|
| | | | |
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, andAcquisitions, Assets and Liabilities Held for Sale, Dispositions and Impairments | | 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 | | |
| | | | |
Property, Plant and Equipment | | AEP, PSO, SWEPCo | | |
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 ninesix months ended SeptemberJune 30, 20172022 is not necessarily indicative of results that may be expected for the year ending December 31, 2017.2022. The condensed financial statements are unaudited and should be read in conjunction with the audited 20162021 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 read24, 2022.
AEP System Tax Allocation
The Registrant Subsidiaries join in conjunction with the audited 2016filing of a consolidated tax return. Historically, the allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocated the benefit of current tax loss of the parent company (Parent Company Loss Benefit) to the AEP System subsidiaries through a reduction of current tax expense. In the first quarter of 2022, AEP and subsidiaries changed accounting for the Parent Company Loss Benefit from a reduction of current tax expense to an allocation through equity. The impact of this change was immaterial to the Registrant Subsidiaries’ financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 2017.statements.
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 June 30, |
| 2022 | | 2021 |
| (in millions, except per share data) |
| | | $/share | | | | $/share |
| | | | | | | |
| | | | | | | |
Earnings Attributable to AEP Common Shareholders | $ | 524.5 | | | | | $ | 578.2 | | | |
| | | | | | | |
Weighted-Average Number of Basic AEP Common Shares Outstanding | 513.6 | | | $ | 1.02 | | | 499.9 | | | $ | 1.16 | |
Weighted-Average Dilutive Effect of Stock-Based Awards | 1.6 | | | — | | | 1.1 | | | (0.01) | |
Weighted-Average Number of Diluted AEP Common Shares Outstanding | 515.2 | | | $ | 1.02 | | | 501.0 | | | $ | 1.15 | |
|
| | | | | | | | | | | | | | | |
| 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 | ) |
| | | | | | | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, |
| 2022 | | 2021 |
| (in millions, except per share data) |
| | | $/share | | | | $/share |
| | | | | | | |
| | | | | | | |
Earnings Attributable to AEP Common Shareholders | $ | 1,239.2 | | | | | $ | 1,153.2 | | | |
| | | | | | | |
Weighted-Average Number of Basic AEP Common Shares Outstanding | 509.9 | | | $ | 2.43 | | | 498.5 | | | $ | 2.31 | |
Weighted-Average Dilutive Effect of Stock-Based Awards | 1.5 | | | (0.01) | | | 1.1 | | | — | |
Weighted-Average Number of Diluted AEP Common Shares Outstanding | 511.4 | | | $ | 2.42 | | | 499.6 | | | $ | 2.31 | |
|
| | | | | | | | | | | | | | | |
| 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 |
|
Equity Units are potentially dilutive securities and were excluded from the calculation of diluted EPS for the three and six months ended June 30, 2022 and 2021, as the dilutive stock price threshold was not met. See Note 12 - Financing Activities for more information related to Equity Units.
There were no antidilutive shares outstanding as of SeptemberJune 30, 20172022 and 2016.2021, respectively.
Nonconsolidated Variable Interest EntityRestricted 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:
| | | | | | | | | | | | | | | | | | | | |
| | June 30, 2022 |
| | AEP | | AEP Texas | | APCo |
| | (in millions) |
Cash and Cash Equivalents | | $ | 575.3 | | | $ | 0.1 | | | $ | 4.9 | |
Restricted Cash | | 45.9 | | | 29.7 | | | 16.2 | |
Total Cash, Cash Equivalents and Restricted Cash | | $ | 621.2 | | | $ | 29.8 | | | $ | 21.1 | |
Supplementary Cash Flow Information (Applies to AEP)
| | | | | | | | | | | | | | | | | | | | |
| | December 31, 2021 |
| | AEP | | AEP Texas | | APCo |
| | (in millions) |
Cash and Cash Equivalents | | $ | 403.4 | | | $ | 0.1 | | | $ | 2.5 | |
Restricted Cash | | 48.0 | | | 30.4 | | | 17.6 | |
Total Cash, Cash Equivalents and Restricted Cash | | $ | 451.4 | | | $ | 30.5 | | | $ | 20.1 | |
|
| | | | | | | | |
| | 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
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2017 | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | Pension | | |
Three Months Ended June 30, 2022 | | Commodity | | Interest Rate | | and OPEB | | Total |
| | (in millions) |
Balance in AOCI as of March 31, 2022 | | $ | 404.0 | | | $ | (13.6) | | | $ | 40.2 | | | $ | 430.6 | |
Change in Fair Value Recognized in AOCI | | 257.3 | | | 2.0 | | (a) | — | | | 259.3 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
Generation & Marketing Revenues (b) | | 0.1 | | | — | | | — | | | 0.1 | |
Purchased Electricity for Resale (b) | | (161.8) | | | — | | | — | | | (161.8) | |
Interest Expense (b) | | — | | | 1.1 | | | — | | | 1.1 | |
Amortization of Prior Service Cost (Credit) | | — | | | — | | | (5.4) | | | (5.4) | |
Amortization of Actuarial (Gains) Losses | | — | | | — | | | 2.1 | | | 2.1 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | (161.7) | | | 1.1 | | | (3.3) | | | (163.9) | |
Income Tax (Expense) Benefit | | (34.0) | | | 0.3 | | | (0.7) | | | (34.4) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | (127.7) | | | 0.8 | | | (2.6) | | | (129.5) | |
Reclassifications of KPCo Pension and OPEB Regulatory Assets to AOCI | | — | | | — | | | (11.4) | | | (11.4) | |
Income Tax (Expense) Benefit | | — | | | — | | | (2.4) | | | (2.4) | |
Reclassifications of KPCo Pension and OPEB Regulatory Assets to AOCI, Net of Income Tax (Expense) Benefit | | — | | | — | | | (9.0) | | | (9.0) | |
Net Current Period Other Comprehensive Income (Loss) | | 129.6 | | | 2.8 | | | (11.6) | | | 120.8 | |
Balance in AOCI as of June 30, 2022 | | $ | 533.6 | | | $ | (10.8) | | | $ | 28.6 | | | $ | 551.4 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | Pension | | |
Three Months Ended June 30, 2021 | | Commodity | | Interest Rate | | and OPEB | | Total |
| | (in millions) |
Balance in AOCI as of March 31, 2021 | | $ | (18.5) | | | $ | (33.3) | | | $ | 21.0 | | | $ | (30.8) | |
Change in Fair Value Recognized in AOCI | | 136.4 | | | (0.4) | | (a) | — | | | 136.0 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
Generation & Marketing Revenues (b) | | (0.1) | | | — | | | — | | | (0.1) | |
Purchased Electricity for Resale (b) | | (9.5) | | | — | | | — | | | (9.5) | |
Interest Expense (b) | | — | | | 1.8 | | | — | | | 1.8 | |
Amortization of Prior Service Cost (Credit) | | — | | | — | | | (4.9) | | | (4.9) | |
Amortization of Actuarial (Gains) Losses | | — | | | — | | | 2.2 | | | 2.2 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | (9.6) | | | 1.8 | | | (2.7) | | | (10.5) | |
Income Tax (Expense) Benefit | | (2.0) | | | 0.3 | | | (0.6) | | | (2.3) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | (7.6) | | | 1.5 | | | (2.1) | | | (8.2) | |
Net Current Period Other Comprehensive Income (Loss) | | 128.8 | | | 1.1 | | | (2.1) | | | 127.8 | |
Balance in AOCI as of June 30, 2021 | | $ | 110.3 | | | $ | (32.2) | | | $ | 18.9 | | | $ | 97.0 | |
|
| | | | | | | | | | | | | | | | | | | |
| 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 Hedges | | Pension | | |
Six Months Ended June 30, 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 | | 535.5 | | | 8.8 | | (a) | — | | | 544.3 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
Purchased Electricity for Resale (b) | | (209.7) | | | — | | | — | | | (209.7) | |
Interest Expense (b) | | — | | | 2.2 | | | — | | | 2.2 | |
Amortization of Prior Service Cost (Credit) | | — | | | — | | | (10.3) | | | (10.3) | |
Amortization of Actuarial (Gains) Losses | | — | | | — | | | 4.2 | | | 4.2 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | (209.7) | | | 2.2 | | | (6.1) | | | (213.6) | |
Income Tax (Expense) Benefit | | (44.1) | | | 0.5 | | | (1.3) | | | (44.9) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | (165.6) | | | 1.7 | | | (4.8) | | | (168.7) | |
Reclassifications of KPCo Pension and OPEB Regulatory Assets to AOCI | | — | | | — | | | (11.4) | | | (11.4) | |
Income Tax (Expense) Benefit | | — | | | — | | | (2.4) | | | (2.4) | |
Reclassifications of KPCo Pension and OPEB Regulatory Assets to AOCI, Net of Income Tax (Expense) Benefit | | — | | | — | | | (9.0) | | | (9.0) | |
Net Current Period Other Comprehensive Income (Loss) | | 369.9 | | | 10.5 | | | (13.8) | | | 366.6 | |
Balance in AOCI as of June 30, 2022 | | $ | 533.6 | | | $ | (10.8) | | | $ | 28.6 | | | $ | 551.4 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | Pension | | |
Six Months Ended June 30, 2021 | | Commodity | | Interest Rate | | and OPEB | | Total |
| | (in millions) |
Balance in AOCI as of December 31, 2020 | | $ | (60.6) | | | $ | (47.5) | | | $ | 23.0 | | | $ | (85.1) | |
Change in Fair Value Recognized in AOCI | | 313.7 | | | 12.7 | | (a) | — | | | 326.4 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
Generation & Marketing Revenues (b) | | 0.7 | | | — | | | — | | | 0.7 | |
Purchased Electricity for Resale (b) | | (181.5) | | | — | | | — | | | (181.5) | |
Interest Expense (b) | | — | | | 3.3 | | | — | | | 3.3 | |
Amortization of Prior Service Cost (Credit) | | — | | | — | | | (9.7) | | | (9.7) | |
Amortization of Actuarial (Gains) Losses | | — | | | — | | | 4.5 | | | 4.5 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | (180.8) | | | 3.3 | | | (5.2) | | | (182.7) | |
Income Tax (Expense) Benefit | | (38.0) | | | 0.7 | | | (1.1) | | | (38.4) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | (142.8) | | | 2.6 | | | (4.1) | | | (144.3) | |
Net Current Period Other Comprehensive Income (Loss) | | 170.9 | | | 15.3 | | | (4.1) | | | 182.1 | |
Balance in AOCI as of June 30, 2021 | | $ | 110.3 | | | $ | (32.2) | | | $ | 18.9 | | | $ | 97.0 | |
AEP Texas
| | | | | | | | | | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Three Months Ended June 30, 2022 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of March 31, 2022 | | | | $ | (1.0) | | | $ | (5.2) | | | $ | (6.2) | |
Change in Fair Value Recognized in AOCI | | | | (0.1) | | | — | | | (0.1) | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | 0.3 | | | — | | | 0.3 | |
| | | | | | | | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 0.3 | | | — | | | 0.3 | |
Income Tax (Expense) Benefit | | | | — | | | — | | | — | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0.3 | | | — | | | 0.3 | |
Net Current Period Other Comprehensive Income (Loss) | | | | 0.2 | | | — | | | 0.2 | |
Balance in AOCI as of June 30, 2022 | | | | $ | (0.8) | | | $ | (5.2) | | | $ | (6.0) | |
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2016 | | | | | | | | | | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Three Months Ended June 30, 2021 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of March 31, 2021 | | | | $ | (2.0) | | | $ | (6.6) | | | $ | (8.6) | |
Change in Fair Value Recognized in AOCI | | | | (0.1) | | | — | | | (0.1) | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | 0.3 | | | — | | | 0.3 | |
| | | | | | | | |
Amortization of Actuarial (Gains) Losses | | | | — | | | 0.1 | | | 0.1 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 0.3 | | | 0.1 | | | 0.4 | |
Income Tax (Expense) Benefit | | | | — | | | — | | | — | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0.3 | | | 0.1 | | | 0.4 | |
Net Current Period Other Comprehensive Income (Loss) | | | | 0.2 | | | 0.1 | | | 0.3 | |
Balance in AOCI as of June 30, 2021 | | | | $ | (1.8) | | | $ | (6.5) | | | $ | (8.3) | |
|
| | | | | | | | | | | | | | | | | | | |
| 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 | ) |
AEP Texas | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Six Months Ended June 30, 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 | | | | (0.1) | | | — | | | (0.1) | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | 0.7 | | | — | | | 0.7 | |
| | | | | | | | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 0.7 | | | — | | | 0.7 | |
Income Tax (Expense) Benefit | | | | 0.1 | | | — | | | 0.1 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0.6 | | | — | | | 0.6 | |
Net Current Period Other Comprehensive Income (Loss) | | | | 0.5 | | | — | | | 0.5 | |
Balance in AOCI as of June 30, 2022 | | | | $ | (0.8) | | | $ | (5.2) | | | $ | (6.0) | |
AEP
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2017 | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Six Months Ended June 30, 2021 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of December 31, 2020 | | | | $ | (2.3) | | | $ | (6.6) | | | $ | (8.9) | |
Change in Fair Value Recognized in AOCI | | | | — | | | — | | | — | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | 0.6 | | | — | | | 0.6 | |
| | | | | | | | |
Amortization of Actuarial (Gains) Losses | | | | — | | | 0.1 | | | 0.1 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 0.6 | | | 0.1 | | | 0.7 | |
Income Tax (Expense) Benefit | | | | 0.1 | | | — | | | 0.1 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0.5 | | | 0.1 | | | 0.6 | |
Net Current Period Other Comprehensive Income (Loss) | | | | 0.5 | | | 0.1 | | | 0.6 | |
Balance in AOCI as of June 30, 2021 | | | | $ | (1.8) | | | $ | (6.5) | | | $ | (8.3) | |
|
| | | | | | | | | | | | | | | | | | | |
| 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 | ) |
AEP
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2016
|
| | | | | | | | | | | | | | | | | | | |
| 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 | ) |
APCo
| | | | | | | | | | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Three Months Ended June 30, 2022 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of March 31, 2022 | | | | $ | 7.3 | | | $ | 15.8 | | | $ | 23.1 | |
Change in Fair Value Recognized in AOCI | | | | — | | | — | | | — | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | (0.2) | | | — | | | (0.2) | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (1.3) | | | (1.3) | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | (0.2) | | | (1.3) | | | (1.5) | |
Income Tax (Expense) Benefit | | | | — | | | (0.3) | | | (0.3) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | (0.2) | | | (1.0) | | | (1.2) | |
Net Current Period Other Comprehensive Income (Loss) | | | | (0.2) | | | (1.0) | | | (1.2) | |
Balance in AOCI as of June 30, 2022 | | | | $ | 7.1 | | | $ | 14.8 | | | $ | 21.9 | |
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2017 | | | | | | | | | | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Three Months Ended June 30, 2021 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of March 31, 2021 | | | | $ | 8.2 | | | $ | 6.9 | | | $ | 15.1 | |
Change in Fair Value Recognized in AOCI | | | | (0.2) | | | — | | | (0.2) | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (1.3) | | | (1.3) | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | — | | | (1.3) | | | (1.3) | |
Income Tax (Expense) Benefit | | | | — | | | (0.3) | | | (0.3) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | — | | | (1.0) | | | (1.0) | |
