Recovered Fuel Costs | | 326.5 | | | 353.0 | |
| Prepayments and Other Current Assets | | 41.9 | | | 47.8 | |
| TOTAL CURRENT ASSETS | | 678.5 | | | 812.2 | |
| | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | |
| Electric: | | | | |
| Generation | | 4,870.3 | | | 5,476.2 | |
| Transmission | | 2,481.5 | | | 2,479.8 | |
| Distribution | | 2,691.1 | | | 2,659.6 | |
Other Property, Plant and Equipment (March 31, 2023 and December 31, 2022 Amounts Include $187.8 and $219.8, Respectively, Related to Sabine) | | 785.7 | | | 804.4 | |
| Construction Work in Progress | | 470.4 | | | 369.5 | |
| Total Property, Plant and Equipment | | 11,299.0 | | | 11,789.5 | |
Accumulated Depreciation and Amortization (March 31, 2023 and December 31, 2022 Amounts Include $187.8 and $212.5, Respectively, Related to Sabine) | | 2,956.4 | | | 3,527.3 | |
| TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 8,342.6 | | | 8,262.2 | |
| | | | |
| OTHER NONCURRENT ASSETS | | | | |
| Regulatory Assets | | 1,040.9 | | | 1,042.4 | |
| | | | |
| | | | |
| Deferred Charges and Other Noncurrent Assets | | 334.6 | | | 262.0 | |
| TOTAL OTHER NONCURRENT ASSETS | | 1,375.5 | | | 1,304.4 | |
| | | | |
| TOTAL ASSETS | | $ | 10,396.6 | | | $ | 10,378.8 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
|
| | | | | | | | |
| | | September 30, | | December 31, |
| | | 2017 | | 2016 |
| CURRENT ASSETS | | | | |
Cash and Cash Equivalents (September 30, 2017 and December 31, 2016 Amounts Include $0 and $8.7, Respectively, Related to Sabine) | | $ | 2.2 |
| | $ | 10.3 |
|
| Advances to Affiliates | | 2.0 |
| | 169.8 |
|
| Accounts Receivable: | | | | |
| Customers | | 23.5 |
| | 48.5 |
|
| Affiliated Companies | | 37.6 |
| | 29.3 |
|
| Miscellaneous | | 20.8 |
| | 17.5 |
|
| Allowance for Uncollectible Accounts | | (1.5 | ) | | (1.2 | ) |
| Total Accounts Receivable | | 80.4 |
| | 94.1 |
|
Fuel (September 30, 2017 and December 31, 2016 Amounts Include $43.2 and $34.3, Respectively, Related to Sabine) | | 93.1 |
| | 107.1 |
|
| Materials and Supplies | | 68.8 |
| | 68.4 |
|
| Risk Management Assets | | 12.5 |
| | 0.9 |
|
| Accrued Tax Benefits | | 14.5 |
| | 51.5 |
|
| Regulatory Asset for Under-Recovered Fuel Costs | | 13.6 |
| | 8.4 |
|
| Prepayments and Other Current Assets | | 35.5 |
| | 35.5 |
|
| TOTAL CURRENT ASSETS | | 322.6 |
| | 546.0 |
|
| | | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | |
| Electric: | | | | |
| Generation | | 4,632.9 |
| | 4,607.6 |
|
| Transmission | | 1,656.4 |
| | 1,584.2 |
|
| Distribution | | 2,084.2 |
| | 2,020.6 |
|
Other Property, Plant and Equipment (September 30, 2017 and December 31, 2016 Amounts Include $266.6 and $267.5, Respectively, Related to Sabine) | | 701.6 |
| | 670.4 |
|
| Construction Work in Progress | | 145.2 |
| | 113.8 |
|
| Total Property, Plant and Equipment | | 9,220.3 |
| | 8,996.6 |
|
Accumulated Depreciation and Amortization (September 30, 2017 and December 31, 2016 Amounts Include $162.8 and $155.6, Respectively, Related to Sabine) | | 2,670.5 |
| | 2,567.1 |
|
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 6,549.8 |
| | 6,429.5 |
|
| | | | | |
| OTHER NONCURRENT ASSETS | | | | |
| Regulatory Assets | | 566.4 |
| | 551.2 |
|
| Long-term Risk Management Assets | | 0.7 |
| | — |
|
| Deferred Charges and Other Noncurrent Assets | | 116.4 |
| | 99.9 |
|
| TOTAL OTHER NONCURRENT ASSETS | | 683.5 |
| | 651.1 |
|
| | | | | |
| TOTAL ASSETS | | $ | 7,555.9 |
| | $ | 7,626.6 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 2017March 31, 2023 and December 31, 20162022
(Unaudited)
| | | | | | | | | | | | | | |
| | | March 31, | | December 31, |
| | | 2023 | | 2022 |
| | | (in millions) |
| CURRENT LIABILITIES | | | | |
| Advances from Affiliates | | $ | 18.8 | | | $ | 310.7 | |
| Accounts Payable: | | | | |
| General | | 188.9 | | | 213.1 | |
| Affiliated Companies | | 51.5 | | | 81.7 | |
| Short-term Debt – Nonaffiliated | | 16.0 | | | — | |
| Long-term Debt Due Within One Year – Nonaffiliated | | — | | | 6.2 | |
| | | | |
| Customer Deposits | | 68.7 | | | 65.4 | |
| Accrued Taxes | | 132.3 | | | 52.8 | |
| Accrued Interest | | 27.9 | | | 36.0 | |
| | | | |
| Obligations Under Operating Leases | | 8.9 | | | 8.4 | |
| | | | |
| Asset Retirement Obligations | | 43.7 | | | 43.7 | |
| Other Current Liabilities | | 105.7 | | | 129.7 | |
| TOTAL CURRENT LIABILITIES | | 662.4 | | | 947.7 | |
| | | | |
| NONCURRENT LIABILITIES | | | | |
| Long-term Debt – Nonaffiliated | | 3,644.8 | | | 3,385.4 | |
| | | | |
| Deferred Income Taxes | | 1,103.7 | | | 1,089.7 | |
| Regulatory Liabilities and Deferred Investment Tax Credits | | 776.5 | | | 825.7 | |
| Asset Retirement Obligations | | 236.9 | | | 237.2 | |
| Employee Benefits and Pension Obligations | | 29.5 | | | 29.7 | |
| | | | |
| Obligations Under Operating Leases | | 121.4 | | | 120.2 | |
| Deferred Credits and Other Noncurrent Liabilities | | 56.2 | | | 68.4 | |
| TOTAL NONCURRENT LIABILITIES | | 5,969.0 | | | 5,756.3 | |
| | | | |
| TOTAL LIABILITIES | | 6,631.4 | | | 6,704.0 | |
| | | | |
| Rate Matters (Note 4) | | | | |
| Commitments and Contingencies (Note 5) | | | | |
| | | | |
| EQUITY | | | | |
| Common Stock – Par Value – $18 Per Share: | | | | |
| Authorized – 3,680 Shares | | | | |
| Outstanding – 3,680 Shares | | 0.1 | | | 0.1 | |
| Paid-in Capital | | 1,492.2 | | | 1,442.2 | |
| Retained Earnings | | 2,276.6 | | | 2,236.0 | |
| Accumulated Other Comprehensive Income (Loss) | | (4.1) | | | (4.2) | |
| TOTAL COMMON SHAREHOLDER’S EQUITY | | 3,764.8 | | | 3,674.1 | |
| | | | |
| Noncontrolling Interest | | 0.4 | | | 0.7 | |
| | | | |
| TOTAL EQUITY | | 3,765.2 | | | 3,674.8 | |
| | | | |
| TOTAL LIABILITIES AND EQUITY | | $ | 10,396.6 | | | $ | 10,378.8 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
|
| | | | | | | | |
| | | September 30, | | December 31, |
| | | 2017 | | 2016 |
| | | (in millions) |
| CURRENT LIABILITIES | | | | |
| Advances from Affiliates | | $ | 48.3 |
| | $ | — |
|
| Accounts Payable: | | | | |
| General | | 120.9 |
| | 117.5 |
|
| Affiliated Companies | | 38.5 |
| | 68.5 |
|
| Short-term Debt – Nonaffiliated | | 14.3 |
| | — |
|
| Long-term Debt Due Within One Year – Nonaffiliated | | 385.4 |
| | 353.7 |
|
| Risk Management Liabilities | | 0.1 |
| | 0.3 |
|
| Customer Deposits | | 61.6 |
| | 62.1 |
|
| Accrued Taxes | | 73.0 |
| | 40.9 |
|
| Accrued Interest | | 25.1 |
| | 45.1 |
|
| Obligations Under Capital Leases | | 11.4 |
| | 11.8 |
|
| Other Current Liabilities | | 77.5 |
| | 83.9 |
|
| TOTAL CURRENT LIABILITIES | | 856.1 |
| | 783.8 |
|
| | | | | |
| NONCURRENT LIABILITIES | | | | |
| Long-term Debt – Nonaffiliated | | 2,056.1 |
| | 2,325.4 |
|
| Deferred Income Taxes | | 1,694.5 |
| | 1,606.9 |
|
| Regulatory Liabilities and Deferred Investment Tax Credits | | 441.3 |
| | 438.9 |
|
| Asset Retirement Obligations | | 159.0 |
| | 147.1 |
|
| Employee Benefits and Pension Obligations | | 19.9 |
| | 34.1 |
|
| Obligations Under Capital Leases | | 60.2 |
| | 65.5 |
|
| Deferred Credits and Other Noncurrent Liabilities | | 11.7 |
| | 9.7 |
|
| TOTAL NONCURRENT LIABILITIES | | 4,442.7 |
| | 4,627.6 |
|
| | | | | |
| TOTAL LIABILITIES | | 5,298.8 |
| | 5,411.4 |
|
| | | | | |
| Rate Matters (Note 4) | |
| |
|
| Commitments and Contingencies (Note 5) | |
| |
|
| | | | | |
| EQUITY | | | | |
| Common Stock – Par Value – $18 Per Share: | | | | |
| Authorized – 7,600,000 Shares | | | | |
| Outstanding – 7,536,640 Shares | | 135.7 |
| | 135.7 |
|
| Paid-in Capital | | 676.6 |
| | 676.6 |
|
| Retained Earnings | | 1,443.3 |
| | 1,411.9 |
|
| Accumulated Other Comprehensive Income (Loss) | | (8.8 | ) | | (9.4 | ) |
| TOTAL COMMON SHAREHOLDER’S EQUITY | | 2,246.8 |
| | 2,214.8 |
|
| | | | | |
| Noncontrolling Interest | | 10.3 |
| | 0.4 |
|
| | | | | |
| TOTAL EQUITY | | 2,257.1 |
| | 2,215.2 |
|
| | | | | |
| TOTAL LIABILITIES AND EQUITY | | $ | 7,555.9 |
| | $ | 7,626.6 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the NineThree Months Ended September 30, 2017March 31, 2023 and 20162022
(in millions)
(Unaudited)
| | | | | | | | | | | | | | |
| | | Three Months Ended March 31, |
| | | 2023 | | 2022 |
| OPERATING ACTIVITIES | | | | |
| Net Income | | $ | 41.8 | | | $ | 45.1 | |
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | |
| Depreciation and Amortization | | 80.4 | | | 77.8 | |
| Deferred Income Taxes | | 10.8 | | | (9.5) | |
| | | | |
| Allowance for Equity Funds Used During Construction | | (0.5) | | | (1.6) | |
| Mark-to-Market of Risk Management Contracts | | 9.9 | | | (7.0) | |
| | | | |
| Property Taxes | | (77.5) | | | (64.5) | |
| Deferred Fuel Over/Under-Recovery, Net | | 42.9 | | | 9.2 | |
| | | | |
| Change in Other Noncurrent Assets | | 7.2 | | | 29.9 | |
| Change in Other Noncurrent Liabilities | | (3.3) | | | 16.7 | |
| Changes in Certain Components of Working Capital: | | | | |
| Accounts Receivable, Net | | 29.9 | | | 7.6 | |
| Fuel, Materials and Supplies | | (4.3) | | | (0.6) | |
| Accounts Payable | | (47.8) | | | (35.1) | |
| Accrued Taxes, Net | | 62.3 | | | 75.7 | |
| | | | |
| Other Current Assets | | 7.3 | | | 3.8 | |
| Other Current Liabilities | | (48.9) | | | (56.7) | |
| Net Cash Flows from Operating Activities | | 110.2 | | | 90.8 | |
| | | | |
| INVESTING ACTIVITIES | | | | |
| Construction Expenditures | | (201.9) | | | (129.5) | |
| Change in Advances to Affiliates, Net | | — | | | 153.8 | |
| Acquisition of the North Central Wind Energy Facilities | | — | | | (658.0) | |
| Other Investing Activities | | 0.4 | | | 1.9 | |
| Net Cash Flows Used for Investing Activities | | (201.5) | | | (631.8) | |
| | | | |
| FINANCING ACTIVITIES | | | | |
| Capital Contribution from Parent | | 50.0 | | | 350.0 | |
| Issuance of Long-term Debt – Nonaffiliated | | 347.3 | | | — | |
| | | | |
| Change in Short-term Debt – Nonaffiliated | | 16.0 | | | — | |
| Change in Advances from Affiliates, Net | | (291.9) | | | 202.9 | |
| Retirement of Long-term Debt – Nonaffiliated | | (94.1) | | | (1.6) | |
| Principal Payments for Finance Lease Obligations | | (14.8) | | | (2.7) | |
| | | | |
| Dividends Paid on Common Stock – Nonaffiliated | | (1.5) | | | (0.8) | |
| Other Financing Activities | | 0.1 | | | 0.1 | |
| Net Cash Flows from Financing Activities | | 11.1 | | | 547.9 | |
| | | | |
| Net Increase (Decrease) in Cash and Cash Equivalents | | (80.2) | | | 6.9 | |
| Cash and Cash Equivalents at Beginning of Period | | 88.4 | | | 51.2 | |
| Cash and Cash Equivalents at End of Period | | $ | 8.2 | | | $ | 58.1 | |
| | | | |
| SUPPLEMENTARY INFORMATION | | | | |
| Cash Paid for Interest, Net of Capitalized Amounts | | $ | 45.3 | | | $ | 37.7 | |
| | | | |
| Noncash Acquisitions Under Finance Leases | | 0.9 | | | 1.0 | |
| Construction Expenditures Included in Current Liabilities as of March 31, | | 113.3 | | | 47.8 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114. |
|
| | | | | | | | |
| | | Nine Months Ended September 30, |
| | | 2017 | | 2016 |
| OPERATING ACTIVITIES | | |
| | |
|
| Net Income | | $ | 126.5 |
| | $ | 153.2 |
|
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | |
| Depreciation and Amortization | | 158.1 |
| | 148.1 |
|
| Deferred Income Taxes | | 79.8 |
| | 141.9 |
|
| Allowance for Equity Funds Used During Construction | | (1.2 | ) | | (9.5 | ) |
| Mark-to-Market of Risk Management Contracts | | (12.5 | ) | | (5.8 | ) |
| Pension Contributions to Qualified Plan Trust | | (8.9 | ) | | (8.3 | ) |
| Property Taxes | | (15.4 | ) | | (13.7 | ) |
| Deferred Fuel Over/Under-Recovery, Net | | 2.4 |
| | 1.2 |
|
| Change in Other Noncurrent Assets | | (2.9 | ) | | 18.4 |
|
| Change in Other Noncurrent Liabilities | | (5.2 | ) | | (25.8 | ) |
| Changes in Certain Components of Working Capital: | | | | |
| Accounts Receivable, Net | | 12.1 |
| | 12.2 |
|
| Fuel, Materials and Supplies | | 13.6 |
| | 33.4 |
|
| Accounts Payable | | (25.7 | ) | | (17.2 | ) |
| Accrued Taxes, Net | | 69.1 |
| | 14.1 |
|
| Accrued Interest | | (20.0 | ) | | (20.0 | ) |
| Other Current Assets | | 0.7 |
| | (2.4 | ) |
| Other Current Liabilities | | (14.6 | ) | | (24.8 | ) |
| Net Cash Flows from Operating Activities | | 355.9 |
| | 395.0 |
|
| | | | | |
| INVESTING ACTIVITIES | | | | |
| Construction Expenditures | | (265.3 | ) | | (315.3 | ) |
| Change in Advances to Affiliates, Net | | 167.8 |
| | (297.4 | ) |
| Other Investing Activities | | 3.1 |
| | (1.9 | ) |
| Net Cash Flows Used for Investing Activities | | (94.4 | ) | | (614.6 | ) |
| | | | | |
| FINANCING ACTIVITIES | | | | |
| Issuance of Long-term Debt – Nonaffiliated | | 114.6 |
| | 402.2 |
|
| Change in Short-term Debt – Nonaffiliated | | 14.3 |
| | — |
|
| Change in Advances from Affiliates, Net | | 48.3 |
| | (58.3 | ) |
| Retirement of Long-term Debt – Nonaffiliated | | (353.6 | ) | | (3.3 | ) |
| Principal Payments for Capital Lease Obligations | | (8.4 | ) | | (18.6 | ) |
| Dividends Paid on Common Stock | | (82.5 | ) | | (90.0 | ) |
| Dividends Paid on Common Stock – Nonaffiliated | | (2.7 | ) | | (3.5 | ) |
| Other Financing Activities | | 0.4 |
| | 1.1 |
|
| Net Cash Flows from (Used for) Financing Activities | | (269.6 | ) | | 229.6 |
|
| | | | | |
| Net Increase (Decrease) in Cash and Cash Equivalents | | (8.1 | ) | | 10.0 |
|
| Cash and Cash Equivalents at Beginning of Period | | 10.3 |
| | 5.2 |
|
| Cash and Cash Equivalents at End of Period | | $ | 2.2 |
| | $ | 15.2 |
|
| | | | | |
| SUPPLEMENTARY INFORMATION | | | | |
| Cash Paid for Interest, Net of Capitalized Amounts | | $ | 109.4 |
| | $ | 107.6 |
|
| Net Cash Paid (Received) for Income Taxes | | (70.5 | ) | | (66.6 | ) |
| Noncash Acquisitions Under Capital Leases | | 2.8 |
| | 5.5 |
|
| Construction Expenditures Included in Current Liabilities as of September 30, | | 40.7 |
| | 54.3 |
|
|
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118. |
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANTS
The condensed notes to condensed 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 |
| | | | |
Note | | Registrant | | Page
Number
|
| | | | |
| Significant Accounting Matters | | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | | |
New Accounting PronouncementsStandards | | 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 | | |
| Commitments, Guarantees and Contingencies | | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | | |
Impairment, Disposition,Acquisitions and Assets and Liabilities Held for Sale | | AEP, I&MAEPTCo, PSO, SWEPCo | | |
| 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 | | |
| Financing Activities | | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | | |
| Variable Interest Entities | | AEP | | |
| | | | |
| Revenue from Contracts with Customers | | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | | |
1. SIGNIFICANT ACCOUNTING MATTERS
The disclosures in this note apply to all Registrants unless indicated otherwise.
General
The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.
In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentationstatement of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three and nine months ended September 30, 2017March 31, 2023 is not necessarily indicative of results that may be expected for the year ending December 31, 2017.2023. The condensed financial statements are unaudited and should be read in conjunction with the audited 20162022 financial statements and notes thereto, which are included in the Registrants (except AEPTCo)Registrants’ Annual Reports on Form 10-K as filed with the SEC on February 27, 2017. AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 2017.23, 2023.
Earnings Per Share (EPS) (Applies to AEP)
Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted averageweighted-average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted averageweighted-average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards.
The following tables presenttable presents AEP’s basic and diluted EPS calculations included on the statements of income:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, |
| 2023 | | 2022 |
| (in millions, except per share data) |
| | | $/share | | | | $/share |
| | | | | | | |
| | | | | | | |
| Earnings Attributable to AEP Common Shareholders | $ | 397.0 | | | | | $ | 714.7 | | | |
| | | | | | | |
| Weighted-Average Number of Basic AEP Common Shares Outstanding | 514.2 | | | $ | 0.77 | | | 506.1 | | | $ | 1.41 | |
| Weighted-Average Dilutive Effect of Stock-Based Awards | 1.4 | | | — | | | 1.6 | | | — | |
| Weighted-Average Number of Diluted AEP Common Shares Outstanding | 515.6 | | | $ | 0.77 | | | 507.7 | | | $ | 1.41 | |
|
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, |
| | 2017 | | 2016 |
| | (in millions, except per share data) |
| | |
| | $/share | | | | $/share |
| Income (Loss) from Continuing Operations | $ | 556.7 |
| | | | $ | (764.2 | ) | | |
| Less: Net Income Attributable to Noncontrolling Interests | 12.0 |
| | | | 1.6 |
| | |
| Earnings (Loss) Attributable to AEP Common Shareholders from Continuing Operations | $ | 544.7 |
| | |
| | $ | (765.8 | ) | | |
|
| | | | | | | | |
| Weighted Average Number of Basic Shares Outstanding | 491.8 |
| | $ | 1.11 |
| | 491.7 |
| | $ | (1.56 | ) |
| Weighted Average Dilutive Effect of Stock-Based Awards | 1.2 |
| | (0.01 | ) | | 0.1 |
| | — |
|
| Weighted Average Number of Diluted Shares Outstanding | 493.0 |
| | $ | 1.10 |
| | 491.8 |
| | $ | (1.56 | ) |
Equity Units are potentially dilutive securities and were excluded from the calculation of diluted EPS for the three months ended March 31, 2023 and 2022, as the dilutive stock price threshold was not met. See Note 12 - Financing Activities for more information related to Equity Units. |
| | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, |
| | 2017 | | 2016 |
| | (in millions, except per share data) |
| | |
| | $/share | | | | $/share |
| Income from Continuing Operations | $ | 1,527.1 |
| | | | $ | 245.3 |
| | |
| Less: Net Income Attributable to Noncontrolling Interests | 15.2 |
| | | | 5.3 |
| | |
| Earnings Attributable to AEP Common Shareholders from Continuing Operations | $ | 1,511.9 |
| | | | $ | 240.0 |
| | |
| | | | | | | | |
| Weighted Average Number of Basic Shares Outstanding | 491.8 |
| | $ | 3.07 |
| | 491.4 |
| | $ | 0.49 |
|
| Weighted Average Dilutive Effect of Stock-Based Awards | 0.6 |
| | — |
| | 0.2 |
| | — |
|
| Weighted Average Number of Diluted Shares Outstanding | 492.4 |
| | $ | 3.07 |
| | 491.6 |
| | $ | 0.49 |
|
There were no antidilutive shares outstanding as of September 30, 2017March 31, 2023 and 2016.2022, respectively.
Nonconsolidated Variable Interest Entity
Restricted Cash (Applies to AEP, AEP Texas and SWEPCo)APCo)
SWEPCo recorded prior year income tax adjustments inRestricted Cash primarily includes funds held by trustees for the second quarterpayment of 2017 relatedsecuritization 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 DHLC that impacted Equity Earnings (Loss)the total of Unconsolidated Subsidiary in the amountsame amounts shown on the statements of $6 million.cash flows:
| | | | | | | | | | | | | | | | | | | | |
| | March 31, 2023 |
| | AEP | | AEP Texas | | APCo |
| | (in millions) |
| Cash and Cash Equivalents | | $ | 343.5 | | | $ | 0.1 | | | $ | 7.1 | |
| Restricted Cash | | 50.0 | | | 42.5 | | | 7.5 | |
| Total Cash, Cash Equivalents and Restricted Cash | | $ | 393.5 | | | $ | 42.6 | | | $ | 14.6 | |
Supplementary Cash Flow Information (Applies to AEP)
| | | | | | | | | | | | | | | | | | | | |
| | December 31, 2022 |
| | AEP | | AEP Texas | | APCo |
| | (in millions) |
| Cash and Cash Equivalents | | $ | 509.4 | | | $ | 0.1 | | | $ | 7.5 | |
| Restricted Cash | | 47.1 | | | 32.7 | | | 14.4 | |
| Total Cash, Cash Equivalents and Restricted Cash | | $ | 556.5 | | | $ | 32.8 | | | $ | 21.9 | |
|
| | | | | | | | |
| | | Nine Months Ended September 30, |
| Cash Flow Information | | 2017 | | 2016 |
| | | (in millions) |
| Cash Paid (Received) for: | | | | |
| Interest, Net of Capitalized Amounts | | $ | 613.8 |
| | $ | 637.0 |
|
| Income Taxes, Net | | (6.8 | ) | | 32.2 |
|
| Noncash Investing and Financing Activities: | | | | |
| Acquisitions Under Capital Leases | | 44.5 |
| | 65.8 |
|
| Construction Expenditures Included in Current Liabilities as of September 30, | | 791.6 |
| | 604.8 |
|
| Construction Expenditures Included in Noncurrent Liabilities as of September 30, | | 71.8 |
| | — |
|
| Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, | | 0.6 |
| | 0.3 |
|
| Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage | | 2.8 |
| | — |
|
2. NEW ACCOUNTING PRONOUNCEMENTSSTANDARDS
The disclosures in this note apply to all Registrants unless indicated otherwise.
UponDuring the FASB’s standard-setting process and upon issuance of final pronouncements,standards, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements willThere are no new standards expected to have a material impact on the Registrants’ financial statements.
ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09)
In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts.
The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted.
Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016 and 2017, revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption.
The evaluation of revenue streams, new contracts and the new revenue standard’s disclosure requirements continues during the fourth quarter of 2017, in particular with respect to various ongoing industry implementation issues. Management will continue to analyze the related impacts to revenue recognition and monitor any new industry implementation issues that arise. Further, given industry conclusions related to implementation issues, including contributions in aid of construction and collectability, management does not anticipate changes to current accounting systems. Management plans to adopt ASU 2014-09 effective January 1, 2018.
ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01)
In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheets or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets.
The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018.
ASU 2016-02 “Accounting for Leases” (ASU 2016-02)
In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheets and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard.
The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented.
Management continues to analyze the impact of the new lease standard. During 2016 and 2017, lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Multiple lease system options were also evaluated. Management plans to elect certain of the following practical expedients upon adoption:
|
| | |
Practical Expedient | | Description |
Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) | | Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases. |
Lease and Non-lease Components (elect by class of underlying asset) | | Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component. |
Short-term Lease (elect by class of underlying asset) | | Elect as an accounting policy to not apply the recognition requirements to short-term leases. |
Lease term | | Elect to use hindsight to determine the lease term. |
Evaluation of new lease contracts continues and the process of implementing a compliant lease system solution began in the third quarter of 2017. Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019.
ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09)
In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income.
Management adopted ASU 2016-09 effective January 1, 2017. As a result of the adoption of this guidance, management made an accounting policy election to recognize the effect of forfeitures in compensation cost when they occur. There was an immaterial impact on results of operations and financial position and no impact on cash flows at adoption.
ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13)
In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination.
The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020.
ASU 2016-18 “Restricted Cash” (ASU 2016-18)
In November 2016, the FASB issued ASU 2016-18 clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows.
The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report.
ASU 2017-07 “Compensation - Retirement Benefits” (ASU 2017-07)
In March 2017, the FASB issued ASU 2017-07 requiring that an employer report the service cost component of pension and postretirement benefits in the same line item or items as other compensation costs. The other components of net benefit cost are required to be presented in the statements of income separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. For 2016, AEP’s actual non-service cost components were a credit of $66 million, of which approximately 37% was capitalized.
The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Management plans to adopt ASU 2017-07 effective January 1, 2018.
ASU 2017-12 “Derivatives and Hedging” (ASU 2017-12)
In August 2017, the FASB issued ASU 2017-12 amending the recognition and presentation requirements for hedge accounting activities. The objectives are to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and reduce the complexity of applying hedge accounting. Under the new standard, the concept of recognizing hedge ineffectiveness within the statements of income for cash flow hedges, which has historically been immaterial to AEP, will be eliminated. In addition, certain required tabular disclosures relating to fair value and cash flow hedges will be modified.
The new accounting guidance is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted for any interim or annual period after August 2017. Management is analyzing the impact of this new standard, including the possibility of early adoption, and at this time, cannot estimate the impact of adoption on net income.
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 condensed financial statements.and OPCo.
Presentation of Comprehensive Income
The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three and nine months ended September 30, 2017 and 2016.AOCI. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 - Benefit Plans for additional details.information.
AEP
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Cash Flow Hedges | | Pension | | |
| Three Months Ended March 31, 2023 | | Commodity | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
| Balance in AOCI as of December 31, 2022 | | $ | 223.5 | | | $ | 0.3 | | | $ | (140.1) | | | $ | 83.7 | |
| Change in Fair Value Recognized in AOCI, Net of Tax | | (195.3) | | | 5.2 | | | (12.9) | | | (203.0) | |
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| Purchased Electricity for Resale (a) | | 47.0 | | | — | | | — | | | 47.0 | |
| Interest Expense (a) | | — | | | 0.7 | | | — | | | 0.7 | |
| Amortization of Prior Service Cost (Credit) | | — | | | — | | | (5.3) | | | (5.3) | |
| Amortization of Actuarial (Gains) Losses | | — | | | — | | | 1.2 | | | 1.2 | |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | | 47.0 | | | 0.7 | | | (4.1) | | | 43.6 | |
| Income Tax (Expense) Benefit | | 9.9 | | | 0.1 | | | (0.9) | | | 9.1 | |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | 37.1 | | | 0.6 | | | (3.2) | | | 34.5 | |
| Reclassifications of KPCo Pension and OPEB Regulatory Assets from AOCI, before Income Tax (Expense) Benefit | | — | | | — | | | 21.1 | | | 21.1 | |
| Income Tax (Expense) Benefit | | — | | | — | | | 4.4 | | | 4.4 | |
| Reclassifications of KPCo Pension and OPEB Regulatory Assets from AOCI, Net of Income Tax (Expense) Benefit | | — | | | — | | | 16.7 | | | 16.7 | |
| Net Current Period Other Comprehensive Income (Loss) | | (158.2) | | | 5.8 | | | 0.6 | | | (151.8) | |
| Balance in AOCI as of March 31, 2023 | | $ | 65.3 | | | $ | 6.1 | | | $ | (139.5) | | | $ | (68.1) | |
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2017 | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Cash Flow Hedges | | Pension | | |
| Three Months Ended March 31, 2022 | | Commodity | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
| Balance in AOCI as of December 31, 2021 | | $ | 163.7 | | | $ | (21.3) | | | $ | 42.4 | | | $ | 184.8 | |
| Change in Fair Value Recognized in AOCI, Net of Tax | | 278.2 | | | 6.8 | | | — | | | 285.0 | |
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| Generation & Marketing Revenues (a) | | (0.1) | | | — | | | — | | | (0.1) | |
| Purchased Electricity for Resale (a) | | (47.9) | | | — | | | — | | | (47.9) | |
| Interest Expense (a) | | — | | | 1.1 | | | — | | | 1.1 | |
| Amortization of Prior Service Cost (Credit) | | — | | | — | | | (4.9) | | | (4.9) | |
| Amortization of Actuarial (Gains) Losses | | — | | | — | | | 2.1 | | | 2.1 | |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | | (48.0) | | | 1.1 | | | (2.8) | | | (49.7) | |
| Income Tax (Expense) Benefit | | (10.1) | | | 0.2 | | | (0.6) | | | (10.5) | |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | (37.9) | | | 0.9 | | | (2.2) | | | (39.2) | |
| Net Current Period Other Comprehensive Income (Loss) | | 240.3 | | | 7.7 | | | (2.2) | | | 245.8 | |
| Balance in AOCI as of March 31, 2022 | | $ | 404.0 | | | $ | (13.6) | | | $ | 40.2 | | | $ | 430.6 | |
|
| | | | | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | | | | | |
| | Commodity | | Interest Rate | | Securities
Available for Sale | | Pension
and OPEB | | Total |
| | (in millions) |
| Balance in AOCI as of June 30, 2017 | $ | (36.0 | ) | | $ | (10.4 | ) | | $ | 10.2 |
| | $ | (125.4 | ) | | $ | (161.6 | ) |
| Change in Fair Value Recognized in AOCI | (15.8 | ) | | (2.0 | ) | | 0.9 |
| | — |
| | (16.9 | ) |
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | | |
| Generation & Marketing Revenues | (0.9 | ) | | — |
| | — |
| | — |
| | (0.9 | ) |
| Purchased Electricity for Resale | 4.9 |
| | — |
| | — |
| | — |
| | 4.9 |
|
| Interest Expense | — |
| | 0.4 |
| | — |
| | — |
| | 0.4 |
|
| Amortization of Prior Service Cost (Credit) | — |
| | — |
| | — |
| | (5.0 | ) | | (5.0 | ) |
| Amortization of Actuarial (Gains)/Losses | — |
| | — |
| | — |
| | 5.4 |
| | 5.4 |
|
| Reclassifications from AOCI, before Income Tax (Expense) Credit | 4.0 |
| | 0.4 |
| | — |
| | 0.4 |
| | 4.8 |
|
| Income Tax (Expense) Credit | 1.4 |
| | 0.2 |
| | — |
| | 0.1 |
| | 1.7 |
|
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 2.6 |
| | 0.2 |
| | — |
| | 0.3 |
| | 3.1 |
|
| Net Current Period Other Comprehensive Income (Loss) | (13.2 | ) | | (1.8 | ) | | 0.9 |
| | 0.3 |
| | (13.8 | ) |
| Balance in AOCI as of September 30, 2017 | $ | (49.2 | ) | | $ | (12.2 | ) | | $ | 11.1 |
| | $ | (125.1 | ) | | $ | (175.4 | ) |
AEP | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
| Three Months Ended March 31, 2023 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
| Balance in AOCI as of December 31, 2022 | | | | $ | (0.3) | | | $ | (8.3) | | | $ | (8.6) | |
| Change in Fair Value Recognized in AOCI, Net of Tax | | | | (0.2) | | | (0.5) | | | (0.7) | |
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Interest Expense (a) | | | | 0.3 | | | — | | | 0.3 | |
| Amortization of Prior Service Cost (Credit) | | | | — | | | (0.1) | | | (0.1) | |
| | | | | | | | |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 0.3 | | | (0.1) | | | 0.2 | |
| Income Tax (Expense) Benefit | | | | 0.1 | | | — | | | 0.1 | |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0.2 | | | (0.1) | | | 0.1 | |
| Net Current Period Other Comprehensive Income (Loss) | | | | — | | | (0.6) | | | (0.6) | |
| Balance in AOCI as of March 31, 2023 | | | | $ | (0.3) | | | $ | (8.9) | | | $ | (9.2) | |
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2016 | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
| Three Months Ended March 31, 2022 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
| Balance in AOCI as of December 31, 2021 | | | | $ | (1.3) | | | $ | (5.2) | | | $ | (6.5) | |
| Change in Fair Value Recognized in AOCI, Net of Tax | | | | — | | | — | | | — | |
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Interest Expense (a) | | | | 0.4 | | | — | | | 0.4 | |
| | | | | | | | |
| | | | | | | | |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 0.4 | | | — | | | 0.4 | |
| Income Tax (Expense) Benefit | | | | 0.1 | | | — | | | 0.1 | |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0.3 | | | — | | | 0.3 | |
| Net Current Period Other Comprehensive Income (Loss) | | | | 0.3 | | | — | | | 0.3 | |
| Balance in AOCI as of March 31, 2022 | | | | $ | (1.0) | | | $ | (5.2) | | | $ | (6.2) | |
|
| | | | | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | | | | | |
| | Commodity | | Interest Rate | | Securities Available for Sale | | Pension and OPEB | | Total |
| | (in millions) |
| Balance in AOCI as of June 30, 2016 | $ | 1.9 |
| | $ | (16.5 | ) | | $ | 8.3 |
| | $ | (111.6 | ) | | $ | (117.9 | ) |
| Change in Fair Value Recognized in AOCI | (26.7 | ) | | — |
| | 0.5 |
| | — |
| | (26.2 | ) |
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | | |
| Generation & Marketing Revenues | (5.4 | ) | | — |
| | — |
| | — |
| | (5.4 | ) |
| Purchased Electricity for Resale | 1.8 |
| | — |
| | — |
| | — |
| | 1.8 |
|
| Interest Expense | — |
| | 0.6 |
| | — |
| | — |
| | 0.6 |
|
| Amortization of Prior Service Cost (Credit) | — |
| | — |
| | — |
| | (4.8 | ) | | (4.8 | ) |
| Amortization of Actuarial (Gains)/Losses | — |
| | — |
| | — |
| | 5.0 |
| | 5.0 |
|
| Reclassifications from AOCI, before Income Tax (Expense) Credit | (3.6 | ) | | 0.6 |
| | — |
| | 0.2 |
| | (2.8 | ) |
| Income Tax (Expense) Credit | (1.3 | ) | | 0.2 |
| | — |
| | — |
| | (1.1 | ) |
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (2.3 | ) | | 0.4 |
| | — |
| | 0.2 |
| | (1.7 | ) |
| Net Current Period Other Comprehensive Income (Loss) | (29.0 | ) | | 0.4 |
| | 0.5 |
| | 0.2 |
| | (27.9 | ) |
| Balance in AOCI as of September 30, 2016 | $ | (27.1 | ) | | $ | (16.1 | ) | | $ | 8.8 |
| | $ | (111.4 | ) | | $ | (145.8 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
| APCo | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
| Three Months Ended March 31, 2023 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
| Balance in AOCI as of December 31, 2022 | | | | $ | 6.7 | | | $ | (11.5) | | | $ | (4.8) | |
| Change in Fair Value Recognized in AOCI, Net of Tax | | | | — | | | (0.1) | | | (0.1) | |
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Interest Expense (a) | | | | (0.3) | | | — | | | (0.3) | |
| Amortization of Prior Service Cost (Credit) | | | | — | | | (1.2) | | | (1.2) | |
| Amortization of Actuarial (Gains) Losses | | | | — | | | 0.3 | | | 0.3 | |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | (0.3) | | | (0.9) | | | (1.2) | |
| Income Tax (Expense) Benefit | | | | (0.1) | | | (0.2) | | | (0.3) | |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | (0.2) | | | (0.7) | | | (0.9) | |
| Net Current Period Other Comprehensive Income (Loss) | | | | (0.2) | | | (0.8) | | | (1.0) | |
| Balance in AOCI as of March 31, 2023 | | | | $ | 6.5 | | | $ | (12.3) | | | $ | (5.8) | |
AEP
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2017 | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
| Three Months Ended March 31, 2022 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
| Balance in AOCI as of December 31, 2021 | | | | $ | 7.5 | | | $ | 16.9 | | | $ | 24.4 | |
| Change in Fair Value Recognized in AOCI, Net of Tax | | | | — | | | — | | | — | |
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Interest Expense (a) | | | | (0.3) | | | — | | | (0.3) | |
| Amortization of Prior Service Cost (Credit) | | | | — | | | (1.4) | | | (1.4) | |
| | | | | | | | |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | (0.3) | | | (1.4) | | | (1.7) | |
| Income Tax (Expense) Benefit | | | | (0.1) | | | (0.3) | | | (0.4) | |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | (0.2) | | | (1.1) | | | (1.3) | |
| Net Current Period Other Comprehensive Income (Loss) | | | | (0.2) | | | (1.1) | | | (1.3) | |
| Balance in AOCI as of March 31, 2022 | | | | $ | 7.3 | | | $ | 15.8 | | | $ | 23.1 | |
|
| | | | | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | | | | | |
| | Commodity | | Interest Rate | | Securities Available for Sale | | Pension and OPEB | | Total |
| | (in millions) |
| Balance in AOCI as of December 31, 2016 | $ | (23.1 | ) | | $ | (15.7 | ) | | $ | 8.4 |
| | $ | (125.9 | ) | | $ | (156.3 | ) |
| Change in Fair Value Recognized in AOCI | (39.4 | ) | | 2.7 |
| | 2.7 |
| | — |
| | (34.0 | ) |
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | | |
| Generation & Marketing Revenues | (5.6 | ) | | — |
| | — |
| | — |
| | (5.6 | ) |
| Purchased Electricity for Resale | 26.0 |
| | — |
| | — |
| | — |
| | 26.0 |
|
| Interest Expense | — |
| | 1.2 |
| | — |
| | — |
| | 1.2 |
|
| Amortization of Prior Service Cost (Credit) | — |
| | — |
| | — |
| | (14.8 | ) | | (14.8 | ) |
| Amortization of Actuarial (Gains)/Losses | — |
| | — |
| | — |
| | 16.0 |
| | 16.0 |
|
| Reclassifications from AOCI, before Income Tax (Expense) Credit | 20.4 |
| | 1.2 |
| | — |
| | 1.2 |
| | 22.8 |
|
| Income Tax (Expense) Credit | 7.1 |
| | 0.4 |
| | — |
| | 0.4 |
| | 7.9 |
|
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 13.3 |
| | 0.8 |
| | — |
| | 0.8 |
| | 14.9 |
|
| Net Current Period Other Comprehensive Income (Loss) | (26.1 | ) | | 3.5 |
| | 2.7 |
| | 0.8 |
| | (19.1 | ) |
| Balance in AOCI as of September 30, 2017 | $ | (49.2 | ) | | $ | (12.2 | ) | | $ | 11.1 |
| | $ | (125.1 | ) | | $ | (175.4 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
| I&M | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
| Three Months Ended March 31, 2023 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
| Balance in AOCI as of December 31, 2022 | | | | $ | (5.1) | | | $ | 4.8 | | | $ | (0.3) | |
| Change in Fair Value Recognized in AOCI, Net of Tax | | | | (1.1) | | | (1.7) | | | (2.8) | |
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Interest Expense (a) | | | | 0.5 | | | — | | | 0.5 | |
| Amortization of Prior Service Cost (Credit) | | | | — | | | (0.3) | | | (0.3) | |
| Amortization of Actuarial (Gains) Losses | | | | — | | | 0.1 | | | 0.1 | |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 0.5 | | | (0.2) | | | 0.3 | |
| Income Tax (Expense) Benefit | | | | 0.1 | | | — | | | 0.1 | |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0.4 | | | (0.2) | | | 0.2 | |
| Net Current Period Other Comprehensive Income (Loss) | | | | (0.7) | | | (1.9) | | | (2.6) | |
| Balance in AOCI as of March 31, 2023 | | | | $ | (5.8) | | | $ | 2.9 | | | $ | (2.9) | |
AEP
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2016 | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
| Three Months Ended March 31, 2022 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
| Balance in AOCI as of December 31, 2021 | | | | $ | (6.7) | | | $ | 5.4 | | | $ | (1.3) | |
| Change in Fair Value Recognized in AOCI, Net of Tax | | | | — | | | — | | | — | |
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Interest Expense (a) | | | | 0.5 | | | — | | | 0.5 | |
| Amortization of Prior Service Cost (Credit) | | | | — | | | (0.2) | | | (0.2) | |
| Amortization of Actuarial (Gains) Losses | | | | — | | | 0.1 | | | 0.1 | |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 0.5 | | | (0.1) | | | 0.4 | |
| Income Tax (Expense) Benefit | | | | 0.1 | | | — | | | 0.1 | |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0.4 | | | (0.1) | | | 0.3 | |
| Net Current Period Other Comprehensive Income (Loss) | | | | 0.4 | | | (0.1) | | | 0.3 | |
| Balance in AOCI as of March 31, 2022 | | | | $ | (6.3) | | | $ | 5.3 | | | $ | (1.0) | |
|
| | | | | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | | | | | |
| | Commodity | | Interest Rate | | Securities Available for Sale | | Pension and OPEB | | Total |
| | (in millions) |
| Balance in AOCI as of December 31, 2015 | $ | (5.2 | ) | | $ | (17.2 | ) | | $ | 7.1 |
| | $ | (111.8 | ) | | $ | (127.1 | ) |
| Change in Fair Value Recognized in AOCI | (17.7 | ) | | — |
| | 1.7 |
| | — |
| | (16.0 | ) |
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | | |
| Generation & Marketing Revenues | (20.7 | ) | | — |
| | — |
| | — |
| | (20.7 | ) |
| Purchased Electricity for Resale | 14.2 |
| | — |
| | — |
| | — |
| | 14.2 |
|
| Interest Expense | — |
| | 1.7 |
| | — |
| | — |
| | 1.7 |
|
| Amortization of Prior Service Cost (Credit) | — |
| | — |
| | — |
| | (14.6 | ) | | (14.6 | ) |
| Amortization of Actuarial (Gains)/Losses | — |
| | — |
| | — |
| | 15.2 |
| | 15.2 |
|
| Reclassifications from AOCI, before Income Tax (Expense) Credit | (6.5 | ) | | 1.7 |
| | — |
| | 0.6 |
| | (4.2 | ) |
| Income Tax (Expense) Credit | (2.3 | ) | | 0.6 |
| | — |
| | 0.2 |
| | (1.5 | ) |
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (4.2 | ) | | 1.1 |
| | — |
| | 0.4 |
| | (2.7 | ) |
| Net Current Period Other Comprehensive Income (Loss) | (21.9 | ) | | 1.1 |
| | 1.7 |
| | 0.4 |
| | (18.7 | ) |
| Balance in AOCI as of September 30, 2016 | $ | (27.1 | ) | | $ | (16.1 | ) | | $ | 8.8 |
| | $ | (111.4 | ) | | $ | (145.8 | ) |
| | | | | | | | | | | | | | |
| PSO | | | | | | | | |
| | | | Cash Flow Hedge – | | | | |
| Three Months Ended March 31, 2023 | | | | Interest Rate | | | | |
| | | (in millions) |
| Balance in AOCI as of December 31, 2022 | | | | $ | 1.3 | | | | | |
| Change in Fair Value Recognized in AOCI, Net of Tax | | | | (1.5) | | | | | |
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Interest Expense (a) | | | | — | | | | | |
| | | | | | | | |
| | | | | | | | |
| 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) | | | | (1.5) | | | | | |
| Balance in AOCI as of March 31, 2023 | | | | $ | (0.2) | | | | | |
APCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2017 | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | | | |
| Three Months Ended March 31, 2022 | | | | Interest Rate | | | | |
| | | (in millions) |
| Balance in AOCI as of December 31, 2021 | | | | $ | — | | | | | |
| Change in Fair Value Recognized in AOCI, Net of Tax | | | | — | | | | | |
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Interest Expense (a) | | | | — | | | | | |
| | | | | | | | |
| | | | | | | | |
| 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 March 31, 2022 | | | | $ | — | | | | | |
|
| | | | | | | | | | | | |
| | | Cash Flow Hedges | | | | |
| | | Interest Rate | | Pension and OPEB | | Total |
| | | (in millions) |
| Balance in AOCI as of June 30, 2017 | | $ | 2.5 |
| | $ | (11.9 | ) | | $ | (9.4 | ) |
| Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
| Interest Expense | | (0.2 | ) | | — |
| | (0.2 | ) |
| Amortization of Prior Service Cost (Credit) | | — |
| | (1.4 | ) | | (1.4 | ) |
| Amortization of Actuarial (Gains)/Losses | | — |
| | 0.9 |
| | 0.9 |
|
| Reclassifications from AOCI, before Income Tax (Expense) Credit | | (0.2 | ) | | (0.5 | ) | | (0.7 | ) |
| Income Tax (Expense) Credit | | (0.1 | ) | | (0.2 | ) | | (0.3 | ) |
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (0.1 | ) | | (0.3 | ) | | (0.4 | ) |
| Net Current Period Other Comprehensive Loss | | (0.1 | ) | | (0.3 | ) | | (0.4 | ) |
| Balance in AOCI as of September 30, 2017 | | $ | 2.4 |
| | $ | (12.2 | ) | | $ | (9.8 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
| SWEPCo | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
| Three Months Ended March 31, 2023 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
| Balance in AOCI as of December 31, 2022 | | | | $ | 1.1 | | | $ | (5.3) | | | $ | (4.2) | |
| Change in Fair Value Recognized in AOCI, Net of Tax | | | | 0.5 | | | — | | | 0.5 | |
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Interest Expense (a) | | | | (0.1) | | | — | | | (0.1) | |
| Amortization of Prior Service Cost (Credit) | | | | — | | | (0.5) | | | (0.5) | |
| Amortization of Actuarial (Gains) Losses | | | | — | | | 0.1 | | | 0.1 | |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | (0.1) | | | (0.4) | | | (0.5) | |
| Income Tax (Expense) Benefit | | | | — | | | (0.1) | | | (0.1) | |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | (0.1) | | | (0.3) | | | (0.4) | |
| Net Current Period Other Comprehensive Income (Loss) | | | | 0.4 | | | (0.3) | | | 0.1 | |
| Balance in AOCI as of March 31, 2023 | | | | $ | 1.5 | | | $ | (5.6) | | | $ | (4.1) | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
| Three Months Ended March 31, 2022 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
| Balance in AOCI as of December 31, 2021 | | | | $ | 1.2 | | | $ | 5.5 | | | $ | 6.7 | |
| Change in Fair Value Recognized in AOCI, Net of Tax | | | | — | | | — | | | — | |
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Interest Expense (a) | | | | 0.1 | | | — | | | 0.1 | |
| Amortization of Prior Service Cost (Credit) | | | | — | | | (0.5) | | | (0.5) | |
| | | | | | | | |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 0.1 | | | (0.5) | | | (0.4) | |
| Income Tax (Expense) Benefit | | | | — | | | (0.1) | | | (0.1) | |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0.1 | | | (0.4) | | | (0.3) | |
| Net Current Period Other Comprehensive Income (Loss) | | | | 0.1 | | | (0.4) | | | (0.3) | |
| Balance in AOCI as of March 31, 2022 | | | | $ | 1.3 | | | $ | 5.1 | | | $ | 6.4 | |
APCo(a)Amounts reclassified to the referenced line item on the statements of income.
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2016
|
| | | | | | | | | | | | |
| | | Cash Flow Hedges | | | | |
| | | Interest Rate | | Pension and OPEB | | Total |
| | | (in millions) |
| Balance in AOCI as of June 30, 2016 | | $ | 3.2 |
| | $ | (7.1 | ) | | $ | (3.9 | ) |
| Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
| Interest Expense | | (0.2 | ) | | — |
| | (0.2 | ) |
| Amortization of Prior Service Cost (Credit) | | — |
| | (1.2 | ) | | (1.2 | ) |
| Amortization of Actuarial (Gains)/Losses | | — |
| | 0.7 |
| | 0.7 |
|
| Reclassifications from AOCI, before Income Tax (Expense) Credit | | (0.2 | ) | | (0.5 | ) | | (0.7 | ) |
| Income Tax (Expense) Credit | | — |
| | (0.2 | ) | | (0.2 | ) |
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (0.2 | ) | | (0.3 | ) | | (0.5 | ) |
| Net Current Period Other Comprehensive Loss | | (0.2 | ) | | (0.3 | ) | | (0.5 | ) |
| Balance in AOCI as of September 30, 2016 | | $ | 3.0 |
| | $ | (7.4 | ) | | $ | (4.4 | ) |
APCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2017
|
| | | | | | | | | | | | |
| | | Cash Flow Hedges | | | | |
| | | Interest Rate | | Pension and OPEB | | Total |
| | | (in millions) |
| Balance in AOCI as of December 31, 2016 | | $ | 2.9 |
| | $ | (11.3 | ) | | $ | (8.4 | ) |
| Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
| Interest Expense | | (0.8 | ) | | — |
| | (0.8 | ) |
| Amortization of Prior Service Cost (Credit) | | — |
| | (4.0 | ) | | (4.0 | ) |
| Amortization of Actuarial (Gains)/Losses | | — |
| | 2.6 |
| | 2.6 |
|
| Reclassifications from AOCI, before Income Tax (Expense) Credit | | (0.8 | ) | | (1.4 | ) | | (2.2 | ) |
| Income Tax (Expense) Credit | | (0.3 | ) | | (0.5 | ) | | (0.8 | ) |
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (0.5 | ) | | (0.9 | ) | | (1.4 | ) |
| Net Current Period Other Comprehensive Loss | | (0.5 | ) | | (0.9 | ) | | (1.4 | ) |
| Balance in AOCI as of September 30, 2017 | | $ | 2.4 |
| | $ | (12.2 | ) | | $ | (9.8 | ) |
APCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2016
|
| | | | | | | | | | | | |
| | | Cash Flow Hedges | | | | |
| | | Interest Rate | | Pension and OPEB | | Total |
| | | (in millions) |
| Balance in AOCI as of December 31, 2015 | | $ | 3.6 |
| | $ | (6.4 | ) | | $ | (2.8 | ) |
| Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
| Interest Expense | | (0.8 | ) | | — |
| | (0.8 | ) |
| Amortization of Prior Service Cost (Credit) | | — |
| | (3.8 | ) | | (3.8 | ) |
| Amortization of Actuarial (Gains)/Losses | | — |
| | 2.2 |
| | 2.2 |
|
| Reclassifications from AOCI, before Income Tax (Expense) Credit | | (0.8 | ) | | (1.6 | ) | | (2.4 | ) |
| Income Tax (Expense) Credit | | (0.2 | ) | | (0.6 | ) | | (0.8 | ) |
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (0.6 | ) | | (1.0 | ) | | (1.6 | ) |
| Net Current Period Other Comprehensive Loss | | (0.6 | ) | | (1.0 | ) | | (1.6 | ) |
| Balance in AOCI as of September 30, 2016 | | $ | 3.0 |
| | $ | (7.4 | ) | | $ | (4.4 | ) |
I&M
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2017
|
| | | | | | | | | | | | |
| | | Cash Flow Hedges | | | | |
| | | Interest Rate | | Pension and OPEB | | Total |
| | | (in millions) |
| Balance in AOCI as of June 30, 2017 | | $ | (11.3 | ) | | $ | (4.2 | ) | | $ | (15.5 | ) |
| Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
| Interest Expense | | 0.5 |
| | — |
| | 0.5 |
|
| Amortization of Prior Service Cost (Credit) | | — |
| | (0.3 | ) | | (0.3 | ) |
| Amortization of Actuarial (Gains)/Losses | | — |
| | 0.3 |
| | 0.3 |
|
| Reclassifications from AOCI, before Income Tax (Expense) Credit | | 0.5 |
| | — |
| | 0.5 |
|
| Income Tax (Expense) Credit | | 0.2 |
| | — |
| | 0.2 |
|
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | 0.3 |
| | — |
| | 0.3 |
|
| Net Current Period Other Comprehensive Income | | 0.3 |
| | — |
| | 0.3 |
|
| Balance in AOCI as of September 30, 2017 | | $ | (11.0 | ) | | $ | (4.2 | ) | | $ | (15.2 | ) |
I&M
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2016
|
| | | | | | | | | | | | |
| | | Cash Flow Hedges | | | | |
| | | Interest Rate | | Pension and OPEB | | Total |
| | | (in millions) |
| Balance in AOCI as of June 30, 2016 | | $ | (12.6 | ) | | $ | (3.4 | ) | | $ | (16.0 | ) |
| Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
| Interest Expense | | 0.5 |
| | — |
| | 0.5 |
|
| Amortization of Prior Service Cost (Credit) | | — |
| | (0.2 | ) | | (0.2 | ) |
| Amortization of Actuarial (Gains)/Losses | | — |
| | 0.2 |
| | 0.2 |
|
| Reclassifications from AOCI, before Income Tax (Expense) Credit | | 0.5 |
| | — |
| | 0.5 |
|
| Income Tax (Expense) Credit | | 0.2 |
| | — |
| | 0.2 |
|
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | 0.3 |
| | — |
| | 0.3 |
|
| Net Current Period Other Comprehensive Income | | 0.3 |
| | — |
| | 0.3 |
|
| Balance in AOCI as of September 30, 2016 | | $ | (12.3 | ) | | $ | (3.4 | ) | | $ | (15.7 | ) |
I&M
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2017
|
| | | | | | | | | | | | |
| | | Cash Flow Hedges | | | | |
| | | Interest Rate | | Pension and OPEB | | Total |
| | | (in millions) |
| Balance in AOCI as of December 31, 2016 | | $ | (12.0 | ) | | $ | (4.2 | ) | | $ | (16.2 | ) |
| Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
| Interest Expense | | 1.5 |
| | — |
| | 1.5 |
|
| Amortization of Prior Service Cost (Credit) | | — |
| | (0.7 | ) | | (0.7 | ) |
| Amortization of Actuarial (Gains)/Losses | | — |
| | 0.7 |
| | 0.7 |
|
| Reclassifications from AOCI, before Income Tax (Expense) Credit | | 1.5 |
| | — |
| | 1.5 |
|
| Income Tax (Expense) Credit | | 0.5 |
| | — |
| | 0.5 |
|
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | 1.0 |
| | — |
| | 1.0 |
|
| Net Current Period Other Comprehensive Income | | 1.0 |
| | — |
| | 1.0 |
|
| Balance in AOCI as of September 30, 2017 | | $ | (11.0 | ) | | $ | (4.2 | ) | | $ | (15.2 | ) |
I&M
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2016
|
| | | | | | | | | | | | |
| | | Cash Flow Hedges | | | | |
| | | Interest Rate | | Pension and OPEB | | Total |
| | | (in millions) |
| Balance in AOCI as of December 31, 2015 | | $ | (13.3 | ) | | $ | (3.4 | ) | | $ | (16.7 | ) |
| Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
| Interest Expense | | 1.5 |
| | — |
| | 1.5 |
|
| Amortization of Prior Service Cost (Credit) | | — |
| | (0.6 | ) | | (0.6 | ) |
| Amortization of Actuarial (Gains)/Losses | | — |
| | 0.6 |
| | 0.6 |
|
| Reclassifications from AOCI, before Income Tax (Expense) Credit | | 1.5 |
| | — |
| | 1.5 |
|
| Income Tax (Expense) Credit | | 0.5 |
| | — |
| | 0.5 |
|
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | 1.0 |
| | — |
| | 1.0 |
|
| Net Current Period Other Comprehensive Income | | 1.0 |
| | — |
| | 1.0 |
|
| Balance in AOCI as of September 30, 2016 | | $ | (12.3 | ) | | $ | (3.4 | ) | | $ | (15.7 | ) |
OPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2017
|
| | | | |
| | | Cash Flow Hedges |
| | | Interest Rate |
| | | (in millions) |
| Balance in AOCI as of June 30, 2017 | | $ | 2.5 |
|
| Change in Fair Value Recognized in AOCI | | — |
|
| Amount of (Gain) Loss Reclassified from AOCI | | |
| Interest Expense | | (0.5 | ) |
| Reclassifications from AOCI, before Income Tax (Expense) Credit | | (0.5 | ) |
| Income Tax (Expense) Credit | | (0.2 | ) |
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (0.3 | ) |
| Net Current Period Other Comprehensive Loss | | (0.3 | ) |
| Balance in AOCI as of September 30, 2017 | | $ | 2.2 |
|
OPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2016
|
| | | | |
| | | Cash Flow Hedges |
| | | Interest Rate |
| | | (in millions) |
| Balance in AOCI as of June 30, 2016 | | $ | 3.5 |
|
| Change in Fair Value Recognized in AOCI | | — |
|
| Amount of (Gain) Loss Reclassified from AOCI | | |
| Interest Expense | | (0.3 | ) |
| Reclassifications from AOCI, before Income Tax (Expense) Credit | | (0.3 | ) |
| Income Tax (Expense) Credit | | (0.1 | ) |
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (0.2 | ) |
| Net Current Period Other Comprehensive Loss | | (0.2 | ) |
| Balance in AOCI as of September 30, 2016 | | $ | 3.3 |
|
OPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2017
|
| | | | |
| | | Cash Flow Hedges |
| | | Interest Rate |
| | | (in millions) |
| Balance in AOCI as of December 31, 2016 | | $ | 3.0 |
|
| Change in Fair Value Recognized in AOCI | | — |
|
| Amount of (Gain) Loss Reclassified from AOCI | | |
| Interest Expense | | (1.3 | ) |
| Reclassifications from AOCI, before Income Tax (Expense) Credit | | (1.3 | ) |
| Income Tax (Expense) Credit | | (0.5 | ) |
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (0.8 | ) |
| Net Current Period Other Comprehensive Loss | | (0.8 | ) |
| Balance in AOCI as of September 30, 2017 | | $ | 2.2 |
|
OPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2016
|
| | | | |
| | | Cash Flow Hedges |
| | | Interest Rate |
| | | (in millions) |
| Balance in AOCI as of December 31, 2015 | | $ | 4.3 |
|
| Change in Fair Value Recognized in AOCI | | — |
|
| Amount of (Gain) Loss Reclassified from AOCI | | |
| Interest Expense | | (1.4 | ) |
| Reclassifications from AOCI, before Income Tax (Expense) Credit | | (1.4 | ) |
| Income Tax (Expense) Credit | | (0.4 | ) |
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (1.0 | ) |
| Net Current Period Other Comprehensive Loss | | (1.0 | ) |
| Balance in AOCI as of September 30, 2016 | | $ | 3.3 |
|
PSO
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2017
|
| | | | |
| | | Cash Flow Hedges |
| | | Interest Rate |
| | | (in millions) |
| Balance in AOCI as of June 30, 2017 | | $ | 3.0 |
|
| Change in Fair Value Recognized in AOCI | | — |
|
| Amount of (Gain) Loss Reclassified from AOCI | | |
| Interest Expense | | (0.4 | ) |
| Reclassifications from AOCI, before Income Tax (Expense) Credit | | (0.4 | ) |
| Income Tax (Expense) Credit | | (0.2 | ) |
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (0.2 | ) |
| Net Current Period Other Comprehensive Loss | | (0.2 | ) |
| Balance in AOCI as of September 30, 2017 | | $ | 2.8 |
|
PSO
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2016
|
| | | | |
| | | Cash Flow Hedges |
| | | Interest Rate |
| | | (in millions) |
| Balance in AOCI as of June 30, 2016 | | $ | 3.8 |
|
| Change in Fair Value Recognized in AOCI | | — |
|
| Amount of (Gain) Loss Reclassified from AOCI | | |
| Interest Expense | | (0.3 | ) |
| Reclassifications from AOCI, before Income Tax (Expense) Credit | | (0.3 | ) |
| Income Tax (Expense) Credit | | (0.1 | ) |
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (0.2 | ) |
| Net Current Period Other Comprehensive Loss | | (0.2 | ) |
| Balance in AOCI as of September 30, 2016 | | $ | 3.6 |
|
PSO
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2017
|
| | | | |
| | | Cash Flow Hedges |
| | | Interest Rate |
| | | (in millions) |
| Balance in AOCI as of December 31, 2016 | | $ | 3.4 |
|
| Change in Fair Value Recognized in AOCI | | — |
|
| Amount of (Gain) Loss Reclassified from AOCI | | |
| Interest Expense | | (1.0 | ) |
| Reclassifications from AOCI, before Income Tax (Expense) Credit | | (1.0 | ) |
| Income Tax (Expense) Credit | | (0.4 | ) |
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (0.6 | ) |
| Net Current Period Other Comprehensive Loss | | (0.6 | ) |
| Balance in AOCI as of September 30, 2017 | | $ | 2.8 |
|
PSO
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2016
|
| | | | |
| | | Cash Flow Hedges |
| | | Interest Rate |
| | | (in millions) |
| Balance in AOCI as of December 31, 2015 | | $ | 4.2 |
|
| Change in Fair Value Recognized in AOCI | | — |
|
| Amount of (Gain) Loss Reclassified from AOCI | | |
| Interest Expense | | (0.9 | ) |
| Reclassifications from AOCI, before Income Tax (Expense) Credit | | (0.9 | ) |
| Income Tax (Expense) Credit | | (0.3 | ) |
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | (0.6 | ) |
| Net Current Period Other Comprehensive Loss | | (0.6 | ) |
| Balance in AOCI as of September 30, 2016 | | $ | 3.6 |
|
SWEPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2017
|
| | | | | | | | | | | | |
| | | Cash Flow Hedges | | | | |
| | | Interest Rate | | Pension and OPEB | | Total |
| | | (in millions) |
| Balance in AOCI as of June 30, 2017 | | $ | (6.7 | ) | | $ | (2.3 | ) | | $ | (9.0 | ) |
| Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
| Interest Expense | | 0.6 |
| | — |
| | 0.6 |
|
| Amortization of Prior Service Cost (Credit) | | — |
| | (0.5 | ) | | (0.5 | ) |
| Amortization of Actuarial (Gains)/Losses | | — |
| | 0.2 |
| | 0.2 |
|
| Reclassifications from AOCI, before Income Tax (Expense) Credit | | 0.6 |
| | (0.3 | ) | | 0.3 |
|
| Income Tax (Expense) Credit | | 0.2 |
| | (0.1 | ) | | 0.1 |
|
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | 0.4 |
| | (0.2 | ) | | 0.2 |
|
| Net Current Period Other Comprehensive Income (Loss) | | 0.4 |
| | (0.2 | ) | | 0.2 |
|
| Balance in AOCI as of September 30, 2017 | | $ | (6.3 | ) | | $ | (2.5 | ) | | $ | (8.8 | ) |
SWEPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2016
|
| | | | | | | | | | | | |
| | | Cash Flow Hedges | | | | |
| | | Interest Rate | | Pension and OPEB | | Total |
| | | (in millions) |
| Balance in AOCI as of June 30, 2016 | | $ | (8.2 | ) | | $ | (0.7 | ) | | $ | (8.9 | ) |
| Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
| Interest Expense | | 0.7 |
| | — |
| | 0.7 |
|
| Amortization of Prior Service Cost (Credit) | | — |
| | (0.4 | ) | | (0.4 | ) |
| Amortization of Actuarial (Gains)/Losses | | — |
| | 0.2 |
| | 0.2 |
|
| Reclassifications from AOCI, before Income Tax (Expense) Credit | | 0.7 |
| | (0.2 | ) | | 0.5 |
|
| Income Tax (Expense) Credit | | 0.3 |
| | (0.1 | ) | | 0.2 |
|
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | 0.4 |
| | (0.1 | ) | | 0.3 |
|
| Net Current Period Other Comprehensive Income (Loss) | | 0.4 |
| | (0.1 | ) | | 0.3 |
|
| Balance in AOCI as of September 30, 2016 | | $ | (7.8 | ) | | $ | (0.8 | ) | | $ | (8.6 | ) |
SWEPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2017
|
| | | | | | | | | | | | |
| | | Cash Flow Hedges | | | | |
| | | Interest Rate | | Pension and OPEB | | Total |
| | | (in millions) |
| Balance in AOCI as of December 31, 2016 | | $ | (7.4 | ) | | $ | (2.0 | ) | | $ | (9.4 | ) |
| Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
| Interest Expense | | 1.7 |
| | — |
| | 1.7 |
|
| Amortization of Prior Service Cost (Credit) | | — |
| | (1.5 | ) | | (1.5 | ) |
| Amortization of Actuarial (Gains)/Losses | | — |
| | 0.7 |
| | 0.7 |
|
| Reclassifications from AOCI, before Income Tax (Expense) Credit | | 1.7 |
| | (0.8 | ) | | 0.9 |
|
| Income Tax (Expense) Credit | | 0.6 |
| | (0.3 | ) | | 0.3 |
|
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | 1.1 |
| | (0.5 | ) | | 0.6 |
|
| Net Current Period Other Comprehensive Income (Loss) | | 1.1 |
| | (0.5 | ) | | 0.6 |
|
| Balance in AOCI as of September 30, 2017 | | $ | (6.3 | ) | | $ | (2.5 | ) | | $ | (8.8 | ) |
SWEPCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2016
|
| | | | | | | | | | | | |
| | | Cash Flow Hedges | | | | |
| | | Interest Rate | | Pension and OPEB | | Total |
| | | (in millions) |
| Balance in AOCI as of December 31, 2015 | | $ | (9.1 | ) | | $ | (0.3 | ) | | $ | (9.4 | ) |
| Change in Fair Value Recognized in AOCI | | — |
| | — |
| | — |
|
| Amount of (Gain) Loss Reclassified from AOCI | | | | | | |
| Interest Expense | | 2.0 |
| | — |
| | 2.0 |
|
| Amortization of Prior Service Cost (Credit) | | — |
| | (1.4 | ) | | (1.4 | ) |
| Amortization of Actuarial (Gains)/Losses | | — |
| | 0.6 |
| | 0.6 |
|
| Reclassifications from AOCI, before Income Tax (Expense) Credit | | 2.0 |
| | (0.8 | ) | | 1.2 |
|
| Income Tax (Expense) Credit | | 0.7 |
| | (0.3 | ) | | 0.4 |
|
| Reclassifications from AOCI, Net of Income Tax (Expense) Credit | | 1.3 |
| | (0.5 | ) | | 0.8 |
|
| Net Current Period Other Comprehensive Income (Loss) | | 1.3 |
| | (0.5 | ) | | 0.8 |
|
| Balance in AOCI as of September 30, 2016 | | $ | (7.8 | ) | | $ | (0.8 | ) | | $ | (8.6 | ) |
4. RATE MATTERS
The disclosures in this note apply to all Registrants unless indicated otherwise.
As discussed in AEP’s and AEPTCo’s 2016the 2022 Annual Reports,Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within AEP’s and AEPTCo’s 2016the 2022 Annual ReportsReport should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 20172023 and updates AEP’sthe 2022 Annual Report.
Coal-Fired Generation Plants (Applies to AEP, PSO and AEPTCo’s 2016 Annual Reports.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 is not deemed recoverable, it could materially reduce future net income and cash flows and impact financial condition.
Regulated Generating Units that have been Retired
SWEPCo
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 through 2046, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $12 million in 2021. As part of the 2021 Arkansas Base Rate Case, the APSC authorized recovery of SWEPCo’s Arkansas jurisdictional share of the Dolet Hills Power Station through 2027, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $2 million in the second quarter of 2022. Also, the APSC did not rule on the prudency of the early retirement of the Dolet Hills Power Station, which will be addressed in a future proceeding. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo’s Louisiana share of the Dolet Hills Power Station, through a separate rider, through 2032, but did not rule on the prudency of the early retirement of the plant, which is being addressed in a separate proceeding. See “2020 Texas Base Rate Case” and “2020 Louisiana Base Rate Case” sections below for additional information.
In March 2023, the Pirkey Plant was retired. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo’s Louisiana jurisdictional share of the Pirkey Plant, through a separate rider, through 2032. As part of the 2021 Arkansas Base Rate Case, the APSC granted SWEPCo regulatory asset treatment. SWEPCo will request recovery including a weighted average cost of capital carrying charge through a future proceeding. The Texas jurisdictional share of the Pirkey Plant will be addressed in SWEPCo’s next base rate case.
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.
SWEPCo
In November 2020, management announced 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 March 31, 2023, 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 | | | | | | $ | 128.5 | | | $ | 150.3 | | | | | $ | 20.3 | | (b) | | 2026 | | (c) | | $ | 14.9 | |
| | | | | | | | | | | | | | | | | | | |
| Welsh Plant, Units 1 and 3 | | | | | | 399.6 | | | 95.5 | | | | | 58.1 | | (d) | | 2028 | | (e) | | 38.3 | |
(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 the removal of Northeastern Plant, Unit 3, after retirement.
(c)Northeastern Plant, Unit 3 is currently being recovered through 2040.
(d)Includes Welsh Plant, Unit 2, which was retired in 2016. Removal of Welsh Plant, Unit 2, will be performed with the removal of Welsh Plant, Units 1 and 3, after retirement.
(e)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 December 2021, the Dolet Hills Power Station was retired. While in operation, DHLC provided 100% of the fuel supply to Dolet Hills Power Station.
The remaining book value of Dolet Hills Power Station non-fuel related assets are recoverable by SWEPCo through rate riders. As of March 31, 2023, SWEPCo’s share of the net investment in the Dolet Hills Power Station was $110 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 and are subject to prudency determinations by the various commissions. After closure of the DHLC mining operations and the Dolet Hills Power Station, additional reclamation and other land-related costs incurred by DHLC and Oxbow will continue to be billed to SWEPCo and included in existing fuel clauses. As of March 31, 2023, SWEPCo had a net under-recovered fuel balance of $233 million, inclusive of costs related to the Dolet Hills Power Station billed by DHLC, but excluding impacts of the February 2021 severe winter weather event.
In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $20 million of fuel costs in 2021 and defer approximately $33 million of additional costs with a recovery period to be determined at a later date. In August 2022, the LPSC staff filed testimony recommending fuel disallowances of $72 million, including denial of recovery of the $33 million deferral, with refunds to customers over five years. In September 2022, SWEPCo filed rebuttal testimony addressing the LPSC staff recommendations.
In March 2021, the APSC approved fuel rates that provide recovery of $20 million for the Arkansas share of the 2021 Dolet Hills Power Station fuel costs over five years through the existing fuel clause.
In August 2022, SWEPCo filed a fuel reconciliation with the PUCT covering the fuel period of January 1, 2020 through December 31, 2021. Intervenors submitted testimony and SWEPCo filed rebuttal testimony in the first quarter of 2023, and a decision from the PUCT is expected in the third quarter of 2023.
If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
Pirkey Plant and Related Fuel Operations (Applies to AEP and SWEPCo)
In March 2023, the Pirkey Plant was retired. SWEPCo is recovering, or will seek recovery of, the remaining net book value of Pirkey Plant non-fuel costs. As of March 31, 2023, SWEPCo’s share of the net investment in the Pirkey Plant was $177 million, including materials and supplies, net of cost of removal. See the “Regulated Generating Units that have been Retired” section above for additional information.Fuel costs are recovered through active fuel clauses and are subject to prudency determinations by the various commissions. As of March 31, 2023, SWEPCo fuel deliveries, including billings of all fixed costs, from Sabine ceased. Additionally, as of March 31, 2023, SWEPCo had a net under-recovered fuel balance of $233 million, inclusive of costs related to the Pirkey Plant billed by Sabine, but excluding impacts of the February 2021 severe winter weather event. Remaining 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.
Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except AEPTCo)
| | | | | | | | | | | | | | |
| | AEP |
| | March 31, | | December 31, |
| | 2023 | | 2022 |
| Noncurrent Regulatory Assets | | (in millions) |
| | | | |
| Regulatory Assets Currently Earning a Return | | | | |
| Unrecovered Winter Storm Fuel Costs (a) | | $ | 115.9 | | | $ | 121.7 | |
| | | | |
| | | | |
| Welsh Plant, Units 1 and 3 Accelerated Depreciation | | 95.5 | | | 85.6 | |
| Pirkey Plant Accelerated Depreciation | | 111.8 | | | 116.5 | |
| | | | |
| Dolet Hills Power Station Fuel Costs - Louisiana | | 33.3 | | | 32.0 | |
| Texas Mobile Generation Lease Payments | | 24.6 | | | 17.6 | |
| | | | |
| | | | |
| Other Regulatory Assets Pending Final Regulatory Approval | | 21.4 | | | 19.3 | |
| Regulatory Assets Currently Not Earning a Return | | | | |
| Storm-Related Costs (b)(c) | | 265.1 | | | 407.2 | |
| 2020-2022 Virginia Triennial Under-Earnings | | 37.9 | | | 37.9 | |
| Plant Retirement Costs – Asset Retirement Obligation Costs | | 25.9 | | | 25.9 | |
| Other Regulatory Assets Pending Final Regulatory Approval | | 43.1 | | | 55.6 | |
| Total Regulatory Assets Pending Final Regulatory Approval | $ | 774.5 | | | $ | 919.3 | |
(a)Includes $37 million and $37 million of unrecovered winter storm fuel costs recorded as a current regulatory asset as of March 31, 2023 and December 31, 2022, respectively. See the “February 2021 Severe Winter Weather Impacts in SPP” section below for additional information.
(b)In April 2023, OPCo filed a request with the PUCO for recovery of $34 million in Ohio storm-related costs.
(c)In April 2023, the LPSC issued an order approving the prudence and future recovery of the Louisiana storm-related costs. See “2021 Louisiana Storm Cost Filing” section below for additional information.
|
| | | | | | | | |
| | | AEP |
| | | September 30, | | December 31, |
| | | 2017 | | 2016 |
| Noncurrent Regulatory Assets | | (in millions) |
| | | | | |
| Regulatory Assets Currently Earning a Return | | | | |
| Plant Retirement Costs - Unrecovered Plant (a) | | $ | 209.1 |
| | $ | 159.9 |
|
| Storm-Related Costs | | 97.4 |
| | 25.1 |
|
| Plant Retirement Costs - Materials and Supplies | | 9.1 |
| | 9.1 |
|
| Ohio Capacity Deferral | | — |
| | 96.7 |
|
| Other Regulatory Assets Pending Final Regulatory Approval | | 1.1 |
| | 1.3 |
|
| Regulatory Assets Currently Not Earning a Return | | |
| | |
|
| Storm-Related Costs | | 42.6 |
| | 25.9 |
|
| Plant Retirement Costs - Asset Retirement Obligation Costs | | 37.2 |
| | 29.6 |
|
| Cook Plant Uprate Project | | 36.3 |
| | 36.3 |
|
| Environmental Control Projects | | 24.3 |
| | 24.1 |
|
| Cook Plant Turbine | | 15.1 |
| | 12.8 |
|
| Deferred Cook Plant Life Cycle Management Project Costs - Michigan | | 13.0 |
| | 8.1 |
|
| Other Regulatory Assets Pending Final Regulatory Approval | | 25.6 |
| | 21.2 |
|
| Total Regulatory Assets Pending Final Regulatory Approval (b) | | $ | 510.8 |
| | $ | 450.1 |
|
| | | | | | | | | | | | | | |
| | AEP Texas |
| | March 31, | | December 31, |
| | 2023 | | 2022 |
| Noncurrent Regulatory Assets | | (in millions) |
| | | | |
| Regulatory Assets Currently Earning a Return | | | | |
| Texas Mobile Generation Lease Payments | | $ | 24.6 | | | $ | 17.6 | |
| Regulatory Assets Currently Not Earning a Return | | | | |
| Storm-Related Costs | | 28.9 | | | 26.7 | |
| Vegetation Management Program | | 5.2 | | | 5.2 | |
| Texas Retail Electric Provider Bad Debt Expense | | 4.1 | | | 4.1 | |
| Other Regulatory Assets Pending Final Regulatory Approval | | 13.5 | | | 13.4 | |
| Total Regulatory Assets Pending Final Regulatory Approval | | $ | 76.3 | | | $ | 67.0 | |
| |
(a) | In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of September 30, 2017, the unrecovered plant balance related to Northeastern Plant, Unit 3 was $52 million. |
| |
(b) | In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. |
| | | | | | | | | | | | | | |
| | APCo |
| | March 31, | | December 31, |
| | 2023 | | 2022 |
| Noncurrent Regulatory Assets | | (in millions) |
| | | | |
| Regulatory Assets Currently Earning a Return | | | | |
| COVID-19 – Virginia | | $ | 7.1 | | | $ | 7.0 | |
| | | | |
| Regulatory Assets Currently Not Earning a Return | | | | |
| Storm-Related Costs - West Virginia | | 72.1 | | | 72.6 | |
| 2020-2022 Virginia Triennial Under-Earnings | | 37.9 | | | 37.9 | |
| Plant Retirement Costs – Asset Retirement Obligation Costs | | 25.9 | | | 25.9 | |
| Other Regulatory Assets Pending Final Regulatory Approval | | 0.6 | | | 1.1 | |
| Total Regulatory Assets Pending Final Regulatory Approval | | $ | 143.6 | | | $ | 144.5 | |
| | | | | | | | | | | | | | |
| | | I&M |
| | March 31, | | December 31, |
| | 2023 | | 2022 |
| Noncurrent Regulatory Assets | | (in millions) |
| | | | |
| Regulatory Assets Currently Earning a Return | | | | |
| Other Regulatory Assets Pending Final Regulatory Approval | | $ | 0.1 | | | $ | 0.1 | |
| Regulatory Assets Currently Not Earning a Return | | | | |
| Storm-Related Costs - Indiana | | 23.0 | | | 21.6 | |
| | | | |
| | | | |
| Other Regulatory Assets Pending Final Regulatory Approval | | 2.2 | | | 2.0 | |
| Total Regulatory Assets Pending Final Regulatory Approval | | $ | 25.3 | | | $ | 23.7 | |
|
| | | | | | | | |
| | | APCo |
| | | September 30, | | December 31, |
| | | 2017 | | 2016 |
| Noncurrent Regulatory Assets | | (in millions) |
| | | | | |
| Regulatory Assets Currently Earning a Return | | | | |
| Plant Retirement Costs - Materials and Supplies | | $ | 9.1 |
| | $ | 9.1 |
|
| Regulatory Assets Currently Not Earning a Return | | | | |
| Plant Retirement Costs - Asset Retirement Obligation Costs | | 37.2 |
| | 29.6 |
|
| Other Regulatory Assets Pending Final Regulatory Approval | | 0.6 |
| | 0.6 |
|
| Total Regulatory Assets Pending Final Regulatory Approval (a) | | $ | 46.9 |
| | $ | 39.3 |
|
| | | | | | | | | | | | | | |
| | | OPCo |
| | March 31, | | December 31, |
| | 2023 | | 2022 |
| Noncurrent Regulatory Assets | | (in millions) |
| | | | |
| Regulatory Assets Currently Not Earning a Return | | | | |
| | | | |
| | | | |
| | | | |
| Storm-Related Costs (a) | | $ | 36.3 | | | $ | 33.8 | |
| | | | |
| | | | |
| Total Regulatory Assets Pending Final Regulatory Approval | | $ | 36.3 | | | $ | 33.8 | |
| |
(a) | In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. |
(a)In April 2023, OPCo filed a request with the PUCO for recovery of $34 million in storm costs. |
| | | | | | | | |
| | | I&M |
| | | September 30, | | December 31, |
| | | 2017 | | 2016 |
| Noncurrent Regulatory Assets | | (in millions) |
| | | | | |
| Regulatory Assets Currently Not Earning a Return | | | | |
| Cook Plant Uprate Project | | $ | 36.3 |
| | $ | 36.3 |
|
| Cook Plant Turbine | | 15.1 |
| | 12.8 |
|
| Deferred Cook Plant Life Cycle Management Project Costs - Michigan | | 13.0 |
| | 8.1 |
|
| Rockport Dry Sorbent Injection System - Indiana | | 9.4 |
| | 6.6 |
|
| Other Regulatory Assets Pending Final Regulatory Approval | | 1.5 |
| | 0.9 |
|
| Total Regulatory Assets Pending Final Regulatory Approval | | $ | 75.3 |
| | $ | 64.7 |
|
| | | | | | | | | | | | | | |
| | | PSO |
| | March 31, | | December 31, |
| | 2023 | | 2022 |
| Noncurrent Regulatory Assets | | (in millions) |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Regulatory Assets Currently Not Earning a Return | | | | |
| | | | |
| | | | |
| Storm-Related Costs | | $ | 29.2 | | | $ | 25.5 | |
| Other Regulatory Assets Pending Final Regulatory Approval | | 0.1 | | | 0.1 | |
| Total Regulatory Assets Pending Final Regulatory Approval | | $ | 29.3 | | | $ | 25.6 | |
|
| | | | | | | | |
| | | OPCo |
| | | September 30, | | December 31, |
| | | 2017 | | 2016 |
| Noncurrent Regulatory Assets | | (in millions) |
| | | | | |
| Regulatory Assets Currently Earning a Return | | | | |
| Capacity Deferral | | $ | — |
| | $ | 96.7 |
|
| Regulatory Assets Currently Not Earning a Return | | |
| | |
|
| Smart Grid Costs | | — |
| | 4.1 |
|
| Total Regulatory Assets Pending Final Regulatory Approval | | $ | — |
| | $ | 100.8 |
|
| | | | | | | | | | | | | | |
| | SWEPCo |
| | March 31, | | December 31, |
| | 2023 | | 2022 |
| Noncurrent Regulatory Assets | | (in millions) |
| | | | |
| Regulatory Assets Currently Earning a Return | | | | |
| Unrecovered Winter Storm Fuel Costs (a) | | $ | 115.9 | | | $ | 121.7 | |
| | | | |
| Welsh Plant, Units 1 and 3 Accelerated Depreciation | | 95.5 | | | 85.6 | |
| Pirkey Plant Accelerated Depreciation | | 111.8 | | | 116.5 | |
| | | | |
| Dolet Hills Power Station Fuel Costs - Louisiana | | 33.3 | | | 32.0 | |
| Dolet Hills Power Station | | 12.1 | | | 9.7 | |
| Other Regulatory Assets Pending Final Regulatory Approval | | 2.1 | | | 2.5 | |
| Regulatory Assets Currently Not Earning a Return | | | | |
| Storm-Related Costs - Louisiana (b) | | — | | | 151.5 | |
| Asset Retirement Obligation - Louisiana | | — | | | 11.8 | |
| Other Regulatory Assets Pending Final Regulatory Approval | | 15.4 | | | 16.0 | |
| Total Regulatory Assets Pending Final Regulatory Approval | | $ | 386.1 | | | $ | 547.3 | |
(a)Includes $37 million and $37 million of unrecovered winter storm fuel costs recorded as a current regulatory asset as of March 31, 2023 and December 31, 2022, respectively. See the “February 2021 Severe Winter Weather Impacts in SPP” section below for additional information.
(b)In April 2023, the LPSC issued an order approving the prudence and future recovery of the Louisiana storm-related costs. See “2021 Louisiana Storm Cost Filing” section below for additional information. |
| | | | | | | | |
| | | PSO |
| | | September 30, | | December 31, |
| | | 2017 | | 2016 |
| Noncurrent Regulatory Assets | | (in millions) |
| | | | | |
| Regulatory Assets Currently Earning a Return | | | | |
| Plant Retirement Costs - Unrecovered Plant (a) | | $ | 133.7 |
| | $ | 84.5 |
|
| Other Regulatory Assets Pending Final Regulatory Approval | | 0.5 |
| | 0.5 |
|
| Regulatory Assets Currently Not Earning a Return | | |
| | |
|
| Storm-Related Costs | | 36.7 |
| | 20.0 |
|
| Environmental Control Projects | | 24.3 |
| | 13.1 |
|
| Other Regulatory Assets Pending Final Regulatory Approval | | 0.4 |
| | — |
|
| Total Regulatory Assets Pending Final Regulatory Approval | | $ | 195.6 |
| | $ | 118.1 |
|
| |
(a) | In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of September 30, 2017, the unrecovered plant balance related to Northeastern Plant, Unit 3 was $52 million. |
|
| | | | | | | | |
| | | SWEPCo |
| | | September 30, | | December 31, |
| | | 2017 | | 2016 |
| Noncurrent Regulatory Assets | | (in millions) |
| | | | | |
| Regulatory Assets Currently Earning a Return | | | | |
| Plant Retirement Costs - Unrecovered Plant | | $ | 75.4 |
| | $ | 75.4 |
|
| Other Regulatory Assets Pending Final Regulatory Approval | | 0.5 |
| | 0.8 |
|
| Regulatory Assets Currently Not Earning a Return | | | | |
| Rate Case Expense - Texas | | 4.1 |
| | 1.0 |
|
| Asset Retirement Obligation - Arkansas, Louisiana | | 3.6 |
| | 2.7 |
|
| Shipe Road Transmission Project - FERC | | 3.3 |
| | 3.1 |
|
| Environmental Control Projects | | — |
| | 11.0 |
|
| Other Regulatory Assets Pending Final Regulatory Approval | | 2.4 |
| | 1.9 |
|
| Total Regulatory Assets Pending Final Regulatory Approval | | $ | 89.3 |
| | $ | 95.9 |
|
If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.
AEP Texas Rate Matters (Applies to AEP)AEP and AEP Texas)
AEP Texas Interim Transmission and Distribution Rates
As of September 30, 2017,Through March 31, 2023, AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2017,that are subject to review are estimated to be $697is approximately $702 million. A base rate review could produceresult 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.
Hurricane Harvey
In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. AEP Texas has a PUCT approved catastrophe reserve in base rates and can defer incremental storm expenses. AEP Texas currently recovers approximately $1 million of storm costs annually through base rates. As of September 30, 2017, the total balance of AEP Texas’ deferred storm costs is approximately $97 million including approximately $73
million of incremental storm expenses as a regulatory asset related to Hurricane Harvey. Management is currently in the early stages of analyzing the impact of potential insurance claims and recoveries and, at this time, cannot estimate this amount. Any future insurance recoveries received will be applied to and will offset the regulatory asset and property, plant and equipment, as applicable. AEP Texas is currently evaluating recovery optionsrequired to file for the regulatory asset; however, management believes the asset is probable of recovery. The other named hurricanes did not have a material impact on AEP’s operations in the third quarter of 2017. If the ultimate costs of the incident are not recovered by insurance or through the regulatory process, it would have an adverse effect on future net income, cash flowscomprehensive rate review no later than April 5, 2024.
APCo and financial condition.
APCoWPCo Rate Matters (Applies to AEP and APCo)
2020-2022 Virginia Legislation Affecting Biennial ReviewsTriennial Review
In 2015, amendments toMarch 2023, APCo submitted its 2020-2022 Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generationtriennial review filing and distribution base rates are frozen until afterrate case with the Virginia SCC rulesas required by state law. APCo requested a $213 million annual increase in Virginia base rates based upon a proposed 10.6% return on common equity. The requested annual increase includes $47 million related to vegetation management and a $35 million increase in depreciation expense. The requested increase in depreciation expense reflects, among other things, the impacts of incremental investments made since APCo’s next biennial review, whichlast depreciation study using property balances as of December 31, 2022. Effective January 1, 2023 and in accordance with past Virginia SCC directives, APCo will file in March 2020implemented updated Virginia depreciation rates. APCo’s proposed revenue requirement also includes the recovery of certain costs incurred that partially contributed to APCo’s calculated earnings shortfall for the 2018 and 2019 test years. These amendments also preclude2020-2022 triennial period. For triennial review periods in which a Virginia utility earns below its authorized ROE band, the utility may file to recover expenses incurred, up to the bottom of the authorized ROE band, related to certain categories of costs, including major storm costs for severe weather events. As of March 31, 2023, APCo deferred approximately $38 million related to previously incurred major storm costs as a result of APCo’s calculation of Virginia earnings below the bottom of its authorized ROE band during the 2020-2022 Triennial Review period. Any APCo Virginia jurisdictional costs that are not recoverable or any refunds of revenues collected from customers during the triennial review period that are ordered by the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo’s2020-2022 Triennial Review period could reduce future net income and cash flows and impact financial statements adequately address the impact of these amendments. The amendments provide that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred from 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA.condition.
ENEC (Expanded Net Energy Cost) Filings
In 2016,April 2021, APCo and WPCo (the Companies) requested a combined $73 million annual increase in ENEC rates based on a cumulative $55 million ENEC under-recovery as of February 28, 2021 and an $18 million increase in projected ENEC costs for the Virginia SCCperiod September 2021 through August 2022. In September 2021, the WVPSC issued an order that denied the petition of certain APCo industrial customers that requested the issuance ofapproving a declaratory order that would find the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, direct APCo to make biennial review filings beginning$7 million overall increase in 2016. In July 2016, the industrial customers filedENEC rates, including an appealapproval for recovery of the Companies’ cumulative $55 million ENEC under-recovery balance and a $48 million reduction in projected costs for the period September 2021 through August 2022. Subsequently, the Companies submitted a request for reconsideration of this order, identifying flaws in the WVPSC’s calculation of forecasted future year fuel expense and purchased power costs.
In March 2022, the WVPSC issued an order granting the Companies’ request for reconsideration, in part, and approving $31 million in projected costs for the period September 2021 through August 2022. The order also reopened the 2021 ENEC case to require the Companies to explain the significant growth in the reported under-recovery of ENEC costs and to provide various other information including revised projected costs for the period March 2022 through August 2022. Also, in March 2022, the Companies filed testimony providing the information requested in the WVPSC’s order and requested a $155 million annual increase in ENEC rates effective May 1, 2022. In May 2022, the WVPSC issued an order approving a $93 million overall increase to ENEC rates to recover projected annual ENEC costs. However, the WVPSC stated that actual and projected ENEC costs are still subject to a prudency review.
In April 2022, the Companies submitted their 2022 annual ENEC filing with the Supreme CourtWVPSC requesting a $297 million annual increase in ENEC revenues, inclusive of Virginia. the previously requested $155 million increase, effective September 1, 2022.
In September 2017,2022, following an agreed upon delay in the Supreme Courtproceedings of the Companies’ 2022 ENEC case, certain intervenors submitted testimony recommending disallowances of at least $83 million to the Companies’ historical period ENEC under-recovery balance along with proposals to either securitize the Companies’ remaining ENEC balance or defer recovery of this balance beyond the traditional one-year period. West Virginia affirmedStaff recommended a $13 million increase in ENEC rates pending the outcome of the ENEC prudency review. In February 2023, the WVPSC issued an order stating that the commission will not grant additional rate increases for fuel costs until the WVPSC staff completes its prudency review.