Net Current Period Other Comprehensive Income (Loss) | | | | (0.2) | | | (1.0) | | | (1.2) | |
Balance in AOCI as of June 30, 2021 | | | | $ | 8.0 | | | $ | 5.9 | | | $ | 13.9 | |
|
| | | | | | | | | | | | |
| | 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 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
APCo | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Six Months Ended June 30, 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 | | | | — | | | — | | | — | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | (0.5) | | | — | | | (0.5) | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (2.7) | | | (2.7) | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | (0.5) | | | (2.7) | | | (3.2) | |
Income Tax (Expense) Benefit | | | | (0.1) | | | (0.6) | | | (0.7) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | (0.4) | | | (2.1) | | | (2.5) | |
Net Current Period Other Comprehensive Income (Loss) | | | | (0.4) | | | (2.1) | | | (2.5) | |
Balance in AOCI as of June 30, 2022 | | | | $ | 7.1 | | | $ | 14.8 | | | $ | 21.9 | |
APCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2016 | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Six Months Ended June 30, 2021 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of December 31, 2020 | | | | $ | (0.8) | | | $ | 8.0 | | | $ | 7.2 | |
Change in Fair Value Recognized in AOCI | | | | 9.1 | | | — | | | 9.1 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | (0.4) | | | — | | | (0.4) | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (2.7) | | | (2.7) | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | (0.4) | | | (2.7) | | | (3.1) | |
Income Tax (Expense) Benefit | | | | (0.1) | | | (0.6) | | | (0.7) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | (0.3) | | | (2.1) | | | (2.4) | |
Net Current Period Other Comprehensive Income (Loss) | | | | 8.8 | | | (2.1) | | | 6.7 | |
Balance in AOCI as of June 30, 2021 | | | | $ | 8.0 | | | $ | 5.9 | | | $ | 13.9 | |
|
| | | | | | | | | | | | |
| | 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 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
I&M | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Three Months Ended June 30, 2022 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of March 31, 2022 | | | | $ | (6.3) | | | $ | 5.3 | | | $ | (1.0) | |
Change in Fair Value Recognized in AOCI | | | | — | | | — | | | — | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | 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 June 30, 2022 | | | | $ | (5.9) | | | $ | 5.2 | | | $ | (0.7) | |
APCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2017 | | | | | | | | | | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Three Months Ended June 30, 2021 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of March 31, 2021 | | | | $ | (7.8) | | | $ | 1.3 | | | $ | (6.5) | |
Change in Fair Value Recognized in AOCI | | | | — | | | — | | | — | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | 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 June 30, 2021 | | | | $ | (7.4) | | | $ | 1.2 | | | $ | (6.2) | |
|
| | | | | | | | | | | | |
| | 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 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
I&M | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Six Months Ended June 30, 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 | | | | — | | | — | | | — | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | 1.0 | | | — | | | 1.0 | |
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) Benefit | | | | 1.0 | | | (0.2) | | | 0.8 | |
Income Tax (Expense) Benefit | | | | 0.2 | | | — | | | 0.2 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0.8 | | | (0.2) | | | 0.6 | |
Net Current Period Other Comprehensive Income (Loss) | | | | 0.8 | | | (0.2) | | | 0.6 | |
Balance in AOCI as of June 30, 2022 | | | | $ | (5.9) | | | $ | 5.2 | | | $ | (0.7) | |
APCo
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2016 | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Six Months Ended June 30, 2021 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of December 31, 2020 | | | | $ | (8.3) | | | $ | 1.3 | | | $ | (7.0) | |
Change in Fair Value Recognized in AOCI | | | | — | | | — | | | — | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | 1.1 | | | — | | | 1.1 | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (0.4) | | | (0.4) | |
Amortization of Actuarial (Gains) Losses | | | | — | | | 0.3 | | | 0.3 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 1.1 | | | (0.1) | | | 1.0 | |
Income Tax (Expense) Benefit | | | | 0.2 | | | — | | | 0.2 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0.9 | | | (0.1) | | | 0.8 | |
Net Current Period Other Comprehensive Income (Loss) | | | | 0.9 | | | (0.1) | | | 0.8 | |
Balance in AOCI as of June 30, 2021 | | | | $ | (7.4) | | | $ | 1.2 | | | $ | (6.2) | |
|
| | | | | | | | | | | | |
| | 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 | ) |
| | | | | | | | | | | | | | |
PSO | | | | | | | | |
| | | | Cash Flow Hedge – | | | | |
Three Months Ended June 30, 2022 | | | | Interest Rate | | | | |
| | | (in millions) |
Balance in AOCI as of March 31, 2022 | | | | $ | — | | | | | |
Change in Fair Value Recognized in AOCI | | | | — | | | | | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | — | | | | | |
| | | | | | | | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | — | | | | | |
Income Tax (Expense) Benefit | | | | — | | | | | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | — | | | | | |
Net Current Period Other Comprehensive Income (Loss) | | | | — | | | | | |
Balance in AOCI as of June 30, 2022 | | | | $ | — | | | | | |
| | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | | | |
Three Months Ended June 30, 2021 | | | | Interest Rate | | | | |
| | | (in millions) |
Balance in AOCI as of March 31, 2021 | | | | $ | — | | | | | |
Change in Fair Value Recognized in AOCI | | | | — | | | | | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | — | | | | | |
| | | | | | | | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | — | | | | | |
Income Tax (Expense) Benefit | | | | — | | | | | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | — | | | | | |
Net Current Period Other Comprehensive Income (Loss) | | | | — | | | | | |
Balance in AOCI as of June 30, 2021 | | | | $ | — | | | | | |
I&M | | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | | | |
Six Months Ended June 30, 2022 | | | | Interest Rate | | | | |
| | | (in millions) |
Balance in AOCI as of December 31, 2021 | | | | $ | — | | | | | |
Change in Fair Value Recognized in AOCI | | | | — | | | | | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | — | | | | | |
| | | | | | | | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | — | | | | | |
Income Tax (Expense) Benefit | | | | — | | | | | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | — | | | | | |
Net Current Period Other Comprehensive Income (Loss) | | | | — | | | | | |
Balance in AOCI as of June 30, 2022 | | | | $ | — | | | | | |
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2017 | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | | | |
Six Months Ended June 30, 2021 | | | | Interest Rate | | | | |
| | | (in millions) |
Balance in AOCI as of December 31, 2020 | | | | $ | 0.1 | | | | | |
Change in Fair Value Recognized in AOCI | | | | — | | | | | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | (0.1) | | | | | |
| | | | | | | | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | (0.1) | | | | | |
Income Tax (Expense) Benefit | | | | — | | | | | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | (0.1) | | | | | |
Net Current Period Other Comprehensive Income (Loss) | | | | (0.1) | | | | | |
Balance in AOCI as of June 30, 2021 | | | | $ | — | | | | | |
|
| | | | | | | | | | | | |
| | 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 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
SWEPCo | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Three Months Ended June 30, 2022 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of March 31, 2022 | | | | $ | 1.3 | | | $ | 5.1 | | | $ | 6.4 | |
Change in Fair Value Recognized in AOCI | | | | — | | | — | | | — | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | (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) | | | (0.6) | |
Income Tax (Expense) Benefit | | | | — | | | (0.1) | | | (0.1) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | (0.1) | | | (0.4) | | | (0.5) | |
Net Current Period Other Comprehensive Income (Loss) | | | | (0.1) | | | (0.4) | | | (0.5) | |
Balance in AOCI as of June 30, 2022 | | | | $ | 1.2 | | | $ | 4.7 | | | $ | 5.9 | |
I&M
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2016 | | | | | | | | | | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Three Months Ended June 30, 2021 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of March 31, 2021 | | | | $ | 0.1 | | | $ | 1.8 | | | $ | 1.9 | |
Change in Fair Value Recognized in AOCI | | | | — | | | — | | | — | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | 0.5 | | | — | | | 0.5 | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (0.5) | | | (0.5) | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 0.5 | | | (0.5) | | | — | |
Income Tax (Expense) Benefit | | | | 0.1 | | | (0.1) | | | — | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0.4 | | | (0.4) | | | — | |
Net Current Period Other Comprehensive Income (Loss) | | | | 0.4 | | | (0.4) | | | — | |
Balance in AOCI as of June 30, 2021 | | | | $ | 0.5 | | | $ | 1.4 | | | $ | 1.9 | |
|
| | | | | | | | | | | | |
| | 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 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
SWEPCo | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Six Months Ended June 30, 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 | | | | — | | | — | | | — | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (1.0) | | | (1.0) | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | — | | | (1.0) | | | (1.0) | |
Income Tax (Expense) Benefit | | | | — | | | (0.2) | | | (0.2) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | — | | | (0.8) | | | (0.8) | |
Net Current Period Other Comprehensive Income (Loss) | | | | — | | | (0.8) | | | (0.8) | |
Balance in AOCI as of June 30, 2022 | | | | $ | 1.2 | | | $ | 4.7 | | | $ | 5.9 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Six Months Ended June 30, 2021 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of December 31, 2020 | | | | $ | (0.3) | | | $ | 2.2 | | | $ | 1.9 | |
Change in Fair Value Recognized in AOCI | | | | — | | | — | | | — | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | 1.0 | | | — | | | 1.0 | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (1.0) | | | (1.0) | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 1.0 | | | (1.0) | | | — | |
Income Tax (Expense) Benefit | | | | 0.2 | | | (0.2) | | | — | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0.8 | | | (0.8) | | | — | |
Net Current Period Other Comprehensive Income (Loss) | | | | 0.8 | | | (0.8) | | | — | |
Balance in AOCI as of June 30, 2021 | | | | $ | 0.5 | | | $ | 1.4 | | | $ | 1.9 | |
(a)The change in fair value includes $1 million and $4 million, respectively, for the three months ended June 30, 2022 and 2021 and $5 million and $0 million, respectively, for the six months ended June 30, 2022 and 2021 related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC.
(b)Amounts reclassified to the referenced line item on the statements of income.
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 2021 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 2021 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 20172022 and updates AEP’sthe 2021 Annual Report.
Coal-Fired Generation Plants (Applies to AEP, PSO and AEPTCo’sSWEPCo)
Compliance with extensive environmental regulations requires significant capital investment in environmental monitoring, installation of pollution control equipment, emission fees, disposal costs and permits. Management continuously evaluates cost estimates of complying with these regulations which has resulted in, and in the future may result in, a decision to retire coal-fired generating facilities earlier than their currently estimated useful lives.
Management is seeking or will seek regulatory recovery, as necessary, for any net book value remaining when the plants are retired. To the extent the net book value of these generation assets are not deemed recoverable, it could materially reduce future net income and cash flows and impact financial condition.
Regulated Generating Units that have been Retired
SWEPCo
In April 2016, Annual Reports.Welsh Plant, Unit 2 was retired. As part of the 2016 Texas Base Rate Case, the PUCT authorized recovery of SWEPCo’s Texas jurisdictional share of Welsh Plant, Unit 2, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $7 million in 2017. See “2016 Texas Base Rate Case” section below for additional information. As part of the 2019 Arkansas Base Rate Case, SWEPCo received approval from the APSC to recover the Arkansas jurisdictional share of Welsh Plant, Unit 2. In December 2020, SWEPCo filed a request with the LPSC to recover the Louisiana jurisdictional share of Welsh Plant, Unit 2. See “2020 Louisiana Base Rate Case” section below for additional information. As of June 30, 2022, SWEPCo had a regulatory asset for plant retirement costs pending approval recorded on its balance sheet of $35 million related to the Louisiana jurisdictional share of Welsh Plant, Unit 2.
In December 2021, the Dolet Hills Power Station was retired. As part of the 2020 Texas Base Rate Case, the PUCT authorized recovery of SWEPCo’s Texas jurisdictional share of the Dolet Hills Power Station, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $12 million in 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 over five years, 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. SWEPCo has requested recovery of the Dolet Hills Power Station in the Louisiana jurisdiction through the 2020 Louisiana Base Rate Case. As of June 30, 2022, SWEPCo had a regulatory asset of $53 million, pending approval, recorded on its balance sheet related to the Louisiana and FERC jurisdictional shares of the Dolet Hills Power Station. The Dolet Hills Power Station is currently being recovered through 2026 in the Louisiana jurisdiction, through 2027 in the Arkansas jurisdiction and through 2046 in the Texas jurisdiction. See “2020 Texas Base Rate Case”, “2020 Louisiana Base Rate Case” and “2021 Arkansas Base Rate Case” sections below for additional information.
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 plans to retire Pirkey Power Plant in 2023 and that it will cease using coal at the Welsh Plant in 2028. As a result of the announcement, SWEPCo began recording a regulatory asset for accelerated depreciation.