In April 2023, the Companies submitted their 2023 annual ENEC filing with the WVPSC, proposing two alternatives to increase ENEC rates effective September 1, 2023. The first alternative is a $293 million annual increase in ENEC rates comprised of an $89 million increase for current year ENEC expense and a $200 million annual increase for the recovery of the Companies’ February 28, 2023 ENEC under-recovery balances over three years, including debt and equity carrying costs. The second alternative is an $89 million annual increase in ENEC rates with the Companies securitizing approximately $1.9 billion of assets, including: (a) $553 million relating to ENEC under-recoveries as of February 28, 2023, (b) $88 million relating to major storm expense deferrals and (c) $1.2 billion relating to APCo’s West Virginia SCC’s 2016 order.jurisdictional book values of the Amos and Mountaineer Plants and forecasted CCR and ELG investments at these generating facilities. The Companies continue to reflect ENEC under-recovery balances as current on their balance sheets since management cannot assert whether the WVPSC will approve recovery of ENEC under-recovery balances over a time frame different from the traditional one-year period.
Additionally, in April 2023, the Staff submitted the prudency review prepared by an independent consultant retained by the WVPSC Staff of the Companies’ operation of the Amos, Mountaineer and Mitchell coal plants that Staff was directed to conduct by the WVPSC in May 2022 (Consultant’s Report). The Consultant’s Report states the opinion of the consultant that the Companies acted imprudently by not taking steps to achieve a 69% capacity factor at their coal-fired plants and recommends applying a disallowance factor of 52.9% to the Companies’ cumulative, September 30, 2022 ENEC under-recovery balance of approximately $430 million. The Consultant’s Report further states the consultant’s opinion that this disallowance factor could also be utilized in future ENEC filings. Adoption of the Consultant’s Report’s findings by the WVPSC could result in a disallowance of up to $285 million of the Companies’ cumulative, March 31, 2023 ENEC under-recovery balance of approximately $539 million. The Companies disagree with the conclusions and recommendations contained in the Consultant’s Report and intend to dispute them in the appropriate proceedings before the WVPSC.
If any deferred ENEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
ETT Rate Matters (Applies to AEP)
ETT Interim Transmission Rates
ParentAEP 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 filed base rate proceeding. Through September 30, 2017,March 31, 2023, AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $709 million.approximately $1.6 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. 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 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, 2025, during which the $1.6 billion of cumulative revenues above will be subject to review.
I&M Rate Matters (Applies to AEP and I&M)
2017 IndianaMichigan Power Supply Cost Recovery (PSCR)
In April 2023, I&M received intervenor testimony in I&M’s 2021 PSCR Reconciliation for the 12-month period ending December 31, 2021 recommending disallowances of purchased power costs of $18 million associated with the OVEC Inter-Company Power Agreement (ICPA) and the AEGCo Unit Power Agreement (UPA) that were alleged to be above market in applying the MPSC’s Code of Conduct rules. Michigan Staff submitted testimony in I&M’s 2021 PSCR Reconciliation with no recommended disallowances for PSCR costs incurred, including those associated with the OVEC ICPA and the AEGCo UPA. An MPSC order on I&M’s 2021 PSCR Reconciliation is expected in 2023. If any PSCR costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
OPCo Rate Matters (Applies to AEP and OPCo)
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. In May 2022, intervenors filed for rehearing on the 2016-2017 OVEC cost recovery audit period claiming the PUCO’s April 2022 order to adopt the findings of the audit report were unjust, unlawful and unreasonable for multiple reasons, including the position that OPCo recovered imprudently incurred costs. In June 2022, the PUCO granted rehearing on the 2016-2017 audit period for purposes of further consideration. Management disagrees with these claims and is unable to predict the impact of these disputes, however, if any costs are disallowed or refunds are ordered it could reduce future net income and cash flows and impact financial condition. See "OVEC" section of Note 17 in the 2022 Annual Report for additional information on AEP and OPCo’s investment in OVEC.
Ohio ESP Filings
In January 2023, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments, proposed new riders and the continuation and modification of certain existing riders, including the DIR, effective June 2024 through May 2030. The proposal includes a return on common equity of 10.65% on capital costs for certain riders. Intervenor testimony is due in the second quarter of 2023 and a hearing is scheduled for the third quarter of 2023. If OPCo is ultimately not permitted to fully collect its ESP rates it could reduce future net income and cash flows and impact financial condition.
PSO Rate Matters (Applies to AEP and PSO)
2022 Oklahoma Base Rate Case
In July 2017, I&MNovember 2022, PSO filed a request with the IURCOCC for a $263$173 million annual increase in Indiana rates based upon a proposed 10.6% return on10.4% ROE with a capital structure of 45.4% debt and 54.6% common equity, with the annual increasenet of existing rider revenues and certain incremental renewable facility benefits expected to be implemented after June 2018. Upon implementation, this proposedprovided to customers through riders. The requested annual revenue increase would be subject toincludes a temporary offsetting $23$47 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures. The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 millionexpense increase related to the accelerated depreciation recovery of the Northeastern Plant, Unit 3 through 2026, and a $16 million annual amortization expense increase to recover intangible plant over a 5-year useful life instead of a 10-year useful life. PSO’s request also includes recovery of the 154 MW Rock Falls Wind Facility through base rates to aid PSO’s near-term capacity needs and support compliance with SPP’s 2023 increased capacity planning reserve margin requirements. In November 2022, PSO entered into an agreement to acquire the Rock Falls Wind Facility. In February 2023, the FERC approved PSO’s acquisition of the Rock Falls Wind Facility under Section 203 of the Federal Power Act. PSO closed on the acquisition and placed the Rock Falls Wind Facility in-service on March 31, 2023. In addition, PSO requested an annual formula based rate tariff, with an initial one-year pilot term. In the event the requested formula based rate tariff is denied, PSO has requested an expanded rider to recover certain Cookdistribution investments and related expenses as well as an expanded transmission cost recovery rider.
In March 2023, OCC staff and various intervenors filed testimony supporting net annual revenue changes ranging from a $42 million net decrease to a $49 million net increase based upon ROEs ranging from 8.6% to 9.5%. The difference between PSO’s request and OCC staff and intervenor testimony is primarily due to: (a) rejection of PSO’s request to accelerate the recovery of Northeastern Plant, and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expectedUnit 3 from its original retirement date of 2040 to its projected retirement date of 2026, (b) rejection of PSO’s request to recover intangible plant over a 5-year useful life instead of a 10-year useful life, (c) recommended disallowance of approximately $9 million in certain distribution plant investments, (d) opposition to inclusion of the Rock Falls Wind Facility revenue requirement in customer rates before PSO’s next base rate case, (e) opposition to PSO’s inclusion of its deferred tax asset associated with net operating loss on a stand-alone tax basis in rate base and (f) lower recommended ROEs and recommendations to use certain hypothetical capital structures. Parties also recommended that the OCC reject PSO’s requested formula based rate, and alternate requests for Rockport Plant, Unit 1 from 2044 to 2028 combined with increasedexpanded distribution investment at the Cook Plant, including the Cook Plant Life Cycle Management Project.and transmission cost recovery riders. A hearing at the IURC is scheduled for January 2018.May 2023. PSO expects to implement interim rates subject to refund starting with the June 2023 billing cycle. A final order is expected in the third quarter of 2023. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
2017 Michigan Base Rate Case
In May 2017, I&M filed a request with the MPSC for a $52 million annual increase in Michigan base rates based upon a proposed 10.6% return on common equity with the increase to be implemented no later than April 2018. The proposed annual increase includes $23 million related to increased annual depreciation rates and a $4 million increase related to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the proposed change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project. Additionally, the total proposed increase includes incremental costs related to the Cook Plant Life Cycle Management Program and increased vegetation management expenses. In October 2017, the MPSC staff and intervenors filed testimony. The MPSC staff recommended an annual net revenue increase of $49 million including proposed retirement dates of 2028 for both Rockport Plant, Units 1 (from 2044) and 2 (from 2022) and a return on common equity of 9.8%. The intervenors proposed certain adjustments to I&M’s request including no change to the current 2044 retirement date of Rockport Plant, Unit 1, but did not propose an annual net revenue increase. Their recommended return on common equity ranged from 9.3% to 9.5%. A hearing at the MPSC is scheduled for November 2017. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR)
In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NOx from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million, excluding AFUDC, to be shared equally between I&M and AEGCo. As of September 30, 2017, total costs incurred related to this project, including AFUDC, were approximately $17 million. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to I&M and KPCo and will be subject to future regulatory approval for recovery. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport Plant, Unit 2 lease. A hearing at the IURC was held in March 2017. An order from the IURC is pending. In July 2017, I&M filed a motion with the U.S. District Court for the Southern District of Ohio to remove the requirement to install SCR technology at Rockport Plant, Unit 2. In August 2017, the district court delayed the deadline for installation of the SCR technology until March 2020.
KPCoSWEPCo Rate Matters (Applies to AEP)
2017 Kentucky Base Rate Case
In June 2017, KPCo filed a request with the KPSC for a $66 million annual increase in Kentucky base rates based upon a proposed 10.31% return on common equity with the increase to be implemented no later than January 2018. The proposed increase includes: (a) lost load since KPCo last changed base rates in July 2015, (b) incremental costs related to OATT charges from PJM not currently recovered from retail ratepayers, (c) increased depreciation expense including updated Big Sandy Plant, Unit 1 depreciation rates using a proposed retirement date of 2031, (d) recovery of other Big Sandy Plant, Unit 1 generation costs currently recovered through a retail rider and (e) incremental purchased power costs. Additionally, KPCo requested a $4 million annual increase in environmental surcharge revenues.
In August 2017, KPCo submitted a supplemental filing with the KPSC that decreased the proposed annual base rate revenue request to $60 million. The modification was due to a lower interest expense related to June 2017 debt refinancings. In October 2017, various intervenors filed testimony that included annual net revenue increase recommendations ranging from $13 million to $40 million. Intervenors recommended returns on common equity ranging from 8.6% to 8.85%. Intervenors also recommended significant delays in KPCo’s proposed recoveries of: (a) depreciation expense related to Big Sandy Plant, Unit 1 (gas unit), proposing a 30-year depreciable life instead of KPCo’s proposed 15-year life and (b) lease expense on Rockport Plant, Unit 2 billed from AEGCo, proposing that the approximate $100 million of lease expense for the period 2018 through 2022 be deferred with a WACC carrying charge for recovery over 10 years beginning 2023. Testimony on behalf of the Attorney General also discussed that the KPSC could consider disallowing all or a portion of the costs currently being recovered over 25 years through the Big Sandy Plant, Unit 2 retirement rider. As of September 30, 2017, KPCo’s regulatory asset related to the retired Big Sandy Plant, Unit 2 was $289 million. A hearing at the KPSC is scheduled for December 2017.
If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
OPCo Rate Matters (Applies to AEP and OPCo)SWEPCo)
Ohio Electric Security Plan Filings
June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024
In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the DIR, effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA.
In 2015, the PUCO issued orders that approved OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The orders included: (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed OVEC PPA and (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal. Also in 2015, OPCo subsequently filed an amended OVEC PPA application that, among other things, addressed certain PPA requirements set forth in a 2015 PUCO order. In 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments.
In 2016, the PUCO issued orders that approved a contested stipulation agreement related to the PPA rider application. Additionally, as part of these orders, the PUCO approved (a) recovery of OVEC-related net margin incurred beginning June 2016, (b) potential additional contingent customer credits of up to $15 million to be included in the PPA rider over the final four years of the PPA rider and (c) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions. In April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final. In June 2017, intervenors filed appeals to the Supreme Court of Ohio stating that the PUCO’s approval of the OVEC PPA was unlawful and does not provide customers with rate stability.
In November 2016, OPCo refiled its amended ESP extension application and supporting testimony, consistent with the terms of the modified and approved stipulation agreement and based upon a 2016 PUCO order. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Renewable Resource Rider.
In August 2017, OPCo and various intervenors filed a stipulation agreement with the PUCO. The stipulation extends the term of the ESP through May 2024 and includes: (a) an extension of the OVEC PPA rider, (b) a proposed 10% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) rate caps related to OPCo’s DIR ranging from $215 million to $290 million for the periods 2018 through 2021 and (e) the addition of various new riders, including a Smart City Rider and a Renewable Generation Rider. DIR rate caps will be reset in OPCo’s next distribution base rate case which must be filed by June 2020. In October 2017, intervenor testimony opposing the stipulation agreement was filed recommending: (a) a return on common equity to not exceed 9.3% for riders earning a return on capital investments, (b) that OPCo should file a base distribution case concurrent with the conclusion of the current ESP in May 2018 and (c) denial of certain new riders proposed in OPCo’s ESP extension. The stipulation is subject to review by the PUCO. A hearing at the PUCO is scheduled for November 2017.
If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.
2016 SEET Filing
Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk.
In December 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings. In May 2017, OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group. Although management believes that OPCo’s adjusted 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s SEET treatment of the Global Settlement issues described above or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could reduce future net income and cash flows and impact financial condition.
PSO Rate Matters (Applies to AEP and PSO)
2017 Oklahoma Base Rate Case
In June 2017, PSO filed an application for a base rate review with the OCC that requested a net increase in annual revenues of $156 million based upon a proposed 10% return on common equity. The proposed base rate increase includes (a) environmental compliance investments, including recovery of previously deferred environmental compliance related costs currently recorded as regulatory assets, (b) Advanced Metering Infrastructure investments, (c) additional capital investments and costs to serve PSO’s customers, and (d) an annual $42 million depreciation rate increase due primarily to shorter service lives and lower net salvage estimates. As part of this filing, consistent with the OCC’s final order in its previous base rate case, PSO requested recovery through 2040 of Northeastern Plant, Unit 3, including the environmental control investment, and the net book value of Northeastern Plant, Unit 4 that was retired in 2016. As of September 30, 2017, the net book value of Northeastern Plant, Unit 4 was $82 million.
In September 2017, various intervenors and the OCC staff filed testimony that included annual net revenue increase recommendations ranging from $28 million to $108 million. The recommended returns on common equity ranged from 8% to 9%. In addition, certain parties recommended investment disallowances that ranged from $27 million to $82 million related to Northeastern Plant, Unit 4 and $38 million associated with capitalized incentives. Also, a party recommended a potential refund of $43 million related to an SPP rider claiming that PSO did not adequately support
the related SPP costs. The combined total impact could result in a write-off and refund of up to approximately $163 million. In addition, if similar plant recovery issues would apply to Northeastern Plant, Unit 3, the net book value of plant, including regulatory assets, materials and supplies inventory and CWIP of $346 million as of September 30, 2017, could be adversely impacted. A hearing at the OCC is scheduled to begin in October 2017.
If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
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. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2.
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, in the fourth quarter of 2013, SWEPCo reversed $114 million of a previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million.disallowance in 2013. In June 2017, the Texas District Court upheld the PUCT’s 2014 order. In July 2017,order and intervenors filed appeals with the Texas Third Court of Appeals.
If certain partsIn July 2018, the Texas Third Court of Appeals reversed the PUCT order are overturned and if SWEPCo cannot ultimately recover its Texas jurisdictional sharePUCT’s judgment affirming the prudence of the Turk Plant investment, includingand 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 judgment affirming the PUCT’s order on AFUDC, concluding that the language of the PUCT’s original 2008 order intended to include AFUDC in the Texas jurisdictional capital cost cap, and remanded the case to the PUCT for future proceedings. SWEPCo disagrees with the Court of Appeals decision. SWEPCo and the PUCT submitted Petitions for Review with the Texas Supreme Court in November 2021. In October 2022, the Texas Supreme Court denied the Petitions for Review submitted by SWEPCo and the PUCT. In December 2022, SWEPCo and the PUCT filed requests for rehearing with the Texas Supreme Court. In April 2023, SWEPCo and the PUCT filed replies to parties’ responses to the requests for rehearing. If SWEPCo’s request for rehearing is denied, the case will be remanded to the PUCT for future proceedings.
Management does not believe a disallowance of capitalized Turk Plant costs or a revenue refund is probable as of March 31, 2023. However, if SWEPCo is ultimately unable to recover AFUDC in excess of the Texas jurisdictional capital cost cap, it couldwould be expected to result in a pretax net disallowance ranging from $80 million to $90 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 $190 million related to revenues collected from February 2013 through March 2023 and such determination may reduce SWEPCo’s future net income and cash flows and impact financial condition.revenues by approximately $15 million on an annual basis.
2016 Texas Base Rate Case
In December 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity.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 annual increase includes approximately:final order also included: (a) $34 million relatedapproval to additional environmental controls, including those installed at the Welsh Plant, to comply with Federal EPA mandates, (b) $25 million for additional generation, transmission and distribution investments and increased operating costs, (c) $8 million related to transmission cost recovery within SWEPCo’s regional transmission organization and (d) $2 million in additional vegetation management. As part of this filing, SWEPCo requested recovery ofrecover the Texas jurisdictional share (approximately 33%)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, through 2042,(c) approval of $2 million in additional vegetation management expenses and (d) the remaining life of Welsh Plant, Unit 3.
In April and May 2017, various intervenors and the PUCT staff filed testimony that included annual net revenue increase recommendations ranging from $36 million to $47 million. The recommended returns on common equity ranged from 9.2% to 9.35%. In addition, no parties recommended approvalrejection 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 certain parties recommended investment disallowances that could result in write-offs of up to approximately $89 million, including approximately $40$12 million related to environmentalother 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 2018and $25(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 related to limiting SWEPCo’s recovery of AFUDC on Turk Plant and recovery of Welsh Plant, Unit 2. A hearing atThe appeal will move forward following the conclusion of the 2012 Texas Base Rate Case. If certain parts of the PUCT was heldorder 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 June 2017.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. 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 September 2017,January 2022, the Administrative Law Judges (ALJs)PUCT issued their proposal for decision includinga final order approving an annual net revenue increase of $50$39 million includingbased 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 and (d) the creation of a rider to 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 to be recovered as a regulatory asset through 2046. As a result of the final order, SWEPCo recorded a disallowance of $12 million in 2021 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. In April 2022, the PUCT denied the motion for rehearing. In May 2022, SWEPCo filed a petition for review with the Texas District Court seeking a judicial review of the several errors challenged in the PUCT’s final order.
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’s requested annual increase includes accelerated depreciation related to the Dolet Hills Power Station, Pirkey Power Plant and Welsh Plant, all of which were or are expected to be retired early. SWEPCo also included recovery of Welsh Plant, Unit 2 environmental investments asover the blended useful life of June 30, 2016.Welsh Plant, Units 1 and 3. SWEPCo subsequently revised the requested annual increase to $95 million to reflect removing hurricane storm restoration costs from the base case filing, to modify the proposed recovery of the Dolet Hills Power Station and revisions to various proposed amortizations. The ALJs proposedhurricane costs have been requested in a separate storm filing. See “2021 Louisiana Storm Cost Filing” below for more information.
In January 2023, the LPSC approved a settlement which provides for an annual revenue increase of $27 million based upon a 9.5% ROE and includes: (a) a $21 million increase in base rates effective February 2023, (b) a $14 million rider to recover costs of the Dolet Hills Power Station and Pirkey Plant including a return, on common equity(c) an $8 million reduction in fuel rates, (d) an adoption of 9.6%a 3-year formula rate term subject to an earnings band and (e) the recovery of but nocertain incremental SPP charges net of associated revenue and the LA jurisdictional share of the return on Welshand of projected transmission capital investment outside of the earnings band. The settlement agreement did not rule on the prudency of the early retirement of the Dolet Hills Power Station, which is being addressed in a separate proceeding.
The primary differences between SWEPCo’s requested annual rate increase and the agreed upon settlement increase are primarily due to: (a) a reduction in the requested ROE, (b) recovery of the Dolet Hills Power Station and Pirkey Plant Unit 2. The ALJs rejected SWEPCo’s proposed transmission cost recovery mechanism. The estimated potential write-off associatedover ten years in a separate rider mechanism as opposed to base rates with the ALJs proposal is approximately $22 million which includes $9 millionassociated with the lack of a return on Welsh Plant, Unit 2.
If any of these costs are not recoverable, including environmental investments and retirement-related costsaccelerated depreciation rates, (c) maintaining existing depreciation rates for Welsh Plant, Unit 2,Units 1 and 3 and (d) the severing of SWEPCo’s proposed adjustment to include a stand-alone NOLC deferred tax asset in rate base. In January 2023, a hearing was held related to the inclusion of a stand-alone NOLC deferred tax asset in rate base and an order from the LPSC is expected in 2023.
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 March 2023, SWEPCo and the LPSC staff filed a joint stipulation and settlement agreement with the LPSC which confirmed the prudency of $150 million of deferred incremental storm restoration expenses. The agreement also authorized an interim carrying charge at a rate of 3.125% until the recovery mechanism is determined in phase two of this proceeding. SWEPCo will submit additional information in phase two of this proceeding to determine whether securitization of the costs is more cost effective than recovery through typical ratemaking. In April 2023, the LPSC issued an order approving the stipulation and settlement agreement.
February 2021 Severe Winter Weather Impacts in SPP
In February 2021, 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 shown in the table below:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
|
| Jurisdiction | | March 31, 2023 | | December 31, 2022 | | Approved Recovery Period | | Approved Carrying Charge |
| | (in millions) | | | | |
| Arkansas | | $ | 71.7 | | | $ | 74.9 | | | 6 years | | (a) |
| Louisiana | | 115.9 | | | 121.7 | | (b) | | (b) |
| Texas | | 124.5 | | | 132.4 | | 5 years | | 1.65% |
| Total | | $ | 312.1 | | | $ | 329.0 | | | | | |
(a)SWEPCo is permitted to record carrying costs on the unrecovered balance of fuel costs at a weighted-cost of capital approved by the APSC.
(b)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 equal to the prime rate. SWEPCo will work with the LPSC to finalize the actual recovery period and determine the appropriate carrying charge in future proceedings.
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.
Louisiana Turk Plant Prudence ReviewFERC Rate Matters
Beginning January 2013, SWEPCo’s formula rates, includingFERC 2019 SPP Transmission Formula Rate Challenge (Applies to AEP, AEPTCo, PSO and SWEPCo)
In May 2021, certain joint customers submitted a formal challenge at the Louisiana jurisdictional share (approximately 33%)FERC related to the 2020 Annual Update of the Turk Plant, have been collected2019 SPP Transmission Formula Rates of the AEP transmission owning subsidiaries within SPP. In March 2022, the FERC issued an order on the formal challenge which ruled in favor of the joint customers on several issues. Management has determined that the result of the order had an immaterial impact to the financial statements of AEP, AEPTCo, PSO and SWEPCo. In November 2022, certain joint customers appealed the FERC decision to the U.S. Court of Appeals for the District of Columbia Circuit.
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 has an ownership interest in 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 (PAPUC) denied the IEC certificate for siting and construction of the portion in Pennsylvania. Transource Energy appealed the PAPUC ruling in Pennsylvania state court and challenged the ruling before the United States District Court for the Middle District of Pennsylvania. In May 2022, the Pennsylvania state court issued an order affirming the PAPUC decision. The PAPUC decision remains subject to refund pending the outcome of a prudencejurisdiction and review of the Turk Plant investment,United States District Court for the Middle District of Pennsylvania, which had stayed review of the PAPUC decision until the Pennsylvania state court had ordered. The procedural schedule for this case states that a decision by the United States District Court for the Middle of Pennsylvania will not be reached until 2023.
In September 2021, PJM notified Transource Energy that the IEC was placed into servicesuspended to allow for the regulatory and related appeals process to proceed in December 2012. In October 2017,an orderly manner without breaching milestone dates in the LPSC staff filed testimony contendingproject agreement. At that SWEPCo failedtime, PJM stated that the IEC has not been cancelled and remains necessary to continuealleviate congestion. PJM continues to evaluate reliability and market efficiency in the suspension or cancellationarea. As of the Turk Plant during its construction period. The testimony also identified five individual items totaling approximately $51 million for potential disallowance relating to Louisiana’s jurisdictionalMarch 31, 2023, AEP’s share of Turk Plant. As a result of SWEPCo’s alleged failure to meet its continuing prudence obligations, the LPSC staff recommends one of the following potential unfavorable scenarios: (a) Even sharing of construction cost overruns between SWEPCoIEC capital expenditures was approximately $90 million, located in Total Property, Plant and ratepayers, (b) an imposition of a cost cap similar to Texas or (c) approximately a 1% reduction of the rateEquipment - Net on common equityAEP’s balance sheets. The FERC has previously granted abandonment benefits for the Turk Plant. As SWEPCo has includedthis project, allowing the full valuerecovery of the Turk Plant in rate base since its in-service date, SWEPCo may be required to refund potential over-collections from January 2013 through the date new rates are implemented. As of September 30, 2017,prudently incurred costs if the LPSC adopts oneproject is cancelled for reasons outside the control of these potential scenarios, and disallows the five individual items, pretax write-offs could range from $50 million to $80 million and refund provisions, including interest, could range from $15 million to $27 million. Future annual revenue reductions could range from $3 million to $4 million. Management will continue to vigorously defend against these claims. If the LPSC orders in favor of one of these scenarios, it could reduce future net income and cash flows and impact financial condition. A hearing at the LPSC is scheduled for December 2017.
2015 Louisiana Formula Rate Filing
In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund.Transource Energy. If any of thesethe IEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
2017 Louisiana Formula Rate FilingFERC RTO Incentive Complaint (Applies to AEP, AEPTCo and OPCo)
In February 2022, the Office of the Ohio Consumers’ Counsel filed a complaint against AEPSC, American Transmission Systems, Inc. and Duke Energy Ohio, alleging the 50 basis point RTO incentive included in Ohio Transmission Owners’ respective transmission formula rates is not just and reasonable and therefore should be eliminated on the basis that RTO participation is not voluntary, but rather is required by Ohio law. In March 2022, AEPSC filed a motion to dismiss the OCC’s February 2022 complaint with the FERC on the basis of certain deficiencies, including that the complaint fails to request relief that can be granted under FERC regulations because AEPSC is not a public utility nor does it have a transmission rate on file with the FERC. In December 2022, the FERC issued an order removing the 50 basis point RTO incentive from OPCo and OHTCo transmission formula rates effective the date of the February 2022 complaint filing and directed OPCo and OHTCo to provide refunds, with interest, within sixty days of the date of its order. In January 2023, both AEPSC and the OCC filed requests for rehearing with the FERC. In February 2023, in compliance with the FERC’s December 2022 order, AEPSC submitted a filing to the FERC to update OPCo and OHTCo 2023 transmission formula rates to exclude the 50 basis point RTO incentive and provide refunds, with interest. In April 2017,2023, the LPSCFERC approved the updated transmission formula rates for OPCo and OHTCo and issued an uncontested stipulation agreement that SWEPCo filedOrder on Rehearing affirming its February 2022 decision. This decision has been appealed to the U.S. Court of Appeals for the Sixth Circuit. Management expects the December 2022 FERC order to reduce AEP’s pretax income by approximately $20 million on an annual basis.
Request to Update AEGCo Depreciation Rates (Applies to AEP and I&M)
In October 2022, AEP, on behalf of AEGCo, submitted proposed revisions to AEGCo’s depreciation rates for its 50% ownership interest in Rockport Plant, Unit 1 and Unit 2, reflected in AEGCo’s unit power agreement with I&M. The proposed depreciation rates for these assets reflect an estimated 2028 retirement date for the Rockport Plant. AEGCo’s previous FERC-approved depreciation rates for Rockport Plant, Unit 1 were based upon a December 31, 2028 estimated retirement date while AEGCo’s previous FERC-approved depreciation rates for Rockport Plant, Unit 2 leasehold improvements were based upon a December 31, 2022 estimated retirement date in conjunction with the termination of the Rockport Plant, Unit 2 lease.
In December 2022, the FERC issued an order approving the proposed AEGCo Rockport depreciation rates effective January 1, 2023, subject to further review and a potential refund. The FERC established a separate proceeding to review: (a) AEGCo’s acquisition value for the Rockport Plant, Unit 2 base generating asset (original cost and accumulated depreciation), (b) the appropriateness of including future capital additions as stated components in proposed depreciation rates, in light of the Unit Power Agreement’s formula rate plan for test year 2015. The filing includedmechanism, (c) the appropriateness of applying two different depreciation rates to a net annual increase notsingle asset common to exceed $31 million, which was effective May 2017both units and includes SWEPCo’s Louisiana jurisdictional share(d) the accounting and regulatory treatment of WelshRockport Plant, Unit 2 costs of removal and Flint Creek Plant environmental controls which were placedrelated AROs. It is expected that the FERC will issue an order on this review in service in 2016. These environmental costs are subject to prudence review. The net annual increase is subject to refund. In October 2017, SWEPCo filed testimony in Louisiana supporting the prudencesecond half of its environmental control investment for Welsh Plant, Units 12023. This FERC review and 3 and Flint Creek power plants. A hearing at the LPSC is scheduled for May 2018. If any ofsubsequent order on these costs are not recoverable, itissues could reduce future net income and cash flows and impact financial condition.conditions.
Welsh Plant - Environmental Impact
Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could total approximately $850 million, excluding AFUDC. As of September 30, 2017, SWEPCo had incurred costs of $398 million, including AFUDC, related to these projects. Management continues to evaluate the impact of environmental rules and related project cost estimates. As of September 30, 2017, the total net book value of Welsh Plant, Units 1 and 3 was $626 million, before cost of removal, including materials and supplies inventory and CWIP.
In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas filed base rate proceeding. In December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant. In April 2017, the LPSC approved SWEPCo’s recovery of these deferred costs effective May 2017. SWEPCo’s approved Louisiana jurisdictional share of Welsh Plant deferrals: (a) are $11 million, excluding $6 million of unrecognized equity as of September 30, 2017, (b) is subject to review by the LPSC, and (c) includes a WACC return on environmental investments and the related depreciation expense and taxes. Effective May
2017, SWEPCo began recovering $131 million in investments related to its Louisiana jurisdictional share of environmental costs. SWEPCo has sought recovery of its project costs from retail customers in its current Texas base rate case at the PUCT and is recovering these costs from wholesale customers through SWEPCo’s FERC-approved agreements. See “2016 Texas Base Rate Case” and “2017 LouisianaFERC 2021 PJM Transmission Formula Rate Filing” disclosures above.
If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
FERC Rate Matters
PJM Transmission Rates (AppliesChallenge (Applies to AEP, AEPTCo, APCo, I&M and OPCo)I&M)
In June 2016, PJM transmission owners, including AEP’s eastern transmission subsidiariesMarch 2023, certain joint customers submitted a complaint and various state commissions filed a settlement agreementformal challenge at the FERC to resolve outstanding issues related to cost responsibilitythe 2022 Annual Update of the 2021 PJM Transmission Formula Rates of the AEP transmission owning subsidiaries within PJM. This challenge primarily relates to stand-alone treatment of NOLCs in the transmission formula rates of the AEP transmission owning subsidiaries within PJM. In April 2023, AEPSC, on behalf of the AEP transmission owning subsidiaries within PJM, filed answers to the joint formal challenge and complaint with the FERC.
AEP transitioned to stand-alone treatment of NOLCs in its PJM and SPP transmission formula rates beginning with the 2022 projected transmission revenue requirements and 2021 true-up to actual transmission revenue requirements, and provided notice of this change in informational filings made with the FERC. Stand-alone treatment of the NOLCs for chargestransmission formula rates increased the annual revenue requirements for years 2023, 2022, and 2021 by $60 million, $60 million and $78 million, respectively (of which $40 million, $53 million, and $56 million relate to PJM transmission customersformula rates, respectively). Through the first quarter of 2023, AEP’s financial statements reflect a provision for refund for certain transmission facilities that operate at or above 500 kV. In July 2016,NOLC revenues billed by PJM and SPP. Also, a certain parties filed comments at the FERC contesting the settlement agreement. Upon final FERC approval, PJM would implement a transmission enhancement charge adjustment through the PJM OATT, billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms.
FERC Transmission Complaint - AEP’s PJM Participants (Applies to AEP, AEPTCo, APCo, I&M and OPCo)
In October 2016, several parties filed a joint complaint at the FERC that states the base return on common equity used by AEP’s eastern transmission subsidiaries in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32%, effective upon the dateportion of the complaint. Management believes its financial statements adequately address the impact of including NOLCs in the complaint. If2021 annual formula rate true-up not yet billed by PJM and SPP is not reflected in the FERC ordersRegistrants’ revenues and expenses as the Registrants have not met the requirements of alternative revenue reductions as a result ofrecognition in accordance with the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.accounting guidance for “Regulated Operations”.
Modifications to AEP’s PJM Transmission Rates (Applies to AEP, AEPTCo, APCo, I&M and OPCo)
In November 2016, AEP’s eastern transmission subsidiaries filed an application with at the FERC to modify the PJM OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to projected expenses. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017, the modified PJM OATT formula rates were implemented, subject to refund, based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
FERC Transmission Complaint - AEP’s SPP Participants (Applies to AEP, AEPTCo, PSO and SWEPCo)
In June 2017, several parties filed a joint complaint at the FERC that states the base return on common equity used by AEP’s western transmission subsidiaries in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36%, effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.
FERC SWEPCo Power Supply Agreements Complaint - East Texas Electric Cooperative, Inc. (ETEC) and Northeast Texas Electric Cooperative, Inc. (NTEC)
In September 2017, ETEC and NTEC filed a complaint at the FERC that states the base return on common equity used by SWEPCo in calculating their power supply formula rates is excessive and should be reduced from 11.1% to 8.41%, effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.
5. 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 RegistrantsRegistrants’ 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. The Commitments, Guarantees and Contingencies note within AEP’s and AEPTCo’s 2016the 2022 Annual ReportsReport should be read in conjunction with this report.
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 partiesthird-parties unless specified below.
Letters of Credit (Applies to AEP and OPCo)AEP Texas)
Standby letters of credit are entered into with third parties.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 a $3$4 billion and $1 billion revolving credit facilityfacilities due in June 2021,March 2027 and 2025, respectively, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of September 30, 2017,March 31, 2023, no letters of credit were issued under the $3 billion revolving credit facility. In May 2017, the $500 million revolving credit facility due in June 2018 was terminated.
An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP also issues letters of credit on behalf of subsidiaries under fivesix uncommitted facilities totaling $445$450 million. In August 2017, AEP executed a $75 million uncommitted letter of credit facility due in August 2018. As of September 30, 2017, theThe Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of March 31, 2023 were as follows:
| | | | | | | | | | | | | | |
| Company | | Amount | | Maturity |
| | (in millions) | | |
| AEP | | $ | 299.0 | | | April 2023 to March 2024 |
| AEP Texas | | 1.8 | | | July 2023 |
| | | | |
|
| | | | | | |
| Company | | Amount | | Maturity |
| | | (in millions) | | |
| AEP | | $ | 123.2 |
| | October 2017 to September 2018 |
| OPCo | | 0.6 |
| | September 2018 |
AEP has $45 million of variable rate Pollution Control Bonds supported by $46 million of bilateral letters of credit maturing in July 2019.
Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo)
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 $115 million, which increased to $140 million in October 2017. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. It is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $76 million. Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2017, SWEPCo has collected $71 million through a rider for final mine closure and reclamation costs, of which $76 million is recorded in Asset Retirement Obligations, offset by $5 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet.
Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause.
Guarantees of Equity Method Investees (Applies to AEP)
AEPParent has issued aguarantees over the performance guarantee forof certain non-consolidated joint ventures included within the competitive contracted renewables portfolio and NM Renewable Development, LLC. If a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEPParent would be required to make payments on behalf of the joint venture. As of September 30, 2017,March 31, 2023, the maximum potential amount of future payments associated with thisthe remaining guarantees was $78 million, with the last guarantee was $75 million, which expiresexpiring in December 2019.2045. The non-contingent liability recorded associated with these guarantees was $5 million, with an additional $1 million expected credit loss liability for the contingent portion of the guarantees. In accordance with the accounting guidance for guarantees, the initial recognition of the non-contingent liabilities increased AEP’s carrying values of the respective equity method investees. 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.
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 September 30, 2017,March 31, 2023, there were no material liabilities recorded for any indemnifications.
AEPSC conducts power purchase-and-sale activity on behalf of APCo, I&M, KPCo and OPCoWPCo, who are jointly and severally liable for activity conducted byon their behalf. AEPSC also conducts power purchase-and-sale activity on behalf of AEP companies related to power purchase and sale activity. PSO and SWEPCo, who are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity.their behalf.
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 either the unamortized balance or 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 unamortized balance.amount guaranteed. As of September 30, 2017,March 31, 2023, 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 iswas as follows:
| | | | | | | | |
| Company | | Maximum
Potential Loss |
| | (in millions) |
| AEP | | $ | 46.4 | |
| AEP Texas | | 11.2 | |
| APCo | | 6.0 | |
| I&M | | 4.3 | |
| OPCo | | 7.4 | |
| PSO | | 4.9 | |
| SWEPCo | | 5.7 | |
|
| | | | |
| Company | | Maximum Potential Loss |
| | | (in millions) |
| AEP | | $ | 42.1 |
|
| APCo | | 8.8 |
|
| I&M | | 3.4 |
|
| OPCo | | 6.0 |
|
| PSO | | 3.3 |
|
| SWEPCo | | 3.7 |
|
Railcar LeaseENVIRONMENTAL CONTINGENCIES (Applies to AEP, I&M and SWEPCo)all Registrants except AEPTCo)
In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $8 million and $9 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2017.
Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% of the projected fair value of the equipment under the current five-year lease term to 77% at the end of the 20-year term. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $8 million and $10 million for I&M and SWEPCo, respectively, as of September 30, 2017, assuming the fair value of the equipment is zero at the end of the current five-year lease term. However, management believes that the fair value would produce a sufficient sales price to avoid any loss.
AEPRO Boat and Barge Leases (Applies to AEP)
In October 2015, AEP signed a Purchase and Sale Agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale closed in November 2015. Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of September 30, 2017, the maximum potential amount of future payments required under the guaranteed leases was $52 million. In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee to the extent of the sale proceeds. As of September 30, 2017, AEP’s boat and barge lease guarantee liability was $7 million, of which $1 million was recorded in Other Current Liabilities and $6 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet.
ENVIRONMENTAL CONTINGENCIES
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 nonhazardousnon-hazardous materials. The Registrants currently incur costs to dispose of these substances safely. For remediation processes not specifically discussed, management does not anticipate that the liabilities, if any, arising from such remediation processes would have a material effect on the financial statements.
In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of September 30, 2017, I&M’s accrual for all of these sites is $3 million. As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any.
NUCLEAR CONTINGENCIES (APPLIES TO(Applies to AEP ANDand I&M)
I&M owns and operates the two-unit 2,278 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC).Commission. 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.
Westinghouse Electric Company Bankruptcy Filing (Applies to AEP and I&M)
In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the U.S. Bankruptcy Code. It intends to reorganize, not cease business operations. However, it is in the early stages of the bankruptcy process and it is unclear whether the company can successfully reorganize. Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication, and ongoing engineering projects. The most significant of these relate to Cook Plant fuel fabrication. I&M is evaluating how this reorganization affects these contracts. Westinghouse has stated that it intends to continue performance on I&M’s contracts, but given the importance of upcoming dates in the fuel fabrication process for Cook Plant, and their vital part in Cook Plant’s ongoing operations, I&M continues to work with Westinghouse in the bankruptcy proceedings to avoid any interruptions to that service. In the unlikely event Westinghouse rejects I&M’s contracts, or is unable to reorganize or sell its profitable businesses in the bankruptcy, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services.
OPERATIONAL CONTINGENCIES
Rockport Plant Litigation (AppliesRelated to AEP and I&M)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 2013,2020, an investigation led by the Wilmington Trust CompanyU.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 complaintputative class action lawsuit in U.S.the U. S. District Court for the Southern District of New YorkOhio against AEGCoAEP and I&M alleging that it will be unlawfully burdened bycertain of its officers for alleged violations of securities laws. In December 2021, 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 or retirement of the unit. The plaintiffs further allege that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M.
In January 2015, thedistrict court issued an opinion and order grantingdismissing the motion in part and denyingsecurities litigation complaint with prejudice, determining that the motion in part.complaint failed to plead any actionable misrepresentations or omissions. The court dismissed certain ofplaintiffs did not appeal the plaintiffs’ claims, including the dismissal without prejudice of plaintiffs’ claims seeking compensatory damages. Several claims remained, including the claim for breach of the participation agreement and a claim alleging breach ofruling.
In January 2021, an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&MAEP shareholder filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. In November 2015, AEGCo and I&M filed a motion to strike the plaintiffs’ motion for partial judgment and filed a motion to dismiss the case for failure to state a claim.
In March 2016, the court entered an opinion and orderderivative action in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, plaintiffs filed an appeal in the U.S. Court of Appeals for the Sixth Circuit on whether AEGCo and I&M are in breach of certain contract provisions that plaintiffs allege operate to protect the plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing.
In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions which had dismissed certain of plaintiffs’ claims for breach of contract and remanding the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. In April 2017, AEGCo and I&M filed a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit, which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reverses the district court’s dismissal of certain of the owners’ claims under the lease agreements, vacates the denial of the owners’ motion for partial summary judgment and remands the case to the district court for further proceedings. The amended opinion and judgment also affirms the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims and removes the instruction to the district court in the original opinion to enter summary judgment in favor of the owners.
In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio seekingpurporting to modifyassert 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 consent decreeCourt 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 eliminatethose alleged in the obligation to install future controls at Rockport Plant, Unit 2 if AEP does not acquire ownershipputative securities class action lawsuit filed against AEP. The derivative complaints together assert claims for: (a) breach of that Unit,fiduciary duty, (b) waste of corporate assets, (c) unjust enrichment, (d) breach of duty for insider trading and to modify the consent decree in other respects to preserve the environmental benefits(e) contribution for violations of sections 10(b) and 21D of the consent decree. In October 2017,Securities Exchange Act of 1934; and seek monetary damages and changes to AEP’s corporate governance and internal policies among other forms of relief. The court entered a scheduling order in the ownersNew York state court derivative action staying the case other than with respect to briefing the motion to dismiss. AEP filed substantive and forum-based motions to dismiss on April 29, 2022. On September 13, 2022, the New York state
court granted the forum-based motion to dismiss with prejudice and the plaintiff subsequently filed a notice of appeal with the New York appellate court. On January 20, 2023, the New York plaintiff filed a motion to stay their claimsintervene in the pending Ohio federal court action and withdrew his appeal in New York. The two derivative actions pending in federal district court in Ohio have been consolidated and the plaintiffs in the consolidated action filed an amended complaint. AEP filed a motion to dismiss the amended complaint and subsequently filed a brief in opposition to the New York plaintiffs’ motion to intervene in the consolidated action in Ohio. On March 20, 2023, the federal district court issued an order granting the motion to dismiss with prejudice and denying the New York plaintiffs’ motion to intervene. On April 20, 2023, one of the plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Sixth Circuit of the Ohio federal district court order dismissing the consolidated action and denying the intervention. On June 15, 2022, the Ohio state court entered an order continuing the stays of that case until January 2018, to afford time forthe final resolution of AEP’s motion to modify the consent decree.
Managementconsolidated derivative actions pending in Ohio federal district court. The defendants will continue to defend against the claims. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, managementManagement is unable to determine a range of potential losses that areis reasonably possible of occurring.
Natural Gas Markets Lawsuits (Applies to AEP)
In 2002,March 2021, AEP received a lawsuitlitigation demand letter from counsel representing a purported AEP shareholder. The litigation demand letter was commenceddirected to the Board of Directors of AEP (AEP Board) and contained factual allegations involving HB 6 that were generally consistent with those in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were alsoderivative litigation filed in state and federal courtscourt. The shareholder that sent the letter has since withdrawn the litigation demand, which is now terminated and of no further effect. In April 2023, AEP received a litigation demand from counsel representing the purported AEP shareholder who filed the dismissed derivative action in several states making essentiallyNew York state court and unsuccessfully tried to intervene in the same allegations underconsolidated derivative actions in Ohio federal or state laws against the same companies. AEPcourt. The litigation demand letter is among the companies named as defendants in some of these cases. AEP settled, received summary judgment or was dismissed from all of these cases. The plaintiffs appealed the Nevada federal district court’s dismissal of several cases involving AEP companiesdirected to the U.S. Court of Appeals for the Ninth Circuit. In April 2013, the appellate court reversed in part,AEP Board and affirmed in part, the district court’s orders in these cases. The United States Supreme Court affirmed the U.S. Court of Appeals for the Ninth Circuit’s opinion. The cases were remanded to the district court for further proceedings. AEP had four pending cases, of which three were class actions and one was a single plaintiff case. In February 2017, a settlement was reachedcontains factual allegations involving HB6 that are generally consistent with those in the single plaintiff case. A settlement was also reached in the three class actions and the district court issued final approval of the settlement in June 2017.
Gavin Landfill Litigation (Applies to AEP and OPCo)
In August 2014, a complaint wasderivative litigation filed in state and federal court. The letter demands, among other things, that the Mason County, West Virginia Circuit Court against AEP AEPSC, OPCo andBoard undertake an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39independent investigation into alleged legal violations by certain current and former contractorsdirectors and officers, and that AEP commence a civil action for breaches of the landfillfiduciary duty and 38 family members of those contractors. Twelve of the family members are pursuing personal injury/illnessrelated claims (non-working direct claims) and the remainder are pursuing loss of consortium claims.against any individuals who allegedly harmed AEP. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filedAEP Board will act in Ohio. In August 2015, the court denied the motion. Defendants appealed that decisionresponse to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants subsequently filed a motion to dismiss the twelve non-working direct claims under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. The West Virginia Supreme Court granted the appeal of the twelve non-working direct claims and heard oral argument in March 2017. In June 2017, the West Virginia Supreme Court reversed the WVMLP decision and dismissed the claims of the twelve non-working direct claim plaintiffs. Management will continue to defend against the remaining claims and believes the provision recorded is adequate.letter as appropriate. Management is unable to determine a range of potential additional losses that areis reasonably possible of occurring.
In May 2021, AEP received a subpoena from the SEC’s Division of Enforcement seeking various documents, including documents relating to the passage of HB 6 and documents relating to AEP’s policies and financial processes and controls. In August 2022, AEP received a second subpoena from the SEC seeking various additional documents relating to its ongoing investigation. AEP is cooperating fully with the SEC’s investigation, which has included taking testimony from certain individuals. Although the outcome of the SEC’s investigation cannot be predicted, management does not believe the results of this investigation will have a material impact on financial condition, results of operations or cash flows.
Claims for Indemnification Related to Damages Resulting from the Federal EPA’s Denial of Alternative Closure Deadline for Gavin Plant and Associated Findings of Compliance
In November 2022, the Federal EPA issued a final decision denying Gavin Power LLC’s requested extension to allow a CCR surface impoundment at the Gavin Power Station to continue to receive CCR and non-CCR waste streams after April 11, 2021 until May 4, 2023 (the Gavin Denial). As part of the Gavin Denial, the Federal EPA made several determinations related to the CCR Rule (see “Environmental Issues - Coal Combustion Residual (CCR) Rule” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information), including a determination that the closure of the 300 acre unlined fly ash reservoir (FAR) is noncompliant with the CCR Rule in multiple respects. The Gavin Power Station was formerly owned and operated by AEP and was sold to Gavin Power LLC and Lightstone Generation LLC in 2017. Pursuant to the PSA, AEP maintained responsibility to complete closure of the FAR in accordance with the closure plan approved by the Ohio EPA which was completed in July 2021. The PSA contains indemnification provisions, pursuant to which the owners of the Gavin Power Station have notified AEP they believe they are entitled to indemnification for any damages that may result from the Gavin Denial, as well as any future enforcement or litigation resulting from the Federal EPA’s determinations of noncompliance with various aspects of the CCR Rule as part of the Gavin Denial. Management does not believe that the owners of the Gavin Power Station have any valid claim for indemnity or otherwise against AEP under the PSA. In addition, Gavin Power LLC, several AEP subsidiaries, and other parties have filed Petitions for Review of the Gavin Denial with the U.S. Court of Appeals for the District of Columbia Circuit. Management is unable to determine a range of potential losses that is reasonably possible of occurring.
Claims for Damages Related to Sabine Coal Supply Contract
In April 2023, AEP received a letter from North American Coal Corporation (NACC) alleging that SWEPCo breached it’s coal supply contract with Sabine, a subsidiary of NACC. The letter contends that SWEPCo is obligated to run the Pirkey Plant until 2035 or to pay $85 million in damages representing lost mining fees to Sabine. The letter threatens legal action for unspecified injunctive relief and breach of contract. Management does not believe SWEPCo is obligated to run the Pirkey Plant for any period of time beyond its useful life or that there is a valid claim for breach of contract or damages. Management is unable to determine a range of potential losses that is reasonably possible of occurring.
6. IMPAIRMENT, DISPOSITION,ACQUISITIONS AND ASSETS AND LIABILITIES HELD FOR SALE
The disclosures in this note apply to AEP only unless indicated otherwise.
IMPAIRMENTACQUISITIONS
Merchant Generating Assets (Generation & MarketingNorth Central Wind Energy Facilities (Vertically Integrated Utilities Segment) (Applies to AEP, PSO and SWEPCo)
In September 2016, due2020, PSO and SWEPCo received regulatory approvals to AEP’s ongoing evaluationacquire the NCWF, comprised of strategic alternatives for its merchant generation assets, declining forecaststhree Oklahoma wind facilities totaling 1,484 MWs, on a fixed cost turn-key basis. PSO and SWEPCo own undivided interests of future energy45.5% and capacity prices,54.5% of the NCWF, respectively. In total, the three wind facilities cost approximately $2 billion and consist of Traverse (998 MW), Maverick (287 MW) and Sundance (199 MW). Output from the NCWF serves 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 until the amounts are reflected in base rates. Recovery of the Arkansas portion of the NCWF revenue requirement through base rates was approved by the APSC in May 2022. The NCWF are subject to various regulatory performance requirements. If these performance requirements are not met, PSO and SWEPCo would recognize a decreasing likelihood of cost recovery through regulatory proceedings or legislationliability to refund retail customers.
In March 2022, PSO and SWEPCo acquired respective undivided ownership interests in the stateentity that owned Traverse during its development and construction for $1.2 billion, the third of Ohio providing for the recovery of AEP’s existing Ohio merchant generation assets, AEP performed an impairment analysis atthree NCWF acquisitions. Immediately following the unit level onacquisition, PSO and SWEPCo liquidated the remaining merchant generationentity and simultaneously distributed the Traverse assets in accordance withproportion to their undivided ownership interests. Traverse was placed in-service in March 2022. PSO and SWEPCo apply the joint plant accounting guidancemodel to account for impairments of long-lived assets. Based on the impairment analysis performedtheir respective undivided interests in the third quarterassets, liabilities, revenues and expenses of 2016, AEP recorded a pretax impairment of $2.3 billion in Asset Impairments and Other Related Charges on the statement of operations.NCWF projects.
Through the third quarter of 2017, AEP recorded an additional pretax impairment of $4 million in Asset Impairments and Other Related Charges on AEP’s statements of income related to the Merchant Coal-fired Generation Assets. In addition, AEP recorded a $7 million pretax impairment as Asset Impairments and Other Related Charges on AEP’s statements of income related to the sale of Zimmer Plant. The sale is further discussed in the “Disposition” section of this note.
DISPOSITION
Zimmer Plant (Generation & Marketing Segment)
In February 2017, AEP signed an agreement to sell its 25.4% ownership share of Zimmer Plant to a nonaffiliated party. The transaction closed in the second quarter of 2017 and did not have a material impact on net income, cash flows or financial condition. The Income before Income Tax Expense and Equity Earnings of Zimmer Plant was immaterial for the three and nine months ended September 30, 2017 and 2016.
Tanners Creek PlantRock Falls Wind Facility (Vertically Integrated Utilities Segment) (Applies to AEP and I&M)PSO)
In October 2016, I&M sold its retired Tanners Creek plant site including its associated asset retirement obligations (AROs)November 2022, PSO entered into an agreement to a nonaffiliated party. I&M paid $92 million andacquire the nonaffiliated party took ownershipRock Falls Wind Facility. In February 2023, the FERC approved PSO’s acquisition of the Tanners Creek plant site assetsRock Falls Wind Facility under Section 203 of the Federal Power Act. In March 2023, PSO acquired an ownership interest in the entity that owned Rock Falls during its development and assumed responsibilityconstruction for environmental liabilities$146 million. In accordance with the guidance for “Business Combinations,” management determined that the acquisition of the Rock Falls Wind Facility represents an asset acquisition. The current and AROs, including ash pond closure, asbestos abatement and decommissioning and demolition. I&M did not record a gain or lossnoncurrent Obligations Under Operating Leases related to this sale and will address recoveryRock Falls were not material as of Tanner’s Creek deferred costs in future rate proceedings. If anyMarch 31, 2023. See the “2022 Oklahoma Base Rate Case” section of the costs associated with Tanner’s Creek are not recoverable, it could reduce future net income and impact financial condition.Note 4 for additional information.
Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)
In September 2016, AEP signed a Purchase and Sale Agreement to sell AGR’s Gavin, Waterford and Darby Plants as well as AEGCo’s Lawrenceburg Plant totaling 5,329 MWs of competitive generation assets to a nonaffiliated party. The sale closed in January 2017 for $2.2 billion, which was recorded in Investing Activities on the statement of cash flows. The net proceeds from the transaction were $1.2 billion in cash after taxes, repayment of debt associated with these assets including a make whole payment related to the debt, payment of a coal contract associated with one of the plants and transaction fees. The sale resulted in a pretax gain of $226 million that was recorded in Gain on Sale of Merchant Generation Assets on AEP’s statement of income.
ASSETS AND LIABILITIES HELD FOR SALE
Gavin, Waterford, DarbyTermination of Planned Disposition of KPCo and Lawrenceburg PlantsKTCo (Vertically Integrated Utilities and AEP Transmission Holdco Segments) (Applies to AEP and AEPTCo)
In October 2021, AEP entered into a Stock Purchase Agreement (SPA) to sell KPCo and KTCo to Liberty Utilities Co., a subsidiary of Algonquin Power & Utilities Corp. (Liberty), for approximately a $2.85 billion enterprise value.The SPA was subsequently amended in September 2022 to reduce the purchase price to approximately $2.646 billion.The sale required approval from the KPSC and from the FERC under Section 203 of the Federal Power Act.The SPA contained certain termination rights if the closing of the sale did not occur by April 26, 2023.
In May 2022, the KPSC approved the sale of KPCo to Liberty subject to certain conditions contingent upon the closing of the sale.In December 2022, the FERC issued an order denying, without prejudice, authorization of the proposed sale stating the applicants failed to demonstrate the proposed transaction will not have an adverse effect on rates.In February 2023, a new filing for approval under Section 203 of the Federal Power Act was submitted.In March 2023, the KPSC and other intervenors made filings recommending the FERC reject AEP and Liberty’s new Section 203 application seeking approval of the sale.
In April 2023, AEP, AEPTCo and Liberty entered into a Mutual Termination Agreement (Termination Agreement) terminating the SPA.The parties entered into the Termination Agreement as all of the conditions precedent to closing the sale could not be satisfied prior to April 26, 2023.As a result of the March 2023 filings made by intervenors with the FERC and the Termination Agreement, the assets and liabilities of KPCo and KTCo were reclassified out of Held for Sale on the March 31, 2023 and December 31, 2022 balance sheets of AEP and AEPTCo.
The impact of the Termination Agreement did not have a material impact on AEP’s statements of income for the three months ended March 31, 2023. Upon reverting to a held and used model, AEP is required to present its investment in the Kentucky Operations at the lower of fair value or historical carrying value. As a result, AEP’s March 31, 2023 and December 31, 2022 balance sheets reflect a $335 million and $363 million, respectively, pretax reduction in the basis of its investment in KPCo’s assets which is recorded in Property, Plant and Equipment. The change in AEP’s basis of its investment in KPCo’s assets from December 31, 2022 to March 31, 2023 reflects the elimination of the expected costs to sell from the measurement.
Planned Disposition of the Competitive Contracted Renewables Portfolio (Generation & Marketing Segment)
(Applies to AEP)
In February 2022, AEP management announced the thirdinitiation of a process to sell all or a portion of AEP Renewables’ competitive contracted renewables portfolio within the Generation & Marketing segment. As of March 31, 2023, the competitive contracted renewable portfolio assets totaled 1.4 gigawatts of generation resources representing consolidated solar and wind assets, with a net book value of $1.2 billion, and a 50% interest in four joint venture wind farms, totaling $247 million, accounted for as equity method investments. In late January 2023, AEP received final bids from interested parties. In February 2023, AEP’s Board of Directors approved management’s plan to sell the competitive contracted renewables portfolio and AEP signed an agreement to sell the competitive contracted renewables portfolio to a nonaffiliated party for $1.5 billion including the assumption of project debt. As part of the sale agreement, AEP provided the acquirer an indemnification related to certain losses, not to exceed $70 million, which could result from one of the joint venture wind farm’s inability to meet certain minimum performance requirements.
The sale is subject to customary closing conditions, including FERC approval, clearance from the Committee on Foreign Investment in the United States and approval under applicable competition laws. AEP expects to close on the sale in the second quarter of 2016, management determined Gavin, Waterford, Darby2023 and Lawrenceburg Plantsreceive cash proceeds, net of taxes, transaction fees and other customary closing adjustments, of approximately $1.2 billion.
Management concluded the consolidated assets within the competitive contracted renewables portfolio met the classificationaccounting requirements to be presented as Held for Sale in the first quarter of held2023 based on the receipt of final bids, Board of Director approval to consummate a sale transaction and the signing of the sale agreement. AEP recorded a pretax loss of $112 million ($88 million after-tax), in the first quarter of 2023 as a result of reaching Held for sale. Accordingly,Sale status. Management concluded the impact of any other than temporary decline in the fair value of the four plants’joint venture wind farms was not material to AEP’s March 31, 2023 financial statements. Any changes to the book value or carrying value of these assets, or the anticipated sale price, could further reduce future net income and impact financial condition.
The Income Before Income Tax Expense (Benefit) of the competitive contracted renewables portfolio was not material to AEP on its statements of income for the three months ended March 31, 2023 and 2022.
In March 2023, AEP ceased recognition of depreciation on the competitive contracted renewable portfolio assets due to their classification as Held for Sale on the balance sheets. The major classes of the assets and liabilities have been recorded aspresented in Assets Held for Sale and Liabilities Held for Sale on AEP’sthe balance sheet assheets of December 31, 2016 and asAEP are shown in the table below. The Income before Income Tax Expense and Equity Earnings of the four plants was approximately $116 million for the three months ended September 30, 2016 and $42 million (excluding the $226 million pretax gain) and $312 million for the nine months ended September 30, 2017 and 2016, respectively.following table:
|
| | | | |
| | | December 31, |
| | | 2016 |
| Assets: | | |
| Fuel | | $ | 145.5 |
|
| Materials and Supplies | | 49.4 |
|
| Property, Plant and Equipment - Net | | 1,756.2 |
|
| Other Class of Assets That Are Not Major | | 0.1 |
|
| Total Assets Classified as Held for Sale on the Balance Sheets | | $ | 1,951.2 |
|
| | | |
| Liabilities: | | |
| Long-term Debt | | $ | 134.8 |
|
| Waterford Plant Upgrade Liability | | 52.2 |
|
| Asset Retirement Obligations | | 36.7 |
|
| Other Classes of Liabilities That Are Not Major | | 12.2 |
|
| Total Liabilities Classified as Held for Sale on the Balance Sheets | | $ | 235.9 |
|
| | | | | | | | |
| | March 31, 2023 |
| | (in millions) |
| ASSETS | | |
| Accounts Receivable and Accrued Unbilled Revenues | | $ | 16.9 | |
| Property, Plant and Equipment, Net | | 1,404.7 | |
| Other Classes of Assets that are not Major | | 63.2 | |
| Total Major Classes of Assets Held for Sale | | 1,484.8 | |
| Loss on the Expected Sale of the Competitive Contracted Renewables Portfolio (net of $23.5 million of Income Taxes) | | (88.5) | |
| Assets Held for Sale | | $ | 1,396.3 | |
| | |
| LIABILITIES | | |
| Accounts Payable | | $ | 6.8 | |
| Asset Retirement Obligations | | 30.6 | |
| Obligations Under Operating Leases | | 20.1 | |
| Other Classes of Liabilities that are not Major | | 9.7 | |
| Liabilities Held for Sale | | $ | 67.2 | |
The four joint venture wind farms totaling $247 million as of March 31, 2023, which are included in the plan of sale, continue to be classified as Deferred Charges and Other Noncurrent Assets and $192 million attributable to noncontrolling interests continues to be classified as Noncontrolling Interests on AEP’s consolidated balance sheets.
7. BENEFIT PLANS
The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise.AEPTCo.
AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees.
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 | | Other Postretirement Benefit Plans | | Pension Plans | | OPEB |
| | Three Months Ended September 30, | | Three Months Ended September 30, | | Three Months Ended March 31, | | Three Months Ended March 31, |
| | 2017 | | 2016 | | 2017 | | 2016 | | 2023 | | 2022 | | 2023 | | 2022 |
| | (in millions) | | (in millions) |
| Service Cost | $ | 24.1 |
| | $ | 21.4 |
| | $ | 2.8 |
| | $ | 2.6 |
| Service Cost | $ | 23.6 | | | $ | 30.8 | | | $ | 1.1 | | | $ | 1.8 | |
| Interest Cost | 50.7 |
| | 52.9 |
| | 14.8 |
| | 15.3 |
| Interest Cost | 54.8 | | | 37.0 | | | 11.6 | | | 7.3 | |
| Expected Return on Plan Assets | (71.1 | ) | | (70.1 | ) | | (25.3 | ) | | (26.8 | ) | Expected Return on Plan Assets | (84.8) | | | (63.4) | | | (27.4) | | | (27.5) | |
| Amortization of Prior Service Cost (Credit) | 0.3 |
| | 0.6 |
| | (17.3 | ) | | (17.3 | ) | |
| Amortization of Prior Service Credit | | Amortization of Prior Service Credit | — | | | — | | | (15.8) | | | (17.8) | |
| Amortization of Net Actuarial Loss | 20.7 |
| | 21.0 |
| | 9.2 |
| | 7.8 |
| Amortization of Net Actuarial Loss | 0.3 | | | 15.8 | | | 3.7 | | | — | |
| Net Periodic Benefit Cost (Credit) | $ | 24.7 |
| | $ | 25.8 |
| | $ | (15.8 | ) | | $ | (18.4 | ) | Net Periodic Benefit Cost (Credit) | $ | (6.1) | | | $ | 20.2 | | | $ | (26.8) | | | $ | (36.2) | |
| | | | |
|
| | | | | | | | | | | | | | | |
| | Pension Plans | | Other Postretirement Benefit Plans |
| | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) |
| Service Cost | $ | 72.3 |
| | $ | 64.3 |
| | $ | 8.4 |
| | $ | 7.7 |
|
| Interest Cost | 152.3 |
| | 158.7 |
| | 44.5 |
| | 45.7 |
|
| Expected Return on Plan Assets | (213.5 | ) | | (210.2 | ) | | (76.0 | ) | | (80.3 | ) |
| Amortization of Prior Service Cost (Credit) | 0.8 |
| | 1.7 |
| | (51.8 | ) | | (51.8 | ) |
| Amortization of Net Actuarial Loss | 62.1 |
| | 62.9 |
| | 27.5 |
| | 23.5 |
|
| Net Periodic Benefit Cost (Credit) | $ | 74.0 |
| | $ | 77.4 |
| | $ | (47.4 | ) | | $ | (55.2 | ) |
AEP Texas
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension Plans | | OPEB |
| Three Months Ended March 31, | | Three Months Ended March 31, |
| | 2023 | | 2022 | | 2023 | | 2022 |
| | (in millions) |
| Service Cost | $ | 2.0 | | | $ | 2.8 | | | $ | 0.1 | | | $ | 0.1 | |
| Interest Cost | 4.6 | | | 3.0 | | | 0.9 | | | 0.6 | |
| Expected Return on Plan Assets | (7.0) | | | (5.3) | | | (2.3) | | | (2.3) | |
| Amortization of Prior Service Credit | — | | | — | | | (1.3) | | | (1.5) | |
| Amortization of Net Actuarial Loss | — | | | 1.3 | | | 0.3 | | | — | |
| Net Periodic Benefit Cost (Credit) | $ | (0.4) | | | $ | 1.8 | | | $ | (2.3) | | | $ | (3.1) | |
| | | | | | | |
| | | |
| | | |
| | | | | | | |
| |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
APCo
| | | | Pension Plans | | Other Postretirement Benefit Plans | | Pension Plans | | OPEB |
| | Three Months Ended September 30, | | Three Months Ended September 30, | | Three Months Ended March 31, | | Three Months Ended March 31, |
| | 2017 |
| 2016 | | 2017 | | 2016 | | 2023 | | 2022 | | 2023 | | 2022 |
| | (in millions) | | (in millions) |
| Service Cost | $ | 2.3 |
| | $ | 2.1 |
| | $ | 0.3 |
| | $ | 0.2 |
| Service Cost | $ | 2.3 | | | $ | 2.9 | | | $ | 0.1 | | | $ | 0.2 | |
| Interest Cost | 6.5 |
| | 6.8 |
| | 2.6 |
| | 2.7 |
| Interest Cost | 6.6 | | | 4.4 | | | 1.8 | | | 1.2 | |
| Expected Return on Plan Assets | (8.9 | ) | | (8.8 | ) | | (4.1 | ) | | (4.3 | ) | Expected Return on Plan Assets | (11.2) | | | (8.1) | | | (4.0) | | | (4.1) | |
| Amortization of Prior Service Credit | — |
| | — |
| | (2.5 | ) | | (2.5 | ) | Amortization of Prior Service Credit | — | | | — | | | (2.3) | | | (2.6) | |
| Amortization of Net Actuarial Loss | 2.6 |
| | 2.6 |
| | 1.6 |
| | 1.4 |
| Amortization of Net Actuarial Loss | — | | | 1.8 | | | 0.6 | | | — | |
| Net Periodic Benefit Cost (Credit) | $ | 2.5 |
| | $ | 2.7 |
| | $ | (2.1 | ) | | $ | (2.5 | ) | Net Periodic Benefit Cost (Credit) | $ | (2.3) | | | $ | 1.0 | | | $ | (3.8) | | | $ | (5.3) | |
| | | | |
|
| | | | | | | | | | | | | | | |
| | Pension Plans | | Other Postretirement Benefit Plans |
| | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) |
| Service Cost | $ | 7.0 |
| | $ | 6.1 |
| | $ | 0.8 |
| | $ | 0.7 |
|
| Interest Cost | 19.3 |
| | 20.4 |
| | 7.9 |
| | 8.1 |
|
| Expected Return on Plan Assets | (26.8 | ) | | (26.5 | ) | | (12.3 | ) | | (13.0 | ) |
| Amortization of Prior Service Cost (Credit) | 0.1 |
| | 0.1 |
| | (7.5 | ) | | (7.5 | ) |
| Amortization of Net Actuarial Loss | 7.8 |
| | 8.0 |
| | 4.7 |
| | 4.1 |
|
| Net Periodic Benefit Cost (Credit) | $ | 7.4 |
| | $ | 8.1 |
| | $ | (6.4 | ) | | $ | (7.6 | ) |
I&M
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension Plans | | OPEB |
| Three Months Ended March 31, | | Three Months Ended March 31, |
| | 2023 | | 2022 | | 2023 | | 2022 |
| | (in millions) |
| Service Cost | $ | 3.0 | | | $ | 4.0 | | | $ | 0.2 | | | $ | 0.2 | |
| Interest Cost | 6.2 | | | 4.2 | | | 1.3 | | | 0.8 | |
| Expected Return on Plan Assets | (11.0) | | | (8.0) | | | (3.4) | | | (3.4) | |
| Amortization of Prior Service Credit | — | | | — | | | (2.2) | | | (2.4) | |
| Amortization of Net Actuarial Loss | — | | | 1.8 | | | 0.5 | | | — | |
| Net Periodic Benefit Cost (Credit) | $ | (1.8) | | | $ | 2.0 | | | $ | (3.6) | | | $ | (4.8) | |
| | | | | | | |
| | | |
| | | |
| | | | | | | |
| |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
|
| | | | | | | | | | | | | | | |
| | Pension Plans | | Other Postretirement Benefit Plans |
| | Three Months Ended September 30, | | Three Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) |
| Service Cost | $ | 3.5 |
| | $ | 3.1 |
| | $ | 0.4 |
| | $ | 0.4 |
|
| Interest Cost | 6.1 |
| | 6.3 |
| | 1.7 |
| | 1.7 |
|
| Expected Return on Plan Assets | (8.6 | ) | | (8.4 | ) | | (3.1 | ) | | (3.2 | ) |
| Amortization of Prior Service Credit | — |
| | — |
| | (2.3 | ) | | (2.4 | ) |
| Amortization of Net Actuarial Loss | 2.4 |
| | 2.5 |
| | 1.1 |
| | 0.9 |
|
| Net Periodic Benefit Cost (Credit) | $ | 3.4 |
| | $ | 3.5 |
| | $ | (2.2 | ) | | $ | (2.6 | ) |
|
| | | | | | | | | | | | | | | |
| | Pension Plans | | Other Postretirement Benefit Plans |
| | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) |
| Service Cost | $ | 10.5 |
| | $ | 9.2 |
| | $ | 1.2 |
| | $ | 1.1 |
|
| Interest Cost | 18.2 |
| | 19.0 |
| | 5.2 |
| | 5.2 |
|
| Expected Return on Plan Assets | (25.9 | ) | | (25.2 | ) | | (9.2 | ) | | (9.6 | ) |
| Amortization of Prior Service Cost (Credit) | 0.1 |
| | 0.1 |
| | (7.0 | ) | | (7.1 | ) |
| Amortization of Net Actuarial Loss | 7.3 |
| | 7.4 |
| | 3.3 |
| | 2.8 |
|
| Net Periodic Benefit Cost (Credit) | $ | 10.2 |
| | $ | 10.5 |
| | $ | (6.5 | ) | | $ | (7.6 | ) |
OPCo
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension Plans | | OPEB |
| Three Months Ended March 31, | | Three Months Ended March 31, |
| | 2023 | | 2022 | | 2023 | | 2022 |
| | (in millions) |
| Service Cost | $ | 2.1 | | | $ | 2.7 | | | $ | 0.1 | | | $ | 0.2 | |
| Interest Cost | 4.9 | | | 3.4 | | | 1.2 | | | 0.7 | |
| Expected Return on Plan Assets | (8.5) | | | (6.2) | | | (2.9) | | | (3.0) | |
| Amortization of Prior Service Credit | — | | | — | | | (1.6) | | | (1.8) | |
| Amortization of Net Actuarial Loss | — | | | 1.4 | | | 0.4 | | | — | |
| Net Periodic Benefit Cost (Credit) | $ | (1.5) | | | $ | 1.3 | | | $ | (2.8) | | | $ | (3.9) | |
| | | | | | | |
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| |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
|
| | | | | | | | | | | | | | | |
| | Pension Plans | | Other Postretirement Benefit Plans |
| | Three Months Ended September 30, | | Three Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) |
| Service Cost | $ | 1.8 |
| | $ | 1.6 |
| | $ | 0.3 |
| | $ | 0.2 |
|
| Interest Cost | 4.8 |
| | 5.1 |
| | 1.6 |
| | 1.8 |
|
| Expected Return on Plan Assets | (6.9 | ) | | (6.9 | ) | | (3.0 | ) | | (3.3 | ) |
| Amortization of Prior Service Credit | — |
| | — |
| | (1.7 | ) | | (1.7 | ) |
| Amortization of Net Actuarial Loss | 2.0 |
| | 2.1 |
| | 1.1 |
| | 0.9 |
|
| Net Periodic Benefit Cost (Credit) | $ | 1.7 |
| | $ | 1.9 |
| | $ | (1.7 | ) | | $ | (2.1 | ) |
|
| | | | | | | | | | | | | | | |
| | Pension Plans | | Other Postretirement Benefit Plans |
| | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) |
| Service Cost | $ | 5.6 |
| | $ | 4.9 |
| | $ | 0.7 |
| | $ | 0.6 |
|
| Interest Cost | 14.5 |
| | 15.4 |
| | 5.0 |
| | 5.3 |
|
| Expected Return on Plan Assets | (20.9 | ) | | (20.8 | ) | | (9.0 | ) | | (9.7 | ) |
| Amortization of Prior Service Cost (Credit) | 0.1 |
| | 0.1 |
| | (5.2 | ) | | (5.2 | ) |
| Amortization of Net Actuarial Loss | 5.9 |
| | 6.1 |
| | 3.3 |
| | 2.8 |
|
| Net Periodic Benefit Cost (Credit) | $ | 5.2 |
| | $ | 5.7 |
| | $ | (5.2 | ) | | $ | (6.2 | ) |
PSO
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension Plans | | OPEB |
| Three Months Ended March 31, | | Three Months Ended March 31, |
| | 2023 | | 2022 | | 2023 | | 2022 |
| | (in millions) |
| Service Cost | $ | 1.4 | | | $ | 1.9 | | | $ | 0.1 | | | $ | 0.1 | |
| Interest Cost | 2.7 | | | 1.8 | | | 0.6 | | | 0.4 | |
| Expected Return on Plan Assets | (4.6) | | | (3.4) | | | (1.5) | | | (1.5) | |
| Amortization of Prior Service Credit | — | | | — | | | (1.0) | | | (1.1) | |
| Amortization of Net Actuarial Loss | — | | | 0.7 | | | 0.2 | | | — | |
| Net Periodic Benefit Cost (Credit) | $ | (0.5) | | | $ | 1.0 | | | $ | (1.6) | | | $ | (2.1) | |
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|
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| | Pension Plans | | Other Postretirement Benefit Plans |
| | Three Months Ended September 30, | | Three Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) |
| Service Cost | $ | 1.7 |
| | $ | 1.5 |
| | $ | 0.2 |
| | $ | 0.2 |
|
| Interest Cost | 2.6 |
| | 2.8 |
| | 0.8 |
| | 0.8 |
|
| Expected Return on Plan Assets | (3.9 | ) | | (3.9 | ) | | (1.4 | ) | | (1.5 | ) |
| Amortization of Prior Service Cost (Credit) | — |
| | 0.1 |
| | (1.1 | ) | | (1.1 | ) |
| Amortization of Net Actuarial Loss | 1.1 |
| | 1.1 |
| | 0.5 |
| | 0.4 |
|
| Net Periodic Benefit Cost (Credit) | $ | 1.5 |
| | $ | 1.6 |
| | $ | (1.0 | ) | | $ | (1.2 | ) |
|
| | | | | | | | | | | | | | | |
| | Pension Plans | | Other Postretirement Benefit Plans |
| | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) |
| Service Cost | $ | 4.9 |
| | $ | 4.6 |
| | $ | 0.5 |
| | $ | 0.5 |
|
| Interest Cost | 8.0 |
| | 8.4 |
| | 2.4 |
| | 2.4 |
|
| Expected Return on Plan Assets | (11.8 | ) | | (11.6 | ) | | (4.2 | ) | | (4.5 | ) |
| Amortization of Prior Service Cost (Credit) | — |
| | 0.2 |
| | (3.2 | ) | | (3.2 | ) |
| Amortization of Net Actuarial Loss | 3.3 |
| | 3.3 |
| | 1.5 |
| | 1.3 |
|
| Net Periodic Benefit Cost (Credit) | $ | 4.4 |
| | $ | 4.9 |
| | $ | (3.0 | ) | | $ | (3.5 | ) |
SWEPCo
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension Plans | | OPEB |
| Three Months Ended March 31, | | Three Months Ended March 31, |
| | 2023 | | 2022 | | 2023 | | 2022 |
| | (in millions) |
| Service Cost | $ | 1.9 | | | $ | 2.6 | | | $ | 0.1 | | | $ | 0.1 | |
| Interest Cost | 3.5 | | | 2.3 | | | 0.7 | | | 0.5 | |
| Expected Return on Plan Assets | (4.8) | | | (3.7) | | | (1.8) | | | (1.9) | |
| Amortization of Prior Service Credit | — | | | — | | | (1.2) | | | (1.3) | |
| Amortization of Net Actuarial Loss | — | | | 1.0 | | | 0.2 | | | — | |
| Net Periodic Benefit Cost (Credit) | $ | 0.6 | | | $ | 2.2 | | | $ | (2.0) | | | $ | (2.6) | |
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|
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| | Pension Plans | | Other Postretirement Benefit Plans |
| | Three Months Ended September 30, | | Three Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) |
| Service Cost | $ | 2.1 |
| | $ | 2.0 |
| | $ | 0.2 |
| | $ | 0.2 |
|
| Interest Cost | 3.1 |
| | 3.1 |
| | 0.9 |
| | 0.9 |
|
| Expected Return on Plan Assets | (4.2 | ) | | (4.0 | ) | | (1.5 | ) | | (1.7 | ) |
| Amortization of Prior Service Credit | — |
| | — |
| | (1.3 | ) | | (1.3 | ) |
| Amortization of Net Actuarial Loss | 1.3 |
| | 1.2 |
| | 0.5 |
| | 0.5 |
|
| Net Periodic Benefit Cost (Credit) | $ | 2.3 |
| | $ | 2.3 |
| | $ | (1.2 | ) | | $ | (1.4 | ) |
|
| | | | | | | | | | | | | | | |
| | Pension Plans | | Other Postretirement Benefit Plans |
| | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) |
| Service Cost | $ | 6.5 |
| | $ | 6.1 |
| | $ | 0.6 |
| | $ | 0.6 |
|
| Interest Cost | 9.2 |
| | 9.3 |
| | 2.7 |
| | 2.7 |
|
| Expected Return on Plan Assets | (12.6 | ) | | (12.3 | ) | | (4.7 | ) | | (5.0 | ) |
| Amortization of Prior Service Cost (Credit) | — |
| | 0.2 |
| | (3.9 | ) | | (3.9 | ) |
| Amortization of Net Actuarial Loss | 3.7 |
| | 3.6 |
| | 1.7 |
| | 1.5 |
|
| Net Periodic Benefit Cost (Credit) | $ | 6.8 |
| | $ | 6.9 |
| | $ | (3.6 | ) | | $ | (4.1 | ) |
8. 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 OPCoAEP Texas and AEP Texas.OPCo.
•OPCo purchases energy and capacity to serve SSOstandard service offer customers and provides transmission and distribution services for all connected load.
With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other.
AEP Transmission Holdco
•Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved returns on equity.ROEs.
•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.ROEs.
Generation & Marketing
Competitive generation in ERCOT•Contracted renewable energy investments and PJM.management services.
•Marketing, risk management and retail activities in ERCOT, MISO, PJM SPP and MISO.SPP.
Contracted renewable energy investments and management services.•Competitive generation in PJM.
The remainder of AEP’s activities is presentedactivities 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 tables below presentrepresent AEP’s reportable segment income statement information for the three and nine months ended September 30, 2017March 31, 2023 and 20162022 and reportable segment balance sheet information as of September 30, 2017March 31, 2023 and December 31, 2016. These amounts2022.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, 2023 |
| 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 | $ | 2,816.3 | | | $ | 1,455.3 | | | $ | 90.1 | | | $ | 326.9 | | | $ | 2.3 | | | $ | — | | | $ | 4,690.9 | |
| Other Operating Segments | 41.5 | | | 8.9 | | | 365.4 | | | 0.1 | | | 27.8 | | | (443.7) | | | — | |
| Total Revenues | $ | 2,857.8 | | | $ | 1,464.2 | | | $ | 455.5 | | | $ | 327.0 | | | $ | 30.1 | | | $ | (443.7) | | | $ | 4,690.9 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Net Income (Loss) | $ | 262.2 | | | $ | 125.7 | | | $ | 182.4 | | | $ | (156.4) | | | $ | (13.5) | | | $ | — | | | $ | 400.4 | |
| | | | | | | | | | | | | |
| Three Months Ended March 31, 2022 |
| | 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 | $ | 2,646.8 | | | $ | 1,242.2 | | | $ | 83.4 | | | $ | 609.5 | | | $ | 10.7 | | | $ | — | | | $ | 4,592.6 | |
| Other Operating Segments | 40.6 | | | 4.6 | | | 328.0 | | | 9.8 | | | 9.2 | | | (392.2) | | | — | |
| Total Revenues | $ | 2,687.4 | | | $ | 1,246.8 | | | $ | 411.4 | | | $ | 619.3 | | | $ | 19.9 | | | $ | (392.2) | | | $ | 4,592.6 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Net Income (Loss) | $ | 299.2 | | | $ | 152.8 | | | $ | 173.7 | | | $ | 116.0 | | | $ | (23.6) | | | $ | — | | | $ | 718.1 | |
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| | March 31, 2023 |
| | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation
&
Marketing | | Corporate and Other (a) | | Reconciling
Adjustments | | Consolidated |
| | | (in millions) |
| | | | | | | | | | | | | | |
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| | | | | | | | | | | | | | |
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| | | | | | | | | | | | | | |
| Total Assets (d) | | $ | 50,164.1 | | | $ | 23,437.0 | | | $ | 15,883.1 | | | $ | 4,159.8 | | | $ | 6,457.2 | | (b) | $ | (5,583.3) | | (c) | $ | 94,517.9 | |
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| | | | | | | | | | | | | | |
| | December 31, 2022 |
| | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation
&
Marketing | | Corporate and Other (a) | | Reconciling
Adjustments | | Consolidated |
| | | (in millions) |
| | | | | | | | | | | | | | |
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| | | | | | | | | | | | | | |
| Total Assets | | $ | 49,761.8 | | | $ | 22,920.2 | | | $ | 15,215.8 | | | $ | 4,520.1 | | | $ | 6,768.4 | | (b) | $ | (5,783.0) | | (c) | $ | 93,403.3 | |
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(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 certain estimateselimination of intercompany advances to affiliates and allocations where necessary.intercompany accounts receivable.
(d)Amount includes Assets Held for Sale on the balance sheet. See “Planned Disposition of the Competitive Contracted Renewables Portfolio” section of Note 6 for additional information.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2017 |
| | 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 | $ | 2,453.8 |
| | $ | 1,149.7 |
| | $ | 45.1 |
| | $ | 441.5 |
| | $ | 14.6 |
| | $ | — |
| | $ | 4,104.7 |
|
| Other Operating Segments | 28.4 |
| | 23.6 |
| | 133.4 |
| | 24.0 |
| | 16.7 |
| | (226.1 | ) | | — |
|
| Total Revenues | $ | 2,482.2 |
| | $ | 1,173.3 |
| | $ | 178.5 |
| | $ | 465.5 |
| | $ | 31.3 |
| | $ | (226.1 | ) | | $ | 4,104.7 |
|
| | | | | | | | | | | | | | |
| Income (Loss) from Continuing Operations | $ | 297.3 |
| | $ | 144.0 |
| | $ | 76.5 |
| | $ | 33.7 |
| | $ | 5.2 |
| | $ | — |
| | $ | 556.7 |
|
| Loss from Discontinued Operations, Net of Tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net Income (Loss) | $ | 297.3 |
| | $ | 144.0 |
| | $ | 76.5 |
| | $ | 33.7 |
| | $ | 5.2 |
| | $ | — |
| | $ | 556.7 |
|
| | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2016 |
| | 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 | $ | 2,538.3 |
| | $ | 1,245.4 |
| | $ | 39.5 |
| | $ | 823.3 |
| | $ | 5.7 |
| | $ | — |
| | $ | 4,652.2 |
|
| Other Operating Segments | 18.0 |
| | 30.2 |
| | 92.9 |
| | 36.1 |
| | 19.1 |
| | (196.3 | ) | | — |
|
| Total Revenues | $ | 2,556.3 |
| | $ | 1,275.6 |
| | $ | 132.4 |
| | $ | 859.4 |
| | $ | 24.8 |
| | $ | (196.3 | ) | | $ | 4,652.2 |
|
| | | | | | | | | | | | | | |
| Income (Loss) from Continuing Operations | $ | 343.4 |
| | $ | 155.7 |
| | $ | 69.5 |
| | $ | (1,369.2 | ) | | $ | 36.4 |
| | $ | — |
| | $ | (764.2 | ) |
| Loss from Discontinued Operations, Net of Tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net Income (Loss) | $ | 343.4 |
| | $ | 155.7 |
| | $ | 69.5 |
| | $ | (1,369.2 | ) | | $ | 36.4 |
| | $ | — |
| | $ | (764.2 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2017 |
| | 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 | $ | 6,819.3 |
| | $ | 3,242.7 |
| | $ | 125.8 |
| | $ | 1,386.8 |
| | $ | 39.9 |
| | $ | — |
| | $ | 11,614.5 |
|
| Other Operating Segments | 73.8 |
| | 70.5 |
| | 456.1 |
| | 80.7 |
| | 46.8 |
| | (727.9 | ) | | — |
|
| Total Revenues | $ | 6,893.1 |
| | $ | 3,313.2 |
| | $ | 581.9 |
| | $ | 1,467.5 |
| | $ | 86.7 |
| | $ | (727.9 | ) | | $ | 11,614.5 |
|
| | | | | | | | | | | | | | |
| Income (Loss) from Continuing Operations | $ | 639.2 |
| | $ | 374.3 |
| | $ | 278.3 |
| | $ | 246.3 |
| | $ | (11.0 | ) | | $ | — |
| | $ | 1,527.1 |
|
| Loss from Discontinued Operations, Net of Tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net Income (Loss) | $ | 639.2 |
| | $ | 374.3 |
| | $ | 278.3 |
| | $ | 246.3 |
| | $ | (11.0 | ) | | $ | — |
| | $ | 1,527.1 |
|
| | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2016 |
| | 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 | $ | 6,864.6 |
| | $ | 3,398.9 |
| | $ | 110.1 |
| | $ | 2,192.5 |
| | $ | 23.9 |
| | $ | — |
| | $ | 12,590.0 |
|
| Other Operating Segments | 63.2 |
| | 69.6 |
| | 272.6 |
| | 98.7 |
| | 55.2 |
| | (559.3 | ) | | — |
|
| Total Revenues | $ | 6,927.8 |
| | $ | 3,468.5 |
| | $ | 382.7 |
| | $ | 2,291.2 |
| | $ | 79.1 |
| | $ | (559.3 | ) | | $ | 12,590.0 |
|
| | | | | | | | | | | | | | |
| Income (Loss) from Continuing Operations | $ | 832.6 |
| | $ | 387.8 |
| | $ | 209.5 |
| | $ | (1,248.8 | ) | | $ | 64.2 |
| | $ | — |
| | $ | 245.3 |
|
| Loss from Discontinued Operations, Net of Tax | — |
| | — |
| | — |
| | — |
| | (2.5 | ) | | — |
| | (2.5 | ) |
| Net Income (Loss) | $ | 832.6 |
| | $ | 387.8 |
| | $ | 209.5 |
| | $ | (1,248.8 | ) | | $ | 61.7 |
| | $ | — |
| | $ | 242.8 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | September 30, 2017 |
| | | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation
&
Marketing | | Corporate and Other (a) | | Reconciling
Adjustments | | Consolidated |
| | | (in millions) |
| Total Property, Plant and Equipment | | $ | 42,722.9 |
| | $ | 15,695.2 |
| | $ | 6,394.2 |
| | $ | 632.9 |
| | $ | 359.5 |
| | $ | (366.5 | ) | (b) | $ | 65,438.2 |
|
| Accumulated Depreciation and Amortization | | 13,042.9 |
| | 3,766.2 |
| | 156.6 |
| | 161.7 |
| | 180.8 |
| | (186.5 | ) | (b) | 17,121.7 |
|
| Total Property Plant and Equipment - Net | | $ | 29,680.0 |
| | $ | 11,929.0 |
| | $ | 6,237.6 |
| | $ | 471.2 |
| | $ | 178.7 |
| | $ | (180.0 | ) | (b) | $ | 48,316.5 |
|
| | | | | | | | | | | | | | | |
| Total Assets | | $ | 38,136.4 |
| | $ | 15,765.0 |
| | $ | 7,631.2 |
| | $ | 1,904.4 |
| | $ | 22,339.9 |
| | $ | (21,812.0 | ) | (b) (c) | $ | 63,964.9 |
|
| | | | | | | | | | | | | | | |
| Long-term Debt Due Within One Year: | | | | | | | | | | | | | | |
| Non-Affiliated | | $ | 1,107.2 |
| | $ | 703.4 |
| | $ | — |
| | $ | 0.1 |
| | $ | 548.6 |
| | $ | — |
| | $ | 2,359.3 |
|
| | | | | | | | | | | | | | | |
| Long-term Debt: | | | | | | | | | | | | | | |
| Affiliated | | 50.0 |
| | — |
| | — |
| | 32.2 |
| | — |
| | (82.2 | ) | | — |
|
| Non-Affiliated | | 10,644.2 |
| | 4,738.0 |
| | 2,682.1 |
| | (0.3 | ) | | 298.4 |
| | — |
| | 18,362.4 |
|
| | | | | | | | | | | | | | | |
| Total Long-term Debt | | $ | 11,801.4 |
| | $ | 5,441.4 |
| | $ | 2,682.1 |
| | $ | 32.0 |
| | $ | 847.0 |
| | $ | (82.2 | ) | | $ | 20,721.7 |
|
| | | | | | | | | | | | | | | |
| | | December 31, 2016 |
| | | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation
&
Marketing | | Corporate and Other (a) | | Reconciling
Adjustments | | Consolidated |
| | | (in millions) |
| Total Property, Plant and Equipment | | $ | 41,552.6 |
| | $ | 14,762.2 |
| | $ | 5,354.0 |
| | $ | 364.7 |
| | $ | 356.6 |
| | $ | (353.5 | ) | (b) | $ | 62,036.6 |
|
| Accumulated Depreciation and Amortization | | 12,596.7 |
| | 3,655.0 |
| | 101.4 |
| | 42.2 |
| | 186.0 |
| | (184.0 | ) | (b) | 16,397.3 |
|
| Total Property Plant and Equipment - Net | | $ | 28,955.9 |
| | $ | 11,107.2 |
| | $ | 5,252.6 |
| | $ | 322.5 |
| | $ | 170.6 |
| | $ | (169.5 | ) | (b) | $ | 45,639.3 |
|
| | | | | | | | | | | | | | | |
| Assets Held for Sale | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,951.2 |
| | $ | — |
| | $ | — |
| | $ | 1,951.2 |
|
| | | | | | | | | | | | | | | |
| Total Assets | | $ | 37,428.3 |
| | $ | 14,802.4 |
| | $ | 6,384.8 |
| | $ | 3,386.1 |
| | $ | 20,354.8 |
| | $ | (18,888.7 | ) | (b) (c) | $ | 63,467.7 |
|
| | | | | | | | | | | | | | | |
| Long-term Debt Due Within One Year: | | | | | | | | | | | | | | |
| Non-Affiliated | | $ | 1,519.9 |
| | $ | 309.4 |
| | $ | — |
| | $ | 500.1 |
| | $ | 548.6 |
| | $ | — |
| | $ | 2,878.0 |
|
| | | | | | | | | | | | | | | |
| Long-term Debt: | | | | | | | | | | | | | | |
| Affiliated | | 20.0 |
| | — |
| | — |
| | 32.2 |
| | — |
| | (52.2 | ) | | — |
|
| Non-Affiliated | | 10,353.3 |
| | 4,672.2 |
| | 2,055.7 |
| | — |
| | 297.2 |
| | — |
| | 17,378.4 |
|
| | | | | | | | | | | | | | | |
| Total Long-term Debt | | $ | 11,893.2 |
| | $ | 4,981.6 |
| | $ | 2,055.7 |
| | $ | 532.3 |
| | $ | 845.8 |
| | $ | (52.2 | ) | | $ | 20,256.4 |
|
| | | | | | | | | | | | | | | |
| Liabilities Held for Sale | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 235.9 |
| | $ | — |
| | $ | — |
| | $ | 235.9 |
|
| |
(a) | 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. |
| |
(b) | Includes eliminations due to an intercompany capital lease. |
| |
(c) | Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. |
Registrant Subsidiaries’ Reportable Segments (Applies to APCo, I&M, OPCo, PSO and SWEPCo)all Registrant Subsidiaries except AEPTCo)
The Registrant Subsidiaries besides AEPTCo, 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. OperationsThe 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 (State Transcos).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 RTO’sRTOs 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 TranscoTranscos 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 three and nine months ended September 30, 2017March 31, 2023 and 20162022 and reportable segment balance sheet information as of September 30, 2017March 31, 2023 and December 31, 2016. These amounts include certain estimates and allocations where necessary.2022.