The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of June 30, 2022, 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 | | | | | | $ | 151.3 | | | $ | 136.9 | | | | | $ | 20.2 | | (b) | | 2026 | | (c) | | $ | 14.9 | |
Pirkey Power Plant | | | | | | 75.1 | | | 129.3 | | | | | 39.5 | | | | 2023 | | (d) | | 13.2 | |
Welsh Plant, Units 1 and 3 | | | | | | 449.4 | | | 65.9 | | | | | 58.8 | | (e) | | 2028 | | (f) | | 38.4 | |
(a)Represents the amount of annual depreciation that has been collected from customers over the prior 12-month period.
(b)Includes Northeastern Plant, Unit 4, which was retired in 2016. Removal of Northeastern Plant, Unit 4, will be performed with Northeastern Plant, Unit 3, after retirement.
(c)Northeastern Plant, Unit 3 is currently being recovered through 2040.
(d)Pirkey Power Plant is currently being recovered through 2025 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.
(e)Includes Welsh Plant, Unit 2, which was retired in 2016. Removal of Welsh Plant, Unit 2, will be performed with Welsh Plant, Units 1 and 3, after retirement.
(f)Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.
Dolet Hills Power Station and Related Fuel Operations (Applies to AEP and SWEPCo)
In 2020, management of SWEPCo and CLECO determined DHLC would not proceed developing additional Oxbow Lignite Company (Oxbow) mining areas for future lignite extraction and ceased extraction of lignite at the mine in May 2020. In April 2020, SWEPCo and CLECO jointly filed a notification letter to the LPSC providing notice of the cessation of lignite mining. In December 2021, the Dolet Hills Power Station was retired. 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 a combination of base rates and rate riders. As of June 30, 2022, SWEPCo’s share of the net investment in the Dolet Hills Power Station was $113 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 June 30, 2022, SWEPCo had a net under-recovered fuel balance of $187 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 $30 million of additional costs with a recovery period to be determined at a later date. In
November 2021, the LPSC issued a directive which deferred the issues regarding modification of the level and timing of recovery of the Dolet Hills Power Station from SWEPCo’s pending rate case to a separate existing docket. In addition, the recovery of the deferred fuel costs are planned to be addressed.
In March 2021, the APSC approved fuel rates that provide recovery of $20 million for the Arkansas share of the 2021 Dolet Hills Power Station fuel costs over five years through the existing fuel clause.
If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
Pirkey Power Plant and Related Fuel Operations (Applies to AEP and SWEPCo)
In 2020, management announced plans to retire the Pirkey Power Plant in 2023. The Pirkey Power Plant non-fuel costs are recoverable by SWEPCo through base rates and fuel costs are recovered through active fuel clauses and are subject to prudency determinations by the various commissions. As of June 30, 2022, SWEPCo’s share of the net investment in the Pirkey Power Plant was $204 million, including CWIP, before cost of removal. Sabine is a mining operator providing mining services to the Pirkey Power Plant. Under the provisions of the mining agreement, SWEPCo is required to pay, as part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. SWEPCo expects fuel deliveries, including billings of all fixed and operating costs, from Sabine to cease during the first quarter of 2023. Under the fuel agreements, SWEPCo’s fuel inventory and unbilled fuel costs from mining related activities were $79 million as of June 30, 2022. As of June 30, 2022, SWEPCo had a net under-recovered fuel balance of $187 million, inclusive of costs related to the Pirkey Power Plant billed by Sabine, but excluding impacts of the February 2021 severe winter weather event. Upon cessation of lignite deliveries by Sabine to the Pirkey Power Plant, additional operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in existing fuel clauses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except AEPTCo)
| | | | | | | | | | | | | | |
| | AEP |
| | June 30, | | December 31, |
| | 2022 | | 2021 |
Noncurrent Regulatory Assets | | (in millions) |
| | | | |
Regulatory Assets Currently Earning a Return | | | | |
Unrecovered Winter Storm Fuel Costs (a) | | $ | 133.7 | | | $ | 430.2 | |
Pirkey Power Plant Accelerated Depreciation | | 129.3 | | | 87.0 | |
Welsh Plant, Units 1 and 3 Accelerated Depreciation | | 65.9 | | | 45.9 | |
Dolet Hills Power Station Accelerated Depreciation | | 52.8 | | | 72.3 | |
| | | | |
Plant Retirement Costs – Unrecovered Plant, Louisiana | | 35.2 | | | 35.2 | |
| | | | |
| | | | |
Dolet Hills Power Station Fuel Costs - Louisiana | | 31.5 | | | 30.9 | |
Other Regulatory Assets Pending Final Regulatory Approval | | 14.7 | | | 9.2 | |
Regulatory Assets Currently Not Earning a Return | | | | |
Storm-Related Costs | | 322.3 | | | 256.9 | |
Plant Retirement Costs – Asset Retirement Obligation Costs | | 25.9 | | | 25.9 | |
Renewable Energy Portfolio Standards Costs - Virginia | | 14.0 | | | 2.1 | |
COVID-19 | | 11.5 | | | 11.2 | |
| | | | |
| | | | |
| | | | |
| | | | |
Other Regulatory Assets Pending Final Regulatory Approval | | 42.8 | | | 41.8 | |
Total Regulatory Assets Pending Final Regulatory Approval | $ | 879.6 | | | $ | 1,048.6 | |
(a) Includes $37 million and $63 million of unrecovered winter storm fuel costs recorded as a current regulatory asset as of June 30, 2022 and December 31, 2021, respectively.
|
| | | | | | | | |
| | 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 |
|
| |
(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. |
| | | | | | | | | | | | | | |
| | AEP Texas |
| | June 30, | | December 31, |
| | 2022 | | 2021 |
Noncurrent Regulatory Assets | | (in millions) |
| | | | |
Regulatory Assets Currently Earning a Return | | | | |
Mobile Generation Lease Payments | | $ | 4.1 | | | $ | — | |
Regulatory Assets Currently Not Earning a Return | | | | |
Storm-Related Costs | | 26.5 | | | 22.4 | |
Vegetation Management Program | | 5.2 | | | 5.2 | |
Texas Retail Electric Provider Bad Debt Expense | | 4.1 | | | 4.1 | |
COVID-19 | | 3.7 | | | 2.1 | |
Other Regulatory Assets Pending Final Regulatory Approval | | 8.1 | | | 7.4 | |
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 51.7 | | | $ | 41.2 | |
| | | | | | | | | | | | | | |
| | APCo |
| | June 30, | | December 31, |
| | 2022 | | 2021 |
Noncurrent Regulatory Assets | | (in millions) |
| | | | |
Regulatory Assets Currently Earning a Return | | | | |
COVID-19 – Virginia | | $ | 6.9 | | | $ | 6.8 | |
| | | | |
Regulatory Assets Currently Not Earning a Return | | | | |
Storm-Related Costs | | 97.4 | | | 68.8 | |
Plant Retirement Costs – Asset Retirement Obligation Costs | | 25.9 | | | 25.9 | |
| | | | |
Renewable Energy Portfolio Standards Costs - Virginia | | 14.0 | | | 2.1 | |
| | | | |
Other Regulatory Assets Pending Final Regulatory Approval | | 2.1 | | | 1.5 | |
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 146.3 | | | $ | 105.1 | |
| | | | | | | | | | | | | | |
| | I&M |
| | June 30, | | December 31, |
| | 2022 | | 2021 |
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 | | | | |
COVID-19 | | 0.1 | | | 1.7 | |
| | | | |
| | | | |
Other Regulatory Assets Pending Final Regulatory Approval | | 1.5 | | | 1.9 | |
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 1.7 | | | $ | 3.7 | |
|
| | | | | | | | |
| | 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 |
| | June 30, | | December 31, |
| | 2022 | | 2021 |
Noncurrent Regulatory Assets | | (in millions) |
| | | | |
Regulatory Assets Currently Not Earning a Return | | | | |
| | | | |
| | | | |
| | | | |
Storm-Related Costs | | $ | 25.1 | | | $ | 3.8 | |
| | | | |
| | | | |
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 25.1 | | | $ | 3.8 | |
| |
(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. |
| | | | I&M | | | PSO |
| | September 30, | | December 31, | | June 30, | | December 31, |
| | 2017 | | 2016 | | 2022 | | 2021 |
Noncurrent Regulatory Assets | | (in millions) | Noncurrent Regulatory Assets | | (in millions) |
| | | | | | | | | |
| Regulatory Assets Currently Not Earning a Return | | | | | 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 |
| |
| Storm-Related Costs | | Storm-Related Costs | | $ | 20.4 | | | $ | 13.9 | |
Other Regulatory Assets Pending Final Regulatory Approval | | 1.5 |
| | 0.9 |
| Other Regulatory Assets Pending Final Regulatory Approval | | 0.1 | | | 0.3 | |
Total Regulatory Assets Pending Final Regulatory Approval | | $ | 75.3 |
| | $ | 64.7 |
| Total Regulatory Assets Pending Final Regulatory Approval | | $ | 20.5 | | | $ | 14.2 | |
| | | | OPCo | | SWEPCo |
| | September 30, | | December 31, | | June 30, | | December 31, |
| | 2017 | | 2016 | | 2022 | | 2021 |
Noncurrent Regulatory Assets | | (in millions) | Noncurrent Regulatory Assets | | (in millions) |
| | | | | | | | | |
Regulatory Assets Currently Earning a Return | | | | | Regulatory Assets Currently Earning a Return | | | | |
Capacity Deferral | | $ | — |
| | $ | 96.7 |
| |
Unrecovered Winter Storm Fuel Costs (a) | | Unrecovered Winter Storm Fuel Costs (a) | | $ | 133.7 | | | $ | 430.2 | |
Pirkey Power Plant Accelerated Depreciation | | Pirkey Power Plant Accelerated Depreciation | | 129.3 | | | 87.0 | |
Welsh Plant, Units 1 and 3 Accelerated Depreciation | | Welsh Plant, Units 1 and 3 Accelerated Depreciation | | 65.9 | | | 45.9 | |
Dolet Hills Power Station Accelerated Depreciation | | Dolet Hills Power Station Accelerated Depreciation | | 52.8 | | | 72.3 | |
Plant Retirement Costs – Unrecovered Plant, Louisiana | | Plant Retirement Costs – Unrecovered Plant, Louisiana | | 35.2 | | | 35.2 | |
Dolet Hills Power Station Fuel Costs- Louisiana | | Dolet Hills Power Station Fuel Costs- Louisiana | | 31.5 | | | 30.9 | |
Other Regulatory Assets Pending Final Regulatory Approval | | Other Regulatory Assets Pending Final Regulatory Approval | | 3.5 | | | 2.4 | |
Regulatory Assets Currently Not Earning a Return | | |
| | |
| Regulatory Assets Currently Not Earning a Return | | | | |
Smart Grid Costs | | — |
| | 4.1 |
| |
Storm-Related Costs | | Storm-Related Costs | | 151.3 | | | 148.0 | |
Asset Retirement Obligation - Louisiana | | Asset Retirement Obligation - Louisiana | | 11.0 | | | 10.3 | |
| Other Regulatory Assets Pending Final Regulatory Approval | | Other Regulatory Assets Pending Final Regulatory Approval | | 17.5 | | | 18.4 | |
Total Regulatory Assets Pending Final Regulatory Approval | | $ | — |
| | $ | 100.8 |
| Total Regulatory Assets Pending Final Regulatory Approval | | $ | 631.7 | | | $ | 880.6 | |
(a) Includes $37 million and $63 million of unrecovered winter storm fuel costs recorded as a current regulatory asset as of June 30, 2022 and December 31, 2021, respectively.
|
| | | | | | | | |
| | 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 SeptemberThrough June 30, 2017,2022, AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2017,that are subject to review are estimated to be $697is approximately $444 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)
2017-2019 Virginia Legislation Affecting Biennial ReviewsTriennial Review
In 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in MarchNovember 2020, for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo’s 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.
In 2016, the Virginia SCC issued an order on APCo’s 2017-2019 Triennial Review filing concluding that deniedAPCo earned above its authorized ROE but within its ROE band for the petition of certain2017-2019 period, resulting in no refund to customers and no change to APCo industrial customers that requestedbase rates on a prospective basis. The Virginia SCC approved a prospective 9.2% ROE for APCo's 2020-2022 triennial review period with the issuancecontinuation of a declaratory140 basis point band (8.5% bottom, 9.2% midpoint, 9.9% top).
In December 2020, an intervenor filed a petition at the Virginia SCC requesting reconsideration of: (a) the failure of the Virginia SCC to apply a threshold earnings test to the approved regulatory asset for APCo’s closed coal-fired generation assets and (b) the Virginia SCC’s use of a 2011 benchmark study to measure the replacement value of capacity for purposes of APCo’s 2017 – 2019 earnings test.
In December 2020, APCo filed a petition at the Virginia SCC requesting reconsideration of: (a) certain issues related to APCo’s going-forward rates and (b) the Virginia SCC’s decision to deny APCo tariff changes that align rates with underlying costs. For APCo’s going-forward rates, APCo requested that the Virginia SCC clarify its final order and clarify whether APCo’s current rates will allow it to earn a fair return. If the Virginia SCC’s order did conclude that would findAPCo was able to earn a fair return through existing base rates, APCo further requested that the amendmentsVirginia SCC clarify whether it has the authority to also permit an increase in base rates.
In March 2021, an intervenor filed its appeal with the Virginia Supreme Court related to the November 2020 order in which it stated the Virginia SCC erred: (a) in determining that Virginia law suspending biennial reviews unconstitutionaldid not apply to its determination to permit amortization for recovery of costs associated with retired coal-fired generation assets, (b) in establishing a new regulatory asset for a cost incurred outside of the triennial review period due to its failure to apply a threshold earnings test before approving deferred cost recovery and accordingly, direct(c) in misapplying the requirement that APCo bear the burden of demonstrating that power purchases made by APCo from its affiliate, OVEC, were priced at the lower of OVEC’s cost or the market price for nonaffiliated power.