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, 2023 |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo
Consolidated |
| (in millions) |
| Revenues from: | | | | | | | |
| External Customers | $ | 89.0 | | | $ | — | | | $ | — | | | $ | 89.0 | |
| Sales to AEP Affiliates | 352.6 | | | — | | | — | | | 352.6 | |
| | | | | | | |
| Total Revenues | $ | 441.6 | | | $ | — | | | $ | — | | | $ | 441.6 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Net Income | $ | 161.6 | | | $ | 1.1 | | (a) | $ | — | | | $ | 162.7 | |
| | | | | | | |
| Three Months Ended March 31, 2022 |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo
Consolidated |
| (in millions) |
| Revenues from: | | | | | | | |
| External Customers | $ | 75.7 | | | $ | — | | | $ | — | | | $ | 75.7 | |
| Sales to AEP Affiliates | 324.7 | | | — | | | — | | | 324.7 | |
| | | | | | | |
| Total Revenues | $ | 400.4 | | | $ | — | | | $ | — | | | $ | 400.4 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Net Income | $ | 155.4 | | | $ | — | | (a) | $ | — | | | $ | 155.4 | |
|
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2017 |
| | State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| | (in millions) |
| Revenues from: | | | | | | | |
| External Customers | $ | 35.9 |
| | $ | — |
| | $ | — |
| | $ | 35.9 |
|
| Sales to AEP Affiliates | 131.3 |
| | — |
| | 0.1 |
| | 131.4 |
|
| Total Revenues | $ | 167.2 |
| | $ | — |
| | $ | 0.1 |
| | $ | 167.3 |
|
| | | | | | | | |
| Interest Income | $ | — |
| | $ | 19.5 |
| | $ | (19.3 | ) | (a) | $ | 0.2 |
|
| Interest Expense | 16.9 |
| | 19.3 |
| | (19.3 | ) | (a) | 16.9 |
|
| Income Tax Expense | 30.2 |
| | — |
| | — |
| | 30.2 |
|
| Equity Earnings in State Transcos | — |
| | 59.8 |
| | (59.8 | ) | (b) | — |
|
| | | | | | | | |
| Net Income | $ | 59.8 |
| | $ | 59.9 |
| | $ | (59.8 | ) | (b) | $ | 59.9 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| |
| | | | | | | |
| |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| |
| | | | | | | |
| |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| March 31, 2023 |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo
Consolidated |
| (in millions) |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Total Assets | $ | 14,493.6 | | | $ | 5,581.6 | | (b) | $ | (5,620.5) | | (c) | $ | 14,454.7 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| December 31, 2022 |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo
Consolidated |
| (in millions) |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Total Assets | $ | 13,875.6 | | | $ | 4,817.4 | | (b) | $ | (4,878.8) | | (c) | $ | 13,814.2 | |
| | | | | | | |
| | | | | | | |
(a)Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos.
(b)Primarily relates to Notes Receivable from the State Transcos.
(c)Primarily relates to the elimination of Notes Receivable from the State Transcos.
|
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2016 |
| | State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| | (in millions) |
| Revenues from: | | | | | | | |
| External Customers | $ | 33.5 |
| | $ | — |
| | $ | — |
| | $ | 33.5 |
|
| Sales to AEP Affiliates | 91.8 |
| | — |
| | — |
| | 91.8 |
|
| Total Revenues | $ | 125.3 |
| | $ | — |
| | $ | — |
| | $ | 125.3 |
|
| | | | | | | | |
| Interest Income | $ | — |
| | $ | 14.0 |
| | $ | (13.9 | ) | (a) | $ | 0.1 |
|
| Interest Expense | 11.0 |
| | 13.9 |
| | (13.9 | ) | (a) | 11.0 |
|
| Income Tax Expense | 26.4 |
| | — |
| | — |
| | 26.4 |
|
| Equity Earnings in State Transcos | — |
| | 52.3 |
| | (52.3 | ) | (b) | — |
|
| | | | | | | | |
| Net Income | $ | 52.3 |
| | $ | 52.4 |
| | $ | (52.3 | ) | (b) | $ | 52.4 |
|
|
| | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2017 |
| | State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| | (in millions) |
| Revenues from: | | | | | | | |
| External Customers | $ | 99.2 |
| | $ | — |
| | $ | — |
| | $ | 99.2 |
|
| Sales to AEP Affiliates | 450.2 |
| | — |
| | — |
| | 450.2 |
|
| Total Revenues | $ | 549.4 |
| | $ | — |
| | $ | — |
| | $ | 549.4 |
|
| | | | | | | | |
| Interest Income | $ | 0.1 |
| | $ | 58.0 |
| | $ | (57.6 | ) | (a) | $ | 0.5 |
|
| Interest Expense | 48.6 |
| | 57.6 |
| | (57.6 | ) | (a) | 48.6 |
|
| Income Tax Expense | 114.3 |
| | 0.2 |
| | — |
| | 114.5 |
|
| Equity Earnings in State Transcos | — |
| | 224.0 |
| | (224.0 | ) | (b) | — |
|
| | | | | | | | |
| Net Income | $ | 224.0 |
| | $ | 224.3 |
| | $ | (224.0 | ) | (b) | $ | 224.3 |
|
|
| | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2016 |
| | State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| | (in millions) |
| Revenues from: | | | | | | | |
| External Customers | $ | 89.6 |
| | $ | — |
| | $ | — |
| | $ | 89.6 |
|
| Sales to AEP Affiliates | 268.4 |
| | — |
| | — |
| | 268.4 |
|
| Total Revenues | $ | 358.0 |
| | $ | — |
| | $ | — |
| | $ | 358.0 |
|
| | | | | | | | |
| Interest Income | $ | — |
| | $ | 41.8 |
| | $ | (41.6 | ) | (a) | $ | 0.2 |
|
| Interest Expense | 32.3 |
| | 41.6 |
| | (41.6 | ) | (a) | 32.3 |
|
| Income Tax Expense | 73.9 |
| | — |
| | — |
| | 73.9 |
|
| Equity Earnings in State Transcos | — |
| | 153.0 |
| | (153.0 | ) | (b) | — |
|
| | | | | | | | |
| Net Income | $ | 153.0 |
| | $ | 153.0 |
| | $ | (153.0 | ) | (b) | $ | 153.0 |
|
|
| | | | | | | | | | | | | | | |
| | September 30, 2017 |
| | State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo
Consolidated |
| | (in millions) |
| Total Transmission Property | $ | 6,067.5 |
| | $ | — |
| | $ | — |
| | $ | 6,067.5 |
|
| Accumulated Depreciation and Amortization | 151.5 |
| | — |
| | — |
| | 151.5 |
|
| Total Transmission Property – Net | $ | 5,916.0 |
| | $ | — |
| | $ | — |
| | $ | 5,916.0 |
|
| | | | | | | | |
| Notes Receivable - Affiliated | $ | — |
| | $ | 2,500.0 |
| | $ | (2,500.0 | ) | (c) | $ | — |
|
| | | | | | | | |
| Total Assets | $ | 6,455.2 |
| | $ | 5,010.8 |
| | $ | (4,917.1 | ) | (d) | $ | 6,548.9 |
|
| | | | | | | | |
| Total Long-term Debt | $ | 2,475.6 |
| | $ | 2,574.4 |
| | $ | (2,500.0 | ) | (c) | $ | 2,550.0 |
|
|
| | | | | | | | | | | | | | | |
| | December 31, 2016 |
| | State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo
Consolidated |
| | (in millions) |
| Total Transmission Property | $ | 5,054.2 |
| | $ | — |
| | $ | — |
| | $ | 5,054.2 |
|
| Accumulated Depreciation and Amortization | 99.6 |
| | — |
| | — |
| | 99.6 |
|
| Total Transmission Property – Net | $ | 4,954.6 |
| | $ | — |
| | $ | — |
| | $ | 4,954.6 |
|
| | | | | | | | |
| Notes Receivable - Affiliated | $ | — |
| | $ | 1,950.0 |
| | $ | (1,950.0 | ) | (c) | $ | — |
|
| | | | | | | | |
| Total Assets | $ | 5,337.5 |
| | $ | 3,947.8 |
| | $ | (3,935.5 | ) | (d) | $ | 5,349.8 |
|
| | | | | | | | |
| Total Long-term Debt | $ | 1,932.0 |
| | $ | 1,950.0 |
| | $ | (1,950.0 | ) | (c) | $ | 1,932.0 |
|
| |
(a) | Elimination of intercompany interest income/interest expense on affiliated debt arrangement. |
| |
(b) | Elimination of AEPTCo Parent’s equity earnings in the State Transcos. |
| |
(c) | Elimination of intercompany debt. |
| |
(d) | Primarily relates to the elimination of AEPTCo Parent’s investment in the State Transcos and Note Receivable from the State Transcos. |
9. DERIVATIVES AND HEDGING
The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any Derivativederivative and Hedginghedging activity.
OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS
AEPSC is agent for and transacts on behalf of certain AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLCAEPEP 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 credit risk and foreign currency exchangecredit 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:
Notional Volume of Derivative Instruments
September 30, 2017March 31, 2023
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Primary Risk
Exposure | | Unit of
Measure | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in millions) |
| Commodity: | | | | | | | | | | | | | | | | |
| Power | | MWhs | | 213.5 | | | — | | | 7.3 | | | 4.1 | | | 2.4 | | | 1.8 | | | 1.3 | |
| | | | | | | | | | | | | | | | |
| Natural Gas | | MMBtus | | 92.8 | | | — | | | 2.9 | | | — | | | — | | | 3.1 | | | 1.8 | |
| Heating Oil and Gasoline | | Gallons | | 5.0 | | | 1.4 | | | 0.8 | | | 0.5 | | | 1.0 | | | 0.7 | | | 0.7 | |
| Interest Rate | | USD | | $ | 91.4 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | |
| Interest Rate on Long-term Debt | | USD | | $ | 1,700.0 | | | $ | 150.0 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Primary Risk Exposure | | Unit of Measure | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | | (in millions) |
| Commodity: | | | | | | | | |
| | |
| | |
| | |
|
| Power | | MWhs | | 406.0 |
| | 73.7 |
| | 45.8 |
| | 10.6 |
| | 13.7 |
| | 34.5 |
|
| Coal | | Tons | | 0.5 |
| | — |
| | 0.2 |
| | — |
| | — |
| | 0.3 |
|
| Natural Gas | | MMBtus | | 48.1 |
| | 2.0 |
| | 1.2 |
| | — |
| | — |
| | 18.3 |
|
| Heating Oil and Gasoline | | Gallons | | 7.9 |
| | 1.5 |
| | 0.7 |
| | 1.8 |
| | 0.8 |
| | 0.9 |
|
| Interest Rate | | USD | | $ | 53.2 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | | | | | | | | | | |
| Interest Rate | | USD | | $ | 1,000.0 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Notional Volume of Derivative Instruments
December 31, 20162022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Primary Risk
Exposure | | Unit of
Measure | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in millions) |
| Commodity: | | | | | | | | | | | | | | | | |
| Power | | MWhs | | 226.8 | | | — | | | 17.9 | | | 4.2 | | | 2.5 | | | 2.9 | | | 2.2 | |
| | | | | | | | | | | | | | | | |
| Natural Gas | | MMBtus | | 77.1 | | | — | | | 1.9 | | | — | | | — | | | 1.9 | | | 2.1 | |
| Heating Oil and Gasoline | | Gallons | | 6.9 | | | 1.9 | | | 1.0 | | | 0.7 | | | 1.4 | | | 0.9 | | | 1.0 | |
| Interest Rate | | USD | | $ | 99.9 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | |
| Interest Rate on Long-term Debt | | USD | | $ | 1,650.0 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 200.0 | | | $ | — | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Primary Risk Exposure | | Unit of Measure | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | | (in millions) |
| Commodity: | | | | | | | | |
| | |
| | |
| | |
|
| Power | | MWhs | | 348.0 |
| | 51.9 |
| | 19.9 |
| | 11.2 |
| | 11.9 |
| | 14.2 |
|
| Coal | | Tons | | 1.5 |
| | — |
| | 0.5 |
| | — |
| | — |
| | 1.0 |
|
| Natural Gas | | MMBtus | | 32.8 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Heating Oil and Gasoline | | Gallons | | 7.4 |
| | 1.4 |
| | 0.7 |
| | 1.6 |
| | 0.8 |
| | 0.9 |
|
| Interest Rate | | USD | | $ | 75.2 |
| | $ | 0.1 |
| | $ | 0.1 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | | | | | | | | | | |
| Interest Rate | | USD | | $ | 500.0 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
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.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.
At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency 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 supply and demand market data andother 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 partythird-party contractual agreements and risk profiles. The RegistrantsAEP netted cash collateral received from third partiesthird-parties against short-term and long-term risk management assets in the amounts of $108 million and $481 million as of March 31, 2023 and December 31, 2022, respectively. There was no cash collateral received from third-parties netted against short-term and long-term risk management assets for the Registrant Subsidiaries as of March 31, 2023 and December 31, 2022. The amount of cash collateral paid to third partiesthird-parties netted against short-term and long-term risk management liabilities was immaterial for the Registrants as follows:of March 31, 2023 and December 31, 2022.
|
| | | | | | | | | | | | | | | | |
| | | September 30, 2017 | | December 31, 2016 |
| | | Cash Collateral | | Cash Collateral | | Cash Collateral | | Cash Collateral |
| | | Received | | Paid | | Received | | Paid |
| | | Netted Against | | Netted Against | | Netted Against | | Netted Against |
| | | Risk Management | | Risk Management | | Risk Management | | Risk Management |
| Company | | Assets | | Liabilities | | Assets | | Liabilities |
| | | (in millions) |
| AEP | | $ | 3.5 |
| | $ | 17.0 |
| | $ | 7.9 |
| | $ | 7.6 |
|
| APCo | | 0.4 |
| | 0.3 |
| | 0.5 |
| | 0.7 |
|
| I&M | | 0.3 |
| | 0.1 |
| | 0.3 |
| | 0.4 |
|
| OPCo | | 0.1 |
| | — |
| | 0.2 |
| | — |
|
| PSO | | — |
| | — |
| | 0.1 |
| | — |
|
| SWEPCo | | — |
| | — |
| | 0.1 |
| | — |
|
The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets:sheets. Unless shown as a separate line on the balance sheets due to materiality, Current Risk Management Assets are included in Prepayments and Other Current Assets, Long-term Risk Management Assets are included in Deferred Charges and Other Noncurrent Assets, Current Risk Management Liabilities are included in Other Current Liabilities and Long-term Risk Management Liabilities are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets.
AEP
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | March 31, 2023 |
| | 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 | | $ | 621.1 | | | $ | 85.0 | | | $ | 8.9 | | | $ | 715.0 | | | $ | (524.4) | | | $ | 190.6 | |
| Long-term Risk Management Assets | | 494.3 | | | 117.0 | | | — | | | 611.3 | | | (293.1) | | | 318.2 | |
| Total Assets | | 1,115.4 | | | 202.0 | | | 8.9 | | | 1,326.3 | | | (817.5) | | | 508.8 | |
| | | | | | | | | | | | |
| Current Risk Management Liabilities | | 562.5 | | | 87.5 | | | 39.5 | | | 689.5 | | | (523.5) | | | 166.0 | |
| Long-term Risk Management Liabilities | | 402.6 | | | 31.4 | | | 82.7 | | | 516.7 | | | (201.3) | | | 315.4 | |
| Total Liabilities | | 965.1 | | | 118.9 | | | 122.2 | | | 1,206.2 | | | (724.8) | | | 481.4 | |
| | | | | | | | | | | | |
| Total MTM Derivative Contract Net Assets (Liabilities) (d) | | $ | 150.3 | | | $ | 83.1 | | | $ | (113.3) | | | $ | 120.1 | | | $ | (92.7) | | | $ | 27.4 | |
Fair Value of Derivative Instruments
September 30, 2017 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2022 |
| | 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 | | $ | 965.4 | | | $ | 212.2 | | | $ | 1.8 | | | $ | 1,179.4 | | | $ | (830.6) | | | $ | 348.8 | |
| Long-term Risk Management Assets | | 565.6 | | | 148.9 | | | 14.3 | | | 728.8 | | | (444.7) | | | 284.1 | |
| Total Assets | | 1,531.0 | | | 361.1 | | | 16.1 | | | 1,908.2 | | | (1,275.3) | | | 632.9 | |
| | | | | | | | | | | | |
| Current Risk Management Liabilities | | 663.8 | | | 60.4 | | | 41.4 | | | 765.6 | | | (620.4) | | | 145.2 | |
| Long-term Risk Management Liabilities | | 412.0 | | | 17.4 | | | 91.1 | | | 520.5 | | | (175.3) | | | 345.2 | |
| Total Liabilities | | 1,075.8 | | | 77.8 | | | 132.5 | | | 1,286.1 | | | (795.7) | | | 490.4 | |
| | | | | | | | | | | | |
| Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 455.2 | | | $ | 283.3 | | | $ | (116.4) | | | $ | 622.1 | | | $ | (479.6) | | | $ | 142.5 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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 | | $ | 277.4 |
| | $ | 8.1 |
| | $ | 4.2 |
| | $ | 289.7 |
| | $ | (143.6 | ) | | $ | 146.1 |
|
| Long-term Risk Management Assets | | 348.1 |
| | 3.8 |
| | — |
| | 351.9 |
| | (41.5 | ) | | 310.4 |
|
| Total Assets | | 625.5 |
| | 11.9 |
| | 4.2 |
| | 641.6 |
| | (185.1 | ) | | 456.5 |
|
| | | | | | | | | | | | | |
| Current Risk Management Liabilities | | 202.2 |
| | 13.5 |
| | 1.4 |
| | 217.1 |
| | (147.7 | ) | | 69.4 |
|
| Long-term Risk Management Liabilities | | 329.6 |
| | 74.0 |
| | — |
| | 403.6 |
| | (50.9 | ) | | 352.7 |
|
| Total Liabilities | | 531.8 |
| | 87.5 |
| | 1.4 |
| | 620.7 |
| | (198.6 | ) | | 422.1 |
|
| | | | | | | | | | | | | |
| Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 93.7 |
| | $ | (75.6 | ) | | $ | 2.8 |
| | $ | 20.9 |
| | $ | 13.5 |
| | $ | 34.4 |
|
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Fair Value of Derivative Instruments |
| December 31, 2016 |
| | | | | | | | | | | | | |
| | | 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 | | $ | 264.4 |
| | $ | 13.2 |
| | $ | — |
| | $ | 277.6 |
| | $ | (183.1 | ) | | $ | 94.5 |
|
| Long-term Risk Management Assets | | 315.0 |
| | 7.7 |
| | — |
| | 322.7 |
| | (33.6 | ) | | 289.1 |
|
| Total Assets | | 579.4 |
| | 20.9 |
| | — |
| | 600.3 |
| | (216.7 | ) | | 383.6 |
|
| | | | | | | | | | | | | |
| Current Risk Management Liabilities | | 227.2 |
| | 6.3 |
| | — |
| | 233.5 |
| | (180.1 | ) | | 53.4 |
|
| Long-term Risk Management Liabilities | | 301.0 |
| | 50.1 |
| | 1.4 |
| | 352.5 |
| | (36.3 | ) | | 316.2 |
|
| Total Liabilities | | 528.2 |
| | 56.4 |
| | 1.4 |
| | 586.0 |
| | (216.4 | ) | | 369.6 |
|
| | | | | | | | | | | | | |
| Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 51.2 |
| | $ | (35.5 | ) | | $ | (1.4 | ) | | $ | 14.3 |
| | $ | (0.3 | ) | | $ | 14.0 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | March 31, 2023 |
| | 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) | | Interest Rate (a) | | | |
| | (in millions) |
| Current Risk Management Assets | | $ | — | | | $ | 0.5 | | | $ | 0.5 | | | $ | — | | | $ | 0.5 | |
| Long-term Risk Management Assets | | — | | | — | | | — | | | — | | | — | |
| Total Assets | | — | | | 0.5 | | | 0.5 | | | — | | | 0.5 | |
| | | | | | | | | | |
| Current Risk Management Liabilities | | 0.4 | | | 0.8 | | | 1.2 | | | (0.4) | | | 0.8 | |
| Long-term Risk Management Liabilities | | — | | | — | | | — | | | — | | | — | |
| Total Liabilities | | 0.4 | | | 0.8 | | | 1.2 | | | (0.4) | | | 0.8 | |
| | | | | | | | | | |
| Total MTM Derivative Contract Net Assets (Liabilities) (d) | | $ | (0.4) | | | $ | (0.3) | | | $ | (0.7) | | | $ | 0.4 | | | $ | (0.3) | |
APCo
Fair Value of Derivative Instruments
September 30, 2017
|
| | | | | | | | | | | | |
| | | 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 | | $ | 50.4 |
| | $ | (20.1 | ) | | $ | 30.3 |
|
| Long-term Risk Management Assets | | 4.9 |
| | (4.3 | ) | | 0.6 |
|
| Total Assets | | 55.3 |
| | (24.4 | ) | | 30.9 |
|
| | | | | | | |
| Current Risk Management Liabilities | | 20.7 |
| | (19.8 | ) | | 0.9 |
|
| Long-term Risk Management Liabilities | | 4.8 |
| | (4.5 | ) | | 0.3 |
|
| Total Liabilities | | 25.5 |
| | (24.3 | ) | | 1.2 |
|
| | | | | | | |
| Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 29.8 |
| | $ | (0.1 | ) | | $ | 29.7 |
|
Fair Value of Derivative Instruments
December 31, 2016
|
| | | | | | | | | | | | |
| | | 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 | | $ | 22.7 |
| | $ | (20.1 | ) | | $ | 2.6 |
|
| Long-term Risk Management Assets | | 1.9 |
| | (1.9 | ) | | — |
|
| Total Assets | | 24.6 |
| | (22.0 | ) | | 2.6 |
|
| | | | | | | |
| Current Risk Management Liabilities | | 20.6 |
| | (20.3 | ) | | 0.3 |
|
| Long-term Risk Management Liabilities | | 2.8 |
| | (1.9 | ) | | 0.9 |
|
| Total Liabilities | | 23.4 |
| | (22.2 | ) | | 1.2 |
|
| | | | | | | |
| Total MTM Derivative Contract Net Assets | | $ | 1.2 |
| | $ | 0.2 |
| | $ | 1.4 |
|
I&M
Fair Value of Derivative Instruments
September 30, 2017
|
| | | | | | | | | | | | |
| | | 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 | | $ | 27.4 |
| | $ | (15.8 | ) | | $ | 11.6 |
|
| Long-term Risk Management Assets | | 3.3 |
| | (2.8 | ) | | 0.5 |
|
| Total Assets | | 30.7 |
| | (18.6 | ) | | 12.1 |
|
| | | | | | | |
| Current Risk Management Liabilities | | 17.6 |
| | (15.6 | ) | | 2.0 |
|
| Long-term Risk Management Liabilities | | 3.0 |
| | (2.8 | ) | | 0.2 |
|
| Total Liabilities | | 20.6 |
| | (18.4 | ) | | 2.2 |
|
| | | | | | | |
| Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 10.1 |
| | $ | (0.2 | ) | | $ | 9.9 |
|
Fair Value of Derivative Instruments
December 31, 2016
|
| | | | | | | | | | | | |
| | | 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 | | $ | 14.9 |
| | $ | (11.4 | ) | | $ | 3.5 |
|
| Long-term Risk Management Assets | | 1.1 |
| | (1.1 | ) | | — |
|
| Total Assets | | 16.0 |
| | (12.5 | ) | | 3.5 |
|
| | | | | | | |
| Current Risk Management Liabilities | | 11.8 |
| | (11.5 | ) | | 0.3 |
|
| Long-term Risk Management Liabilities | | 1.9 |
| | (1.1 | ) | | 0.8 |
|
| Total Liabilities | | 13.7 |
| | (12.6 | ) | | 1.1 |
|
| | | | | | | |
| Total MTM Derivative Contract Net Assets | | $ | 2.3 |
| | $ | 0.1 |
| | $ | 2.4 |
|
OPCo
Fair Value of Derivative Instruments
September 30, 2017
|
| | | | | | | | | | | | |
| | | 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 |
| | $ | (0.1 | ) | | $ | 0.2 |
|
| Long-term Risk Management Assets | | — |
| | — |
| | — |
|
| Total Assets | | 0.3 |
| | (0.1 | ) | | 0.2 |
|
| | | | | | | |
| Current Risk Management Liabilities | | 7.6 |
| | — |
| | 7.6 |
|
| Long-term Risk Management Liabilities | | 130.9 |
| | — |
| | 130.9 |
|
| Total Liabilities | | 138.5 |
| | — |
| | 138.5 |
|
| | | | | | | |
| Total MTM Derivative Contract Net Liabilities | | $ | (138.2 | ) | | $ | (0.1 | ) | | $ | (138.3 | ) |
Fair Value of Derivative Instruments
December 31, 2016
|
| | | | | | | | | | | | |
| | | 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 |
| | $ | (0.2 | ) | | $ | 0.2 |
|
| Long-term Risk Management Assets | | — |
| | — |
| | — |
|
| Total Assets | | 0.4 |
| | (0.2 | ) | | 0.2 |
|
| | | | | | | |
| Current Risk Management Liabilities | | 5.9 |
| | — |
| | 5.9 |
|
| Long-term Risk Management Liabilities | | 113.1 |
| | — |
| | 113.1 |
|
| Total Liabilities | | 119.0 |
| | — |
| | 119.0 |
|
| | | | | | | |
| Total MTM Derivative Contract Net Liabilities | | $ | (118.6 | ) | | $ | (0.2 | ) | | $ | (118.8 | ) |
PSO
Fair Value of Derivative Instruments
September 30, 2017
|
| | | | | | | | | | | | |
| | | 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 | | $ | 4.7 |
| | $ | — |
| | $ | 4.7 |
|
| Long-term Risk Management Assets | | — |
| | — |
| | — |
|
| Total Assets | | 4.7 |
| | — |
| | 4.7 |
|
| | | | | | | |
| Current Risk Management Liabilities | | — |
| | — |
| | — |
|
| Long-term Risk Management Liabilities | | — |
| | — |
| | — |
|
| Total Liabilities | | — |
| | — |
| | — |
|
| | | | | | | |
| Total MTM Derivative Contract Net Assets | | $ | 4.7 |
| | $ | — |
| | $ | 4.7 |
|
Fair Value of Derivative Instruments
December 31, 2016
|
| | | | | | | | | | | | |
| | | 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 | | $ | 0.9 |
| | $ | (0.1 | ) | | $ | 0.8 |
|
| Long-term Risk Management Assets | | — |
| | — |
| | — |
|
| Total Assets | | 0.9 |
| | (0.1 | ) | | 0.8 |
|
| | | | | | | |
| Current Risk Management Liabilities | | — |
| | — |
| | — |
|
| Long-term Risk Management Liabilities | | — |
| | — |
| | — |
|
| Total Liabilities | | — |
| | — |
| | — |
|
| | | | | | | |
| Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 0.9 |
| | $ | (0.1 | ) | | $ | 0.8 |
|
SWEPCo
Fair Value of Derivative Instruments
September 30, 2017
|
| | | | | | | | | | | | |
| | | 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 | | $ | 12.7 |
| | $ | (0.2 | ) | | $ | 12.5 |
|
| Long-term Risk Management Assets | | 0.7 |
| | — |
| | 0.7 |
|
| Total Assets | | 13.4 |
| | (0.2 | ) | | 13.2 |
|
| | | | | | | |
| Current Risk Management Liabilities | | 0.3 |
| | (0.2 | ) | | 0.1 |
|
| Long-term Risk Management Liabilities | | — |
| | — |
| | — |
|
| Total Liabilities | | 0.3 |
| | (0.2 | ) | | 0.1 |
|
| | | | | | | |
| Total MTM Derivative Contract Net Assets | | $ | 13.1 |
| | $ | — |
| | $ | 13.1 |
|
Fair Value of Derivative Instruments
December 31, 2016
|
| | | | | | | | | | | | |
| | | 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 | | $ | 1.1 |
| | $ | (0.2 | ) | | $ | 0.9 |
|
| Long-term Risk Management Assets | | — |
| | — |
| | — |
|
| Total Assets | | 1.1 |
| | (0.2 | ) | | 0.9 |
|
| | | | | | | |
| Current Risk Management Liabilities | | 0.4 |
| | (0.1 | ) | | 0.3 |
|
| Long-term Risk Management Liabilities | | — |
| | — |
| | — |
|
| Total Liabilities | | 0.4 |
| | (0.1 | ) | | 0.3 |
|
| | | | | | | |
| Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 0.7 |
| | $ | (0.1 | ) | | $ | 0.6 |
|
| | | | | | | | | | | | | | | | | | | | |
(a) | Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on | December 31, 2022 |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the balance sheets on a net basisStatement of | | Presented in accordance with the accounting guidance for “Derivatives and Hedging.”Statement of |
| Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) |
| Current Risk Management Assets | | $ | — | | | $ | — | | | $ | — | |
| Long-term Risk Management Assets | | — | | | — | | | — | |
| Total Assets | | — | | | — | | | — | |
| | | | | | |
(b)Current Risk Management Liabilities | Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” | — | | | — | | | — | |
| Long-term Risk Management Liabilities | | — | | | — | | | — | |
| Total Liabilities | | — | | | — | | | — | |
| | | | | | |
(c)Total MTM Derivative Contract Net Assets | There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. | $ | — | | | $ | — | | | $ | — | |
APCo
| | | | | | | | | | | | | | | | | | | | | | | | |
| | March 31, 2023 |
| | | | | | | | | | |
| | | | | | | | | | |
| | Risk Management | | | | | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | | | | | in the Statement of | | Presented in the Statement of |
| Balance Sheet Location | | Commodity (a) | | | | | | Financial Position (b) | | Financial Position (c) |
| | (in millions) |
| Current Risk Management Assets | | $ | 12.8 | | | | | | | $ | (0.4) | | | $ | 12.4 | |
| Long-term Risk Management Assets | | 0.5 | | | | | | | (0.5) | | | — | |
| Total Assets | | 13.3 | | | | | | | (0.9) | | | 12.4 | |
| | | | | | | | | | |
| Current Risk Management Liabilities | | 7.6 | | | | | | | (0.6) | | | 7.0 | |
| Long-term Risk Management Liabilities | | 0.5 | | | | | | | (0.5) | | | — | |
| Total Liabilities | | 8.1 | | | | | | | (1.1) | | | 7.0 | |
| | | | | | | | | | |
| Total MTM Derivative Contract Net Assets (d) | | $ | 5.2 | | | | | | | $ | 0.2 | | | $ | 5.4 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2022 |
| | | | | | | | | | |
| | | | | | | | | | |
| | Risk Management | | | | | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | | | | | in the Statement of | | Presented in the Statement of |
| Balance Sheet Location | | Commodity (a) | | | | | | Financial Position (b) | | Financial Position (c) |
| | (in millions) |
| Current Risk Management Assets | | $ | 69.3 | | | | | | | $ | (0.2) | | | $ | 69.1 | |
| Long-term Risk Management Assets | | 0.7 | | | | | | | (0.7) | | | — | |
| Total Assets | | 70.0 | | | | | | | (0.9) | | | 69.1 | |
| | | | | | | | | | |
| Current Risk Management Liabilities | | 4.1 | | | | | | | (0.5) | | | 3.6 | |
| Long-term Risk Management Liabilities | | 0.7 | | | | | | | (0.6) | | | 0.1 | |
| Total Liabilities | | 4.8 | | | | | | | (1.1) | | | 3.7 | |
| | | | | | | | | | |
| Total MTM Derivative Contract Net Assets | | $ | 65.2 | | | | | | | $ | 0.2 | | | $ | 65.4 | |
I&M
| | | | | | | | | | | | | | | | | | | | |
| | March 31, 2023 |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
| Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) |
| Current Risk Management Assets | | $ | 8.1 | | | $ | (2.2) | | | $ | 5.9 | |
| Long-term Risk Management Assets | | 5.5 | | | (4.4) | | | 1.1 | |
| Total Assets | | 13.6 | | | (6.6) | | | 7.0 | |
| | | | | | |
| Current Risk Management Liabilities | | 2.7 | | | (2.3) | | | 0.4 | |
| Long-term Risk Management Liabilities | | 4.4 | | | (4.4) | | | — | |
| Total Liabilities | | 7.1 | | | (6.7) | | | 0.4 | |
| | | | | | |
| Total MTM Derivative Contract Net Assets (d) | | $ | 6.5 | | | $ | 0.1 | | | $ | 6.6 | |
| | | | | | | | | | | | | | | | | | | | |
| | December 31, 2022 |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
| Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) |
| Current Risk Management Assets | | $ | 16.0 | | | $ | (0.8) | | | $ | 15.2 | |
| Long-term Risk Management Assets | | 0.5 | | | (0.3) | | | 0.2 | |
| Total Assets | | 16.5 | | | (1.1) | | | 15.4 | |
| | | | | | |
| Current Risk Management Liabilities | | 0.9 | | | (0.9) | | | — | |
| Long-term Risk Management Liabilities | | 0.3 | | | (0.3) | | | — | |
| Total Liabilities | | 1.2 | | | (1.2) | | | — | |
| | | | | | |
| Total MTM Derivative Contract Net Assets | | $ | 15.3 | | | $ | 0.1 | | | $ | 15.4 | |
OPCo
| | | | | | | | | | | | | | | | | | | | |
| | March 31, 2023 |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
| Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) |
| Current Risk Management Assets | | $ | — | | | $ | — | | | $ | — | |
| Long-term Risk Management Assets | | — | | | — | | | — | |
| Total Assets | | — | | | — | | | — | |
| | | | | | |
| Current Risk Management Liabilities | | 6.2 | | | (0.2) | | | 6.0 | |
| Long-term Risk Management Liabilities | | 40.9 | | | — | | | 40.9 | |
| Total Liabilities | | 47.1 | | | (0.2) | | | 46.9 | |
| | | | | | |
| Total MTM Derivative Contract Net Assets (Liabilities) (d) | | $ | (47.1) | | | $ | 0.2 | | | $ | (46.9) | |
| | | | | | | | | | | | | | | | | | | | |
| | December 31, 2022 |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
| Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) |
| Current Risk Management Assets | | $ | — | | | $ | — | | | $ | — | |
| Long-term Risk Management Assets | | — | | | — | | | — | |
| Total Assets | | — | | | — | | | — | |
| | | | | | |
| Current Risk Management Liabilities | | 2.1 | | | (0.3) | | | 1.8 | |
| Long-term Risk Management Liabilities | | 37.9 | | | — | | | 37.9 | |
| Total Liabilities | | 40.0 | | | (0.3) | | | 39.7 | |
| | | | | | |
| Total MTM Derivative Contract Net Assets (Liabilities) | | $ | (40.0) | | | $ | 0.3 | | | $ | (39.7) | |
PSO
| | | | | | | | | | | | | | | | | | | | | | | | |
| | March 31, 2023 |
| | Risk Management | | | | | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | | | in the Statement of | | Presented in the Statement of |
| Balance Sheet Location | | Commodity (a) | | | | | Financial Position (b) | | Financial Position (c) |
| | (in millions) |
| Current Risk Management Assets | | $ | 9.9 | | | | | | | $ | (0.5) | | | $ | 9.4 | |
| Long-term Risk Management Assets | | — | | | | | | | — | | | — | |
| Total Assets | | 9.9 | | | | | | | (0.5) | | | 9.4 | |
| | | | | | | | | | |
| Current Risk Management Liabilities | | 1.8 | | | | | | | (0.7) | | | 1.1 | |
| Long-term Risk Management Liabilities | | — | | | | | | | — | | | — | |
| Total Liabilities | | 1.8 | | | | | | | (0.7) | | | 1.1 | |
| | | | | | | | | | |
| Total MTM Derivative Contract Net Assets (d) | | $ | 8.1 | | | | | | | $ | 0.2 | | | $ | 8.3 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2022 |
| | 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) | | Interest Rate (a) | | | |
| | (in millions) |
| Current Risk Management Assets | | $ | 24.1 | | | $ | 1.6 | | | $ | 25.7 | | | $ | (0.4) | | | $ | 25.3 | |
| Long-term Risk Management Assets | | — | | | — | | | — | | | — | | | — | |
| Total Assets | | 24.1 | | | 1.6 | | | 25.7 | | | (0.4) | | | 25.3 | |
| | | | | | | | | | |
| Current Risk Management Liabilities | | 2.1 | | | — | | | 2.1 | | | (0.5) | | | 1.6 | |
| Long-term Risk Management Liabilities | | — | | | — | | | — | | | — | | | — | |
| Total Liabilities | | 2.1 | | | — | | | 2.1 | | | (0.5) | | | 1.6 | |
| | | | | | | | | | |
| Total MTM Derivative Contract Net Assets | | $ | 22.0 | | | $ | 1.6 | | | $ | 23.6 | | | $ | 0.1 | | | $ | 23.7 | |
SWEPCo
| | | | | | | | | | | | | | | | | | | | |
| | March 31, 2023 |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
| Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) |
| Current Risk Management Assets | | $ | 6.4 | | | $ | (0.1) | | | $ | 6.3 | |
| Long-term Risk Management Assets | | — | | | — | | | — | |
| Total Assets | | 6.4 | | | (0.1) | | | 6.3 | |
| | | | | | |
| Current Risk Management Liabilities | | 1.4 | | | (0.3) | | | 1.1 | |
| Long-term Risk Management Liabilities | | — | | | — | | | — | |
| Total Liabilities | | 1.4 | | | (0.3) | | | 1.1 | |
| | | | | | |
| Total MTM Derivative Contract Net Assets (d) | | $ | 5.0 | | | $ | 0.2 | | | $ | 5.2 | |
| | | | | | | | | | | | | | | | | | | | |
| | December 31, 2022 |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of |
| Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | (in millions) |
| Current Risk Management Assets | | $ | 16.8 | | | $ | (0.4) | | | $ | 16.4 | |
| Long-term Risk Management Assets | | — | | | — | | | — | |
| Total Assets | | 16.8 | | | (0.4) | | | 16.4 | |
| | | | | | |
| Current Risk Management Liabilities | | 2.0 | | | (0.6) | | | 1.4 | |
| Long-term Risk Management Liabilities | | — | | | — | | | — | |
| Total Liabilities | | 2.0 | | | (0.6) | | | 1.4 | |
| | | | | | |
| Total MTM Derivative Contract Net Assets | | $ | 14.8 | | | $ | 0.2 | | | $ | 15.0 | |
(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)Decrease in amounts as of March 31, 2023 are primarily due to decreases in commodity prices for power and natural gas and a decrease in value of FTRs.
The tables below present the Registrants’ activityamount of derivativegain (loss) recognized on risk management contracts:
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2023 |
| Location of Gain (Loss) | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
| Vertically Integrated Utilities Revenues | | $ | (5.3) | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | |
| Generation & Marketing Revenues | | (147.4) | | | — | | | — | | | — | | | — | | | — | | | — | |
| Electric Generation, Transmission and Distribution Revenues | | — | | | — | | | — | | | (5.3) | | | — | | | — | | | — | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| Purchased Electricity for Resale | | 0.7 | | | — | | | 0.6 | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | |
| Maintenance | | 0.1 | | | — | | | — | | | — | | | — | | | — | | | — | |
| Regulatory Assets (a) | | (24.8) | | | (0.4) | | | (7.1) | | | (0.5) | | | (12.3) | | | (1.2) | | | (1.5) | |
| Regulatory Liabilities (a) | | (1.5) | | | — | | | (26.2) | | | 1.2 | | | — | | | 18.0 | | | 11.9 | |
| Total Gain (Loss) on Risk Management Contracts (b) | | $ | (178.2) | | | $ | (0.4) | | | $ | (32.7) | | | $ | (4.6) | | | $ | (12.3) | | | $ | 16.8 | | | $ | 10.4 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2022 |
| Location of Gain (Loss) | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| Generation & Marketing Revenues | | $ | 152.3 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Electric Generation, Transmission and Distribution Revenues | | — | | | — | | | 0.1 | | | (0.1) | | | — | | | — | | | — | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| Purchased Electricity for Resale | | 1.5 | | | — | | | 1.4 | | | — | | | — | | | — | | | — | |
| Other Operation | | 0.6 | | | 0.2 | | | — | | | 0.1 | | | 0.1 | | | 0.1 | | | 0.1 | |
| Maintenance | | 0.8 | | | 0.2 | | | 0.1 | | | 0.1 | | | 0.1 | | | 0.1 | | | 0.1 | |
| Regulatory Assets (a) | | 23.6 | | | — | | | (0.1) | | | (1.6) | | | 23.9 | | | 3.6 | | | (2.1) | |
| Regulatory Liabilities (a) | | 36.5 | | | 0.9 | | | (1.4) | | | 1.7 | | | — | | | 12.7 | | | 20.9 | |
| Total Gain on Risk Management Contracts | | $ | 215.3 | | | $ | 1.3 | | | $ | 0.1 | | | $ | 0.2 | | | $ | 24.1 | | | $ | 16.5 | | | $ | 19.0 | |
(a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the Three Months Ended September 30, 2017balance sheets.
(b)Decrease in amounts as of March 31, 2023 are primarily due to decreases in commodity prices for power and natural gas and a decrease in value of FTRs. |
| | | | | | | | | | | | | | | | | | | | | | | | |
| Location of Gain (Loss) | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in millions) |
| Vertically Integrated Utilities Revenues | | $ | 0.9 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Generation & Marketing Revenues | | 17.7 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Electric Generation, Transmission and Distribution Revenues | | — |
| | 0.3 |
| | 0.6 |
| | — |
| | — |
| | (0.1 | ) |
| Purchased Electricity for Resale | | 1.0 |
| | 0.3 |
| | 0.2 |
| | — |
| | — |
| | — |
|
| Other Operation | | 0.1 |
| | — |
| | — |
| | 0.1 |
| | — |
| | — |
|
| Maintenance | | 0.1 |
| | 0.1 |
| | — |
| | 0.1 |
| | — |
| | — |
|
| Regulatory Assets (a) | | (8.8 | ) | | 0.1 |
| | (0.8 | ) | | (8.7 | ) | | — |
| | 0.3 |
|
| Regulatory Liabilities (a) | | 15.6 |
| | 3.7 |
| | 2.1 |
| | — |
| | 2.6 |
| | 7.0 |
|
| Total Gain (Loss) on Risk Management Contracts | | $ | 26.6 |
| | $ | 4.5 |
| | $ | 2.1 |
| | $ | (8.5 | ) | | $ | 2.6 |
| | $ | 7.2 |
|
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended September 30, 2016
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Location of Gain (Loss) | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in millions) |
| Vertically Integrated Utilities Revenues | | $ | 2.4 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Transmission and Distribution Utilities Revenues | | 0.1 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Generation & Marketing Revenues | | 9.2 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Electric Generation, Transmission and Distribution Revenues | | — |
| | 1.0 |
| | 1.2 |
| | 0.1 |
| | — |
| | (0.1 | ) |
| Purchased Electricity for Resale | | 1.5 |
| | 0.8 |
| | 0.1 |
| | — |
| | — |
| | — |
|
| Other Operation | | (0.4 | ) | | — |
| | — |
| | (0.1 | ) | | — |
| | — |
|
| Maintenance | | (0.4 | ) | | (0.1 | ) | | — |
| | (0.1 | ) | | (0.1 | ) | | (0.1 | ) |
| Regulatory Assets (a) | | (22.5 | ) | | 5.2 |
| | 1.6 |
| | (95.4 | ) | | 0.1 |
| | 2.8 |
|
| Regulatory Liabilities (a) | | 28.6 |
| | 16.9 |
| | 5.5 |
| | — |
| | 0.8 |
| | 3.7 |
|
| Total Gain (Loss) on Risk Management Contracts | | $ | 18.5 |
| | $ | 23.8 |
| | $ | 8.4 |
| | $ | (95.5 | ) | | $ | 0.8 |
| | $ | 6.3 |
|
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Nine Months Ended September 30, 2017
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Location of Gain (Loss) | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in millions) |
| Vertically Integrated Utilities Revenues | | $ | 7.0 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Generation & Marketing Revenues | | 38.5 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Electric Generation, Transmission and Distribution Revenues | | — |
| | 0.6 |
| | 6.3 |
| | — |
| | — |
| | — |
|
| Purchased Electricity for Resale | | 4.9 |
| | 1.6 |
| | 0.5 |
| | — |
| | — |
| | — |
|
| Other Operation | | 0.5 |
| | — |
| | — |
| | 0.1 |
| | — |
| | — |
|
| Maintenance | | 0.4 |
| | 0.1 |
| | — |
| | 0.1 |
| | — |
| | — |
|
| Regulatory Assets (a) | | (26.8 | ) | | — |
| | (1.0 | ) | | (25.9 | ) | | — |
| | 0.1 |
|
| Regulatory Liabilities (a) | | 81.8 |
| | 28.2 |
| | 15.3 |
| | — |
| | 13.7 |
| | 22.0 |
|
| Total Gain (Loss) on Risk Management Contracts | | $ | 106.3 |
| | $ | 30.5 |
| | $ | 21.1 |
| | $ | (25.7 | ) | | $ | 13.7 |
| | $ | 22.1 |
|
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Nine Months Ended September 30, 2016
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Location of Gain (Loss) | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in millions) |
| Vertically Integrated Utilities Revenues | | $ | 3.1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Transmission and Distribution Utilities Revenues | | 0.1 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Generation & Marketing Revenues | | 50.1 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Electric Generation, Transmission and Distribution Revenues | | — |
| | (0.8 | ) | | 3.7 |
| | 0.1 |
| | — |
| | (0.1 | ) |
| Sales to AEP Affiliates | | — |
| | 2.1 |
| | 5.8 |
| | — |
| | — |
| | — |
|
| Purchased Electricity for Resale | | 4.9 |
| | 2.7 |
| | 0.2 |
| | — |
| | — |
| | — |
|
| Other Operation | | (1.3 | ) | | (0.1 | ) | | (0.1 | ) | | (0.3 | ) | | (0.1 | ) | | (0.2 | ) |
| Maintenance | | (1.6 | ) | | (0.3 | ) | | (0.1 | ) | | (0.3 | ) | | (0.2 | ) | | (0.2 | ) |
| Regulatory Assets (a) | | (51.0 | ) | | (7.2 | ) | | 3.0 |
| | (115.9 | ) | | 0.4 |
| | 5.5 |
|
| Regulatory Liabilities (a) | | 58.0 |
| | 39.2 |
| | 11.2 |
| | (15.2 | ) | | 3.2 |
| | 14.7 |
|
| Total Gain (Loss) on Risk Management Contracts | | $ | 62.3 |
| | $ | 35.6 |
| | $ | 23.7 |
| | $ | (131.6 | ) | | $ | 3.3 |
| | $ | 19.7 |
|
| |
(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 expense line item on the statements of income as that of the associated risk.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 Incomenet 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 resultsimpacts recognized on the balance sheets related to the hedged items in fair value hedging relationships:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Carrying Amount of the Hedged Liabilities | | Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Liabilities |
| | March 31, 2023 | | December 31, 2022 | | March 31, 2023 | | December 31, 2022 |
| | (in millions) |
| Long-term Debt (a) (b) | | $ | (860.8) | | | $ | (855.5) | | | $ | 84.7 | | | $ | 89.7 | |
(a)Amounts included on the Balance Sheet within Noncurrent Liabilities line item Long-term Debt.
(b)Amounts include $(36) million and $(38) million as of hedging gains (losses):March 31, 2023 and December 31, 2022, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued.
|
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) |
| Gain (Loss) on Fair Value Hedging Instruments | $ | 0.1 |
| | $ | (1.1 | ) | | $ | (0.1 | ) | | $ | 3.0 |
|
| Gain (Loss) on Fair Value Portion of Long-term Debt | (0.1 | ) | | 1.1 |
| | 0.1 |
| | (3.0 | ) |
During | | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| 2023 | | 2022 | | | | |
| (in millions) |
| Gain (Loss) on Interest Rate Contracts: | | | | | | | |
| Fair Value Hedging Instruments (a) | $ | 6.9 | | | $ | (44.8) | | | | | |
| Fair Value Portion of Long-term Debt (a) | (6.9) | | | 44.8 | | | | | |
(a)Gain (Loss) is included in Interest Expense on the three and nine months ended September 30, 2017 and 2016, hedge ineffectiveness was immaterial.statements of income.
Accounting for Cash Flow Hedging Strategies (Applies to AEP, AEP Texas, 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 effective portion of 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. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable.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 three and nine months ended September 30, 2017March 31, 2023 and 2016,2022, AEP applied cash flow hedging to outstanding power derivatives. During the threederivatives and nine months ended September 30, 2017 and 2016, the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives.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 three and nine months ended September 30, 2017March 31, 2023, AEP, AEP Texas, I&M, PSO and 2016,SWEPCo applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not. During the three months ended March 31, 2022, AEP applied cash flow hedging to outstanding interest rate derivatives. During the threederivatives and nine months ended September 30, 2017 and 2016, the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives.not.
The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2017 and 2016, the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives.
During the three and nine months ended September 30, 2017 and 2016, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.
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 3.3 - 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
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | March 31, 2023 | | December 31, 2022 |
| | Commodity | | Interest Rate | | Commodity | | Interest Rate |
| | (in millions) |
| AOCI Gain Net of Tax | | $ | 65.3 | | | $ | 6.1 | | | $ | 223.5 | | | $ | 0.3 | |
| Portion Expected to be Reclassed to Net Income During the Next Twelve Months | | (2.0) | | | 1.9 | | | 119.9 | | | 0.3 | |
|
| | | | | | | | | | | | | | | | |
| | | September 30, 2017 | | December 31, 2016 |
| | | Commodity | | Interest Rate | | Commodity | | Interest Rate |
| | | (in millions) |
| Hedging Assets (a) | | $ | 4.3 |
| | $ | 4.2 |
| | $ | 11.2 |
| | $ | — |
|
| Hedging Liabilities (a) | | 79.9 |
| | — |
| | 46.7 |
| | — |
|
| AOCI Gain (Loss) Net of Tax | | (49.2 | ) | | (12.2 | ) | | (23.1 | ) | | (15.7 | ) |
| Portion Expected to be Reclassified to Net Income During the Next Twelve Months | | (3.6 | ) | | (0.7 | ) | | 4.3 |
| | (1.0 | ) |
| |
(a) | Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. |
As of September 30, 2017March 31, 2023 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 123 months.96 months and 93 months for commodity and interest rate hedges, respectively.
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | March 31, 2023 | | December 31, 2022 |
| | 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 | | $ | (0.3) | | | $ | — | | | $ | (0.3) | | | $ | (0.2) | |
| APCo | | 6.5 | | | 0.8 | | | 6.7 | | | 0.8 | |
| I&M | | (5.8) | | | (0.4) | | | (5.1) | | | (0.6) | |
| | | | | | | | |
| PSO | | (0.2) | | | — | | | 1.3 | | | 0.1 | |
| SWEPCo | | 1.5 | | | 0.3 | | | 1.1 | | | 0.2 | |
|
| | | | | | | | | | | | | | | | |
| | | September 30, 2017 | | December 31, 2016 |
| | | 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) |
| APCo | | $ | 2.4 |
| | $ | 0.7 |
| | $ | 2.9 |
| | $ | 0.7 |
|
| I&M | | (11.0 | ) | | (1.3 | ) | | (12.0 | ) | | (1.3 | ) |
| OPCo | | 2.2 |
| | 1.1 |
| | 3.0 |
| | 1.1 |
|
| PSO | | 2.8 |
| | 0.8 |
| | 3.4 |
| | 0.8 |
|
| SWEPCo | | (6.3 | ) | | (1.4 | ) | | (7.4 | ) | | (1.4 | ) |
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 Moody’s, Standard and Poor’s,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 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. A counterparty is required 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-Risk-Related Contingent Features
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. AEP, APCo, I&M, PSO and SWEPCoThe 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 with a total exposure of $0 and $2 million as of March 31, 2023 and December 31, 2022, respectively. The RegistrantsRegistrant Subsidiaries had immaterialno derivative contracts with collateral triggering events in a net liability position as of September 30, 2017March 31, 2023 and December 31, 2016.2022.
Cross-Acceleration Triggers
Certain interest rate derivative contracts contain cross-acceleration provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-acceleration provisions could be triggered if there was a non-performance event by the Registrants under any of their outstanding debt of at least $50 million and the lender on that debt has accelerated the entire repayment obligation. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-acceleration provisions in contracts. AEP had derivative contracts with cross-acceleration provisions in a net liability position of $121 million and $127 million as of March 31, 2023 and December 31, 2022, respectively. There was no cash collateral posted as of March 31, 2023 and December 31, 2022, respectively. If a cross-acceleration provision would have been triggered, settlement at fair value would have been required. AEP Texas’ derivative contracts with cross-acceleration provisions in a net liability position were immaterial as of March 31, 2023 and AEP Texas had no derivative contracts with cross-acceleration provisions in a net liability as of December 31, 2022. The other Registrant Subsidiaries had no derivative contracts with cross-acceleration provisions outstanding as of March 31, 2023 and December 31, 2022.
Cross-Default Triggers (Applies to AEP, APCo, I&M, PSO and I&M)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 partythird-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 theseAEP had derivative liabilities subject to cross-default provisions prior to considerationin a net liability position of $193 million and $217 million as of March 31, 2023 and December 31, 2022, respectively, after considering contractual netting arrangements, (b) the amount that the exposure has been reduced byarrangements. There was no cash collateral posted as of March 31, 2023 and (c) ifDecember 31, 2022. If a cross-default provision would have been triggered, the settlement amount thatat fair value would be required after considering contractual netting arrangements:have been required. The Registrant Subsidiaries’ derivative contracts with cross-default provisions outstanding as of March 31, 2023 and December 31, 2022 were not material.
|
| | | | | | | | | | | | |
| | | September 30, 2017 |
| | | 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 | | $ | 285.9 |
| | $ | 2.5 |
| | $ | 274.4 |
|
| APCo | | — |
| | — |
| | — |
|
| I&M | | — |
| | — |
| | — |
|
|
| | | | | | | | | | | | |
| | | December 31, 2016 |
| | | 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 | | $ | 259.6 |
| | $ | 0.4 |
| | $ | 235.8 |
|
| APCo | | 0.1 |
| | — |
| | — |
|
| I&M | | 0.1 |
| | — |
| | — |
|
10. FAIR VALUE MEASUREMENTS
The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise.
Fair Value Hierarchy and Valuation Techniques
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 tradedexchange-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 contractsexchange-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 basednonmarket-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 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. The trustee uses multiple pricing vendors for the assets held in the trusts.
Assets in the 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 domestic 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 and cash equivalent funds.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.
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:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | March 31, 2023 | | December 31, 2022 |
| Company | | Book Value | | Fair Value | | Book Value | | Fair Value |
| | (in millions) |
| AEP (a) | | $ | 39,144.2 | | | $ | 36,126.4 | | | $ | 36,801.0 | | | $ | 32,915.9 | |
| AEP Texas | | 5,522.0 | | | 5,009.5 | | | 5,657.8 | | | 5,045.8 | |
| AEPTCo | | 5,472.1 | | | 4,836.2 | | | 4,782.8 | | | 3,940.5 | |
| APCo | | 5,398.7 | | | 5,227.7 | | | 5,410.5 | | | 5,079.2 | |
| I&M | | 3,489.0 | | | 3,249.1 | | | 3,260.8 | | | 2,929.0 | |
| OPCo | | 2,970.8 | | | 2,566.6 | | | 2,970.3 | | | 2,516.6 | |
| PSO | | 2,383.6 | | | 2,172.6 | | | 1,912.8 | | | 1,635.8 | |
| SWEPCo | | 3,644.8 | | | 3,195.9 | | | 3,391.6 | | | 2,870.9 | |
|
| | | | | | | | | | | | | | | | | | |
| | | September 30, 2017 | | December 31, 2016 | |
| Company | | Book Value | | Fair Value | | Book Value | | | Fair Value | |
| | | (in millions) | |
| AEP | | $ | 20,721.7 |
| | $ | 22,988.8 |
| | $ | 20,391.2 |
| (a) | | $ | 22,211.9 |
| (a) |
| AEPTCo | | 2,550.0 |
| | 2,720.8 |
| | 1,932.0 |
| | | 1,984.3 |
| |
| APCo | | 3,979.3 |
| | 4,721.3 |
| | 4,033.9 |
| | | 4,613.2 |
| |
| I&M | | 2,658.5 |
| | 2,898.7 |
| | 2,471.4 |
| | | 2,661.6 |
| |
| OPCo | | 1,718.9 |
| | 2,068.9 |
| | 1,763.9 |
| | | 2,092.5 |
| |
| PSO | | 1,286.4 |
| | 1,448.0 |
| | 1,286.0 |
| | | 1,419.0 |
| |
| SWEPCo | | 2,441.5 |
| | 2,620.7 |
| | 2,679.1 |
| | | 2,814.3 |
| |
(a)The fair value amounts include debt related to AEP’s Equity Units and had a fair value of $856 million and $877 million as of March 31, 2023 and December 31, 2022, respectively. See “Equity Units” section of Note 12 for additional information.
| |
(a) | Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million. See the Assets and Liabilities Held for Sale section of Note 6 for additional information. |
Fair Value Measurements of Other Temporary Investments and Restricted Cash (Applies to AEP)
Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS.
The following is a summary of Other Temporary Investments:Investments and Restricted Cash:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | March 31, 2023 |
| | | | Gross | | Gross | | |
| | | | Unrealized | | Unrealized | | Fair |
| Other Temporary Investments and Restricted Cash | | Cost | | Gains | | Losses | | Value |
| | (in millions) |
| Restricted Cash (a) | | $ | 50.0 | | | $ | — | | | $ | — | | | $ | 50.0 | |
| Other Cash Deposits | | 11.4 | | | — | | | — | | | 11.4 | |
| Fixed Income Securities – Mutual Funds (b) | | 153.4 | | | — | | | (7.2) | | | 146.2 | |
| Equity Securities – Mutual Funds | | 15.2 | | | 21.8 | | | — | | | 37.0 | |
| Total Other Temporary Investments and Restricted Cash | | $ | 230.0 | | | $ | 21.8 | | | $ | (7.2) | | | $ | 244.6 | |
| | | | | | | | | | | | December 31, 2022 |
| | | September 30, 2017 | | | Gross | | Gross | |
| | | | | Gross | | Gross | | | | Unrealized | | Unrealized | | Fair |
| | | | | Unrealized | | Unrealized | | Fair | |
| Other Temporary Investments | | Cost | | Gains | | Losses | | Value | |
| Other Temporary Investments and Restricted Cash | | Other Temporary Investments and Restricted Cash | | Cost | | Gains | | Losses | | Value |
| | | (in millions) | | | (in millions) |
| Restricted Cash (a) | | $ | 172.9 |
| | $ | — |
| | $ | — |
| | $ | 172.9 |
| Restricted Cash (a) | | $ | 47.1 | | | $ | — | | | $ | — | | | $ | 47.1 | |
| Other Cash Deposits | | Other Cash Deposits | | 9.0 | | | — | | | — | | | 9.0 | |
| Fixed Income Securities – Mutual Funds (b) | | 103.9 |
| | — |
| | (0.7 | ) | | 103.2 |
| Fixed Income Securities – Mutual Funds (b) | | 152.4 | | | — | | | (8.3) | | | 144.1 | |
Equity Securities – Mutual Funds | | 16.8 |
| | 17.8 |
| | — |
| | 34.6 |
| Equity Securities – Mutual Funds | | 15.1 | | | 19.4 | | | — | | | 34.5 | |
| Total Other Temporary Investments | | $ | 293.6 |
| | $ | 17.8 |
| | $ | (0.7 | ) | | $ | 310.7 |
| |
| Total Other Temporary Investments and Restricted Cash | | Total Other Temporary Investments and Restricted Cash | | $ | 223.6 | | | $ | 19.4 | | | $ | (8.3) | | | $ | 234.7 | |
|
| | | | | | | | | | | | | | | | |
| | | December 31, 2016 |
| | | | | Gross | | Gross | | |
| | | | | Unrealized | | Unrealized | | Fair |
| Other Temporary Investments | | Cost | | Gains | | Losses | | Value |
| | | (in millions) |
| Restricted Cash (a) | | $ | 211.7 |
| | $ | — |
| | $ | — |
| | $ | 211.7 |
|
Fixed Income Securities – Mutual Funds (b) | | 92.7 |
| | — |
| | (1.0 | ) | | 91.7 |
|
Equity Securities – Mutual Funds | | 14.4 |
| | 13.9 |
| | — |
| | 28.3 |
|
| Total Other Temporary Investments | | $ | 318.8 |
| | $ | 13.9 |
| | $ | (1.0 | ) | | $ | 331.7 |
|
| |
(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. |
(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:
| | | | | | | | | | | | | | | |
| | Three Months Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| (in millions) |
| Proceeds from Investment Sales | $ | — | | | $ | 3.9 | | | | | |
| Purchases of Investments | 1.0 | | | 0.8 | | | | | |
| Gross Realized Gains on Investment Sales | — | | | 0.3 | | | | | |
| Gross Realized Losses on Investment Sales | — | | | 0.1 | | | | | |
|
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) |
| Proceeds from Investment Sales | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Purchases of Investments | 12.6 |
| | 0.6 |
| | 13.6 |
| | 1.6 |
|
| Gross Realized Gains on Investment Sales | — |
| | — |
| | — |
| | — |
|
| Gross Realized Losses on Investment Sales | — |
| | — |
| | — |
| | — |
|
For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and nine months ended September 30, 2017 and 2016, see Note 3.
Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M)
Nuclear decommissioning and spent nuclear fuelSNF trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuelSNF 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 managers whomanager 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 both debt and equity 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.
The following is a summary of nuclear trust fund investments:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | March 31, 2023 | | December 31, 2022 |
| | | Gross | | Gross | | Other-Than- | | | | Gross | | Gross | | Other-Than- |
| Fair | | Unrealized | | Unrealized | | Temporary | | Fair | | Unrealized | | Unrealized | | Temporary |
| Value | | Gains | | Losses | | Impairments | | Value | | Gains | | Losses | | Impairments |
| (in millions) |
| Cash and Cash Equivalents | $ | 26.5 | | | $ | — | | | $ | — | | | $ | — | | | $ | 21.2 | | | $ | — | | | $ | — | | | $ | — | |
| Fixed Income Securities: | | | | | | | | | | | | | | | |
| United States Government | 1,207.6 | | | 20.9 | | | (6.4) | | | (28.3) | | | 1,123.8 | | | 11.8 | | | (14.9) | | | (18.8) | |
| Corporate Debt | 66.0 | | | 1.0 | | | (6.1) | | | (2.2) | | | 61.6 | | | 0.7 | | | (7.7) | | | (9.6) | |
| State and Local Government | 3.3 | | | — | | | — | | | — | | | 3.3 | | | 0.1 | | | — | | | (0.1) | |
| Subtotal Fixed Income Securities | 1,276.9 | | | 21.9 | | | (12.5) | | | (30.5) | | | 1,188.7 | | | 12.6 | | | (22.6) | | | (28.5) | |
| Equity Securities - Domestic | 2,197.7 | | | 1,565.1 | | | (2.9) | | | — | | | 2,131.3 | | | 1,483.7 | | | (6.4) | | | — | |
| Spent Nuclear Fuel and Decommissioning Trusts | $ | 3,501.1 | | | $ | 1,587.0 | | | $ | (15.4) | | | $ | (30.5) | | | $ | 3,341.2 | | | $ | 1,496.3 | | | $ | (29.0) | | | $ | (28.5) | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, 2017 | | December 31, 2016 |
| | | | Gross | | Other-Than- | | | | Gross | | Other-Than- |
| | Fair | | Unrealized | | Temporary | | Fair | | Unrealized | | Temporary |
| | Value | | Gains | | Impairments | | Value | | Gains | | Impairments |
| | (in millions) |
| Cash and Cash Equivalents | $ | 20.5 |
| | $ | — |
| | $ | — |
| | $ | 18.7 |
| | $ | — |
| | $ | — |
|
| Fixed Income Securities: | |
| | |
| | |
| | |
| | |
| | |
|
| United States Government | 974.3 |
| | 32.6 |
| | (1.9 | ) | | 785.4 |
| | 27.1 |
| | (5.5 | ) |
| Corporate Debt | 60.0 |
| | 3.5 |
| | (1.2 | ) | | 60.9 |
| | 2.3 |
| | (1.4 | ) |
| State and Local Government | 9.0 |
| | 1.0 |
| | (0.2 | ) | | 121.1 |
| | 0.4 |
| | (0.7 | ) |
| Subtotal Fixed Income Securities | 1,043.3 |
| | 37.1 |
| | (3.3 | ) | | 967.4 |
| | 29.8 |
| | (7.6 | ) |
| Equity Securities - Domestic | 1,369.2 |
| | 783.1 |
| | (75.4 | ) | | 1,270.1 |
| | 677.9 |
| | (79.6 | ) |
| Spent Nuclear Fuel and Decommissioning Trusts | $ | 2,433.0 |
| | $ | 820.2 |
| | $ | (78.7 | ) | | $ | 2,256.2 |
| | $ | 707.7 |
| | $ | (87.2 | ) |
The following table provides the securities activity within the decommissioning and SNF trusts:
| | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, | | |
| | | 2023 | | 2022 | | | | |
| | | (in millions) |
| Proceeds from Investment Sales | | $ | 517.6 | | | $ | 493.5 | | | | | |
| Purchases of Investments | | 536.3 | | | 507.7 | | | | | |
| Gross Realized Gains on Investment Sales | | 48.5 | | | 5.8 | | | | | |
| Gross Realized Losses on Investment Sales | | 8.6 | | | 7.2 | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| | | (in millions) |
| Proceeds from Investment Sales | | $ | 519.5 |
| | $ | 650.0 |
| | $ | 1,808.6 |
| | $ | 2,427.0 |
|
| Purchases of Investments | | 525.0 |
| | 656.5 |
| | 1,842.2 |
| | 2,452.9 |
|
| Gross Realized Gains on Investment Sales | | 9.8 |
| | 13.9 |
| | 198.1 |
| | 41.9 |
|
| Gross Realized Losses on Investment Sales | | 5.2 |
| | 6.5 |
| | 145.4 |
| | 22.2 |
|
The base cost of fixed income securities was $1$1.3 billion and $938 million$1.2 billion as of September 30, 2017March 31, 2023 and December 31, 2016,2022, respectively. The base cost of equity securities was $586$635 million and $592$654 million as of September 30, 2017March 31, 2023 and December 31, 2016,2022, respectively.
The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2017March 31, 2023 was as follows:
| | | | | |
| Fair Value of Fixed |
| Income Securities |
| (in millions) |
| Within 1 year | $ | 347.8 | |
| After 1 year through 5 years | 489.1 | |
| After 5 years through 10 years | 215.6 | |
| After 10 years | 224.4 | |
| Total | $ | 1,276.9 | |
|
| | | |
| | Fair Value of Fixed Income Securities |
| | (in millions) |
| Within 1 year | $ | 403.6 |
|
| After 1 year through 5 years | 287.9 |
|
| After 5 years through 10 years | 184.2 |
|
| After 10 years | 167.6 |
|
| Total | $ | 1,043.3 |
|
Fair Value Measurements of Financial Assets and Liabilities
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
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2017March 31, 2023
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Other Temporary Investments and Restricted Cash | | | | | | | | | | |
| Restricted Cash | | $ | 50.0 | | | $ | — | | | $ | — | | | $ | — | | | $ | 50.0 | |
| Other Cash Deposits (a) | | — | | | — | | | — | | | 11.4 | | | 11.4 | |
| Fixed Income Securities – Mutual Funds | | 146.2 | | | — | | | — | | | — | | | 146.2 | |
| Equity Securities – Mutual Funds (b) | | 37.0 | | | — | | | — | | | — | | | 37.0 | |
| Total Other Temporary Investments and Restricted Cash | | 233.2 | | | — | | | — | | | 11.4 | | | 244.6 | |
| | | | | | | | | | |
| Risk Management Assets | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (d) | | 13.0 | | | 861.2 | | | 209.2 | | | (720.2) | | | 363.2 | |
| Cash Flow Hedges: | | | | | | | | | | |
| Commodity Hedges (c) | | — | | | 177.8 | | | 20.3 | | | (61.4) | | | 136.7 | |
| Interest Rate Hedges | | — | | | 8.9 | | | — | | | — | | | 8.9 | |
| | | | | | | | | | |
| Total Risk Management Assets | | 13.0 | | | 1,047.9 | | | 229.5 | | | (781.6) | | | 508.8 | |
| | | | | | | | | | |
| Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | |
| Cash and Cash Equivalents (e) | | 17.1 | | | — | | | — | | | 9.4 | | | 26.5 | |
| Fixed Income Securities: | | | | | | | | | | |
| United States Government | | — | | | 1,207.6 | | | — | | | — | | | 1,207.6 | |
| Corporate Debt | | — | | | 66.0 | | | — | | | — | | | 66.0 | |
| State and Local Government | | — | | | 3.3 | | | — | | | — | | | 3.3 | |
| Subtotal Fixed Income Securities | | — | | | 1,276.9 | | | — | | | — | | | 1,276.9 | |
| Equity Securities – Domestic (b) | | 2,197.7 | | | — | | | — | | | — | | | 2,197.7 | |
| Total Spent Nuclear Fuel and Decommissioning Trusts | | 2,214.8 | | | 1,276.9 | | | — | | | 9.4 | | | 3,501.1 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Total Assets | | $ | 2,461.0 | | | $ | 2,324.8 | | | $ | 229.5 | | | $ | (760.8) | | | $ | 4,254.5 | |
| | | | | | | | | | |
| Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
| Risk Management Liabilities | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (d) | | $ | 33.5 | | | $ | 721.1 | | | $ | 178.5 | | | $ | (627.5) | | | $ | 305.6 | |
| Cash Flow Hedges: | | | | | | | | | | |
| Commodity Hedges (c) | | — | | | 109.1 | | | 5.9 | | | (61.4) | | | 53.6 | |
| Interest Rate Hedges | | — | | | 1.7 | | | — | | | — | | | 1.7 | |
| Fair Value Hedges | | — | | | 120.5 | | | — | | | — | | | 120.5 | |
| Total Risk Management Liabilities | | $ | 33.5 | | | $ | 952.4 | | | $ | 184.4 | | | $ | (688.9) | | | $ | 481.4 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
| | | | | | | | | | | |
| Cash and Cash Equivalents (a) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 343.9 |
| | $ | 343.9 |
|
| | | | | | | | | | | |
| Other Temporary Investments | | | | | | | | | | |
| Restricted Cash (a) | | 158.6 |
| | 1.4 |
| | — |
| | 12.9 |
| | 172.9 |
|
Fixed Income Securities – Mutual Funds | | 103.2 |
| | — |
| | — |
| | — |
| | 103.2 |
|
Equity Securities – Mutual Funds (b) | | 34.6 |
| | — |
| | — |
| | — |
| | 34.6 |
|
Total Other Temporary Investments | | 296.4 |
| | 1.4 |
| | — |
| | 12.9 |
| | 310.7 |
|
| | | | | | | | | | | |
| Risk Management Assets | | |
| | |
| | |
| | |
| | |
|
| Risk Management Commodity Contracts (c) (d) | | 1.2 |
| | 307.9 |
| | 300.3 |
| | (161.4 | ) | | 448.0 |
|
| Cash Flow Hedges: | | |
| | |
| | |
| | |
| | |
|
| Commodity Hedges (c) | | — |
| | 9.1 |
| | 1.3 |
| | (6.1 | ) | | 4.3 |
|
| Interest Rate/Foreign Currency Hedges | | — |
| | 4.2 |
| | — |
| | — |
| | 4.2 |
|
| Total Risk Management Assets | | 1.2 |
| | 321.2 |
| | 301.6 |
| | (167.5 | ) | | 456.5 |
|
| | | | | | | | | | | |
| Spent Nuclear Fuel and Decommissioning Trusts | | |
| | |
| | |
| | |
| | |
|
| Cash and Cash Equivalents (e) | | 14.0 |
| | — |
| | — |
| | 6.5 |
| | 20.5 |
|
| Fixed Income Securities: | | |
| | |
| | |
| | |
| | |
|
| United States Government | | — |
| | 974.3 |
| | — |
| | — |
| | 974.3 |
|
| Corporate Debt | | — |
| | 60.0 |
| | — |
| | — |
| | 60.0 |
|
| State and Local Government | | — |
| | 9.0 |
| | — |
| | — |
| | 9.0 |
|
| Subtotal Fixed Income Securities | | — |
| | 1,043.3 |
| | — |
| | — |
| | 1,043.3 |
|
Equity Securities – Domestic (b) | | 1,369.2 |
| | — |
| | — |
| | — |
| | 1,369.2 |
|
Total Spent Nuclear Fuel and Decommissioning Trusts | | 1,383.2 |
| | 1,043.3 |
| | — |
| | 6.5 |
| | 2,433.0 |
|
| | | | | | | | | | | |
| Total Assets | | $ | 1,680.8 |
| | $ | 1,365.9 |
| | $ | 301.6 |
| | $ | 195.8 |
| | $ | 3,544.1 |
|
| | | | | | | | | | | |
| Liabilities: | | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | | |
| Risk Management Liabilities | | |
| | |
| | |
| | |
| | |
|
| Risk Management Commodity Contracts (c) (d) | | $ | 3.2 |
| | $ | 306.6 |
| | $ | 205.9 |
| | $ | (174.9 | ) | | $ | 340.8 |
|
| Cash Flow Hedges: | | |
| | |
| | |
| | |
| | |
|
| Commodity Hedges (c) | | — |
| | 35.3 |
| | 50.7 |
| | (6.1 | ) | | 79.9 |
|
| Fair Value Hedges | | — |
| | 1.4 |
| | — |
| | — |
| | 1.4 |
|
| Total Risk Management Liabilities | | $ | 3.2 |
| | $ | 343.3 |
| | $ | 256.6 |
| | $ | (181.0 | ) | | $ | 422.1 |
|
AEP
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 20162022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Other Temporary Investments and Restricted Cash | | | | | | | | | | |
| Restricted Cash | | $ | 47.1 | | | $ | — | | | $ | — | | | $ | — | | | $ | 47.1 | |
| Other Cash Deposits (a) | | — | | | — | | | — | | | 9.0 | | | 9.0 | |
| Fixed Income Securities – Mutual Funds | | 144.1 | | | — | | | — | | | — | | | 144.1 | |
| Equity Securities – Mutual Funds (b) | | 34.5 | | | — | | | — | | | — | | | 34.5 | |
| Total Other Temporary Investments and Restricted Cash | | 225.7 | | | — | | | — | | | 9.0 | | | 234.7 | |
| | | | | | | | | | |
| Risk Management Assets | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (f) | | 15.0 | | | 1,197.5 | | | 314.4 | | | (1,211.5) | | | 315.4 | |
| Cash Flow Hedges: | | | | | | | | | | |
| Commodity Hedges (c) | | — | | | 332.6 | | | 26.7 | | | (52.8) | | | 306.5 | |
| Interest Rate Hedges | | — | | | 11.0 | | | — | | | — | | | 11.0 | |
| | | | | | | | | | |
| Total Risk Management Assets | | 15.0 | | | 1,541.1 | | | 341.1 | | | (1,264.3) | | | 632.9 | |
| | | | | | | | | | |
| Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | |
| Cash and Cash Equivalents (e) | | 11.3 | | | — | | | — | | | 9.9 | | | 21.2 | |
| Fixed Income Securities: | | | | | | | | | | |
| United States Government | | — | | | 1,123.8 | | | — | | | — | | | 1,123.8 | |
| Corporate Debt | | — | | | 61.6 | | | — | | | — | | | 61.6 | |
| State and Local Government | | — | | | 3.3 | | | — | | | — | | | 3.3 | |
| Subtotal Fixed Income Securities | | — | | | 1,188.7 | | | — | | | — | | | 1,188.7 | |
| Equity Securities – Domestic (b) | | 2,131.3 | | | — | | | — | | | — | | | 2,131.3 | |
| Total Spent Nuclear Fuel and Decommissioning Trusts | | 2,142.6 | | | 1,188.7 | | | — | | | 9.9 | | | 3,341.2 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Total Assets | | $ | 2,383.3 | | | $ | 2,729.8 | | | $ | 341.1 | | | $ | (1,245.4) | | | $ | 4,208.8 | |
| | | | | | | | | | |
| Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
| Risk Management Liabilities | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (f) | | $ | 21.8 | | | $ | 870.9 | | | $ | 179.0 | | | $ | (731.9) | | | $ | 339.8 | |
| Cash Flow Hedges: | | | | | | | | | | |
| Commodity Hedges (c) | | — | | | 74.3 | | | 1.7 | | | (52.8) | | | 23.2 | |
| | | | | | | | | | |
| Fair Value Hedges | | — | | | 127.4 | | | — | | | — | | | 127.4 | |
| Total Risk Management Liabilities | | $ | 21.8 | | | $ | 1,072.6 | | | $ | 180.7 | | | $ | (784.7) | | | $ | 490.4 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
| | | | | | | | | | | |
| Cash and Cash Equivalents (a) | | $ | 8.7 |
| | $ | — |
| | $ | — |
| | $ | 201.8 |
| | $ | 210.5 |
|
| | | | | | | | | | | |
| Other Temporary Investments | | | | | | | | | | |
| Restricted Cash (a) | | 173.8 |
| | 5.1 |
| | — |
| | 32.8 |
| | 211.7 |
|
Fixed Income Securities – Mutual Funds | | 91.7 |
| | — |
| | — |
| | — |
| | 91.7 |
|
Equity Securities – Mutual Funds (b) | | 28.3 |
| | — |
| | — |
| | — |
| | 28.3 |
|
Total Other Temporary Investments | | 293.8 |
| | 5.1 |
| | — |
| | 32.8 |
| | 331.7 |
|
| | | | | | | | | | | |
| Risk Management Assets | | |
| | |
| | |
| | |
| | |
|
| Risk Management Commodity Contracts (c) (f) | | 6.0 |
| | 379.9 |
| | 192.2 |
| | (205.7 | ) | | 372.4 |
|
| Cash Flow Hedges: | | |
| | |
| | |
| | |
| | |
|
| Commodity Hedges (c) | | — |
| | 16.8 |
| | 1.7 |
| | (7.3 | ) | | 11.2 |
|
| Total Risk Management Assets | | 6.0 |
| | 396.7 |
| | 193.9 |
| | (213.0 | ) | | 383.6 |
|
| | | | | | | | | | | |
| Spent Nuclear Fuel and Decommissioning Trusts | | |
| | |
| | |
| | |
| | |
|
| Cash and Cash Equivalents (e) | | 7.3 |
| | — |
| | — |
| | 11.4 |
| | 18.7 |
|
| Fixed Income Securities: | | |
| | |
| | |
| | |
| | |
|
| United States Government | | — |
| | 785.4 |
| | — |
| | — |
| | 785.4 |
|
| Corporate Debt | | — |
| | 60.9 |
| | — |
| | — |
| | 60.9 |
|
| State and Local Government | | — |
| | 121.1 |
| | — |
| | — |
| | 121.1 |
|
| Subtotal Fixed Income Securities | | — |
| | 967.4 |
| | — |
| | — |
| | 967.4 |
|
Equity Securities – Domestic (b) | | 1,270.1 |
| | — |
| | — |
| | — |
| | 1,270.1 |
|
Total Spent Nuclear Fuel and Decommissioning Trusts | | 1,277.4 |
| | 967.4 |
| | — |
| | 11.4 |
| | 2,256.2 |
|
| | | | | | | | | | | |
| Total Assets | | $ | 1,585.9 |
| | $ | 1,369.2 |
| | $ | 193.9 |
| | $ | 33.0 |
| | $ | 3,182.0 |
|
| | | | | | | | | | | |
| Liabilities: | | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | | |
| Risk Management Liabilities | | |
| | |
| | |
| | |
| | |
|
| Risk Management Commodity Contracts (c) (f) | | $ | 8.2 |
| | $ | 352.0 |
| | $ | 166.7 |
| | $ | (205.4 | ) | | $ | 321.5 |
|
| Cash Flow Hedges: | | |
| | |
| | |
| | |
| | |
|
| Commodity Hedges (c) | | — |
| | 29.3 |
| | 24.7 |
| | (7.3 | ) | | 46.7 |
|
| Fair Value Hedges | | — |
| | 1.4 |
| | — |
| | — |
| | 1.4 |
|
| Total Risk Management Liabilities | | $ | 8.2 |
| | $ | 382.7 |
| | $ | 191.4 |
| | $ | (212.7 | ) | | $ | 369.6 |
|
APCo
AEP Texas
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2017March 31, 2023
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
| | | | | | | | | | |
| Restricted Cash for Securitized Funding | | $ | 42.5 | | | $ | — | | | $ | — | | | $ | — | | | $ | 42.5 | |
| | | | | | | | | | |
| Risk Management Assets | | | | | | | | | | |
| | | | | | | | | | |
| Cash Flow Hedges: | | | | | | | | | | |
| Interest Rate Hedges | | — | | | 0.5 | | | — | | | — | | | 0.5 | |
| | | | | | | | | | |
| | | | | | | | | | |
| Total Assets | | $ | 42.5 | | | $ | 0.5 | | | $ | — | | | $ | — | | | $ | 43.0 | |
| | | | | | | | | | |
| Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
| Risk Management Liabilities | | | | | | | | | | |
| Risk Management Commodity Contracts (c) | | $ | — | | | $ | 0.4 | | | $ | — | | | $ | (0.4) | | | $ | — | |
| Cash Flow Hedges: | | | | | | | | | | |
| Interest Rate Hedges | | — | | | 0.8 | | | — | | | — | | | 0.8 | |
| | | | | | | | | | |
| | | | | | | | | | |
| Total Liabilities | | $ | — | | | $ | 1.2 | | | $ | — | | | $ | (0.4) | | | $ | 0.8 | |
| | | | | | | | | | |
December 31, 2022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
| | | | | | | | | | |
| Restricted Cash for Securitized Funding | | $ | 32.7 | | | $ | — | | | $ | — | | | $ | — | | | $ | 32.7 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
| | | | | | | | | | | |
| Restricted Cash for Securitized Funding (a) | | $ | 8.3 |
| | $ | — |
| | $ | — |
| | $ | 0.1 |
| | $ | 8.4 |
|
| | | | | | | | | | | |
| Risk Management Assets | | |
| | |
| | |
| | |
| | |
|
| Risk Management Commodity Contracts (c) (g) | | — |
| | 22.2 |
| | 30.0 |
| | (21.3 | ) | | 30.9 |
|
| | | | | | | | | | | |
| Total Assets | | $ | 8.3 |
| | $ | 22.2 |
| | $ | 30.0 |
| | $ | (21.2 | ) | | $ | 39.3 |
|
| | | | | | | | | | | |
| Liabilities: | | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | | |
| Risk Management Liabilities | | |
| | |
| | |
| | |
| | |
|
| Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | 21.8 |
| | $ | 0.6 |
| | $ | (21.2 | ) | | $ | 1.2 |
|
APCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 2023
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
| | | | | | | | | | |
| Restricted Cash for Securitized Funding | | $ | 7.5 | | | $ | — | | | $ | — | | | $ | — | | | $ | 7.5 | |
| | | | | | | | | | |
| Risk Management Assets | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (g) | | — | | | 0.4 | | | 12.4 | | | (0.4) | | | 12.4 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Total Assets | | $ | 7.5 | | | $ | 0.4 | | | $ | 12.4 | | | $ | (0.4) | | | $ | 19.9 | |
| | | | | | | | | | |
| Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
| Risk Management Liabilities | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.9 | | | $ | 6.7 | | | $ | (0.6) | | | $ | 7.0 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
December 31, 20162022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
| | | | | | | | | | |
| Restricted Cash for Securitized Funding | | $ | 14.4 | | | $ | — | | | $ | — | | | $ | — | | | $ | 14.4 | |
| | | | | | | | | | |
| Risk Management Assets | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (g) | | — | | | 0.7 | | | 69.4 | | | (1.0) | | | 69.1 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Total Assets | | $ | 14.4 | | | $ | 0.7 | | | $ | 69.4 | | | $ | (1.0) | | | $ | 83.5 | |
| | | | | | | | | | |
| Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
| Risk Management Liabilities | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 4.6 | | | $ | 0.3 | | | $ | (1.4) | | | $ | 3.5 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
| | | | | | | | | | | |
| Restricted Cash for Securitized Funding (a) | | $ | 15.8 |
| | $ | — |
| | $ | — |
| | $ | 0.1 |
| | $ | 15.9 |
|
| | | | | | | | | | | |
| Risk Management Assets | | |
| | |
| | |
| | |
| | |
|
| Risk Management Commodity Contracts (c) (g) | | — |
| | 20.5 |
| | 3.9 |
| | (21.8 | ) | | 2.6 |
|
| | | | | | | | | | | |
| Total Assets | | $ | 15.8 |
| | $ | 20.5 |
| | $ | 3.9 |
| | $ | (21.7 | ) | | $ | 18.5 |
|
| | | | | | | | | | | |
| Liabilities: | | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | | |
| Risk Management Liabilities | | |
| | |
| | |
| | |
| | |
|
| Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | 20.7 |
| | $ | 2.5 |
| | $ | (22.0 | ) | | $ | 1.2 |
|
I&M
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2017March 31, 2023
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
| | | | | | | | | | |
| Risk Management Assets | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 6.6 | | | $ | 1.6 | | | $ | (1.2) | | | $ | 7.0 | |
| | | | | | | | | | |
| Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | |
| Cash and Cash Equivalents (e) | | 17.1 | | | — | | | — | | | 9.4 | | | 26.5 | |
| Fixed Income Securities: | | | | | | | | | | |
| United States Government | | — | | | 1,207.6 | | | — | | | — | | | 1,207.6 | |
| Corporate Debt | | — | | | 66.0 | | | — | | | — | | | 66.0 | |
| State and Local Government | | — | | | 3.3 | | | — | | | — | | | 3.3 | |
| Subtotal Fixed Income Securities | | — | | | 1,276.9 | | | — | | | — | | | 1,276.9 | |
| Equity Securities - Domestic (b) | | 2,197.7 | | | — | | | — | | | — | | | 2,197.7 | |
| Total Spent Nuclear Fuel and Decommissioning Trusts | | 2,214.8 | | | 1,276.9 | | | — | | | 9.4 | | | 3,501.1 | |
| | | | | | | | | | |
| Total Assets | | $ | 2,214.8 | | | $ | 1,283.5 | | | $ | 1.6 | | | $ | 8.2 | | | $ | 3,508.1 | |
| | | | | | | | | | |
| Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
| Risk Management Liabilities | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 1.3 | | | $ | 0.5 | | | $ | (1.4) | | | $ | 0.4 | |
December 31, 2022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
| | | | | | | | | | |
| Risk Management Assets | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 11.3 | | | $ | 5.3 | | | $ | (1.2) | | | $ | 15.4 | |
| | | | | | | | | | |
| Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | |
| Cash and Cash Equivalents (e) | | 11.3 | | | — | | | — | | | 9.9 | | | 21.2 | |
| Fixed Income Securities: | | | | | | | | | | |
| United States Government | | — | | | 1,123.8 | | | — | | | — | | | 1,123.8 | |
| Corporate Debt | | — | | | 61.6 | | | — | | | — | | | 61.6 | |
| State and Local Government | | — | | | 3.3 | | | — | | | — | | | 3.3 | |
| Subtotal Fixed Income Securities | | — | | | 1,188.7 | | | — | | | — | | | 1,188.7 | |
| Equity Securities - Domestic (b) | | 2,131.3 | | | — | | | — | | | — | | | 2,131.3 | |
| Total Spent Nuclear Fuel and Decommissioning Trusts | | 2,142.6 | | | 1,188.7 | | | — | | | 9.9 | | | 3,341.2 | |
| | | | | | | | | | |
| Total Assets | | $ | 2,142.6 | | | $ | 1,200.0 | | | $ | 5.3 | | | $ | 8.7 | | | $ | 3,356.6 | |
| | | | | | | | | | |
| Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
| Risk Management Liabilities | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.6 | | | $ | 0.7 | | | $ | (1.3) | | | $ | — | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
| | | | | | | | | | | |
| Risk Management Assets | | |
| | |
| | |
| | |
| | |
|
| Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | 16.3 |
| | $ | 12.4 |
| | $ | (16.6 | ) | | $ | 12.1 |
|
| | | | | | | | | | | |
| Spent Nuclear Fuel and Decommissioning Trusts | | |
| | |
| | |
| | |
| | |
|
| Cash and Cash Equivalents (e) | | 14.0 |
| | — |
| | — |
| | 6.5 |
| | 20.5 |
|
| Fixed Income Securities: | | |
| | |
| | |
| | |
| | |
|
| United States Government | | — |
| | 974.3 |
| | — |
| | — |
| | 974.3 |
|
| Corporate Debt | | — |
| | 60.0 |
| | — |
| | — |
| | 60.0 |
|
| State and Local Government | | — |
| | 9.0 |
| | — |
| | — |
| | 9.0 |
|
| Subtotal Fixed Income Securities | | — |
| | 1,043.3 |
| | — |
| | — |
| | 1,043.3 |
|
| Equity Securities - Domestic (b) | | 1,369.2 |
| | — |
| | — |
| | — |
| | 1,369.2 |
|
Total Spent Nuclear Fuel and Decommissioning Trusts | | 1,383.2 |
| | 1,043.3 |
| | — |
| | 6.5 |
| | 2,433.0 |
|
| | | | | | | | | | | |
| Total Assets | | $ | 1,383.2 |
| | $ | 1,059.6 |
| | $ | 12.4 |
| | $ | (10.1 | ) | | $ | 2,445.1 |
|
| | | | | | | | | | | |
| Liabilities: | | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | | |
| Risk Management Liabilities | | |
| | |
| | |
| | |
| | |
|
| Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | 16.4 |
| | $ | 2.2 |
| | $ | (16.4 | ) | | $ | 2.2 |
|
I&M
OPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 2023
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Risk Management Assets | | | | | | | | | | |
| Risk Management Commodity Contracts (g) | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Liabilities: | | |
| | | | | | | | | | |
| Risk Management Liabilities | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.2 | | | $ | 46.9 | | | $ | (0.2) | | | $ | 46.9 | |
December 31, 20162022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Risk Management Assets | | | | | | | | | | |
| Risk Management Commodity Contracts (g) | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Liabilities: | | |
| | | | | | | | | | |
| Risk Management Liabilities | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | — | | | $ | 40.0 | | | $ | (0.3) | | | $ | 39.7 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
| | | | | | | | | | | |
| Risk Management Assets | | |
| | |
| | |
| | |
| | |
|
| Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | 12.8 |
| | $ | 3.0 |
| | $ | (12.3 | ) | | $ | 3.5 |
|
| | | | | | | | | | | |
| Spent Nuclear Fuel and Decommissioning Trusts | | |
| | |
| | |
| | |
| | |
|
| Cash and Cash Equivalents (e) | | 7.3 |
| | — |
| | — |
| | 11.4 |
| | 18.7 |
|
| Fixed Income Securities: | | |
| | |
| | |
| | |
| |
|
|
| United States Government | | — |
| | 785.4 |
| | — |
| | — |
| | 785.4 |
|
| Corporate Debt | | — |
| | 60.9 |
| | — |
| | — |
| | 60.9 |
|
| State and Local Government | | — |
| | 121.1 |
| | — |
| | — |
| | 121.1 |
|
| Subtotal Fixed Income Securities | | — |
| | 967.4 |
| | — |
| | — |
| | 967.4 |
|
| Equity Securities - Domestic (b) | | 1,270.1 |
| | — |
| | — |
| | — |
| | 1,270.1 |
|
Total Spent Nuclear Fuel and Decommissioning Trusts | | 1,277.4 |
| | 967.4 |
| | — |
| | 11.4 |
| | 2,256.2 |
|
| | | | | | | | | | | |
| Total Assets | | $ | 1,277.4 |
| | $ | 980.2 |
| | $ | 3.0 |
| | $ | (0.9 | ) | | $ | 2,259.7 |
|
| | | | | | | | | | | |
| Liabilities: | | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | | |
| Risk Management Liabilities | | |
| | |
| | |
| | |
| | |
|
| Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | 13.3 |
| | $ | 0.2 |
| | $ | (12.4 | ) | | $ | 1.1 |
|
OPCo
PSO
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2017March 31, 2023
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
| | | | | | | | | | |
| Risk Management Assets | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | — | | | $ | 9.9 | | | $ | (0.5) | | | $ | 9.4 | |
| | | | | | | | | | |
| Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
| Risk Management Liabilities | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 1.2 | | | $ | 0.6 | | | $ | (0.7) | | | $ | 1.1 | |
December 31, 2022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
| | | | | | | | | | |
| Risk Management Assets | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | — | | | $ | 24.0 | | | $ | 1.3 | | | $ | 25.3 | |
| Cash Flow Hedges: | | | | | | | | | | |
| Interest Rate Hedges | | — | | | 1.6 | | | — | | | (1.6) | | | — | |
| Total Assets | | $ | — | | | $ | 1.6 | | | $ | 24.0 | | | $ | (0.3) | | | $ | 25.3 | |
| | | | | | | | | | |
| Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
| Risk Management Liabilities | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 1.7 | | | $ | 0.3 | | | $ | (0.4) | | | $ | 1.6 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
| | | | | | | | | | | |
| Restricted Cash for Securitized Funding (a) | | $ | 15.6 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 15.6 |
|
| | | | | | | | | | | |
| Risk Management Assets | | |
| | |
| | |
| | |
| | |
|
| Risk Management Commodity Contracts (c) (g) | | — |
| | 0.3 |
| | — |
| | (0.1 | ) | | 0.2 |
|
| | | | | | | | | | | |
| Total Assets | | $ | 15.6 |
| | $ | 0.3 |
| | $ | — |
| | $ | (0.1 | ) | | $ | 15.8 |
|
| | | | | | | | | | | |
| Liabilities: | | | | | | | | | | |
| | | | | | | | | | | |
| Risk Management Liabilities | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | — |
| | $ | 138.5 |
| | $ | — |
| | $ | 138.5 |
|
OPCo
SWEPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 2023
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| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
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| Risk Management Assets | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | — | | | $ | 6.4 | | | $ | (0.1) | | | $ | 6.3 | |
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| Liabilities: | | | | | | | | | | |
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| Risk Management Liabilities | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.8 | | | $ | 0.6 | | | $ | (0.3) | | | $ | 1.1 | |
December 31, 20162022
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| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
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| Risk Management Assets | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 2.2 | | | $ | 14.6 | | | $ | (0.4) | | | $ | 16.4 | |
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| Liabilities: | | | | | | | | | | |
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| Risk Management Liabilities | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 1.6 | | | $ | 0.4 | | | $ | (0.6) | | | $ | 1.4 | |
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| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
| | | | | | | | | | | |
| Restricted Cash for Securitized Funding (a) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 27.2 |
| | $ | 27.2 |
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| Risk Management Assets | | |
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| Risk Management Commodity Contracts (c) (g) | | — |
| | 0.4 |
| | — |
| | (0.2 | ) | | 0.2 |
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| Total Assets | | $ | — |
| | $ | 0.4 |
| | $ | — |
| | $ | 27.0 |
| | $ | 27.4 |
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| Liabilities: | | |
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| Risk Management Liabilities | | |
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| Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | — |
| | $ | 119.0 |
| | $ | — |
| | $ | 119.0 |
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PSO
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2017
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| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
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| Risk Management Assets | | |
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| Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | — |
| | $ | 4.8 |
| | $ | (0.1 | ) | | $ | 4.7 |
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| Liabilities: | | |
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| Risk Management Liabilities | | |
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| | |
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| Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | — |
| | $ | 0.1 |
| | $ | (0.1 | ) | | $ | — |
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PSO
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2016
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| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
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| Risk Management Assets | | |
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| Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | 0.2 |
| | $ | 0.7 |
| | $ | (0.1 | ) | | $ | 0.8 |
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SWEPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2017
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| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
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| Cash and Cash Equivalents (a) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2.2 |
| | $ | 2.2 |
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| Risk Management Assets | | |
| | |
| | |
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| Risk Management Commodity Contracts (c) (g) | | — |
| | 0.1 |
| | 13.3 |
| | (0.2 | ) | | 13.2 |
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| Total Assets | | $ | — |
| | $ | 0.1 |
| | $ | 13.3 |
| | $ | 2.0 |
| | $ | 15.4 |
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| Liabilities: | | |
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| Risk Management Liabilities | | |
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| Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | 0.1 |
| | $ | 0.2 |
| | $ | (0.2 | ) | | $ | 0.1 |
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SWEPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2016
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| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | | (in millions) |
| | | | | | | | | | | |
| Cash and Cash Equivalents (a) | | $ | 8.7 |
| | $ | — |
| | $ | — |
| | $ | 1.6 |
| | $ | 10.3 |
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| Risk Management Assets | | |
| | |
| | |
| | |
| | |
|
| Risk Management Commodity Contracts (c) (g) | | — |
| | 0.3 |
| | 0.8 |
| | (0.2 | ) | | 0.9 |
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| Total Assets | | $ | 8.7 |
| | $ | 0.3 |
| | $ | 0.8 |
| | $ | 1.4 |
| | $ | 11.2 |
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| Liabilities: | | |
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| Risk Management Liabilities | | |
| | |
| | |
| | |
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| Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | 0.3 |
| | $ | 0.1 |
| | $ | (0.1 | ) | | $ | 0.3 |
|
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(a) | Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. |
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(b) | Amounts represent publicly traded equity securities and equity-based mutual funds. |
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(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.’’ |
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(d) | The September 30, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in periods 2018-2020; Level 2 matures $(1) million in 2017 and $3 million in periods 2018-2020 and $(1) million in periods 2021-2022; Level 3 matures $23 million in 2017, $77 million in periods 2018-2020, $16 million in periods 2021-2022 and $(21) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. |
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(e) | Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. |
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(f) | The December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in periods 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. |
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(g) | Substantially comprised of power contracts for the Registrant Subsidiaries. |
There were no transfers between(a)Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or third-parties. Level 1 and Level 2 duringamounts 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 threeaccounting guidance for “Derivatives and nine months ended September 30, 2017Hedging.’’