In March 2021, APCo filed its appeal with the Virginia Supreme Court related to the November 2020 order in which it stated the Virginia SCC erred: (a) in finding that costs associated with asset impairments related to early retirement determinations made by APCo for certain generation facilities should not be attributed to the test periods under review and deemed fully recovered in the period recorded, (b) in finding that it was permitted to evaluate the reasonableness of APCo’s decision to record, per books for financial reporting purposes, asset impairments related to early retirement determinations for certain generation facilities, (c) as a result of the errors described in (a) and (b), in denying APCo an increase in rates, (d) in failing to review and make biennial review filings beginningany findings regarding whether APCo’s rates would allow it to earn a fair rate of return going forward, (e) in 2016. denying APCo an increase in base rates by failing to ensure that APCo has an opportunity to recover its costs and earn a fair rate of return, thereby resulting in a taking of private property for public use without just compensation and (f) in retroactively adjusting APCo’s depreciation expense for purposes of calculating APCo’s earnings for the 2017-2019 triennial period.
In July 2016,March 2021, the industrial customersVirginia SCC issued an order confirming certain decisions from the November 2020 order and rejecting the various requests for reconsideration from APCo and an intervenor. In March 2021, APCo filed ana notice of appeal of the reconsideration order with the Virginia Supreme Court. In September 2021, APCo submitted its brief before the Virginia Supreme Court. The brief was in alignment with the previous items of appeal filed by APCo in March 2021. In October 2021, the Virginia SCC and additional intervenors filed briefs with the Virginia Supreme Court disagreeing with the items appealed by APCo in the Triennial Review decision. Additionally, the Virginia SCC and APCo filed briefs disagreeing with the items appealed by an intervenor in a separate appeal of Virginia.the same decision. In September 2017,March 2022, oral arguments were held at the Virginia Supreme Court and APCo is currently awaiting the Virginia Supreme Court’s decision.
APCo ultimately seeks an increase in base rates through its appeal to the Virginia Supreme Court. Among other issues, this appeal includes APCo’s request for proper treatment of the closed coal-fired plant assets in APCo’s 2017-2019 triennial period, reducing APCo’s earnings below the bottom of its authorized ROE band. If APCo’s appeal regarding treatment of the closed coal plants is granted by the Virginia affirmedSupreme Court, it could initially reduce future net income and impact financial condition as a consequence of expensing the closed coal-fired plant regulatory asset established as a result of the Virginia SCC’s 2016 order.decision in the 2017-2019 Triennial Review. A Virginia Supreme Court decision in favor of APCo’s original expensing of the closed coal-fired plant asset balances would likely result in a remand to the Virginia SCC. Upon a subsequent Virginia SCC order, the initial negative impact for the write-off of the closed coal-fired plant asset balances could potentially be offset by an increase in base rates for earning below APCo’s 2017-2019 authorized ROE band.
CCR/ELG Compliance Plan Filings
In December 2020, APCo submitted filings with the Virginia SCC and WVPSC requesting approvals necessary to implement CCR/ELG compliance plans at the Amos and Mountaineer Plants. In August 2021, the Virginia SCC issued an order approving APCo’s request to construct CCR-related investments at the Amos and Mountaineer Plants and approved recovery of CCR-related other operation and maintenance expenses and investments through an active rider. The order denied APCo’s request to construct the ELG investments and denied recovery of previously incurred ELG costs. In March 2022, APCo refiled for approval of the ELG investments and previously incurred ELG costs. A hearing is scheduled to take place in September 2022 and an order is anticipated in the fourth quarter of 2022.
Also in August 2021, the WVPSC approved the request to construct CCR/ELG investments at the Amos and Mountaineer Plants and approved recovery of the West Virginia jurisdictional share of these costs through an active rider. In October 2021, due to the Virginia SCC previously rejecting the ELG investments, the WVPSC issued an order directing APCo to proceed with CCR/ELG compliance plans that would allow the plants to continue operating beyond 2028. The October 2021 order further states that APCo will not share capacity and energy from the plants with customers from Virginia if those customers are not paying for ELG compliance costs, or for any new capital investment or continuing operations costs incurred, to allow the plants to operate beyond 2028 or prevent downgrades prior to 2028. The WVPSC also ordered that APCo will be given the opportunity to recover, from West Virginia customers, the new capital and operating costs arising solely from the WVPSC's directive to operate the plants beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred.
APCo expects total Amos and Mountaineer Plant ELG investment, excluding AFUDC, to be approximately $197 million. As of June 30, 2022, APCo’s Virginia jurisdictional share of the net book value, before cost of removal including CWIP and inventory, of the Amos and Mountaineer Plants was approximately $1.5 billion and APCo’s Virginia jurisdictional share of its ELG investment balance in CWIP for these plants was $56 million.
If any of the ELG costs are not approved for recovery and/or the retirement dates of the Amos and Mountaineer plants are accelerated to 2028 without commensurate cost recovery, it would reduce future net income and cash flows and impact financial condition.
2021 and 2022 ENEC (Expanded Net Energy Cost) Filings
In April 2021, APCo and WPCo (the Companies) requested a $73 million annual increase in ENEC rates based on a cumulative combined $55 million ENEC under-recovery as of February 28, 2021 and a combined $18 million increase in projected ENEC costs for the period September 2021 through August 2022. In September 2021, the WVPSC issued an order approving a $7 million overall increase in ENEC rates, including an approval 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 WVPSC requesting a $297 million annual increase in ENEC revenues, inclusive of the previously requested $155 million increase, effective September 1, 2022. The procedural schedule is currently stayed amid negotiations to agree to a modified procedural schedule that suits all parties.As of June 30, 2022, the Companies’ cumulative ENEC under-recovery was $375 million. If any deferred ENEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
June 2022 Storm Costs
In June 2022, the service territories of APCo and WPCo (the Companies) were impacted by strong winds from multiple storms resulting in system damages and power outages. As of June 30, 2022, the Companies incurred and deferred an estimated $7 million and $17 million in incremental distribution operation and maintenance expenses in Virginia and West Virginia, respectively, related to service restoration efforts. The Companies will seek recovery of these deferrals in future filings. If any of the storm restoration 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 SeptemberJune 30, 2017,2022, AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $709 million.approximately $1.4 billion.A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. 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, 2023, during which the $1.4 billion of cumulative revenues above will be subject to review.
I&M Rate Matters (Applies to AEP and I&M)
2017 Indiana Base Rate CaseMichigan Power Supply Cost Recovery (PSCR) Reconciliation
In July 2017,April 2022, an Administrative Law Judge (ALJ) issued a Proposal for Decision (PFD) for I&M’s PSCR reconciliation for the 12-month period ending December 31, 2020, recommending the MPSC disallow approximately $8 million of purchased power costs that I&M incurred under the Inter-Company Power Agreement with OVEC and the Unit Power Agreement with AEGCo. In May 2022, I&M submitted exceptions to the ALJ’s PFD related to the recommended disallowance of purchased power costs described above. I&M anticipates that the MPSC will issue a final decision in the second half of 2022. Management is unable to predict the impact, if any, that the MPSC’s final decision may have on future results of operations, financial condition and cash flows.
Indiana Earnings Test Filings
I&M is required by Indiana law to submit an earnings test evaluation for the most recent one-year and five-year periods as part of I&M’s semi-annual Indiana FAC filings. These earnings test evaluations require I&M to include a credit in the FAC factor computation for periods in which I&M earned above its authorized return for both the one-year and five-year periods. The credit is determined as 50% of the lower of the one-year or five-year earnings above the authorized level. In the third quarter of 2022, I&M will submit its FAC filing and earnings test evaluation for the period ended May 2022. As of June 30, 2022, I&M’s financial statements adequately reflect the estimated impact of I&M’s upcoming Indiana earnings test filings. If it is determined that I&M’s over-earnings exceed what has been recorded, it could reduce future net income and cash flows and impact financial condition.
2022 Michigan Integrated Resource Plan (IRP) Filing
In February 2022, I&M filed a request with the MPSC for approval of its 2022 IRP. Included in that filing were requests for approval and deferral of costs associated with resources commencing construction within three years of the Commission’s order in the filing. These resources include the new generation resources expected to be in-service by 2028, and demand-side resources, including load management programs and conservation voltage reduction investments. I&M is also requesting MPSC approval of I&M’s Rockport Unit 2 transition plan consistent with that approved by the IURC, including certain cost recovery related to remaining net book value of investments made during the term of the Rockport Unit 2 lease and future use of Rockport Unit 2 as a capacity resource. In addition, I&M has made requests for approval of a $263 million annual increasefinancial incentive on certain power purchase agreements and load management programs.
In June 2022, intervening parties recommended various adjustments to I&M’s proposals, including the process I&M would use to receive approval of new generation resources, changes to or denial of requested financial incentives and requests for deferral and pre-approval of costs. Specific to I&M’s Rockport Unit 2 transition plan, certain intervening parties recommended that the MPSC order I&M to credit back to Michigan ratepayers the jurisdictional
share of post-lease revenues in Indiana rates based uponexcess of costs from Rockport Unit 2’s operations as a proposed 10.6%merchant facility and that I&M only receive a post-lease debt return on common equityremaining net book value of Rockport Unit 2 leasehold improvements.
Management currently anticipates that the MPSC will issue an order on I&M’s 2022 Michigan IRP filing in the first quarter of 2023. Any disallowance or reduction in the recovery of Rockport Unit 2 leasehold improvements could reduce future net income and cash flows and impact financial condition.
KPCo Rate Matters (Applies to AEP)
CCR/ELG Compliance Plan Filings
KPCo and WPCo each own a 50% interest in the Mitchell Plant. As of June 30, 2022, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $584 million. In December 2020 and February 2021, WPCo and KPCo filed requests with the annual increaseWVPSC and KPSC, respectively, to obtain the regulatory approvals necessary to implement CCR and ELG compliance plans and seek recovery of the estimated $132 million investment for the Mitchell Plant that would allow the plant to continue operating beyond 2028. Within those requests, WPCo and KPCo also filed a $25 million alternative to implement only the CCR-related investments with the WVPSC and KPSC, respectively, which would allow the Mitchell Plant to continue operating only through 2028.
In July 2021, the KPSC issued an order approving the CCR only alternative and rejecting the full CCR and ELG compliance plan. In May 2022, the KPSC approved recovery of the Kentucky jurisdictional share of ELG costs incurred at the Mitchell Plant prior to July 15, 2021.
In August 2021, the WVPSC approved the full CCR and ELG compliance plan for the WPCo share of the Mitchell Plant. In September 2021, WPCo submitted a filing with the WVPSC to reopen the CCR/ELG case that was approved by the WVPSC in August 2021. Due to the rejection by the KPSC of the KPCo share of the ELG investments, WPCo requested the WVPSC consider approving the construction and recovery of all ELG costs at the plant. In October 2021, the WVPSC affirmed its August 2021 order approving the construction of CCR/ELG investments and directed WPCo to proceed with CCR/ELG compliance plans that would allow the plant to continue operating beyond 2028. The WVPSC’s order further states WPCo will not share capacity and energy from the plant with KPCo customers if those customers are not paying for ELG compliance costs, or for any new capital investment or continuing operations costs incurred, to allow the plant to operate beyond 2028 or prevent downgrades prior to 2028. The WVPSC also ordered that WPCo will be implemented aftergiven the opportunity to recover, from its customers, the new capital and operating costs arising solely from the WVPSC's directive to operate the plant beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred.
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 2018. Upon implementation, this proposed annual increase would be subject2022, the PUCO granted rehearing on the 2016-2017 audit period. Management disagrees with these claims and is unable to a temporary offsetting $23predict the impact, if any, these disputes may have on future results of operations, financial condition and cash flows. See "OVEC" section of Note 17 in the 2021 Annual Report for additional information on AEP and OPCo’s investment in OVEC.
June 2022 Storm Costs
In June 2022, the service territory of OPCo was impacted by strong winds from multiple storms resulting in power outages and damage to the transmission and distribution infrastructures. As of June 30, 2022, OPCo had incurred approximately $14 million annual reduction to customer bills through December 2018 for a credit adjustment riderin incremental operation and maintenance costs related to service restoration efforts. The incremental storm restoration costs have been deferred as regulatory assets and OPCo is expected to seek recovery in a future filing. In July 2022, intervenors filed a motion requesting the timingPUCO open a formal investigation into the power outages that occurred as a result of estimated in-service datesthe June storms and determine if OPCo was negligent and liable to consumers for damages incurred as a result 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.power outages. If any of thesethe storm restoration 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.
KPCoPSO 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)PSO)
Ohio Electric Security Plan FilingsFebruary 2021 Severe Winter Weather Impacts in SPP
June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024
In 2013, OPCoFebruary 2021, severe winter weather had a significant impact in SPP, resulting in the declaration of Energy Emergency Alert Levels 2 and 3 for the first time in SPP’s history. The winter storm increased the demand for natural gas and restricted the available natural gas supply resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system. For the time period of February 9, 2021, to February 20, 2021, PSO’s natural gas expenses and purchases of electricity still to be recovered from customers are $684 million as of June 30, 2022.
In April 2021, the OCC approved a waiver for PSO allowing the deferral of the extraordinary fuel and purchases of electricity, including a carrying charge at an interim rate of 0.75%, over a longer time period than what the FAC traditionally allows. In January 2022, PSO, OCC staff and certain intervenors filed an applicationa joint stipulation and settlement agreement with the PUCOOCC to approve an ESPPSO’s securitization of the extraordinary fuel and purchases of electricity. The agreement includes a determination that included proposed rate adjustmentsall of PSO’s extraordinary fuel and the continuationpurchases of electricity were prudent and modification of certain existing riders, including the DIR, effective June 2015 through May 2018. The proposal also involvedreasonable and a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing0.75% carrying 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 returntrue-up based on common equity of 10.2% on capital costs for certain riders. The orders included: (a) approval ofactual financing costs. In February 2022, the DIR, with modified rate caps established byOCC approved the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed OVEC PPAjoint stipulation and (c) the option for OPCo to reapplysettlement agreement 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 PUCOits financing 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 toMay 2022, the Supreme Court of Ohio stating thatOklahoma approved the PUCO’s approvalissuance 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 withsecuritization bonds. PSO expects to complete 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 approvedsecuritization process 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 is2022, subject to review by the PUCO. A hearing at the PUCO is scheduled for November 2017.market conditions.
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.