(d)The March 31, 2023 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $(14) million in 2023 and 2016.$(6) million in periods 2024-2026; Level 2 matures $24 million in 2023, $105 million in periods 2024-2026, $9 million in periods 2027-2028 and $1 million in periods 2029-2033; Level 3 matures $18 million in 2023, $9 million in periods 2024-2026, $11 million in periods 2027-2028 and $(7) million in periods 2029-2033. 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, 2022 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $(7) million in 2023; Level 2 matures $182 million in 2023, $134 million in periods 2024-2026, $10 million in periods 2027-2028 and $1 million in periods 2029-2033; Level 3 matures $128 million in 2023, $6 million in periods 2024-2026, $6 million in periods 2027-2028 and $(5) million in periods 2029-2033. Risk management commodity contracts are substantially comprised of power contracts.
(g)Substantially comprised of power contracts for the Registrant Subsidiaries.
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:
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| Three Months Ended March 31, 2023 | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in millions) |
| Balance as of December 31, 2022 | | $ | 160.4 | | | $ | 69.1 | | | $ | 4.6 | | | $ | (40.0) | | | $ | 23.7 | | | $ | 14.2 | |
| Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | (7.1) | | | (31.9) | | | 1.2 | | | (1.3) | | | 16.6 | | | 12.9 | |
| Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | 14.8 | | | — | | | — | | | — | | | — | | | — | |
| Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) | | (13.9) | | | — | | | — | | | — | | | — | | | — | |
| Settlements | | (96.6) | | | (27.3) | | | (4.2) | | | 1.0 | | | (34.3) | | | (23.0) | |
| Transfers into Level 3 (d) (e) | | (6.1) | | | — | | | — | | | — | | | — | | | — | |
| Transfers out of Level 3 (e) | | 1.0 | | | — | | | — | | | — | | | — | | | — | |
| Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | (7.4) | | | (4.2) | | | (0.5) | | | (6.6) | | | 3.3 | | | 1.7 | |
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| Balance as of March 31, 2023 | | $ | 45.1 | | | $ | 5.7 | | | $ | 1.1 | | | $ | (46.9) | | | $ | 9.3 | | | $ | 5.8 | |
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| Three Months Ended March 31, 2022 | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in millions) |
| Balance as of December 31, 2021 | | $ | 103.1 | | | $ | 41.7 | | | $ | (0.7) | | | $ | (92.5) | | | $ | 12.1 | | | $ | 10.9 | |
| Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | 18.2 | | | (2.9) | | | 3.8 | | | 0.5 | | | 12.1 | | | 9.8 | |
| Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | (19.0) | | | — | | | — | | | — | | | — | | | — | |
| Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) | | 19.3 | | | — | | | — | | | — | | | — | | | — | |
| Settlements | | (51.6) | | | (32.4) | | | (2.3) | | | 1.4 | | | (19.8) | | | (16.2) | |
| Transfers into Level 3 (d) (e) | | 2.5 | | | — | | | — | | | — | | | — | | | — | |
| Transfers out of Level 3 (e) | | 2.9 | | | — | | | — | | | — | | | — | | | — | |
| Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | 7.4 | | | 0.2 | | | 0.2 | | | 22.1 | | | 2.1 | | | 11.2 | |
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| Balance as of March 31, 2022 | | $ | 82.8 | | | $ | 6.6 | | | $ | 1.0 | | | $ | (68.5) | | | $ | 6.5 | | | $ | 15.7 | |
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| Three Months Ended September 30, 2017 | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in millions) |
| Balance as of June 30, 2017 | | $ | 87.3 |
| | $ | 41.3 |
| | $ | 15.5 |
| | $ | (130.5 | ) | | $ | 9.5 |
| | $ | 12.4 |
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| Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) | | 19.8 |
| | 6.2 |
| | 3.8 |
| | (0.1 | ) | | 4.0 |
| | 3.8 |
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| Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) | | 14.8 |
| | — |
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| | — |
| | — |
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| Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | (24.3 | ) | | — |
| | — |
| | — |
| | — |
| | — |
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| Settlements | | (49.2 | ) | | (16.2 | ) | | (8.4 | ) | | 1.2 |
| | (6.9 | ) | | (7.6 | ) |
| Transfers into Level 3 (d) (e) | | 5.7 |
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| | — |
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| Transfers out of Level 3 (e) | | 0.2 |
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| Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | (9.3 | ) | | (1.9 | ) | | (0.7 | ) | | (9.1 | ) | | (1.9 | ) | | 4.5 |
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| Balance as of September 30, 2017 | | $ | 45.0 |
| | $ | 29.4 |
| | $ | 10.2 |
| | $ | (138.5 | ) | | $ | 4.7 |
| | $ | 13.1 |
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(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.
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| Three Months Ended September 30, 2016 | | AEP | | APCo (a) | | I&M (a) | | OPCo | | PSO | | SWEPCo |
| | | (in millions) |
| Balance as of June 30, 2016 | | $ | 149.3 |
| | $ | (12.9 | ) | | $ | 3.5 |
| | $ | (14.6 | ) | | $ | 1.1 |
| | $ | 1.4 |
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| Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) | | 34.2 |
| | 22.7 |
| | 3.8 |
| | (0.1 | ) | | 0.4 |
| | 4.0 |
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| Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) | | 12.3 |
| | — |
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| Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | (34.4 | ) | | — |
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| Settlements | | (37.1 | ) | | (17.9 | ) | | (5.0 | ) | | 0.9 |
| | (0.7 | ) | | (4.4 | ) |
| Transfers into Level 3 (d) (e) | | 13.1 |
| | 0.1 |
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| Transfers out of Level 3 (e) | | (10.0 | ) | | — |
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| Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | (29.0 | ) | | 0.9 |
| | 2.2 |
| | (95.3 | ) | | 0.3 |
| | 0.3 |
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| Balance as of September 30, 2016 | | $ | 98.4 |
| | $ | (7.1 | ) | | $ | 4.5 |
| | $ | (109.1 | ) | | $ | 1.1 |
| | $ | 1.3 |
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| Nine Months Ended September 30, 2017 | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in millions) |
| Balance as of December 31, 2016 | | $ | 2.5 |
| | $ | 1.4 |
| | $ | 2.8 |
| | $ | (119.0 | ) | | $ | 0.7 |
| | $ | 0.7 |
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| Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) | | 37.4 |
| | 17.2 |
| | 4.0 |
| | (1.0 | ) | | 3.1 |
| | 6.0 |
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| Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) | | 37.2 |
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| Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | (29.5 | ) | | — |
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| Settlements | | (49.7 | ) | | (18.9 | ) | | (7.1 | ) | | 5.1 |
| | (3.8 | ) | | (6.8 | ) |
| Transfers into Level 3 (d) (e) | | 16.1 |
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| Transfers out of Level 3 (e) | | (9.1 | ) | | — |
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| Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | 40.1 |
| | 29.7 |
| | 10.5 |
| | (23.6 | ) | | 4.7 |
| | 13.2 |
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| Balance as of September 30, 2017 | | $ | 45.0 |
| | $ | 29.4 |
| | $ | 10.2 |
| | $ | (138.5 | ) | | $ | 4.7 |
| | $ | 13.1 |
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| Nine Months Ended September 30, 2016 | | AEP | | APCo (a) | | I&M (a) | | OPCo | | PSO | | SWEPCo |
| | | (in millions) |
| Balance as of December 31, 2015 | | $ | 146.9 |
| | $ | 11.7 |
| | $ | 4.3 |
| | $ | 15.9 |
| | $ | 0.6 |
| | $ | 0.8 |
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| Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) | | 42.1 |
| | 25.5 |
| | 7.0 |
| | (1.8 | ) | | (1.0 | ) | | 7.7 |
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| Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) | | 45.5 |
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| Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | (16.7 | ) | | — |
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| Settlements | | (67.1 | ) | | (36.2 | ) | | (10.3 | ) | | 4.0 |
| | 0.4 |
| | (8.4 | ) |
| Transfers into Level 3 (d) (e) | | 11.2 |
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| Transfers out of Level 3 (e) | | 1.1 |
| | 0.1 |
| | 0.1 |
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| Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | (64.6 | ) | | (8.2 | ) | | 3.4 |
| | (127.2 | ) | | 1.1 |
| | 1.2 |
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| Balance as of September 30, 2016 | | $ | 98.4 |
| | $ | (7.1 | ) | | $ | 4.5 |
| | $ | (109.1 | ) | | $ | 1.1 |
| | $ | 1.3 |
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(a) | Includes both affiliated and nonaffiliated transactions. |
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(b) | Included in revenues on the statements of income. |
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(c) | Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. |
| |
(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 net gains (losses) are recorded as regulatory liabilities/assets or accounts payable. |
The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions:
AEP
Significant Unobservable Inputs
September 30, 2017March 31, 2023
AEP | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Significant | | Input/Range |
| Fair Value | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (b) |
| (in millions) | | | | | | | | | | |
| Energy Contracts | $ | 190.7 | | | $ | 166.5 | | | Discounted Cash Flow | | Forward Market Price | | $ | 0.74 | | | $ | 101.65 | | | $ | 48.48 | |
| | | | | | | | | | | | | |
| FTRs | 38.8 | | | 17.9 | | | Discounted Cash Flow | | Forward Market Price | | (55.98) | | | 101.82 | | | (0.45) | |
| | | | | | | | | | | | | |
| Total | $ | 229.5 | | | $ | 184.4 | | | | | | | | | | | |
December 31, 2022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Significant | | Input/Range |
| Fair Value | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (b) |
| (in millions) | | | | | | | | | | |
| Energy Contracts | $ | 204.0 | | | $ | 167.4 | | | Discounted Cash Flow | | Forward Market Price | | $2.91 | | $ | 187.34 | | | $ | 49.14 | |
| | | | | | | | | | | | | |
| FTRs | 137.1 | | | 13.3 | | | Discounted Cash Flow | | Forward Market Price | | (36.45) | | | 20.72 | | 1.18 | |
| | | | | | | | | | | | | |
| Total | $ | 341.1 | | | $ | 180.7 | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Significant | | Input/Range |
| | Fair Value | Valuation | | Unobservable | | | | | | Weighted |
| | Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average |
| | (in millions) | | | | | | | | | | |
| Energy Contracts | $ | 233.8 |
| | $ | 252.6 |
| | Discounted Cash Flow | | Forward Market Price (a) | | $ | (0.05 | ) | | $ | 92.77 |
| | $ | 35.82 |
|
| | | | | | | | Counterparty Credit Risk (b) | | 10 |
| | 539 |
| | 204 |
|
| Natural Gas Contracts | 0.9 |
| | — |
| | Discounted Cash Flow | | Forward Market Price (c) | | 2.47 |
| | 3.03 |
| | 2.68 |
|
| FTRs | 66.9 |
| | 4.0 |
| | Discounted Cash Flow | | Forward Market Price (a) | | (9.80 | ) | | 9.37 |
| | 0.32 |
|
| Total | $ | 301.6 |
| | $ | 256.6 |
| | | | | | |
| | |
| | |
APCo
Significant Unobservable Inputs
March 31, 2023
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (b) |
| (in millions) | | | | | | | | | | |
| | | | | | | | | | | | | |
| FTRs | $ | 12.4 | | | $ | 6.7 | | | Discounted Cash Flow | | Forward Market Price | | $ | (1.67) | | | $ | 6.59 | | | $ | 0.79 | |
| | | | | | | | | | | | | |
December 31, 20162022
AEP | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (b) |
| (in millions) | | | | | | | | | | |
| | | | | | | | | | | | | |
| FTRs | $ | 69.4 | | | $ | 0.3 | | | Discounted Cash Flow | | Forward Market Price | | $ | (2.82) | | | $ | 18.88 | | | $ | 3.89 | |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Significant | | Input/Range |
| | Fair Value | Valuation | | Unobservable | | | | | | Weighted |
| | Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average |
| | (in millions) | | | | | | | | | | |
| Energy Contracts | $ | 183.8 |
| | $ | 187.1 |
| | Discounted Cash Flow | | Forward Market Price (a) | | $ | 6.51 |
| | $ | 86.59 |
| | $ | 39.40 |
|
| | | | | | | | Counterparty Credit Risk (b) | | 35 |
| | 824 |
| | 391 |
|
| FTRs | 10.1 |
| | 4.3 |
| | Discounted Cash Flow | | Forward Market Price (a) | | (7.99 | ) | | 8.91 |
| | 0.86 |
|
| Total | $ | 193.9 |
| | $ | 191.4 |
| | | | | | |
| | |
| | |
I&M
Significant Unobservable Inputs
September 30, 2017March 31, 2023
APCo | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (b) |
| (in millions) | | | | | | | | | | |
| | | | | | | | | | | | | |
| FTRs | $ | 1.6 | | | $ | 0.5 | | | Discounted Cash Flow | | Forward Market Price | | $ | 0.24 | | | $ | 4.75 | | | $ | 0.78 | |
| | | | | | | | | | | | | |
December 31, 2022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (b) |
| (in millions) | | | | | | | | | | |
| | | | | | | | | | | | | |
| FTRs | $ | 5.3 | | | $ | 0.7 | | | Discounted Cash Flow | | Forward Market Price | | $ | 0.16 | | | $ | 18.79 | | | $ | 1.23 | |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Significant | | Input/Range |
| | Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| | Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| | (in millions) | | | | | | | | | | |
| Energy Contracts | $ | 1.0 |
| | $ | 0.4 |
| | Discounted Cash Flow | | Forward Market Price | | $ | 14.85 |
| | $ | 45.72 |
| | $ | 33.99 |
|
| FTRs | 29.0 |
| | 0.2 |
| | Discounted Cash Flow | | Forward Market Price | | 0.08 |
| | 6.36 |
| | 1.20 |
|
| Total | $ | 30.0 |
| | $ | 0.6 |
| | | | | | |
| | |
| | |
OPCo
Significant Unobservable Inputs
March 31, 2023
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (b) |
| (in millions) | | | | | | | | | | |
| Energy Contracts | $ | — | | | $ | 46.9 | | | Discounted Cash Flow | | Forward Market Price | | $ | 14.41 | | | $ | 79.98 | | | $ | 45.92 | |
| | | | | | | | | | | | | |
December 31, 20162022
APCo | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (b) |
| (in millions) | | | | | | | | | | |
| Energy Contracts | $ | — | | | $ | 40.0 | | | Discounted Cash Flow | | Forward Market Price | | $ | 2.91 | | | $ | 187.34 | | | $ | 48.76 | |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Significant | | Input/Range |
| | Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| | Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| | (in millions) | | | | | | | | | | |
| Energy Contracts | $ | 0.4 |
| | $ | 0.4 |
| | Discounted Cash Flow | | Forward Market Price | | $ | 19.68 |
| | $ | 48.55 |
| | $ | 36.34 |
|
| FTRs | 3.5 |
| | 2.1 |
| | Discounted Cash Flow | | Forward Market Price | | (0.23 | ) | | 8.91 |
| | 2.37 |
|
| Total | $ | 3.9 |
| | $ | 2.5 |
| | | | | | |
| | |
| | |
PSO
Significant Unobservable Inputs
September 30, 2017March 31, 2023
I&M | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (b) |
| (in millions) | | | | | | | | | | |
| | | | | | | | | | | | | |
| FTRs | $ | 9.9 | | | $ | 0.6 | | | Discounted Cash Flow | | Forward Market Price | | $ | (21.10) | | | $ | 3.04 | | | $ | (4.75) | |
| | | | | | | | | | | | | |
December 31, 2022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (b) |
| (in millions) | | | | | | | | | | |
| FTRs | $ | 24.0 | | | $ | 0.3 | | | Discounted Cash Flow | | Forward Market Price | | $ | (36.45) | | | $ | 3.40 | | | $ | (7.55) | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Significant | | Input/Range |
| | Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| | Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| | (in millions) | | | | | | | | | | |
| Energy Contracts | $ | 0.6 |
| | $ | 0.3 |
| | Discounted Cash Flow | | Forward Market Price | | $ | 14.85 |
| | $ | 45.72 |
| | $ | 33.99 |
|
| FTRs | 11.8 |
| | 1.9 |
| | Discounted Cash Flow | | Forward Market Price | | (0.02 | ) | | 6.36 |
| | 0.71 |
|
| Total | $ | 12.4 |
| | $ | 2.2 |
| | | | | | |
| | |
| | |
SWEPCo
Significant Unobservable Inputs
March 31, 2023
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (b) |
| (in millions) | | | | | | | | | | |
| | | | | | | | | | | | | |
| FTRs | $ | 6.4 | | | $ | 0.6 | | | Discounted Cash Flow | | Forward Market Price | | $ | (21.10) | | | $ | 3.04 | | | $ | (4.75) | |
| | | | | | | | | | | | | |
December 31, 20162022
I&M | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (b) |
| (in millions) | | | | | | | | | | |
| | | | | | | | | | | | | |
| FTRs | $ | 14.6 | | | $ | 0.4 | | | Discounted Cash Flow | | Forward Market Price | | $ | (36.45) | | | $ | 3.40 | | | $ | (7.55) | |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Significant | | Input/Range |
| | Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| | Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| | (in millions) | | | | | | | | | | |
| Energy Contracts | $ | 0.3 |
| | $ | 0.2 |
| | Discounted Cash Flow | | Forward Market Price | | $ | 19.68 |
| | $ | 48.55 |
| | $ | 36.34 |
|
| FTRs | 2.7 |
| | — |
| | Discounted Cash Flow | | Forward Market Price | | (7.90 | ) | | 8.91 |
| | 1.32 |
|
| Total | $ | 3.0 |
| | $ | 0.2 |
| | | | | | |
| | |
| | |
(b)The weighted average is the product of the forward market price of the underlying commodity and volume weighted by term.
Significant Unobservable Inputs
September 30, 2017
OPCo
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Significant | | Input/Range |
| | Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| | Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average |
| | (in millions) | | | | | | | | | | |
| Energy Contracts | $ | — |
| | $ | 138.5 |
| | Discounted Cash Flow | | Forward Market Price (a) | | $ | 22.89 |
| | $ | 61.48 |
| | $ | 41.21 |
|
| | | | | | | | Counterparty Credit Risk (b) | | 10 |
| | 210 |
| | 150 |
|
| Total | $ | — |
| | $ | 138.5 |
| | | | | | | | | | |
Significant Unobservable Inputs
December 31, 2016
OPCo
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Significant | | Input/Range |
| | Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| | Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average |
| | (in millions) | | | | | | | | | | |
| Energy Contracts | $ | — |
| | $ | 119.0 |
| | Discounted Cash Flow | | Forward Market Price (a) | | $ | 30.14 |
| | $ | 71.85 |
| | $ | 47.45 |
|
| |
|
| |
|
| | | | Counterparty Credit Risk (b) | | 47 |
| | 340 |
| | 272 |
|
| Total | $ | — |
| | $ | 119.0 |
| | | | | | | | | | |
Significant Unobservable Inputs
September 30, 2017
PSO
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Significant | | Input/Range |
| | Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| | Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| | (in millions) | | | | | | | | | | |
| FTRs | $ | 4.8 |
| | $ | 0.1 |
| | Discounted Cash Flow | | Forward Market Price | | $ | (9.80 | ) | | $ | 1.03 |
| | $ | (0.69 | ) |
Significant Unobservable Inputs
December 31, 2016
PSO
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Significant | | Input/Range |
| | Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| | Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| | (in millions) | | | | | | | | | | |
| FTRs | $ | 0.7 |
| | $ | — |
| | Discounted Cash Flow | | Forward Market Price | | $ | (7.99 | ) | | $ | 1.03 |
| | $ | (0.36 | ) |
Significant Unobservable Inputs
September 30, 2017
SWEPCo
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Significant | | Input/Range |
| | Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| | Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average |
| | (in millions) | | | | | | | | | | |
| Natural Gas Contracts | $ | 0.9 |
| | $ | — |
| | Discounted Cash Flow | | Forward Market Price (c) | | $ | 2.47 |
| | $ | 3.03 |
| | $ | 2.68 |
|
| FTRs | 12.4 |
| | 0.2 |
| | Discounted Cash Flow | | Forward Market Price (a) | | (9.80 | ) | | 1.03 |
| | (0.69 | ) |
| | $ | 13.3 |
| | $ | 0.2 |
| | | | | | | | | | |
Significant Unobservable Inputs
December 31, 2016
SWEPCo
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Significant | | Input/Range |
| | Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| | Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average |
| | (in millions) | | | | | | | | | | |
| FTRs | $ | 0.8 |
| | $ | 0.1 |
| | Discounted Cash Flow | | Forward Market Price | | $ | (7.99 | ) | | $ | 1.03 |
| | $ | (0.36 | ) |
| |
(a) | Represents market prices in dollars per MWh. |
| |
(b) | Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. |
| |
(c) | Represents market prices in dollars per MMBtu. |
The following table provides sensitivitythe measurement uncertainty of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts Natural Gas Contracts and FTRs for the Registrants as of September 30, 2017March 31, 2023 and December 31, 2016:2022:
SensitivityUncertainty 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) |
| | | | | | |
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) |
Counterparty Credit Risk | | Loss | | Increase (Decrease) | | Higher (Lower) |
Counterparty Credit Risk | | Gain | | Increase (Decrease) | | Lower (Higher) |
11. INCOME TAXES
The disclosures in this note apply to all Registrants unless indicated otherwise.
Effective Tax Rates (ETR)
The Registrants’ interim ETR for AEP’s operating companies reflect the estimated annual ETR for 20172023 and 2016,2022, adjusted for tax expense associated with certain discrete items.
The Registrants include the amortization of Excess ADIT not subject to normalization requirements in the annual estimated ETR when regulatory proceedings instruct the Registrants to provide the benefits of Tax Reform to customers over multiple interim periods. Certain regulatory proceedings instruct the Registrants to provide the benefits of Tax Reform to customers in a single period (e.g. by applying the Excess ADIT not subject to normalization requirements against an existing regulatory asset balance) and in these circumstances, the Registrants recognize the tax benefit discretely in the period recorded. The annual amount of Excess ADIT approved by the Registrant’s regulatory commissions may not impact the ETR differs from the federal statutory tax rate of 35% primarilyratably during each interim period due to tax adjustments, statethe variability of pretax book income taxesbetween interim periods and other book/tax differences which are accounted for on a flow-through basis.the application of an annual estimated ETR.
The ETR from continuing operations for each of the Registrants are included in the following table. Significant variances in the ETR are described below.tables:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2023 |
| | AEP | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| U.S. Federal Statutory Rate | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % |
| Increase (decrease) due to: | | | | | | | | | | | | | | | | |
| State Income Tax, net of Federal Benefit | | 1.9 | % | | 0.3 | % | | 2.6 | % | | 2.4 | % | | 3.6 | % | | 1.0 | % | | 3.2 | % | | (0.4) | % |
| Tax Reform Excess ADIT Reversal | | (6.2) | % | | (1.5) | % | | 0.3 | % | | (4.6) | % | | (7.9) | % | | (6.8) | % | | (18.7) | % | | (3.8) | % |
| Production and Investment Tax Credits | | (9.7) | % | | (0.2) | % | | — | % | | — | % | | (1.1) | % | | — | % | | (55.7) | % | | (26.4) | % |
| Flow Through | | 0.1 | % | | 0.2 | % | | 0.3 | % | | 0.6 | % | | (1.8) | % | | 0.5 | % | | 0.3 | % | | 0.5 | % |
| AFUDC Equity | | (1.4) | % | | (1.5) | % | | (1.6) | % | | (0.7) | % | | (0.5) | % | | (0.8) | % | | (1.4) | % | | (0.8) | % |
| | | | | | | | | | | | | | | | |
| Discrete Tax Adjustments | | (3.2) | % | | — | % | | — | % | | 3.2 | % | | 1.8 | % | | — | % | | — | % | | — | % |
| Other | | 0.1 | % | | 0.1 | % | | 0.1 | % | | — | % | | — | % | | — | % | | (2.0) | % | | (0.8) | % |
| Effective Income Tax Rate | | 2.6 | % | | 18.4 | % | | 22.7 | % | | 21.9 | % | | 15.1 | % | | 14.9 | % | | (53.3) | % | | (10.7) | % |
| | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2022 |
| | AEP | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| U.S. Federal Statutory Rate | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % |
| Increase (decrease) due to: | | | | | | | | | | | | | | | | |
| State Income Tax, net of Federal Benefit | | 1.5 | % | | 0.3 | % | | 2.6 | % | | 2.9 | % | | 1.6 | % | | 0.7 | % | | 0.6 | % | | 2.3 | % |
| Tax Reform Excess ADIT Reversal | | (6.6) | % | | (2.0) | % | | 0.3 | % | | (5.8) | % | | (17.3) | % | | (7.8) | % | | (15.3) | % | | (4.9) | % |
| Production and Investment Tax Credits | | (8.0) | % | | (0.2) | % | | — | % | | — | % | | (1.4) | % | | — | % | | (26.2) | % | | (23.1) | % |
| Flow Through | | 0.3 | % | | 0.3 | % | | 0.3 | % | | 1.7 | % | | (1.9) | % | | 0.9 | % | | 0.6 | % | | (0.6) | % |
| AFUDC Equity | | (0.9) | % | | (0.9) | % | | (1.6) | % | | (0.7) | % | | (0.6) | % | | (0.6) | % | | (0.7) | % | | (0.5) | % |
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| Discrete Tax Adjustments | | (0.6) | % | | — | % | | — | % | | (0.6) | % | | — | % | | — | % | | — | % | | — | % |
| Other | | 0.2 | % | | (0.1) | % | | — | % | | — | % | | (0.2) | % | | — | % | | (0.8) | % | | 0.6 | % |
| Effective Income Tax Rate | | 6.9 | % | | 18.4 | % | | 22.6 | % | | 18.5 | % | | 1.2 | % | | 14.2 | % | | (20.8) | % | | (5.2) | % |
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| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| Company | | 2017 | | 2016 | | 2017 | | 2016 |
| AEP | | 33.0 | % | | 40.4 | % | | 35.3 | % | | (195.6 | )% |
| AEPTCo | | 33.5 | % | | 33.5 | % | | 33.8 | % | | 32.6 | % |
| APCo | | 33.4 | % | | 36.1 | % | | 35.5 | % | | 36.2 | % |
| I&M | | 30.6 | % | | 31.8 | % | | 30.1 | % | | 29.5 | % |
| OPCo | | 36.9 | % | | 31.7 | % | | 35.6 | % | | 33.4 | % |
| PSO | | 37.2 | % | | 37.7 | % | | 37.4 | % | | 36.8 | % |
| SWEPCo | | 21.2 | % | | 28.9 | % | | 25.7 | % | | 26.7 | % |
AEP
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016
The decrease in the ETR is due to the prior year reversal of a $66 million capital loss valuation allowance related to the pending sale of certain merchant generation assets and prior year tax return adjustments related to the disposition of AEP’s commercial barging operations.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
The increase in the ETR is primarily due to the increase in pretax book income driven by the impairment of certain merchant generation assets in the third quarter of 2016. The increase in the ETR is also due to the prior year reversal of a $56 million unrealized capital loss valuation allowance where AEP effectively settled a 2011 audit issue with the IRS, the prior year reversal of a $66 million capital loss valuation allowance related to the pending sale of certain merchant generation assets and prior year tax return adjustments related to the disposition of AEP’s commercial barging operations.
APCo
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016
The decrease in the ETR is primarily due to the recording of favorable federal income tax adjustments and a decrease in pretax book income.
OPCo
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016
The increase in the ETR is primarily due to changes in other book/tax differences which are accounted for on a flow-through basis and the recording of federal income tax adjustments.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
The increase in the ETR is primarily due to changes in other book/tax differences which are accounted for on a flow-through basis, the recording of federal income tax adjustments and an increase in pretax book income.
SWEPCo
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016
The decrease in the ETR is primarily due to a $10 million decrease in Income Tax Expense related to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine.
Federal and State Income Tax Audit Status
The statute of limitations for the IRS to examine AEP and subsidiaries are no longer subjectoriginally filed federal return has expired for tax years 2016 and earlier. AEP has agreed to U.S. federal examinationextend the statute of limitations on the 2017 and 2018 tax returns to December 31, 2023, to allow time for years before 2011.the current IRS audit to be completed including a refund claim approval by the Congressional Joint Committee on Taxation. The statute of limitations for the 2019 return is set to naturally expire in 2023 as well.
The current IRS examination of years 2011, 2012audit and 2013 startedassociated refund claim evolved from a net operating loss carryback to 2015 that originated in April 2014.the 2017 return. AEP has received and subsidiaries received a Revenue Agents Report in April 2016, completingagreed to two IRS proposed adjustments on the 2011 through 2013 audit cycle indicating an agreed upon audit.2017 tax return, which were immaterial. The 2011 through 2013 audit was submittedexam is nearly complete, and AEP is currently working with the IRS to submit the refund claim to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that uponresolution and final resolution are expected to materially impact net income.approval.
AEP and subsidiaries file income tax returns in various state and local or foreign jurisdictions. These taxing authorities routinely examine the tax returns.returns, and AEP and subsidiaries are currently under examination in several state and local jurisdictions. However, itGenerally, the statutes of limitations have expired for tax years prior to 2017. In addition, management is possible that previously filedmonitoring and continues to evaluate the potential impact of federal legislation and corresponding state conformity.
Federal Legislation
In August 2022, President Biden signed H.R. 5376 into law, commonly known as the Inflation Reduction Act of 2022 or IRA. Most notably this budget reconciliation legislation creates a 15% minimum tax returns have positions that may be challenged by theseon adjusted financial statement income (Corporate Alternative Minimum Tax or CAMT), extends and increases the value of PTCs and ITCs, adds a nuclear and clean hydrogen PTC, an energy storage ITC and allows the sale or transfer of tax authorities. Management believes that adequatecredits to third parties for cash. As further significant guidance from Treasury and the IRS is expected on the tax provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009.
State Tax Legislation (Applies to AEP, APCo, I&M and OPCo)
Legislation was enacted in the state of Illinois in July 2017 increasingIRA, AEP will continue to monitor any issued guidance and evaluate the corporate income tax rate from 5.25% to 7% effective July 1, 2017, with the increased rate applied to the portion of the tax year fallingimpact on or after that date. With the inclusion of the 2.5% Illinois Replacement Tax, the total Illinois corporate income tax rate increased from 7.75% to 9.5%, effective July 1, 2017. The legislation is not expected to materially impactfuture net income, cash flows orand financial condition.
In December 2022, the IRS released Notice 2023-7 addressing time sensitive issues related to the CAMT. The notice provided initial guidance that AEP can begin to rely on in 2023 and also stated that additional guidance is expected, of which AEP will continue to monitor and assess. Notably, the interim guidance in Notice 2023-7 confirmed the CAMT depreciation adjustment includes tax depreciation that is capitalized to inventory under §263A and recovered as part of cost of goods sold, providing significant relief to AEP’s potential CAMT exposure.
AEP and subsidiaries expect to be applicable corporations for purposes of the CAMT beginning in 2023. CAMT cash taxes are expected to be partially offset by regulatory recovery, the utilization of tax credits and additionally the cash inflow generated by the sale of tax credits. The sale of tax credits will be presented in the operating section of the statements of cash flows consistent with the presentation of cash taxes paid. AEP will present the gain or loss on sale of tax credits through income tax expense.
12. FINANCING ACTIVITIES
The disclosures in this note apply to all Registrants, unless indicated otherwise.
Common Stock (Applies to AEP)
At-the-Market (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. There were no issuances under the ATM program for the three months ended March 31, 2023.
Long-term Debt Outstanding (Applies to AEP)
The following table details long-term debt outstanding:outstanding, net of issuance costs and premiums or discounts:
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| Type of Debt | | March 31, 2023 | | December 31, 2022 |
| | | (in millions) |
| Senior Unsecured Notes | | $ | 32,654.3 | | | $ | 30,174.8 | |
| Pollution Control Bonds | | 1,770.4 | | | 1,770.2 | |
| Notes Payable | | 190.0 | | | 269.7 | |
| Securitization Bonds | | 463.4 | | | 487.8 | |
| Spent Nuclear Fuel Obligation (a) | | 288.8 | | | 285.6 | |
| Junior Subordinated Notes (b) | | 2,383.3 | | | 2,381.3 | |
| Other Long-term Debt | | 1,394.0 | | | 1,431.6 | |
| Total Long-term Debt Outstanding | | 39,144.2 | | | 36,801.0 | |
| Long-term Debt Due Within One Year | | 2,905.1 | | | 2,486.4 | |
| Long-term Debt | | $ | 36,239.1 | | | $ | 34,314.6 | |
(a)Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for SNF disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $335 million and $330 million as of March 31, 2023 and December 31, 2022, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.
(b)See “Equity Units” section below for additional information.
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| Type of Debt | | September 30, 2017 | | December 31, 2016 | |
| | | (in millions) | |
| Senior Unsecured Notes | | $ | 16,038.6 |
| | $ | 14,761.0 |
| (b) |
| Pollution Control Bonds | | 1,612.4 |
| | 1,725.1 |
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| Notes Payable | | 224.5 |
| | 326.9 |
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| Securitization Bonds | | 1,449.4 |
| | 1,705.0 |
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| Spent Nuclear Fuel Obligation (a) | | 267.9 |
| | 266.3 |
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| Other Long-term Debt | | 1,128.9 |
| | 1,606.9 |
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| Total Long-term Debt Outstanding | | 20,721.7 |
| | 20,391.2 |
| (b) |
| Long-term Debt Due Within One Year | | 2,359.3 |
| | 3,013.4 |
| (b) |
| Long-term Debt | | $ | 18,362.4 |
| | $ | 17,377.8 |
| (b) |
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(a) | Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $311 million and $311 million as of September 30, 2017 and December 31, 2016, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. |
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(b) | Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. |
Long-term Debt Activity
Long-term debt and other securities issued, retired and principal payments made during the first ninethree months of 20172023 are shown in the tables below:following tables:
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| Company | | Type of Debt | | Amount (a) | | Rate | | Due Date |
| Issuances: | | | | (in millions) | | (%) | | |
| AEP | | Senior Unsecured Notes | | $ | 850.0 | | | 5.63 | | 2033 |
| AEPTCo | | Senior Unsecured Notes | | 700.0 | | | 5.40 | | 2053 |
| I&M | | Senior Unsecured Notes | | 500.0 | | | 5.63 | | 2053 |
| PSO | | Senior Unsecured Notes | | 475.0 | | | 5.25 | | 2033 |
| SWEPCo | | Senior Unsecured Notes | | 350.0 | | | 5.30 | | 2033 |
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| Non-Registrant: | | | | | | | | |
| Transource Energy | | Other Long-term Debt | | 1.0 | | | Variable | | 2025 |
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| Total Issuances | | | | $ | 2,876.0 | | | | | |
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| Company | | Type of Debt | | Principal Amount (a) | | Interest Rate | | Due Date |
| Issuances: | | | | (in millions) | | (%) | | |
| AEPTCo | | Senior Unsecured Notes | | $ | 125.0 |
| | 3.10 | | 2026 |
| AEPTCo | | Senior Unsecured Notes | | 500.0 |
| | 3.75 | | 2047 |
| APCo | | Senior Unsecured Notes | | 325.0 |
| | 3.30 | | 2027 |
| I&M | | Pollution Control Bonds | | 25.0 |
| | Variable | | 2019 |
| I&M | | Pollution Control Bonds | | 40.0 |
| | 2.05 | | 2021 |
| I&M | | Pollution Control Bonds | | 52.0 |
| | Variable | | 2021 |
| I&M | | Senior Unsecured Notes | | 300.0 |
| | 3.75 | | 2047 |
| SWEPCo | | Other Long-term Debt | | 115.0 |
| | Variable | | 2020 |
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| AEP Texas | | Pollution Control Bonds | | 60.0 |
| | 1.75 | | 2020 |
| AEP Texas | | Senior Unsecured Notes | | 400.0 |
| | 2.40 | | 2022 |
| AEP Texas | | Senior Unsecured Notes | | 300.0 |
| | 3.80 | | 2047 |
| KPCo | | Pollution Control Bonds | | 65.0 |
| | 2.00 | | 2020 |
| KPCo | | Senior Unsecured Notes | | 65.0 |
| | 3.13 | | 2024 |
| KPCo | | Senior Unsecured Notes | | 40.0 |
| | 3.35 | | 2027 |
| KPCo | | Senior Unsecured Notes | | 165.0 |
| | 3.45 | | 2029 |
| KPCo | | Senior Unsecured Notes | | 55.0 |
| | 4.12 | | 2047 |
| Transource Missouri | | Other Long-term Debt | | 7.0 |
| | Variable | | 2018 |
| Transource Energy | | Other Long-term Debt | | 132.1 |
| | Variable | | 2020 |
| Total Issuances | | | | $ | 2,771.1 |
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(a) | Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. |
(a)Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
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| Company | | Type of Debt | | Amount Paid | | Rate | | Due Date |
| Retirements and Principal Payments: | | | | (in millions) | | (%) | | |
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| AEP Texas | | Senior Unsecured Notes | | $ | 125.0 | | | 3.09 | | 2023 |
| AEP Texas | | Securitization Bonds | | 11.7 | | | 2.06 | | 2025 |
| APCo | | Securitization Bonds | | 9.7 | | | 2.01 | | 2023 |
| APCo | | Securitization Bonds | | 3.3 | | | 3.77 | | 2028 |
| I&M | | Senior Unsecured Notes | | 250.0 | | | 3.20 | | 2023 |
| I&M | | Notes Payable | | 0.6 | | | Variable | | 2023 |
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| I&M | | Notes Payable | | 1.2 | | | Variable | | 2024 |
| I&M | | Notes Payable | | 4.6 | | | Variable | | 2025 |
| I&M | | Notes Payable | | 3.9 | | | 0.93 | | 2025 |
| I&M | | Notes Payable | | 6.8 | | | 3.44 | | 2026 |
| I&M | | Notes Payable | | 6.7 | | | 5.93 | | 2027 |
| I&M | | Other Long-term Debt | | 0.5 | | | 6.00 | | 2025 |
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| PSO | | Other Long-term Debt | | 0.1 | | | 3.00 | | 2027 |
| SWEPCo | | Notes Payable | | 25.0 | | | 6.37 | | 2024 |
| SWEPCo | | Notes Payable | | 30.9 | | | 4.58 | | 2032 |
| SWEPCo | | Other Long-term Debt | | 38.2 | | | 4.68 | | 2028 |
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| Non-Registrant: | | | | | | | | |
| Transource Energy | | Senior Unsecured Notes | | 1.3 | | | 2.75 | | 2050 |
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| Total Retirements and Principal Payments | | | | $ | 519.5 | | | | | |
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| Company | | Type of Debt | | Principal Amount Paid | | Interest Rate | | Due Date |
| Retirements and Principal Payments: | | | | (in millions) | | (%) | | |
| APCo | | Senior Unsecured Notes | | $ | 250.0 |
| | 5.00 | | 2017 |
| APCo | | Securitization Bonds | | 23.5 |
| | 2.008 | | 2024 |
| APCo | | Pollution Control Bonds | | 104.4 |
| | Variable | | 2017 |
| I&M | �� | Notes Payable | | 4.9 |
| | Variable | | 2017 |
| I&M | | Pollution Control Bonds | | 25.0 |
| | Variable | | 2017 |
| I&M | | Notes Payable | | 22.3 |
| | Variable | | 2019 |
| I&M | | Notes Payable | | 23.6 |
| | Variable | | 2019 |
| I&M | | Notes Payable | | 23.9 |
| | Variable | | 2020 |
| I&M | | Pollution Control Bonds | | 52.0 |
| | Variable | | 2017 |
| I&M | | Notes Payable | | 24.3 |
| | Variable | | 2021 |
| I&M | | Other Long-term Debt | | 1.1 |
| | 6.00 | | 2025 |
| I&M | | Pollution Control Bonds | | 50.0 |
| | Variable | | 2025 |
| OPCo | | Securitization Bonds | | 16.2 |
| | 0.958 | | 2017 |
| OPCo | | Securitization Bonds | | 22.5 |
| | 0.958 | | 2018 |
| OPCo | | Securitization Bonds | | 7.6 |
| | 2.049 | | 2019 |
| OPCo | | Other Long-term Debt | | 0.1 |
| | 1.149 | | 2028 |
| PSO | | Other Long-term Debt | | 0.3 |
| | 3.00 | | 2027 |
| SWEPCo | | Senior Unsecured Notes | | 250.0 |
| | 5.55 | | 2017 |
| SWEPCo | | Other Long-term Debt | | 100.0 |
| | Variable | | 2017 |
| SWEPCo | | Other Long-term Debt | | 0.2 |
| | 3.50 | | 2023 |
| SWEPCo | | Other Long-term Debt | | 0.1 |
| | 4.28 | | 2023 |
| SWEPCo | | Notes Payable | | 3.3 |
| | 4.58 | | 2032 |
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| Non-Registrant: | | | | | | | | |
| AEGCo | | Senior Unsecured Notes | | 152.7 |
| | 6.33 | | 2037 |
| AGR | | Other Long-term Debt | | 500.0 |
| | Variable | | 2017 |
| KPCo | | Pollution Control Bonds | | 65.0 |
| | Variable | | 2017 |
| KPCo | | Senior Unsecured Notes | | 325.0 |
| | 6.00 | | 2017 |
| TCC | | Securitization Bonds | | 27.2 |
| | 0.88 | | 2017 |
| TCC | | Securitization Bonds | | 161.2 |
| | 5.17 | | 2018 |
| TCC | | Pollution Control Bonds | | 60.0 |
| | 5.20 | | 2030 |
| Transource Missouri | | Other Long-term Debt | | 130.8 |
| | Variable | | 2018 |
| Total Retirements and Principal Payments | | | | $ | 2,427.2 |
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Long-term Debt Subsequent Event
In October 2017,April 2023, I&M retired $1$8 million of Notes Payable related to DCC Fuel.
Equity Units (Applies to AEP)
2020 Equity Units
In October 2017,August 2020, AEP Texas retired $41issued 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 August 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 5.625% Pollution Control Bonds duenotes were recorded within Long-term Debt on the balance sheets. The present value of the purchase contract payments of $121 million were recorded in 2017.Deferred Credits and Other Noncurrent Liabilitieswith 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).
As of September 30, 2017, trustees held, on behalf of AEP, $728 million of their reacquired Pollution Control Bonds. Of this total, $104 million, $50 million and $345 million related to APCo, I&M and OPCo, respectively.
Debt Covenants (Applies to AEP and AEPTCo)
Covenants in AEPTCo’s note purchase agreements and indenture also 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 0.0% of consolidated tangible net assets as of March 31, 2023. The method for calculating the consolidated tangible net assets is contractually definedcontractually-defined in the note purchase agreements.
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 restrictionrequirement that prohibits the payment of dividends out of capital accounts without regulatory approval;in certain circumstances; payment of dividends is generally allowed out of retained earnings only. Additionally, theearnings. The Federal Power Act also creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M.
Certain AEP subsidiaries have credit agreements that contain a covenantcovenants that limitslimit their debt to capitalization ratio to 67.5%. As of September 30, 2017, no subsidiaries have exceeded their debt to capitalization limit. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the AEP subsidiary distributing the dividend. The method for calculating outstanding debt and capitalization is contractually definedcontractually-defined in the credit agreements.
As of September 30, 2017, theThe Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings.
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%. As of September 30, 2017, AEP has not exceeded its debt to capitalization limit. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually definedcontractually-defined in the credit agreements.
Corporate Borrowing Program - AEP System (Applies to all 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, andsubsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries.subsidiaries; and direct borrowing from AEP. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Poolits agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of September 30, 2017March 31, 2023 and December 31, 20162022 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the ninethree months ended September 30, 2017March 31, 2023 are described in the following table:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 | | March 31, 2023 | | Limit | |
| | | (in millions) |
| AEP Texas | | $ | 453.7 | | | $ | — | | | $ | 285.3 | | | $ | — | | | $ | (450.8) | | | $ | 500.0 | | |
| AEPTCo | | 471.3 | | | 309.4 | | | 272.9 | | | 45.7 | | | 260.5 | | | 820.0 | | (a) |
| APCo | | 373.6 | | | 19.8 | | | 285.3 | | | 18.9 | | | (291.5) | | | 500.0 | | |
| I&M | | 475.3 | | | 82.9 | | | 212.5 | | | 28.1 | | | 60.0 | | | 500.0 | | |
| OPCo | | 483.0 | | | — | | | 292.6 | | | — | | | (414.6) | | | 500.0 | | |
| PSO | | 375.0 | | | 121.5 | | | 321.7 | | | 74.8 | | | (130.7) | | | 400.0 | | |
| SWEPCo | | 401.6 | | (b) | — | | | 353.9 | | | — | | | (18.8) | | | 400.0 | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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 | | September 30, 2017 | | Limit | |
| | | (in millions) | |
| AEPTCo | | $ | 467.2 |
| | $ | 194.8 |
| | $ | 235.7 |
| | $ | 19.3 |
| | $ | 162.9 |
| | $ | 795.0 |
| (a) |
| APCo | | 231.5 |
| | 160.7 |
| | 152.2 |
| | 32.2 |
| | (45.9 | ) | | 600.0 |
| |
| I&M | | 367.4 |
| | 12.6 |
| | 205.7 |
| | 12.6 |
| | (164.9 | ) | | 500.0 |
| |
| OPCo | | 280.6 |
| | 56.2 |
| | 141.0 |
| | 27.9 |
| | (167.6 | ) | | 400.0 |
| |
| PSO | | 185.2 |
| | — |
| | 121.3 |
| | — |
| | (118.0 | ) | | 300.0 |
| |
| SWEPCo | | 187.5 |
| | 178.6 |
| | 109.6 |
| | 169.5 |
| | (48.3 | ) | | 350.0 |
| |
(a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
| |
(a) | Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions. |
(b) SWEPCo’s maximum borrowings from the Utility Money Pool exceeded the authorized short-term borrowing limit by $1.6 million on March 15, 2023. On March 16, 2023, SWEPCo’s borrowings from the Utility Money Pool were reduced below the $400 million authorized limit and borrowings have continued to remain below the authorized limit.
The activity in the above table 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, LP, which is a participantLLC participate in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2017March 31, 2023 and December 31, 20162022 are included in Advances to Affiliates on SWEPCo’sthe subsidiaries’ balance sheets. ForThe Nonutility Money Pool participants’ activity for the ninethree months ended September 30, 2017, Mutual Energy SWEPCo, LP hadMarch 31, 2023 is described in the following activity in the Nonutility Money Pool:table:
| | | | | | | | | | | | | | | | | | | | |
| | Maximum Loans | | Average Loans | | Loans to the Nonutility |
| | to the Nonutility | | to the Nonutility | | Money Pool as of |
| Company | | Money Pool | | Money Pool | | March 31, 2023 |
| (in millions) |
| AEP Texas | | $ | 6.9 | | | $ | 6.8 | | | $ | 6.8 | |
| SWEPCo | | 2.1 | | | 2.1 | | | 2.1 | |
|
| | | | | | | | | | |
| Maximum | | Average | | Loans |
| Loans | | Loans | | to the Nonutility |
| to the Nonutility | | to the Nonutility | | Money Pool as of |
| Money Pool | | Money Pool | | September 30, 2017 |
| (in millions) |
| $ | 2.0 |
| | $ | 2.0 |
| | $ | 2.0 |
|
AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to (borrowings from)and borrowings from AEP as of September 30, 2017March 31, 2023 and December 31, 20162022 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP and corresponding authorized borrowing limit for the ninethree months ended September 30, 2017 isMarch 31, 2023 are described in the following table:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 | | March 31, 2023 | | March 31, 2023 | | Borrowing Limit | |
| (in millions) |
| $ | 29.4 | | | $ | 158.1 | | | $ | 3.1 | | | $ | 80.2 | | | $ | 1.6 | | | $ | 34.2 | | | $ | 50.0 | | (a) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 | | September 30, 2017 | | September 30, 2017 | | Borrowing Limit | |
| (in millions) | |
| $ | 1.1 |
| | $ | 151.9 |
| | $ | 1.1 |
| | $ | 38.9 |
| | $ | 0.9 |
| | $ | 96.1 |
| | $ | 75.0 |
| (a) |
| |
(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 were as follows:are summarized in the following table:
| | | | | | | | | | | | | | |
| | | Three Months Ended March 31, |
| | 2023 | | 2022 |
| Maximum Interest Rate | | 5.42 | % | | 1.00 | % |
| Minimum Interest Rate | | 4.66 | % | | 0.10 | % |
|
| | | | | | |
| | | Nine Months Ended September 30, |
| | | 2017 | | 2016 |
| Maximum Interest Rate | | 1.49 | % | | 0.91 | % |
| Minimum Interest Rate | | 0.92 | % | | 0.69 | % |
The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for all Registrant Subsidiaries in the following table:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Average Interest Rate for Funds | | Average Interest Rate for Funds |
| | Borrowed from the Utility Money Pool | | Loaned to the Utility Money Pool |
| | for Three Months Ended March 31, | | for Three Months Ended March 31, |
| Company | | 2023 | | 2022 | | 2023 | | 2022 |
| AEP Texas | | 5.18 | % | | 0.70 | % | | — | % | | — | % |
| AEPTCo | | 5.09 | % | | 0.66 | % | | 5.29 | % | | 0.60 | % |
| APCo | | 5.14 | % | | 0.55 | % | | 5.12 | % | | 0.62 | % |
| I&M | | 5.12 | % | | 0.63 | % | | 5.16 | % | | 0.62 | % |
| OPCo | | 5.17 | % | | 0.77 | % | | — | % | | 0.48 | % |
| PSO | | 4.84 | % | | 0.69 | % | | 5.11 | % | | 0.65 | % |
| SWEPCo | | 5.12 | % | | 0.98 | % | | — | % | | 0.55 | % |
|
| | | | | | | | | | | | |
| | | Average Interest Rate | | Average Interest Rate |
| | | for Funds Borrowed | | for Funds Loaned |
| | | from the Utility Money Pool for | | to the Utility Money Pool for |
| | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| Company | | 2017 | | 2016 | | 2017 | | 2016 |
| AEPTCo | | 1.36 | % | | 0.82 | % | | 1.04 | % | | 0.74 | % |
| APCo | | 1.24 | % | | 0.78 | % | | 1.28 | % | | 0.79 | % |
| I&M | | 1.24 | % | | 0.73 | % | | 1.27 | % | | 0.78 | % |
| OPCo | | 1.40 | % | | 0.85 | % | | 0.98 | % | | 0.74 | % |
| PSO | | 1.30 | % | | 0.76 | % | | — | % | | 0.81 | % |
| SWEPCo | | 1.26 | % | | 0.79 | % | | 0.98 | % | | 0.91 | % |
Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LP in the following table:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2023 | | Three Months Ended March 31, 2022 |
| | | Maximum | | Minimum | | Average | | Maximum | | Minimum | | 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 |
| | Loaned to | | Loaned to | | Loaned to | | Loaned to | | Loaned to | | Loaned to |
| | the Nonutility | | the Nonutility | | the Nonutility | | the Nonutility | | the Nonutility | | the Nonutility |
| Company | | Money Pool | | Money Pool | | Money Pool | | Money Pool | | Money Pool | | Money Pool |
| AEP Texas | | 5.42 | % | | 4.66 | % | | 5.12 | % | | 1.00 | % | | 0.46 | % | | 0.62 | % |
| SWEPCo | | 5.42 | % | | 4.66 | % | | 5.13 | % | | 1.00 | % | | 0.46 | % | | 0.62 | % |
|
| | | | | | | | | |
| | | Maximum | | Minimum | | Average |
| | | Interest Rate | | Interest Rate | | Interest Rate |
| Nine Months | | for Funds Loaned | | for Funds Loaned | | for Funds Loaned |
| Ended | | to the Nonutility | | to the Nonutility | | to the Nonutility |
| September 30, | Money Pool | | Money Pool | | Money Pool |
| 2017 | | 1.49 | % | | — | % | | 1.27 | % |
| 2016 | | 0.91 | % | | 0.69 | % | | 0.79 | % |
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 |
| Nine Months | | for Funds | | for Funds | | for Funds | | for Funds | | for Funds | | for Funds |
| Ended | | Borrowed | | Borrowed | | Loaned | | Loaned | | Borrowed | | Loaned |
| September 30, | | from AEP | | from AEP | to AEP | | to AEP | | from AEP | | to AEP |
| 2017 | | 1.49 | % | | 0.92 | % | | 1.49 | % | | 0.92 | % | | 1.27 | % | | 1.31 | % |
| 2016 | | 0.91 | % | | 0.69 | % | | 0.91 | % | | 0.69 | % | | 0.80 | % | | 0.81 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Maximum | | Minimum | | Maximum | | Minimum | | Average | | Average |
| | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate |
| Three Months | | for Funds | | for Funds | | for Funds | | for Funds | | for Funds | | for Funds |
| Ended | | Borrowed | | Borrowed | | Loaned | | Loaned | | Borrowed | | Loaned |
| March 31, | | from AEP | | from AEP | to AEP | | to AEP | | from AEP | | to AEP |
| 2023 | | 5.38 | % | | 4.53 | % | | 5.38 | % | | 4.53 | % | | 5.03 | % | | 5.15 | % |
| 2022 | | 1.00 | % | | 0.46 | % | | 1.00 | % | | 0.46 | % | | 0.66 | % | | 0.60 | % |
Short-term Debt (Applies to AEP and SWEPCo)
Outstanding short-term debt was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | March 31, 2023 | | December 31, 2022 |
| | | | Outstanding | | Interest | | Outstanding | | Interest |
| Company | | Type of Debt | | Amount | | Rate (a) | | Amount | | Rate (a) |
| | | | (dollars in millions) |
| AEP | | Securitized Debt for Receivables (b) | | $ | 750.0 | | | 5.05 | % | | $ | 750.0 | | | 4.67 | % |
| AEP | | Commercial Paper | | 1,981.1 | | | 5.20 | % | | 2,862.2 | | | 4.80 | % |
| AEP | | Term Loan | | 500.0 | | | 5.67 | % | | — | | | — | % |
| AEP | | Term Loan | | 150.0 | | | 5.63 | % | | 150.0 | | | 5.17 | % |
| AEP | | Term Loan | | 125.0 | | | 5.64 | % | | 125.0 | | | 5.17 | % |
| AEP | | Term Loan | | 100.0 | | | 5.64 | % | | 100.0 | | | 5.23 | % |
| AEP | | Term Loan | | — | | | — | % | | 125.0 | | | 4.87 | % |
| | | | | | | | | | |
| SWEPCo | | Notes Payable | | 16.0 | | | 7.27 | % | | — | | | — | % |
| AEP | | Total Short-term Debt | | $ | 3,622.1 | | | | | $ | 4,112.2 | | | |
|
| | | | | | | | | | | | | | | | |
| | | | | September 30, 2017 | | December 31, 2016 |
| 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 |
| | 1.17 | % | | $ | 673.0 |
| | 0.70 | % |
| AEP | | Commercial Paper | | 295.0 |
| | 1.39 | % | | 1,040.0 |
| | 1.02 | % |
| SWEPCo | | Notes Payable | | 14.3 |
| | 2.88 | % | | — |
| | — | % |
| | | Total Short-term Debt | | $ | 1,059.3 |
| | |
| | $ | 1,713.0 |
| | |
|
(a)Weighted-average rate as of March 31, 2023 and December 31, 2022, respectively.
| |
(a) | Weighted average rate. |
| |
(b) | Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. |
(b)Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.
Credit Facilities
For a discussion of credit facilities, see “Letters of Credit” section of Note 5.
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 expiresincludes a $125 million and a $625 million facility, both of which expire in June 2019.September 2024. As of March 31, 2023, the affiliated utility subsidiaries were in compliance with all requirements under the agreement. SWEPCo temporarily eased credit policies from August 2022 through October 2022 to assist customers with higher than normal bills driven by increased fuel costs and, in turn, experienced higher than normal aged receivables. In response, in January 2023, AEP Credit amended its receivables securitization agreement to increase the eligibility criteria related to their aged receivables requirements to ensure SWEPCo remains in compliance.
Accounts receivable information for AEP Credit iswas as follows:
| | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| | (dollars in millions) |
| Effective Interest Rates on Securitization of Accounts Receivable | | 4.86 | % | | 0.31 | % | | | | |
| Net Uncollectible Accounts Receivable Written-Off | | $ | 6.9 | | | $ | 7.4 | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| | | (dollars in millions) |
| Effective Interest Rates on Securitization of Accounts Receivable | | 1.33 | % | | 0.73 | % | | 1.17 | % | | 0.65 | % |
| Net Uncollectible Accounts Receivable Written Off | | $ | 7.0 |
| | $ | 7.7 |
| | $ | 18.2 |
| | $ | 17.5 |
|
| | | | | | | | | | | | | | |
| | March 31, 2023 | | December 31, 2022 |
| | (in millions) |
| Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts | | $ | 1,091.8 | | | $ | 1,167.7 | |
| Short-term – Securitized Debt of Receivables | | 750.0 | | | 750.0 | |
| Delinquent Securitized Accounts Receivable | | 49.3 | | | 44.2 | |
| Bad Debt Reserves Related to Securitization | | 41.2 | | | 39.7 | |
| Unbilled Receivables Related to Securitization | | 287.3 | | | 360.9 | |
|
| | | | | | | | |
| | | September 30, 2017 | | December 31, 2016 |
| | | (in millions) |
| Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts | | $ | 939.8 |
| | $ | 945.0 |
|
| Short-term – Securitized Debt of Receivables | | 750.0 |
| | 673.0 |
|
| Delinquent Securitized Accounts Receivable | | 44.3 |
| | 42.7 |
|
| Bad Debt Reserves Related to Securitization | | 27.8 |
| | 27.7 |
|
| Unbilled Receivables Related to Securitization | | 264.2 |
| | 322.1 |
|
AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due.
Securitized Accounts Receivables – AEP Credit (Applies to all 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 ceased selling accounts receivable to AEP Credit in the first quarter of 2022, based on the expected sale to Liberty. As a result, in the first quarter of 2022, KPCo recorded 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 for each Registrant Subsidiary was as follows:agreements were:
| | | | | | | | | | | | | | |
| Company | | March 31, 2023 | | December 31, 2022 |
| | | (in millions) |
| APCo | | $ | 195.5 | | | $ | 194.4 | |
| I&M | | 167.9 | | | 166.9 | |
| OPCo | | 457.5 | | | 478.6 | |
| PSO | | 134.2 | | | 155.5 | |
| SWEPCo | | 157.8 | | | 194.0 | |
|
| | | | | | | | |
| Company | | September 30, 2017 | | December 31, 2016 |
| | | (in millions) |
| APCo | | $ | 116.9 |
| | $ | 142.0 |
|
| I&M | | 132.7 |
| | 136.7 |
|
| OPCo | | 356.3 |
| | 388.3 |
|
| PSO | | 143.4 |
| | 110.4 |
|
| SWEPCo | | 167.1 |
| | 130.9 |
|
The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were:
| | | | | | | | | | | | | | | | | | |
| | | | | Three Months Ended March 31, |
| Company | | | | | | 2023 | | 2022 |
| | | | | | | (in millions) |
| APCo | | | | | | $ | 4.9 | | | $ | 1.3 | |
| I&M | | | | | | 3.9 | | | 1.7 | |
| OPCo | | | | | | 7.3 | | | 7.4 | |
| PSO | | | | | | 3.2 | | | 0.9 | |
| SWEPCo | | | | | | 4.3 | | | 1.3 | |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| Company | | 2017 | | 2016 | | 2017 | | 2016 |
| | | (in millions) |
| APCo | | $ | 1.5 |
| | $ | 1.6 |
| | $ | 4.2 |
| | $ | 5.4 |
|
| I&M | | 1.8 |
| | 2.0 |
| | 4.9 |
| | 5.6 |
|
| OPCo | | 6.1 |
| | 8.1 |
| | 16.5 |
| | 23.4 |
|
| PSO | | 2.0 |
| | 1.8 |
| | 5.2 |
| | 4.7 |
|
| SWEPCo | | 2.0 |
| | 2.1 |
| | 5.4 |
| | 5.3 |
|
The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were:
| | | | | | | | | | | | | | | | | | |
| | | Three Months Ended March 31, | | |
| Company | | 2023 | | 2022 | | | | |
| | (in millions) |
| APCo | | $ | 506.2 | | | $ | 415.5 | | | | | |
| I&M | | 525.4 | | | 513.4 | | | | | |
| OPCo | | 884.4 | | | 716.6 | | | | | |
| PSO | | 416.3 | | | 363.4 | | | | | |
| SWEPCo | | 437.6 | | | 394.5 | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| Company | | 2017 | | 2016 | | 2017 | | 2016 |
| | | (in millions) |
| APCo | | $ | 335.5 |
| | $ | 361.7 |
| | $ | 1,029.4 |
| | $ | 1,071.6 |
|
| I&M | | 409.9 |
| | 448.0 |
| | 1,218.9 |
| | 1,220.2 |
|
| OPCo | | 616.3 |
| | 750.9 |
| | 1,741.7 |
| | 2,011.2 |
|
| PSO | | 407.0 |
| | 390.6 |
| | 1,022.6 |
| | 971.9 |
|
| SWEPCo | | 455.0 |
| | 460.4 |
| | 1,200.8 |
| | 1,183.9 |
|
13. VARIABLE INTEREST ENTITIES
The disclosures in this note apply to AEP 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.
AEP holds ownership interests in businesses with varying ownership structures. 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
The Annual Report on Form 10-K for the year ended December 31, 2022 includes a detailed discussion of the Registrants’ consolidated VIEs. There were no reconsideration events with respect to those VIEs in the first quarter of 2023.
The balances below represent the assets and liabilities of consolidated VIEs. These balances include intercompany transactions that are eliminated upon consolidation.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| American Electric Power Company, Inc. and Subsidiary Companies |
| Variable Interest Entities |
| March 31, 2023 |
| | |
| 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 | $ | 23.0 | | | $ | 84.3 | | | $ | 43.0 | | | $ | 13.4 | | | $ | 6.1 | | |
| Net Property, Plant and Equipment | — | | | 154.3 | | | — | | | — | | | — | | |
| Other Noncurrent Assets | 135.1 | | | 76.0 | | | 125.2 | | (a) | 163.0 | | (b) | 157.4 | | (c) |
| Total Assets | $ | 158.1 | | | $ | 314.6 | | | $ | 168.2 | | | $ | 176.4 | | | $ | 163.5 | | |
| | | | | | | | | | |
| LIABILITIES AND EQUITY | | | | | | | | | | |
| Current Liabilities | $ | 33.5 | | | $ | 84.2 | | | $ | 74.3 | | | $ | 30.5 | | | $ | 28.1 | | |
| Noncurrent Liabilities | 124.2 | | | 230.4 | | | 89.6 | | | 144.7 | | | 133.5 | | |
| Equity | 0.4 | | | — | | | 4.3 | | | 1.2 | | | 1.9 | | |
| Total Liabilities and Equity | $ | 158.1 | | | $ | 314.6 | | | $ | 168.2 | | | $ | 176.4 | | | $ | 163.5 | | |
(a)Includes an intercompany item eliminated in consolidation of $14 million.
(b)Includes an intercompany item eliminated in consolidation of $7 million.
(c)Includes an intercompany item eliminated in consolidation of $2 million.
| | | | | | | | | | | | | | | | | |
| American Electric Power Company, Inc. and Subsidiary Companies |
| Variable Interest Entities |
| March 31, 2023 |
| | | | | |
| Other Consolidated VIEs |
| AEP Credit | | Protected
Cell
of EIS | | Transource Energy |
| (in millions) |
| ASSETS | | | | | |
| Current Assets | $ | 1,092.6 | | | $ | 203.2 | | | $ | 22.1 | |
| Net Property, Plant and Equipment | — | | | — | | | 495.1 | |
| Other Noncurrent Assets | 8.9 | | | — | | | 6.8 | |
| Total Assets | $ | 1,101.5 | | | $ | 203.2 | | | $ | 524.0 | |
| | | | | |
| LIABILITIES AND EQUITY | | | | | |
| Current Liabilities | $ | 1,043.2 | | | $ | 50.2 | | | $ | 33.4 | |
| Noncurrent Liabilities | 0.9 | | | 78.0 | | | 219.0 | |
| Equity | 57.4 | | | 75.0 | | | 271.6 | |
| Total Liabilities and Equity | $ | 1,101.5 | | | $ | 203.2 | | | $ | 524.0 | |
Apple Blossom, Black Oak, Santa Rita East and Dry Lake are consolidated VIEs included in the plan of sale of the Competitive Contracted Renewables Portfolio. See the “Planned Disposition of the Competitive Contracted Renewables Portfolio” section of Note 6 for the assets and liabilities classified Held for Sale as of March 31, 2023 inclusive of the assets and liabilities of the aforementioned consolidated VIEs.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| American Electric Power Company, Inc. and Subsidiary Companies |
| Variable Interest Entities |
| December 31, 2022 |
| | |
| 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 | $ | 108.3 | | | $ | 90.2 | | | $ | 27.0 | | | $ | 21.1 | | | $ | 13.5 | | |
| Net Property, Plant and Equipment | 7.2 | | | 179.1 | | | — | | | — | | | — | | |
| Other Noncurrent Assets | 130.0 | | | 94.0 | | | 140.9 | | (a) | 168.8 | | (b) | 164.6 | | (c) |
| Total Assets | $ | 245.5 | | | $ | 363.3 | | | $ | 167.9 | | | $ | 189.9 | | | $ | 178.1 | | |
| | | | | | | | | | |
| LIABILITIES AND EQUITY | | | | | | | | | | |
| Current Liabilities | $ | 25.4 | | | $ | 90.0 | | | $ | 73.2 | | | $ | 31.3 | | | $ | 29.3 | | |
| Noncurrent Liabilities | 219.4 | | | 273.3 | | | 90.4 | | | 157.4 | | | 146.9 | | |
| Equity | 0.7 | | | — | | | 4.3 | | | 1.2 | | | 1.9 | | |
| Total Liabilities and Equity | $ | 245.5 | | | $ | 363.3 | | | $ | 167.9 | | | $ | 189.9 | | | $ | 178.1 | | |
(a)Includes an intercompany item eliminated in consolidation of $16 million.
(b)Includes an intercompany item eliminated in consolidation of $7 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, 2022 |
| | | | | | | | |
| 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 | $ | 1,181.0 | | | $ | 194.5 | | | $ | 23.5 | | | | | $ | 8.3 | | | $ | 21.3 | | | $ | 4.0 | | |
| Net Property, Plant and Equipment | — | | | — | | | 482.3 | | | | | 216.5 | | | 421.6 | | | 142.6 | | |
| Other Noncurrent Assets | 9.0 | | | 0.3 | | | 2.7 | | | | | 13.6 | | | 0.1 | | | 0.3 | | |
| Total Assets | $ | 1,190.0 | | | $ | 194.8 | | | $ | 508.5 | | | | | $ | 238.4 | | | $ | 443.0 | | | $ | 146.9 | | |
| | | | | | | | | | | | | | |
| LIABILITIES AND EQUITY | | | | | | | | | | | | | | |
| Current Liabilities | $ | 1,087.8 | | | $ | 46.4 | | | $ | 22.8 | | | | | $ | 4.5 | | | $ | 9.6 | | | $ | 1.0 | | |
| Noncurrent Liabilities | 0.9 | | | 79.1 | | | 218.6 | | | | | 5.4 | | | 7.3 | | | 0.7 | | |
| Equity | 101.3 | | | 69.3 | | | 267.1 | | | | | 228.5 | | | 426.1 | | | 145.2 | | |
| Total Liabilities and Equity | $ | 1,190.0 | | | $ | 194.8 | | | $ | 508.5 | | | | | $ | 238.4 | | | $ | 443.0 | | | $ | 146.9 | | |
Significant Variable Interests in Non-Consolidated VIEs and Significant Equity Method Investments
The Annual Report on Form 10-K for the year ended December 31, 2022 includes a detailed discussion of significant variable interests in non-consolidated VIEs and other significant equity method investments. There were no reconsideration events or material changes in carrying values as of March 31, 2023.
14. REVENUE FROM CONTRACTS WITH CUSTOMERS
The disclosures in this note apply to all Registrants, unless indicated otherwise.
Disaggregated Revenues from Contracts with Customers
The tables below represent AEP’s reportable segment revenues from contracts with customers, net of respective provisions for refund, by type of revenue:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2023 |
| | 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 | | $ | 1,170.4 | | | $ | 656.8 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 1,827.2 | |
| Commercial Revenues | | 633.4 | | | 375.9 | | | — | | | — | | | — | | | — | | | 1,009.3 | |
| Industrial Revenues | | 670.3 | | | 212.9 | | | — | | | — | | | — | | | (0.2) | | | 883.0 | |
| Other Retail Revenues | | 56.8 | | | 12.1 | | | — | | | — | | | — | | | — | | | 68.9 | |
| Total Retail Revenues | | 2,530.9 | | | 1,257.7 | | | — | | | — | | | — | | | (0.2) | | | 3,788.4 | |
| | | | | | | | | | | | | | |
| Wholesale and Competitive Retail Revenues: | | | | | | | | | | | | | | |
| Generation Revenues | | 182.8 | | | — | | | — | | | 32.4 | | | — | | | — | | | 215.2 | |
| Transmission Revenues (a) | | 114.7 | | | 164.2 | | | 450.1 | | | — | | | — | | | (401.8) | | | 327.2 | |
| Renewable Generation Revenues (b) | | — | | | — | | | — | | | 21.3 | | | — | | | (0.1) | | | 21.2 | |
| Retail, Trading and Marketing Revenues (b) | | — | | | — | | | — | | | 413.7 | | | (0.3) | | | 0.1 | | | 413.5 | |
| Total Wholesale and Competitive Retail Revenues | | 297.5 | | | 164.2 | | | 450.1 | | | 467.4 | | | (0.3) | | | (401.8) | | | 977.1 | |
| | | | | | | | | | | | | | |
| Other Revenues from Contracts with Customers (c) | | 32.6 | | | 42.8 | | | 3.6 | | | 0.6 | | | 29.4 | | | (43.7) | | | 65.3 | |
| | | | | | | | | | | | | | |
| Total Revenues from Contracts with Customers | | 2,861.0 | | | 1,464.7 | | | 453.7 | | | 468.0 | | | 29.1 | | | (445.7) | | | 4,830.8 | |
| | | | | | | | | | | | | | |
| Other Revenues: | | | | | | | | | | | | | | |
| Alternative Revenue Programs (d) | | (3.1) | | | (11.6) | | | 1.8 | | | — | | | — | | | 2.9 | | | (10.0) | |
| Other Revenues (b) (e) | | (0.1) | | | 11.1 | | | — | | | (141.0) | | | 1.0 | | | (0.9) | | | (129.9) | |
| Total Other Revenues | | (3.2) | | | (0.5) | | | 1.8 | | | (141.0) | | | 1.0 | | | 2.0 | | | (139.9) | |
| | | | | | | | | | | | | | |
| Total Revenues | | $ | 2,857.8 | | | $ | 1,464.2 | | | $ | 455.5 | | | $ | 327.0 | | | $ | 30.1 | | | $ | (443.7) | | | $ | 4,690.9 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $357 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 Corporate and Other was $29 million. The remaining affiliated amounts were immaterial.
(d)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.
(e)Generation & Marketing includes economic hedge activity.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2022 |
| | 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 | | $ | 1,150.8 | | | $ | 600.6 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 1,751.4 | |
| Commercial Revenues | | 572.9 | | | 289.7 | | | — | | | — | | | — | | | — | | | 862.6 | |
| Industrial Revenues | | 563.0 | | | 133.3 | | | — | | | — | | | — | | | (0.4) | | | 695.9 | |
| Other Retail Revenues | | 47.4 | | | 11.6 | | | — | | | — | | | — | | | — | | | 59.0 | |
| Total Retail Revenues | | 2,334.1 | | | 1,035.2 | | | — | | | — | | | — | | | (0.4) | | | 3,368.9 | |
| | | | | | | | | | | | | | |
| Wholesale and Competitive Retail Revenues: | | | | | | | | | | | | | | |
| Generation Revenues | | 187.2 | | | — | | | — | | | 40.3 | | | — | | | — | | | 227.5 | |
| Transmission Revenues (a) | | 105.3 | | | 154.9 | | | 414.5 | | | — | | | — | | | (361.8) | | | 312.9 | |
| Renewable Generation Revenues (b) | | — | | | — | | | — | | | 22.4 | | | — | | | (0.8) | | | 21.6 | |
| Retail, Trading and Marketing Revenues (c) | | — | | | — | | | — | | | 388.8 | | | 3.2 | | | (9.0) | | | 383.0 | |
| Total Wholesale and Competitive Retail Revenues | | 292.5 | | | 154.9 | | | 414.5 | | | 451.5 | | | 3.2 | | | (371.6) | | | 945.0 | |
| | | | | | | | | | | | | | |
| Other Revenues from Contracts with Customers (b) | | 61.6 | | | 53.8 | | | (0.2) | | | 8.6 | | | 13.9 | | | (18.6) | | | 119.1 | |
| | | | | | | | | | | | | | |
| Total Revenues from Contracts with Customers | | 2,688.2 | | | 1,243.9 | | | 414.3 | | | 460.1 | | | 17.1 | | | (390.6) | | | 4,433.0 | |
| | | | | | | | | | | | | | |
| Other Revenues: | | | | | | | | | | | | | | |
| Alternative Revenue Programs (d) | | (0.8) | | | (3.4) | | | (2.9) | | | — | | | — | | | 1.3 | | | (5.8) | |
| Other Revenues (b) (e) | | — | | | 6.3 | | | — | | | 159.2 | | | 2.8 | | | (2.9) | | | 165.4 | |
| Total Other Revenues | | (0.8) | | | 2.9 | | | (2.9) | | | 159.2 | | | 2.8 | | | (1.6) | | | 159.6 | |
| | | | | | | | | | | | | | |
| Total Revenues | | $ | 2,687.4 | | | $ | 1,246.8 | | | $ | 411.4 | | | $ | 619.3 | | | $ | 19.9 | | | $ | (392.2) | | | $ | 4,592.6 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $327 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 $9 million. The remaining affiliated amounts were immaterial.
(d)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.
(e)Generation & Marketing includes economic hedge activity.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2023 |
| | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
| Retail Revenues: | | | | | | | | | | | | | | |
| Residential Revenues | | $ | 130.7 | | | $ | — | | | $ | 470.5 | | | $ | 239.6 | | | $ | 526.0 | | | $ | 170.9 | | | $ | 175.9 | |
| Commercial Revenues | | 97.3 | | | — | | | 171.3 | | | 138.9 | | | 278.5 | | | 109.1 | | | 143.5 | |
| Industrial Revenues | | 39.3 | | | — | | | 185.8 | | | 152.6 | | | 173.6 | | | 98.3 | | | 104.2 | |
| Other Retail Revenues | | 8.3 | | | — | | | 26.2 | | | 1.3 | | | 3.8 | | | 24.2 | | | 2.6 | |
| Total Retail Revenues | | 275.6 | | | — | | | 853.8 | | | 532.4 | | | 981.9 | | | 402.5 | | | 426.2 | |
| | | | | | | | | | | | | | |
| Wholesale Revenues: | | | | | | | | | | | | | | |
| Generation Revenues (a) | | — | | | — | | | 80.2 | | | 104.0 | | | — | | | 0.9 | | | 39.6 | |
| Transmission Revenues (b) | | 146.3 | | | 438.7 | | | 41.4 | | | 8.1 | | | 17.9 | | | 11.3 | | | 42.9 | |
| Total Wholesale Revenues | | 146.3 | | | 438.7 | | | 121.6 | | | 112.1 | | | 17.9 | | | 12.2 | | | 82.5 | |
| | | | | | | | | | | | | | |
| Other Revenues from Contracts with Customers (c) | | 9.7 | | | 3.7 | | | 13.0 | | | 21.4 | | | 33.2 | | | 2.3 | | | 7.9 | |
| | | | | | | | | | | | | | |
| Total Revenues from Contracts with Customers | | 431.6 | | | 442.4 | | | 988.4 | | | 665.9 | | | 1,033.0 | | | 417.0 | | | 516.6 | |
| | | | | | | | | | | | | | |
| Other Revenues: | | | | | | | | | | | | | | |
| Alternative Revenue Programs (d) | | (2.1) | | | (0.8) | | | (0.7) | | | (2.9) | | | (9.5) | | | — | | | (0.7) | |
| Other Revenues (e) | | — | | | — | | | — | | | — | | | 11.1 | | | — | | | — | |
| Total Other Revenues | | (2.1) | | | (0.8) | | | (0.7) | | | (2.9) | | | 1.6 | | | — | | | (0.7) | |
| | | | | | | | | | | | | | |
| Total Revenues | | $ | 429.5 | | | $ | 441.6 | | | $ | 987.7 | | | $ | 663.0 | | | $ | 1,034.6 | | | $ | 417.0 | | | $ | 515.9 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $47 million primarily related to the PPA with KGPCo.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $349 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $18 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.
(e)Amounts include affiliated and nonaffiliated revenues.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2022 |
| | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
| Retail Revenues: | | | | | | | | | | | | | | |
| Residential Revenues | | $ | 141.9 | | | $ | — | | | $ | 458.0 | | | $ | 231.8 | | | $ | 458.7 | | | $ | 165.9 | | | $ | 175.9 | |
| Commercial Revenues | | 94.9 | | | — | | | 153.9 | | | 126.6 | | | 194.7 | | | 97.5 | | | 130.5 | |
| Industrial Revenues | | 30.6 | | | — | | | 153.8 | | | 136.5 | | | 102.7 | | | 78.6 | | | 84.7 | |
| Other Retail Revenues | | 8.2 | | | — | | | 20.6 | | | 1.3 | | | 3.3 | | | 21.2 | | | 2.4 | |
| Total Retail Revenues | | 275.6 | | | — | | | 786.3 | | | 496.2 | | | 759.4 | | | 363.2 | | | 393.5 | |
| | | | | | | | | | | | | | |
| Wholesale Revenues: | | | | | | | | | | | | | | |
| Generation Revenues (a) | | — | | | — | | | 56.2 | | | 90.4 | | | — | | | 9.5 | | | 61.2 | |
| Transmission Revenues (b) | | 133.1 | | | 400.3 | | | 41.1 | | | 8.8 | | | 21.8 | | | 9.6 | | | 35.2 | |
| Total Wholesale Revenues | | 133.1 | | | 400.3 | | | 97.3 | | | 99.2 | | | 21.8 | | | 19.1 | | | 96.4 | |
| | | | | | | | | | | | | | |
| Other Revenues from Contracts with Customers (c) | | 9.3 | | | (0.3) | | | 24.3 | | | 29.9 | | | 44.6 | | | 5.4 | | | 5.3 | |
| | | | | | | | | | | | | | |
| Total Revenues from Contracts with Customers | | 418.0 | | | 400.0 | | | 907.9 | | | 625.3 | | | 825.8 | | | 387.7 | | | 495.2 | |
| | | | | | | | | | | | | | |
| Other Revenues: | | | | | | | | | | | | | | |
| Alternative Revenue Programs (d) | | (1.3) | | | 0.4 | | | (0.7) | | | — | | | (2.1) | | | (0.1) | | | (0.4) | |
| Other Revenues (e) | | — | | | — | | | 0.1 | | | (0.1) | | | 6.3 | | | — | | | — | |
| Total Other Revenues | | (1.3) | | | 0.4 | | | (0.6) | | | (0.1) | | | 4.2 | | | (0.1) | | | (0.4) | |
| | | | | | | | | | | | | | |
| Total Revenues | | $ | 416.7 | | | $ | 400.4 | | | $ | 907.3 | | | $ | 625.2 | | | $ | 830.0 | | | $ | 387.6 | | | $ | 494.8 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $36 million primarily related to the PPA with KGPCo.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $323 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $10 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.
(e)Amounts include affiliated and nonaffiliated revenues.
Fixed Performance Obligations (Applies to AEP, APCo and I&M)
The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of March 31, 2023. Fixed performance obligations primarily include electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market. The Registrants elected to apply the exemption to not disclose the value of unsatisfied performance obligations for contracts with an original expected term of one year or less. Due to the annual establishment of revenue requirements, transmission revenues are excluded from the table below. The Registrant Subsidiaries amounts shown in the table below include affiliated and nonaffiliated revenues.
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| Company | | 2023 | | 2024-2025 | | 2026-2027 | | After 2027 | | Total |
| | (in millions) |
| AEP | | $ | 63.4 | | | $ | 160.5 | | | $ | 137.1 | | | $ | 61.0 | | | $ | 422.0 | |
| | | | | | | | | | |
| | | | | | | | | | |
| APCo | | 12.1 | | | 32.2 | | | 24.3 | | | 11.7 | | | 80.3 | |
| I&M | | 3.4 | | | 9.2 | | | 9.2 | | | 4.6 | | | 26.4 | |
| | | | | | | | | | |
| | | | | | | | | | |
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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 material contract assets as of March 31, 2023 and December 31, 2022.
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 sheets 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 material contract liabilities as of March 31, 2023 and December 31, 2022.
Accounts Receivable from Contracts with Customers
Accounts receivable from contracts with customers are presented on the Registrant Subsidiaries’ balance sheets within the Accounts Receivable - Customers line item. The Registrant Subsidiaries’ 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 March 31, 2023 and December 31, 2022. See “Securitized Accounts Receivable - AEP Credit” section of Note 12 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:
| | | | | | | | | | | | | | |
| Company | | March 31, 2023 | | December 31, 2022 |
| | (in millions) |
| AEP Texas | | $ | — | | | $ | 0.1 | |
| AEPTCo | | 122.5 | | | 113.8 | |
| APCo | | 65.1 | | | 64.5 | |
| I&M | | 56.4 | | | 75.3 | |
| OPCo | | 57.5 | | | 49.9 | |
| PSO | | 12.7 | | | 18.8 | |
| SWEPCo | | 19.6 | | | 19.1 | |
CONTROLS AND PROCEDURES
During the thirdfirst quarter of 2017,2023, management, including the principal executive officer and principal financial officer of each of the Registrants, evaluated the Registrants’ disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants 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 SEC’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 the Registrants’ 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 September 30, 2017,March 31, 2023, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives.
There was no change 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 thirdfirst quarter of 20172023 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
For a discussion of material legal proceedings, see “Commitments, Guarantees and Contingencies,” of Note 5incorporated herein by reference.
Item 1A. Risk Factors
The AEP 2016 Annual Report on Form 10-K andfor the AEPTCo 2016 Annual Report included within AEPTCo’s Registration Statementyear ended December 31, 2022 includes a detailed discussion of risk factors. As of September 30, 2017,March 31, 2023, there have been no material changes to the risk factors previously disclosed in AEPTCo’s Registration Statement. As of September 30, 2017, the risk factor appearing in AEP’s 20162022 Annual Report under the heading set forth below is supplemented and updated as follows:on Form 10-K.
AEP is exposed to nuclear generation risk. (Applies to AEP and I&M)
Through I&M, AEP owns the Cook Plant. It consists of two nuclear generating units for a rated capacity of 2,278 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 spent nuclear fuel.
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.
Uncertainties related to reliance on a vendor for manufacturing nuclear fuel and for providing specialized engineering services and parts.
There can be no assurance that I&M’s preparations or risk mitigation measures will be adequate if these risks are triggered.
The Nuclear Regulatory Commission 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.
Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication, and ongoing engineering projects. The most significant of these relate to Cook Plant fuel fabrication. In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the U.S. Bankruptcy Code. It intends to reorganize, not cease business operations. However, it is in the early stages of the bankruptcy process and it is unclear whether the company can successfully reorganize. In the event Westinghouse rejects I&M’s contracts, or is unable to reorganize or sell its profitable businesses in the bankruptcy, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services.
AEP’s transmission investment strategy and execution bears certain risks associated with these activities. (Applies to all Registrants)
Management expects that a growing portion of AEP’s earnings in the future will be 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 or other RTOs will authorize new transmission projects or will award such projects to AEP.
In October 2016, several parties filed a joint complaint with the FERC claiming that the base return on common equity used by eastern AEP affiliates in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint. In June 2017, several parties filed a joint complaint with the FERC that states the base return on common equity used by western AEP affiliates, including the State Transcos that operate in SPP, in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36%, effective upon the date of the complaint. If the FERC orders revenue reductions as a result of these complaints, including refunds from the date each complaint was filed, it could reduce future net income and cash flows and impact financial condition.
If the FERC were to lower the rate of return it has authorized for AEP’s transmission investments and facilities, or if one or more states were to successfully limit FERC jurisdiction on recovery of costs on transmission investment and its return, it could reduce future net income and cash flows and negatively impact financial condition.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None
Item 3. Defaults Upon Senior Securities
None
Item 4. Mine Safety Disclosures
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 September 30, 2017.March 31, 2023.
Item 5. Other Information
NoneNone.
Item 6. Exhibits
The documents designated with an (*) below have previously been filed on behalf of the Registrants shown and are incorporated herein by reference to the documents indicated and made a part hereof.
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| Exhibit | | Description | | Previously Filed as Exhibit to: |
| | |
| AEP‡ File No. 1-3525 | | |
| | |
| 4(a) | | Company Order and Officer’s Certificate between AEP and The Bank of New York Mellon Trust Company, N.A. as Trustee dated March 1, 2023 establishing terms of the 5.625% Senior Notes, Series Q, due 2033. | | |
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| | | | |
| | |
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| | | | |
| AEPTCo‡ File No. 333-217143 | | |
| | | | |
| 4 | | Company Order and Officer’s Certificate between AEP Transmission Company and The Bank of New York Mellon Trust Company, N.A. as Trustee dated March 13, 2023 establishing terms of the 5.40% Senior Notes, Series P, due 2053. | | |
| | |
| | | | |
| | | | |
| | | | |
| I&M‡ File No. 1-3570 | | |
| | | | |
| 4 | | Company Order and Officer’s Certificate between Indiana Michigan Power Company and The Bank of New York Mellon Trust Company, N.A. as Trustee dated March 23, 2023 establishing terms of the 5.625% Senior Notes, Series P, due 2053. | | |
| | |
| | | | |
| | | | |
| | |
| | | | |
| | | | |
| SWEPCo‡ File No. 1-3146 | | |
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| 4 | | Sixteenth Supplemental Indenture dated as of March 1, 2023 between Southwestern Electric Power Company and The Bank of New York Mellon Trust Company, N.A. as Trustee establishing terms of the 5.30% Senior Notes, Series P, due 2033. | | |
| | | | |
The exhibits designated with an (X) in the table below are being filed on behalf of the Registrants.
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| Exhibit | | Description | | AEP | | AEPTCoAEP
Texas | | APCoAEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
124(b) | | Computation of Consolidated Ratio of EarningsMarch 31, 2023 Amendment and extension to Fixed Charges$1,000,000,000 Credit Agreement dated March 31, 2021 among the Company Initial Lenders and Wells Fargo Bank National Association as Administrative Agent. | | | | | | | | | | | | | | | | |
| 31(a) | | Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | | | | | | | | | | | | | | | | |
| 31(b) | | Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | | | | | | | | | | | | | | | | |
| 32(a) | | Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code | | | | | | | | | | | | | | | | |
| 32(b) | | Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code | | | | | | | | | | | | | | | | |
| 95 | | Mine Safety Disclosures | | | | | | | | | | | | | | | | |
| 101.INS | | XBRL Instance Document | | X | | X | | X | | X | | X | | X | | XThe instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document. |
| 101.SCH | | XBRL Taxonomy Extension Schema | | X | | X | | X | | X | | X | | X | | X | | X |
| 101.CAL | | XBRL Taxonomy Extension Calculation Linkbase | | X | | X | | X | | X | | X | | X | | X | | X |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
101.DEFExhibit | | Description | | AEP | | AEP
Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| 101.DEF | | XBRL Taxonomy Extension Definition Linkbase | | X | | X | | X | | X | | X | | X | | X | | X |
| 101.LAB | | XBRL Taxonomy Extension Label Linkbase | | X | | X | | X | | X | | X | | X | | X | | X |
| 101.PRE | | XBRL Taxonomy Extension Presentation Linkbase | | X | | X | | X | | X | | X | | X | | X | | X |
| 104 | | Cover Page Interactive Data File | | Formatted as Inline XBRL and contained in Exhibit 101. |
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
AMERICAN ELECTRIC POWER COMPANY, INC.
By: /s/ Joseph M. Buonaiuto
Joseph M. Buonaiuto
Controller and Chief Accounting Officer
AEP TEXAS INC.
AEP TRANSMISSION COMPANY, LLC
APPALACHIAN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
OHIO POWER COMPANY
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY
By: /s/ Joseph M. Buonaiuto
Joseph M. Buonaiuto
Controller and Chief Accounting Officer
Date: October 26, 2017
May 4, 2023