PSOSWEPCo Rate Matters (Applies to AEP and PSO)SWEPCo)
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,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 and submitted a Petition for Review with the Texas Supreme Court in November 2021. In June 2022, SWEPCo and the PUCT filed replies to the responses of the Petition for Review.
If SWEPCo is ultimately unable to recover capitalized Turk Plant costs, including 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 $180 million related to revenues collected from February 2013 through June 2022 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 and certain parties recommended investment disallowances that couldmechanism.
As a result of the final order, in write-offs2017 SWEPCo: (a) recorded an impairment charge of up to approximately $89$19 million, including approximately $40which included $7 million related to environmental investments and $25 million related to Welsh Plant, Unit 2. A hearing atassociated with the PUCT was held in June 2017.
In September 2017, the Administrative Law Judges (ALJs) issued their proposal for decision including an annual net revenue increaselack 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 2.2 and $12 million related to other disallowed plant investments, (b) recognized $32 million of additional revenues, for the period of May 2017 through December 2017, that was surcharged to customers in 2018and (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 ALJs rejected SWEPCo’s proposed transmission cost recovery mechanism.$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 estimated potential write-off associated withorder has been appealed by various intervenors. The appeal will move forward following the ALJs proposal is approximately $22 million which includes $9 millionassociated withconclusion of the lack2012 Texas Base Rate Case. If certain parts of a return on Welsh Plant, Unit 2.
If any of these coststhe PUCT order are not recoverable, including environmental investments and retirement-related costs for Welsh Plant, Unit 2,overturned, it could reduce future net income and cash flows and impact financial condition.
2020 Texas Base Rate Case
Louisiana Turk Plant Prudence Review
In October 2020, SWEPCo filed a request with the PUCT for a $105 million annual increase in Texas base rates based upon a proposed 10.35% ROE. The request would move transmission and distribution interim revenues recovered through riders into base rates. Eliminating these riders would result in a net annual requested base rate increase of $90 million primarily due to increased investments. 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.
Beginning
In January 2013, SWEPCo’s formula2022, the PUCT issued a final order approving an annual revenue increase of $39 million based upon a 9.25% ROE. The order also includes: (a) rates includingimplemented retroactively back to March 18, 2021, (b) $5 million of the Louisianaproposed increase related to vegetation management, (c) $2 million annually to establish a storm catastrophe reserve and (d) the creation of a rider that would recover the Dolet Hills Power Station as if it were in rate base until its retirement at the end of 2021 and starting in 2022 the remaining net book value would be recovered as a regulatory asset through 2046. As a result of the final order, SWEPCo recorded a disallowance of $12 million 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 (approximately 33%) of the Turk Plant, have been collected subject to refund pendingstorm catastrophe reserve. In April 2022, the outcome ofPUCT denied the motion for rehearing. In
May 2022, SWEPCo filed a prudencepetition for review with the Texas District Court seeking a judicial review of the Turkseveral 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 subsequently revised the requested annual increase to $114 million to reflect removing hurricane storm restoration costs from the base case filing. The hurricane costs have been requested in a separate storm filing. See “2021 Louisiana Storm Cost Filing” below for more information. The base case filing would extend the formula rate plan for five years and includes modifications to the formula rate plan to allow for forward-looking transmission costs, reflects the impact of net operating losses associated with the acceleration of certain tax benefits and incorporates future federal corporate income tax changes. The proposed net annual increase requests a $32 million annual depreciation increase to recover Louisiana’s share of the Dolet Hills Power Station, Pirkey Power Plant investment,and Welsh Plant, all of which was placed into service in December 2012. are expected to be retired early.
In October 2017,July 2021, the LPSC staff filed testimony contending that SWEPCo failedsupporting a $6 million annual increase in base rates based upon a ROE of 9.1% while other intervenors recommended a ROE ranging from 9.35% to continue to evaluate9.8%. The primary differences between SWEPCo’s requested annual increase in base rates and the suspension or cancellationLPSC staff’s recommendation include: (a) a reduction in depreciation expense, (b) recovery of Dolet Hills Power Station and Pirkey Power Plant in a separate rider mechanism, (c) the 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 resultrejection of SWEPCo’s alleged failureproposed adjustment 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 SWEPCo and ratepayers, (b) an imposition ofinclude 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 Plantstand-alone net operating loss carryforward deferred tax asset in rate base since its in-service date, SWEPCo may be required to refund potential over-collections from January 2013 throughand (d) a reduction in 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.proposed ROE.
2015 Louisiana Formula Rate Filing
In April 2015,September 2021, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing includedrebuttal testimony supporting a $14 millionrevised requested annual increase which was effective August 2015. This increase is subjectin base rates of $95 million. The primary differences in the rebuttal testimony from the previous revised request of $114 million are modifications to the proposed recovery of the Dolet Hills Power Station and revisions to various proposed amortizations. LPSC staff review and intervenor responses to SWEPCo’s rebuttal testimony were filed in October 2021. The procedural schedule for the case is subjecton hold due to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.ongoing settlement discussions.
2017 Louisiana Formula Rate Filing
In April 2017, the LPSC approved an uncontested stipulation agreement that SWEPCo filed for its formula rate plan for test year 2015. The filing included a net annual increase not to exceed $31 million, which was effective May 2017 and includes SWEPCo’s Louisiana jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls which were placed 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 prudence of its environmental control investment for Welsh Plant, Units 1 and 3 and Flint Creek power plants. A hearing at the LPSC is scheduled for May 2018. If any of these costs are not recoverable, 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. See “2016 Texas Base Rate Case” and “2017 Louisiana 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.
2021 Arkansas Base Rate Case
In July 2021, SWEPCo filed a request with the APSC for an $85 million annual increase in Arkansas base rates based upon a proposed 10.35% ROE with a capital structure of 48.7% debt and 51.3% common equity. The proposed annual increase includes: (a) a $41 million revenue requirement for the North Central Wind Facilities, (b) a $14 million annual depreciation increase primarily due to recovery of the Dolet Hills Power Station through 2026 and Pirkey Plant and Welsh Plant, Units 1 and 3 through 2037 and (c) a $6 million increase due to SPP costs. In January 2022, SWEPCo filed testimony revising the requested annual increase in Arkansas base rates to $81 million. SWEPCo requested that rates become effective in June 2022.
In May 2022, the APSC issued a final order approving an annual revenue increase of $49 million based upon a 9.5% ROE. The order also includes: (a) a capital structure of 55% debt and 45% common equity, (b) approval to recover the Dolet Hills Power Station as a regulatory asset over five years without a return on this investment resulting in an immaterial disallowance in the second quarter of 2022, (c) the denial of accelerated depreciation for the Pirkey Plant and Welsh Plant, Units 1 and 3 and (d) approval of a rider to recover SPP costs and revenues. The final order also denied the inclusion of the stand-alone NOLC in SWEPCo’s deferred tax assets, but included approval of the deferral of the forgone revenue requirement associated with the NOLC and excess NOLC, with recovery of the deferral contingent upon receipt of a supportive private letter ruling from the IRS. Rates were implemented with the first billing cycle of July 2022. In June 2022, SWEPCo filed a motion for rehearing with the APSC challenging the capital structure that was approved. In July 2022, the APSC denied the motion for rehearing.
2021 Louisiana Storm Cost Filing
In 2020, Hurricanes Laura and Delta caused power outages and extensive damage to the SWEPCo service territories, primarily impacting the Louisiana jurisdiction. Following both hurricanes, the LPSC issued orders allowing Louisiana utilities, including SWEPCo, to establish regulatory assets to track and defer expenses associated with these storms. In February 2021, severe winter weather impacted the Louisiana jurisdiction and in March 2021, the LPSC approved the deferral of incremental storm restoration expenses related to the winter storm. In October 2021, SWEPCo filed a request with the LPSC for recovery of $145 million in deferred storm costs associated with the three storms. As part of the filing, SWEPCo requested recovery of the carrying charges on the deferred regulatory asset at a weighted average cost of capital through a rider beginning in January 2022. In May 2022, LPSC staff testimony was submitted to the LPSC. In July 2022, SWEPCo filed rebuttal testimony which agreed to make a request for securitization as the LPSC staff had recommended in their testimony. An order is expected before the end of 2022. If any of the storm costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
February 2021 Severe Winter Weather Impacts in SPP
As discussed in the “PSO Rate Matters” section above, severe winter weather had a significant impact in SPP, resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system. For the time period of February 9, 2021, to February 20, 2021, SWEPCo’s natural gas expenses and purchases of electricity still to be recovered from customers are $375 million as of June 30, 2022, of which $95 million, $134 million and $146 million is related to the Arkansas, Louisiana and Texas jurisdictions, respectively.
In March 2021, the APSC issued an order authorizing recovery of the Arkansas jurisdictional share of the retail customer fuel costs over five years, with the appropriate carrying charge to be determined at a later date. Subsequently, SWEPCo began recovery of these fuel costs. In April 2021, SWEPCo filed testimony supporting a five-year recovery with a carrying charge of 6.05%. In June 2022, the APSC ordered SWEPCo to recover the Arkansas jurisdictional share of the fuel costs over six years with a carrying charge equal to its weighted average cost of capital, subject to a prudency review and true-up.
In March 2021, the LPSC approved a special order granting a temporary modification to the FAC and shortly after SWEPCo began recovery of its Louisiana jurisdictional share of these fuel costs based on a five-year recovery period inclusive of an interim carrying charge of 3.25%. SWEPCo will work with the LPSC to finalize the actual recovery period and determine the appropriate carrying charge in future proceedings.
In August 2021, SWEPCo filed an application with the PUCT to implement a net interim fuel surcharge for the Texas jurisdictional share of these retail fuel costs. The application requested a five-year recovery with a carrying charge of 7.18%. In March 2022, the PUCT ordered SWEPCo to recover the Texas jurisdictional share of the fuel costs over five years with a carrying charge of 1.65% and ordered SWEPCo to file a fuel reconciliation addressing fuel costs from January 1, 2020 through December 31, 2021.
If SWEPCo is unable to recover any of the costs relating to the extraordinary fuel and purchases of electricity, or obtain authorization of a reasonable carrying charge on these costs, it could reduce future net income and cash flows and impact financial condition.
FERC Rate Matters
PJMFERC SPP Transmission Rates (AppliesFormula Rate Challenge (Applies to AEP, AEPTCo, APCo, I&MPSO and OPCo)SWEPCo)
In June 2016, PJM transmission owners, including AEP’s eastern transmission subsidiaries and various state commissions filedMay 2021, certain joint customers submitted a settlement agreementformal challenge at the FERC to resolve outstanding issues related to cost responsibility for charges tothe 2020 Annual Update of the 2019 SPP Transmission Formula Rates of the AEP transmission customers for certain transmission facilities that operate at or above 500 kV.owning subsidiaries within SPP. In July 2016, certain parties filed comments atMarch 2022, the FERC contestingissued an order on the settlementformal challenge which ruled in favor of the joint customers on several issues. Management has determined that the result of the order will have an immaterial impact to the financial statements of AEP, AEPTCo, PSO and SWEPCo.
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 the jurisdiction and review of the 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.
In September 2021, PJM notified Transource Energy that the IEC was suspended to allow for the regulatory and related appeals process to proceed in an orderly manner without breaching milestone dates in the project agreement. Upon finalAt that time, PJM stated that the IEC has not been cancelled and remains necessary to alleviate congestion. PJM continues to evaluate reliability and market efficiency in the area. As of June 30, 2022, AEP’s share of IEC capital expenditures was approximately $82 million, located in Total Property, Plant and Equipment - Net on AEP’s balance sheets. The FERC approval, PJM would implement a transmission enhancement charge adjustment throughhas previously granted abandonment benefits for this project, allowing the PJM OATT, billable through 2025. Management expects thatfull recovery of prudently incurred costs if the project is cancelled for reasons outside the control of Transource Energy. If any refunds received would generally be returned to retail customers through existing state rider mechanisms.of the IEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
FERC TransmissionRTO Incentive Complaint - AEP’s PJM Participants (Applies(Applies to AEP, AEPTCo APCo, I&M and OPCo)
In October 2016, several partiesFebruary 2022, the Office of the Ohio Consumers’ Counsel filed a joint complaint atagainst 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 Ohio Consumers’ Counsel’s February 2022 complaint with the FERC on the basis of certain deficiencies, including that states the base returncomplaint 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 common equity used by AEP’s eastern transmission subsidiaries in calculating formula transmission rates underfile with the PJM OATT is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint.FERC. Management believes its financial statements adequately address the impact of the February 2022 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 (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 2021 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 2024, respectively, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of SeptemberJune 30, 2017,2022, 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 five uncommitted facilities totaling $445$400 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 June 30, 2022 were as follows:
| | | | | | | | | | | | | | |
Company | | Amount | | Maturity |
| | (in millions) | | |
AEP | | $ | 323.8 | | | July 2022 to June 2023 |
AEP Texas | | 2.2 | | | July 2022 |
| | | | |
|
| | | | | | |
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)
In 2019, AEP issued a performance guarantee foracquired Sempra Renewables LLC. The transaction resulted in the acquisition of a 50% ownedownership interest in five non-consolidated joint venture which is accounted for as anventures and the acquisition of two tax equity method investment.partnerships. Parent has issued guarantees over the performance of the joint ventures. If thea joint venture were to default on payments or performance, AEPParent would be required to make payments on behalf of the joint venture. As of SeptemberJune 30, 2017,2022, the maximum potential amount of future payments associated with thisthese guarantees was $135 million, with the last guarantee was $75 million, which expiresexpiring in December 2019.2037. The non-contingent liability recorded associated with these guarantees was $27 million, with an additional $2 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 SeptemberJune 30, 2017,2022, 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 SeptemberJune 30, 2017,2022, 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 | | $ | 45.1 | |
AEP Texas | | 10.9 | |
APCo | | 6.1 | |
I&M | | 4.2 | |
OPCo | | 7.4 | |
PSO | | 4.6 | |
SWEPCo | | 5.2 | |
|
| | | | |
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 |
|
RailcarRockport Lease (Applies to AEP and I&M)
AEGCo and I&M and SWEPCo)
In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2. The trusts were capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors.
The trusts own undivided interests in Rockport Plant, Unit 2 and leases equal portions to AEGCo and I&M. In April 2021, AEGCo and I&M executed an agreement 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 assignedpurchase 100% of 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 specifiedinterests in the lease, which declines from 83% of the projected fair value of the equipment under the current five-year lease term to 77%Rockport Plant, Unit 2 effective at the end of the 20-year term.lease term in December 2022. In December 2021, AEGCo and I&M satisfied the necessary regulatory approvals to complete the acquisition. Upon receipt of the regulatory approval, the addition of the lessee forward purchase obligation resulted in the modified lease changing classification from operating to finance for AEGCo and SWEPCo have assumedI&M. The future minimum lease payments as of June 30, 2022, inclusive of the guarantee underpurchase obligation, were as follows:
| | | | | | | | | | | | | | |
Future Minimum Lease Payments | | AEP (a) | | I&M |
| | (in millions) |
| | | | |
2022 | | $ | 174.9 | | | $ | 87.4 | |
Total Future Minimum Lease Payments | | $ | 174.9 | | | $ | 87.4 | |
(a)AEP’s future minimum lease payments include equal shares from AEGCo and I&M.
The lease modification also created variable interests in the return-and-sale option. Thetrusts that own the undivided interests in Rockport Plant, Unit 2 for AEGCo and I&M. Neither AEGCo nor I&M are the primary beneficiaries of the trusts because AEGCo nor I&M has the power to direct the most significant activities of the trusts. AEP and I&M’s maximum potential losses relatedexposure to loss associated with the trust is equal to the guarantee are $8 million and $10 million for I&M and SWEPCo, respectively, as of September 30, 2017, assuming the fair valuetotal future minimum lease payments, inclusive of the equipment is zero atpurchase obligation, as shown in 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.table above.
AEPRO Boat and Barge Leases (Applies to AEP)
In October 2015, AEP signed a Purchase and Sale Agreement to sellsold 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,respective lessors, ensuring future payments under such leases with maturities up to 2027. As of SeptemberJune 30, 2017,2022, the maximum potential amount of future payments required under the guaranteed leases was $52$38 million. InUnder the terms of certain instances, AEP has no recourse againstof the arrangements, upon the lessors exercising their rights after an event of default by the nonaffiliated party, if requiredAEP is entitled to payenter into new lease arrangements as a lessee that would have substantially the same terms as the existing leases. Alternatively, for the arrangements with one of the lessors, upon an event of default by the nonaffiliated party and the lessor under a guarantee, butexercising its rights, payment to the lessor would allow AEP to step into the lessor’s rights as well as obtaining title to the assets. Under either situation, AEP would have accessthe ability to utilize the assets in the normal course of barging operations. AEP would also have the right to sell the leasedacquired assets in order to recover payments made by AEP under the guarantee to the extent of the sale proceeds.for which it obtained title. As of SeptemberJune 30, 2017,2022, AEP’s boat and barge lease guarantee liability was $7$2 million, of which $1 million was recorded in Other Current Liabilities and $6$1 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet.sheets.
In February 2020, the nonaffiliated party filed Chapter 11 bankruptcy. The party entered into a restructuring support agreement and has announced it expected to continue their operations as normal. In March 2020, the bankruptcy court approved the party’s recapitalization plan. In April 2020, the nonaffiliated party emerged from bankruptcy. Management has determined that it is reasonably possible that enforcement of AEP’s liability for future payments under these leases will be exercised within the next twelve months. In such an event, if AEP is unable to sell or incorporate any of the acquired assets into its fleet operations, it could reduce future net income and cash flows and impact financial condition.
ENVIRONMENTAL CONTINGENCIES (Applies to all Registrants except AEPTCo)
The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation
By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and 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 (Applies to AEP and I&M)
In July 2013, the Wilmington Trust Company filed a complaintsuit in the U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it willwould be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering, refueling or retirement of the unit. The plaintiffs further allege that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiffs seeksought a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs.
After the litigation proceeded at the district court and appellate court, in April 2021, I&M and AEGCo reached an agreement to acquire 100% of the interests in Rockport Plant, Unit 2 for $116 million from certain financial institutions that own the unit through trusts established by Wilmington Trust, the nonaffiliated owner trustee of the ownership interests in the unit, with closing to occur as of the end of the Rockport Plant, Unit 2 lease in December 2022. The New Yorkagreement is subject to customary closing conditions and as of the closing will result in a final settlement of, and release of claims in, the lease litigation. As a result, in May 2021, at the parties’ request, the district court grantedentered a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismissstipulation and order dismissing the case was filed on behalf of AEGCowithout prejudice to plaintiffs asserting their claims in a re-filed action or a new action. The required regulatory approvals at the IURC and I&M.
In January 2015,FERC have been obtained that would allow the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certainclosing to occur as of the plaintiffs’ claims, including the dismissal without prejudice of plaintiffs’ claims seeking compensatory damages. Several claims remained, including the claim for breachend of the participationlease in December 2022. The IURC order approved a settlement agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment onaddressing 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 order 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 operationfuture use of Rockport Plant, Unit 2. In April 2016,2 as a capacity resource and associated adjustments to I&M’s Indiana retail rates, along with certain other matters. Management believes its financial statements appropriately reflect the plaintiffsresolution of the litigation.
Claims Challenging Transition of American Electric Power System Retirement Plan to Cash Balance Formula
Four participants in The American Electric Power System Retirement Plan (the Plan) filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, plaintiffs filed an appealclass action complaint in the U.S. Court of Appeals for the Sixth Circuit on whether AEGCo and I&M areDecember 2021 in breach of certain contract provisions that plaintiffs allege operate to protect the plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing.
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 seekingagainst AEPSC and the Plan. When the Plan’s benefit formula was changed in the year 2000, AEP provided a special provision for employees hired before January 1, 2001, allowing them to modifycontinue benefit accruals under the consent decree to eliminate the 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 benefitsthen benefit formula for a full 10 years alongside of the consent decree. In October 2017,new cash balance benefit formula then being implemented. Employees who were hired on or after January 1, 2001 accrued benefits only under the ownersnew cash balance benefit formula. The Plaintiffs assert a number of claims on behalf of themselves and the purported class, including that: (a) the Plan violates the requirements under the Employee Retirement Income Security Act (ERISA) intended to preclude back-loading the accrual of benefits to the end of a participant’s career, (b) the Plan violates the age discrimination prohibitions of ERISA and the Age Discrimination in Employment Act and (c) AEP failed to provide required notice regarding the changes to the Plan. Among other relief, the Complaint seeks reformation of the Plan to provide additional benefits and the recovery of plan benefits for former employees under such reformed plan. The Plaintiffs previously had submitted claims for additional plan benefits to AEP, which were denied. On February 15, 2022, AEPSC and the Plan filed a motion to stay their claims until January 2018,dismiss the complaint for failure to afford time for resolution of AEP’sstate a claim and briefing on the motion to modify the consent decree.
Managementdismiss has been completed. AEP 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 (AppliesLitigation Related to AEP)Ohio House Bill 6 (HB 6)
In 2002,2019, Ohio adopted and implemented HB 6 which benefits OPCo by authorizing rate recovery for certain costs including renewable energy contracts and OVEC’s coal-fired generating units. OPCo engaged in lobbying efforts and provided testimony during the legislative process in connection with HB 6. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a lawsuit was commencedfederal grand jury indictment of an Ohio legislator and associates 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 informationconnection with an intentalleged racketeering conspiracy involving the adoption of HB 6. After AEP learned of the criminal allegations against the Ohio legislator and others relating to affectHB 6, AEP, with assistance from outside advisors, conducted a review of the market pricecircumstances surrounding the passage of natural gas and electricity.the bill. Management does not believe that AEP was dismissed frominvolved in any wrongful conduct in connection with the case. A numberpassage of similar cases were also filed in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP 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 companies to the U.S. Court of Appeals for the Ninth Circuit. In April 2013, the appellate court reversed in part, 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 reached 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.HB 6.
Gavin Landfill Litigation (Applies to AEP and OPCo)
In August 2014,2020, an AEP shareholder filed a complaint was filedputative class action lawsuit in the Mason County, West Virginia CircuitUnited States District Court for the Southern District of Ohio against AEP AEPSC, OPCo and certain of its officers for alleged violations of securities laws. The amended complaint alleged misrepresentations or omissions by AEP regarding: (a) its alleged participation in or connection to public corruption with respect to the passage of HB 6 and (b) its regulatory, legislative, political contribution, 501(c)(4) organization contribution and lobbying activities in Ohio. The complaint sought monetary damages, among other forms of relief. In December 2021, the District Court issued an individual supervisor alleging wrongful deathopinion and personal injury/illnessorder dismissing the securities litigation complaint with prejudice, determining that the complaint failed to plead any actionable misrepresentations or omissions. The plaintiffs did not appeal the ruling.
In January 2021, an AEP shareholder filed a derivative action in the United States District Court for the Southern District of Ohio purporting to assert 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, consistingAEP against certain AEP officers and directors. In February 2021, a second AEP shareholder filed a similar derivative action in the Court of 39 currentCommon 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 former contractorsa fourth AEP shareholder filed a similar derivative action in the Supreme Court for the State of New York, Nassau County. These derivative complaints allege the officers and directors made misrepresentations and omissions similar to those alleged in the putative securities class action lawsuit filed against AEP. The derivative complaints together assert claims for: (a) breach of fiduciary duty, (b) waste of corporate assets, (c) unjust enrichment, (d) breach of duty for insider trading and (e) contribution for violations of sections 10(b) and 21D of the landfillSecurities Exchange Act of 1934; and 38 family membersseek monetary damages and changes to AEP’s corporate governance and internal policies among other forms of those contractors. Twelve ofrelief. The court has entered a scheduling order in the family members are pursuing personal injury/illness claims (non-working direct claims)New York state court derivative action staying the case other than with respect to briefing the motion to dismiss. AEP filed its motion to dismiss on April 29, 2022 and briefing on the motion to dismiss has been completed. The two derivative actions pending in federal district court in Ohio have been consolidated and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, defendantsin the consolidated action filed an amended complaint.AEP filed a motion to dismiss on May 3, 2022 and briefing on the complaint, contendingmotion to dismiss has been completed. Discovery remains stayed pending the district court’s ruling
on the motion to dismiss. The plaintiff in the Ohio state court case should be filed in Ohio. In August 2015,advised that they no longer agreed to stay the court denied the motion. Defendants appealed that decision 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 subsequentlyproceedings, therefore, AEP filed a motion to dismisscontinue the twelve non-working direct claims understays of proceedings on May 20, 2022 and the plaintiff filed an amended complaint on June 2, 2022. On June 15, 2022 the Ohio law. The WVMLP deniedstate court entered an order continuing the motion and defendants again appealed tostay of that case until the West Virginia Supreme Court. The West Virginia Supreme Court granted the appealresolution of the twelve non-working direct claims and heard oral argumentconsolidated derivative actions pending 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. ManagementOhio federal district court. The defendants will continue to defend against the remaining claims and believes the provision recorded is adequate.claims. Management is unable to determine a range of potential additional 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 is directed to the Board of Directors of AEP and contains factual allegations involving HB 6 that are generally consistent with those in the derivative litigation filed in state and federal court. The letter demands, among other things, that the AEP Board undertake an independent investigation into alleged legal violations by directors and officers, and that, following such investigation, AEP commence a civil action for breaches of fiduciary duty and related claims and take appropriate disciplinary action against those individuals who allegedly harmed the company. The shareholder that sent the letter has since withdrawn the litigation demand, which is now terminated and of no further effect.
In May 2021, AEP received a subpoena from the SEC’s Division of Enforcement seeking various documents, including documents relating to the benefits to AEP from the passage of HB 6 and documents relating to AEP’s financial processes and controls. AEP is cooperating fully with the SEC’s subpoena. Although the outcome of the SEC’s investigation cannot be predicted, management does not believe the results of this inquiry will have a material impact on financial condition, results of operations or cash flows.
6. IMPAIRMENT, DISPOSITION, ANDACQUISITIONS, ASSETS AND LIABILITIES HELD FOR SALE, DISPOSITIONS AND IMPAIRMENTS
The disclosures in this note apply to AEP only unless indicated otherwise.
IMPAIRMENTACQUISITIONS
Merchant Generating AssetsDry Lake Solar Project (Generation & Marketing Segment) (Applies to AEP)
In September 2016, due to AEP’s ongoing evaluation of strategic alternatives for its merchant generation assets, declining forecasts of future energy and capacity prices, and a decreasing likelihood of cost recovery through regulatory proceedings or legislation in the state of Ohio providing for the recovery of AEP’s existing Ohio merchant generation assets, AEP performed an impairment analysis at the unit level on the remaining merchant generation assets in accordance with accounting guidance for impairments of long-lived assets. Based on the impairment analysis performed in the third quarter of 2016, AEP recorded a pretax impairment of $2.3 billion in Asset Impairments and Other Related Charges on the statement of operations.
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 Plant (Vertically Integrated Utilities Segment) (Applies to AEP and I&M)
In October 2016, I&M sold its retired Tanners Creek plant site including its associated asset retirement obligations (AROs) to a nonaffiliated party. I&M paid $92 million and the nonaffiliated party took ownership of the Tanners Creek plant site assets and assumed responsibility for environmental liabilities and AROs, including ash pond closure, asbestos abatement and decommissioning and demolition. I&M did not record a gain or loss related to this sale and will address recovery of Tanner’s Creek deferred costs in future rate proceedings. If any of the costs associated with Tanner’s Creek are not recoverable, it could reduce future net income and impact financial condition.
Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)
In September 2016,November 2020, AEP signed a Purchase and Sale Agreement with a nonaffiliate to sell AGR’s Gavin, Waterfordacquire a 75% interest in the entity that owns the 100 MW Dry Lake Solar Project (collectively referred to as Dry Lake) located in southern Nevada for approximately $114 million. In March 2021, AEP closed the transaction and Darby Plantsthe solar project was placed in-service in May 2021. Approximately $103 million of the purchase price was paid upon closing of the transaction and the remaining $11 million was paid when the project was placed in-service. In accordance with the accounting guidance for “Business Combinations,” management determined that the acquisition of Dry Lake represents an asset acquisition. Additionally, and in accordance with the accounting guidance for “Consolidation,” management concluded that Dry Lake is a VIE and that AEP is the primary beneficiary based on its power as well as AEGCo’s Lawrenceburg Plant totaling 5,329 MWsmanaging member to direct the activities that most significantly impact Dry Lake’s economic performance. As the primary beneficiary of competitive generation assetsDry Lake, AEP consolidates Dry Lake into its financial statements. As a result, to a nonaffiliated party. The sale closed in January 2017account for $2.2 billion, which was recorded in Investing Activitiesthe initial consolidation of Dry Lake, management applied the acquisition method by allocating the purchase price based on the statementrelative fair value of cash flows.the assets acquired and noncontrolling interest assumed. The net proceedsfair value of the primary assets acquired and the noncontrolling interest assumed was determined using the market approach. The key input assumptions were the transaction price paid for AEP’s interest in Dry Lake and recent third-party market transactions for similar solar generation facilities. The nonaffiliated interest in Dry Lake is presented in Noncontrolling Interests on the balance sheets. Subsequent to close of the transaction, the noncontrolling interest made additional asset contributions of $16 million. As of June 30, 2022, AEP recognized approximately $144 million of Property, Plant and Equipment and approximately $35 million of Noncontrolling Interest on the balance sheets.
North Central Wind Energy Facilities (Vertically Integrated Utilities Segment) (Applies to AEP, PSO and SWEPCo)
In 2020, PSO and SWEPCo received regulatory approvals to acquire the NCWF, comprised of three Oklahoma wind facilities totaling 1,484 MWs, on a fixed cost turn-key basis at completion. PSO and SWEPCo own undivided interests of 45.5% and 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 transaction wereNCWF 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 beginning at commercial operation and until such time as amounts are reflected in base rates. Recovery of the Arkansas portion of the NCWF revenue requirement 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 regulatory liability to refund retail customers.
In April 2021, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Sundance during its development and construction for $270 million, the first of the three NCWF acquisitions. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Sundance assets in proportion to their undivided ownership interests. Sundance was placed in-service in April 2021.
In September 2021, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Maverick during its development and construction for $383 million, the second of the three NCWF acquisitions. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the
Maverick assets in proportion to their undivided ownership interests. Maverick was placed in-service in September 2021.
In March 2022, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Traverse during its development and construction for $1.2 billion, the third of the three NCWF acquisitions. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Traverse assets in cash after taxes, repaymentproportion to their undivided ownership interests. Traverse was placed in-service in March 2022.
In accordance with the guidance for “Business Combinations,” management determined that the acquisitions of debt associated with these assets including a make whole paymentthe NCWF projects represent asset acquisitions. As of June 30, 2022, PSO and SWEPCo had approximately $889 million and $1.1 billion, of gross Property, Plant and Equipment on the balance sheets, respectively, related to the debt, payment of a coal contract associated with oneNCWF projects. On an ongoing basis, management further determined that PSO and SWEPCo should apply the joint plant accounting model to account for their respective undivided interests in the assets, liabilities, revenues and expenses of the plantsNCWF projects.
The respective Purchase and transaction fees.Sale Agreements (PSAs) include interests in numerous land contracts, as originally executed between the nonaffiliated party and the respective owners of the properties as defined in the contracts. These contracts provide for easement and access rights to the land that Sundance, Maverick and Traverse were built upon. The sale resultedlessee interests in the land contracts were transferred to Sundance, Maverick and Traverse (and subsequently to PSO and SWEPCo) as a pretax gainpart of $226 million that was recorded in Gain on Salethe closings of Merchant Generation Assets on AEP’s statementthe respective PSAs. The Current Obligations Under Operating Leases related to the NCWF projects were immaterial as of income.June 30, 2022 and December 31, 2021 for PSO and SWEPCo. See the table below for the Noncurrent Obligations Under Operating Leases for the NCWF projects for PSO and SWEPCo:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | PSO | | SWEPCo |
| | June 30, 2022 | | December 31, 2021 | | June 30, 2022 | | December 31, 2021 |
| | (in millions) |
Project | | | | | | | | |
Sundance | | $ | 12.6 | | | $ | 12.6 | | | $ | 15.0 | | | $ | 15.1 | |
Maverick | | 18.0 | | | 18.0 | | | 21.6 | | | 21.6 | |
Traverse | | 40.0 | | | — | | | 47.9 | | | — | |
Total | | $ | 70.6 | | | $ | 30.6 | | | $ | 84.5 | | | $ | 36.7 | |
ASSETS AND LIABILITIES HELD FOR SALE
Gavin, Waterford, DarbyDisposition of KPCo and Lawrenceburg Plants (Generation & Marketing Segment)KTCo (Vertically Integrated Utilities and AEP Transmission Holdco Segments) (Applies to AEP and AEPTCo)
In October 2021, AEP entered into a Stock Purchase Agreement to sell KPCo and KTCo to Liberty Utilities Co., a subsidiary of Algonquin Power & Utilities Corp. (Liberty), for approximately a $2.85 billion enterprise value. In May 2022, the KPSC approved the transfer of KPCo to Liberty subject to certain conditions contingent upon the closing of the sale. Clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and clearance from the Committee on Foreign Investment in the United States has also been received. The sale remains subject to FERC approval and to the satisfaction or waiver of the Stock Purchase Agreement condition precedent requiring the issuance of orders by the KPSC, WVPSC and FERC approving a new proposed Mitchell Plant Operations and Maintenance Agreement and Mitchell Plant Ownership Agreement between KPCo and WPCo.
Mitchell Plant Operations and Maintenance Agreement and Ownership Agreement
KPCo currently operates and owns a 50% undivided interest in the 1,560 MW coal-fired Mitchell Plant with the remaining 50% owned by WPCo. As of June 30, 2022, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $584 million.
In November 2021, AEP made filings with the KPSC, WVPSC and FERC seeking approval of a new proposed Mitchell Plant Operations and Maintenance Agreement and Mitchell Plant Ownership Agreement. In February 2022, AEP filed a motion to withdraw its filing with the FERC. The KPSC and WVPSC issued orders addressing AEP’s filings in May 2022 and July 2022. Those orders approved agreements that differ in material respects. In July 2022, KPCo and WPCo made filings with the KPSC and WVPSC, respectively, informing the respective commissions that until consistent new agreements are approved by the two state jurisdictions and the FERC, the new proposed agreements cannot be entered into by KPCo and WPCo. The existing Mitchell Plant agreement remains in place in accordance with its terms as the document governing operations and the contractual relationship between the two owners, including CCR and ELG investments in accordance with each state commission’s directives.
Transfer of Ownership
FERC Proceedings
In December 2021, Liberty, KPCo and KTCo requested FERC approval of the sale under Section 203 of the Federal Power Act. In February 2022, several intervenors in the case filed protests related to whether the sale will negatively impact the wholesale transmission rates of applicants. In April 2022, the FERC issued a deficiency letter stating that the Section 203 application is deficient and that additional information is required to process it. In May 2022, Liberty, KPCo and KTCo supplemented the application and in June 2022, the FERC issued an order formally notifying AEP that it was exercising its ability to take up to an additional 180 days to act on the application. An order from the FERC is expected on the matter in the third quarter of 2016, management determined Gavin, Waterford, Darby2022.
KPSC Proceedings
In May 2022, the KPSC approved the transfer of KPCo to Liberty subject to conditions contingent upon the closing of the sale, including establishment of regulatory liabilities to subsidize retail customer transmission and Lawrenceburg Plants metdistribution expenses, a fuel adjustment clause bill credit, and a three-year Big Sandy decommissioning rider rate holiday during which KPCo’s carrying charge is reduced by fifty percent. As a result of the classificationconditions imposed by the KPSC, in the second quarter of held2022, AEP recorded a $69 million loss on the expected sale of the Kentucky Operations in accordance with the accounting guidance for sale. Accordingly,Fair Value Measurement. AEP expects cash proceeds, net of taxes and transaction fees, from the four plants’sale of approximately $1.4 billion.
Subject to receipt of FERC authorization under Section 203 of the Federal Power Act and satisfaction or waiver of certain conditions precedent in the Stock Purchase Agreement, including the approval of the proposed new Mitchell agreements mentioned above, the sale is expected to close in the third quarter of 2022 with Liberty acquiring the assets and assuming the liabilities of KPCo and KTCo, excluding pension and other post-retirement benefit plan assets and liabilities. AEP expects to provide customary transition services to Liberty for a period of time after closing of the transaction. AEP plans to use the proceeds to eliminate forecasted equity needs in 2022 as the company invests in regulated renewables, transmission and other projects. If additional reductions in the fair value of the Kentucky Operations occur, it would reduce future net income and cash flows.
The Income Before Income Tax Expense (Benefit) of KPCo and KTCo were not material to AEP and AEPTCo for the three and six months ended June 30, 2022 and 2021, respectively.
The major classes of KPCo and KTCo’s 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, 2016AEP and asAEPTCo are shown in the table below.below:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | AEP | | AEPTCo |
| | June 30, 2022 | | December 31, 2021 | | June 30, 2022 | | December 31, 2021 |
| | (in millions) |
ASSETS | | | | | | | | |
Accounts Receivable and Accrued Unbilled Revenues | | $ | 87.1 | | | $ | 33.2 | | | $ | 1.9 | | | $ | 1.5 | |
Fuel, Materials and Supplies | | 37.4 | | | 30.6 | | | — | | | — | |
Property, Plant and Equipment, Net | | 2,358.0 | | | 2,302.7 | | | 166.9 | | | 165.3 | |
Regulatory Assets | | 484.5 | | | 484.7 | | | — | | | — | |
Other Classes of Assets that are not Major | | 47.5 | | | 68.5 | | | 2.7 | | | 1.1 | |
Total Major Classes of Assets Held for Sale | | 3,014.5 | | | 2,919.7 | | | 171.5 | | | 167.9 | |
Loss on the Expected Sale of Kentucky Operations | | (68.8) | | | — | | | — | | | — | |
Assets Held for Sale | | $ | 2,945.7 | | | $ | 2,919.7 | | | $ | 171.5 | | | $ | 167.9 | |
| | | | | | | | |
LIABILITIES | | | | | | | | |
Accounts Payable | | $ | 74.3 | | | $ | 53.4 | | | $ | 1.2 | | | $ | 1.1 | |
Long-term Debt Due Within One Year | | 415.0 | | | 200.0 | | | — | | | — | |
Customer Deposits | | 38.0 | | | 32.4 | | | — | | | — | |
Deferred Income Taxes | | 453.5 | | | 441.6 | | | 16.2 | | | 15.4 | |
Long-term Debt | | 688.3 | | | 903.1 | | | — | | | — | |
Regulatory Liabilities and Deferred Investment Tax Credits | | 140.1 | | | 148.1 | | | 7.9 | | | 7.6 | |
Other Classes of Liabilities that are not Major | | 91.1 | | | 102.3 | | | 2.3 | | | 3.5 | |
Liabilities Held for Sale | | $ | 1,900.3 | | | $ | 1,880.9 | | | $ | 27.6 | | | $ | 27.6 | |
DISPOSITIONS
Disposition of Mineral Rights (Generation & Marketing Segment) (Applies to AEP)
In June 2022, AEP closed on the sale of certain mineral rights to a nonaffiliated third-party and received $120 million of proceeds. The Income before Income Tax Expensesale resulted in a pretax gain of $116 million in the second quarter of 2022.
IMPAIRMENTS
Flat Ridge 2 Wind LLC (Generation & Marketing Segment) (Applies to AEP)
In April 2019, AEP acquired Sempra Renewables LLC and its ownership interests in 724 MWs of wind generation and battery assets. The acquisition included a 50% ownership interest in five non-consolidated joint ventures, including Flat Ridge 2 Wind LLC (Flat Ridge 2), and two tax equity partnerships. The five non-consolidated joint ventures are jointly owned and operated by BP Wind Energy. Flat Ridge 2 sells electricity to three counterparties through long-term PPAs.
Regarding AEP’s investment in Flat Ridge 2, in June 2022, as a result of deteriorating financial performance, sale negotiations AEP’s ongoing evaluation and ultimate decision to exit the investment in the near term, in June 2022 management determined a decline in the fair value of AEP’s investment in Flat Ridge 2 was other than temporary. In accordance with the accounting guidance for “Investments - Equity Method and Joint Ventures”, AEP recorded a pretax other than temporary impairment charge of $186 million in Equity Earnings (Losses) of Unconsolidated Subsidiaries in AEP’s Statement of Income in the second quarter of 2022. AEP’s determination of fair value utilized ASC 820 Fair Value Measurement market approach to valuation and was based on Level 2 pricing information from a third-party market participant. The carrying value of the four plantsinvestment in Flat Ridge 2 was approximately $116 million for the three months ended Septembernot material to AEP as of June 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.2022.
|
| | | | |
| | 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 |
|
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 June 30, | | Three Months Ended June 30, |
| 2017 | | 2016 | | 2017 | | 2016 | | 2022 | | 2021 | | 2022 | | 2021 |
| (in millions) | | (in millions) |
Service Cost | $ | 24.1 |
| | $ | 21.4 |
| | $ | 2.8 |
| | $ | 2.6 |
| Service Cost | $ | 30.8 | | | $ | 32.3 | | | $ | 1.9 | | | $ | 2.4 | |
Interest Cost | 50.7 |
| | 52.9 |
| | 14.8 |
| | 15.3 |
| Interest Cost | 37.1 | | | 34.3 | | | 7.3 | | | 7.6 | |
Expected Return on Plan Assets | (71.1 | ) | | (70.1 | ) | | (25.3 | ) | | (26.8 | ) | Expected Return on Plan Assets | (63.3) | | | (57.4) | | | (27.5) | | | (22.8) | |
Amortization of Prior Service Cost (Credit) | 0.3 |
| | 0.6 |
| | (17.3 | ) | | (17.3 | ) | |
Amortization of Prior Service Credit | | Amortization of Prior Service Credit | — | | | — | | | (17.9) | | | (17.7) | |
Amortization of Net Actuarial Loss | 20.7 |
| | 21.0 |
| | 9.2 |
| | 7.8 |
| Amortization of Net Actuarial Loss | 15.7 | | | 25.4 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | $ | 24.7 |
| | $ | 25.8 |
| | $ | (15.8 | ) | | $ | (18.4 | ) | Net Periodic Benefit Cost (Credit) | $ | 20.3 | | | $ | 34.6 | | | $ | (36.2) | | | $ | (30.5) | |
| | | | Pension Plans | | OPEB |
| | | Six Months Ended June 30, | | Six Months Ended June 30, |
| | | 2022 | | 2021 | | 2022 | | 2021 |
| | | (in millions) |
Service Cost | | Service Cost | $ | 61.6 | | | $ | 64.6 | | | $ | 3.7 | | | $ | 4.8 | |
Interest Cost | | Interest Cost | 74.1 | | | 68.6 | | | 14.6 | | | 15.2 | |
Expected Return on Plan Assets | | Expected Return on Plan Assets | (126.7) | | | (114.9) | | | (55.0) | | | (45.6) | |
Amortization of Prior Service Credit | | Amortization of Prior Service Credit | — | | | — | | | (35.7) | | | (35.4) | |
Amortization of Net Actuarial Loss | | Amortization of Net Actuarial Loss | 31.5 | | | 50.8 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | | Net Periodic Benefit Cost (Credit) | $ | 40.5 | | | $ | 69.1 | | | $ | (72.4) | | | $ | (61.0) | |
|
| | | | | | | | | | | | | | | |
| 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 June 30, | | Three Months Ended June 30, |
| 2022 | | 2021 | | 2022 | | 2021 |
| (in millions) |
Service Cost | $ | 2.8 | | | $ | 2.9 | | | $ | 0.1 | | | $ | 0.1 | |
Interest Cost | 3.0 | | | 2.8 | | | 0.5 | | | 0.6 | |
Expected Return on Plan Assets | (5.2) | | | (4.8) | | | (2.2) | | | (1.8) | |
Amortization of Prior Service Credit | — | | | — | | | (1.5) | | | (1.5) | |
Amortization of Net Actuarial Loss | 1.3 | | | 2.0 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | $ | 1.9 | | | $ | 2.9 | | | $ | (3.1) | | | $ | (2.6) | |
| | | | | | | |
| Pension Plans | | OPEB |
| Six Months Ended June 30, | | Six Months Ended June 30, |
| 2022 | | 2021 | | 2022 | | 2021 |
| (in millions) |
Service Cost | $ | 5.6 | | | $ | 5.9 | | | $ | 0.2 | | | $ | 0.3 | |
Interest Cost | 6.0 | | | 5.6 | | | 1.1 | | | 1.2 | |
Expected Return on Plan Assets | (10.5) | | | (9.7) | | | (4.5) | | | (3.7) | |
Amortization of Prior Service Credit | — | | | — | | | (3.0) | | | (3.0) | |
Amortization of Net Actuarial Loss | 2.6 | | | 4.1 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | $ | 3.7 | | | $ | 5.9 | | | $ | (6.2) | | | $ | (5.2) | |
APCo
| | | Pension Plans | | Other Postretirement Benefit Plans | | Pension Plans | | OPEB |
| Three Months Ended September 30, | | Three Months Ended September 30, | | Three Months Ended June 30, | | Three Months Ended June 30, |
| 2017 |
| 2016 | | 2017 | | 2016 | | 2022 | | 2021 | | 2022 | | 2021 |
| (in millions) | | (in millions) |
Service Cost | $ | 2.3 |
| | $ | 2.1 |
| | $ | 0.3 |
| | $ | 0.2 |
| Service Cost | $ | 2.8 | | | $ | 2.9 | | | $ | 0.2 | | | $ | 0.2 | |
Interest Cost | 6.5 |
| | 6.8 |
| | 2.6 |
| | 2.7 |
| Interest Cost | 4.4 | | | 4.1 | | | 1.1 | | | 1.2 | |
Expected Return on Plan Assets | (8.9 | ) | | (8.8 | ) | | (4.1 | ) | | (4.3 | ) | Expected Return on Plan Assets | (8.1) | | | (7.2) | | | (4.0) | | | (3.3) | |
Amortization of Prior Service Credit | — |
| | — |
| | (2.5 | ) | | (2.5 | ) | Amortization of Prior Service Credit | — | | | — | | | (2.6) | | | (2.6) | |
Amortization of Net Actuarial Loss | 2.6 |
| | 2.6 |
| | 1.6 |
| | 1.4 |
| Amortization of Net Actuarial Loss | 1.8 | | | 3.0 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | $ | 2.5 |
| | $ | 2.7 |
| | $ | (2.1 | ) | | $ | (2.5 | ) | Net Periodic Benefit Cost (Credit) | $ | 0.9 | | | $ | 2.8 | | | $ | (5.3) | | | $ | (4.5) | |
| | | | Pension Plans | | OPEB |
| | | Six Months Ended June 30, | | Six Months Ended June 30, |
| | | 2022 | | 2021 | | 2022 | | 2021 |
| | | (in millions) |
Service Cost | | Service Cost | $ | 5.7 | | | $ | 5.9 | | | $ | 0.4 | | | $ | 0.5 | |
Interest Cost | | Interest Cost | 8.8 | | | 8.2 | | | 2.3 | | | 2.4 | |
Expected Return on Plan Assets | | Expected Return on Plan Assets | (16.2) | | | (14.5) | | | (8.1) | | | (6.7) | |
Amortization of Prior Service Credit | | Amortization of Prior Service Credit | — | | | — | | | (5.2) | | | (5.2) | |
Amortization of Net Actuarial Loss | | Amortization of Net Actuarial Loss | 3.6 | | | 6.0 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | | Net Periodic Benefit Cost (Credit) | $ | 1.9 | | | $ | 5.6 | | | $ | (10.6) | | | $ | (9.0) | |
|
| | | | | | | | | | | | | | | |
| 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 June 30, | | Three Months Ended June 30, |
| 2022 | | 2021 | | 2022 | | 2021 |
| (in millions) |
Service Cost | $ | 4.1 | | | $ | 4.3 | | | $ | 0.3 | | | $ | 0.3 | |
Interest Cost | 4.2 | | | 4.1 | | | 0.9 | | | 0.9 | |
Expected Return on Plan Assets | (8.1) | | | (7.2) | | | (3.5) | | | (2.8) | |
Amortization of Prior Service Credit | — | | | — | | | (2.5) | | | (2.4) | |
Amortization of Net Actuarial Loss | 1.7 | | | 3.0 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | $ | 1.9 | | | $ | 4.2 | | | $ | (4.8) | | | $ | (4.0) | |
| | | | | | | |
| Pension Plans | | OPEB |
| Six Months Ended June 30, | | Six Months Ended June 30, |
| 2022 | | 2021 | | 2022 | | 2021 |
| (in millions) |
Service Cost | $ | 8.1 | | | $ | 8.7 | | | $ | 0.5 | | | $ | 0.6 | |
Interest Cost | 8.4 | | | 8.1 | | | 1.7 | | | 1.8 | |
Expected Return on Plan Assets | (16.1) | | | (14.4) | | | (6.9) | | | (5.6) | |
Amortization of Prior Service Credit | — | | | — | | | (4.9) | | | (4.8) | |
Amortization of Net Actuarial Loss | 3.5 | | | 5.9 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | $ | 3.9 | | | $ | 8.3 | | | $ | (9.6) | | | $ | (8.0) | |
|
| | | | | | | | | | | | | | | |
| 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 June 30, | | Three Months Ended June 30, |
| 2022 | | 2021 | | 2022 | | 2021 |
| (in millions) |
Service Cost | $ | 2.9 | | | $ | 2.8 | | | $ | 0.1 | | | $ | 0.2 | |
Interest Cost | 3.2 | | | 3.1 | | | 0.8 | | | 0.8 | |
Expected Return on Plan Assets | (6.2) | | | (5.5) | | | (2.9) | | | (2.5) | |
Amortization of Prior Service Credit | — | | | — | | | (1.8) | | | (1.8) | |
Amortization of Net Actuarial Loss | 1.4 | | | 2.3 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | $ | 1.3 | | | $ | 2.7 | | | $ | (3.8) | | | $ | (3.3) | |
| | | | | | | |
| Pension Plans | | OPEB |
| Six Months Ended June 30, | | Six Months Ended June 30, |
| 2022 | | 2021 | | 2022 | | 2021 |
| (in millions) |
Service Cost | $ | 5.6 | | | $ | 5.7 | | | $ | 0.3 | | | $ | 0.4 | |
Interest Cost | 6.6 | | | 6.2 | | | 1.5 | | | 1.6 | |
Expected Return on Plan Assets | (12.4) | | | (11.1) | | | (5.9) | | | (4.9) | |
Amortization of Prior Service Credit | — | | | — | | | (3.6) | | | (3.6) | |
Amortization of Net Actuarial Loss | 2.8 | | | 4.5 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | $ | 2.6 | | | $ | 5.3 | | | $ | (7.7) | | | $ | (6.5) | |
|
| | | | | | | | | | | | | | | |
| 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 June 30, | | Three Months Ended June 30, |
| 2022 | | 2021 | | 2022 | | 2021 |
| (in millions) |
Service Cost | $ | 1.8 | | | $ | 2.1 | | | $ | 0.1 | | | $ | 0.1 | |
Interest Cost | 1.7 | | | 1.6 | | | 0.3 | | | 0.4 | |
Expected Return on Plan Assets | (3.4) | | | (3.1) | | | (1.5) | | | (1.2) | |
Amortization of Prior Service Credit | — | | | — | | | (1.1) | | | (1.1) | |
Amortization of Net Actuarial Loss | 0.8 | | | 1.2 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | $ | 0.9 | | | $ | 1.8 | | | $ | (2.2) | | | $ | (1.8) | |
| | | | | | | |
| Pension Plans | | OPEB |
| Six Months Ended June 30, | | Six Months Ended June 30, |
| 2022 | | 2021 | | 2022 | | 2021 |
| (in millions) |
Service Cost | $ | 3.7 | | | $ | 4.0 | | | $ | 0.2 | | | $ | 0.3 | |
Interest Cost | 3.5 | | | 3.3 | | | 0.7 | | | 0.8 | |
Expected Return on Plan Assets | (6.8) | | | (6.2) | | | (3.0) | | | (2.5) | |
Amortization of Prior Service Credit | — | | | — | | | (2.2) | | | (2.2) | |
Amortization of Net Actuarial Loss | 1.5 | | | 2.5 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | $ | 1.9 | | | $ | 3.6 | | | $ | (4.3) | | | $ | (3.6) | |
|
| | | | | | | | | | | | | | | |
| 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 June 30, | | Three Months Ended June 30, |
| 2022 | | 2021 | | 2022 | | 2021 |
| (in millions) |
Service Cost | $ | 2.7 | | | $ | 2.8 | | | $ | 0.2 | | | $ | 0.2 | |
Interest Cost | 2.3 | | | 2.1 | | | 0.4 | | | 0.5 | |
Expected Return on Plan Assets | (3.6) | | | (3.4) | | | (1.8) | | | (1.5) | |
Amortization of Prior Service Credit | — | | | — | | | (1.3) | | | (1.3) | |
Amortization of Net Actuarial Loss | 0.9 | | | 1.6 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | $ | 2.3 | | | $ | 3.1 | | | $ | (2.5) | | | $ | (2.1) | |
| | | | | | | |
| Pension Plans | | OPEB |
| Six Months Ended June 30, | | Six Months Ended June 30, |
| 2022 | | 2021 | | 2022 | | 2021 |
| (in millions) |
Service Cost | $ | 5.3 | | | $ | 5.7 | | | $ | 0.3 | | | $ | 0.3 | |
Interest Cost | 4.6 | | | 4.2 | | | 0.9 | | | 1.0 | |
Expected Return on Plan Assets | (7.3) | | | (6.8) | | | (3.7) | | | (3.0) | |
Amortization of Prior Service Credit | — | | | — | | | (2.6) | | | (2.6) | |
Amortization of Net Actuarial Loss | 1.9 | | | 3.1 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | $ | 4.5 | | | $ | 6.2 | | | $ | (5.1) | | | $ | (4.3) | |
|
| | | | | | | | | | | | | | | |
| 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, PJM, SPP and MISO.
Contracted renewable energy investments and management services.•Competitive generation in PJM.
The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income, and interest expense, income tax expense and other nonallocated costs.
The tables below presentrepresent AEP’s reportable segment income statement information for the three and ninesix months ended SeptemberJune 30, 20172022 and 20162021 and reportable segment balance sheet information as of SeptemberJune 30, 20172022 and December 31, 2016. These amounts2021.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, 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 | $ | 2,595.0 | | | $ | 1,296.8 | | | $ | 79.1 | | | $ | 654.4 | | | $ | 14.4 | | | $ | — | | | $ | 4,639.7 | |
Other Operating Segments | 53.5 | | | 4.8 | | | 299.7 | | | 5.2 | | | 10.1 | | | (373.3) | | | — | |
Total Revenues | $ | 2,648.5 | | | $ | 1,301.6 | | | $ | 378.8 | | | $ | 659.6 | | | $ | 24.5 | | | $ | (373.3) | | | $ | 4,639.7 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Net Income (Loss) | $ | 303.3 | | | $ | 164.8 | | | $ | 142.7 | | | $ | 65.9 | | | $ | (155.9) | | | $ | — | | | $ | 520.8 | |
| | | | | | | | | | | | | |
| Three Months Ended June 30, 2021 |
| 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 | $ | 2,224.6 | | | $ | 1,089.6 | | | $ | 86.4 | | | $ | 422.5 | | | $ | 3.4 | | | $ | — | | | $ | 3,826.5 | |
Other Operating Segments | 36.0 | | | 13.8 | | | 291.8 | | | 14.1 | | | 12.1 | | | (367.8) | | | — | |
Total Revenues | $ | 2,260.6 | | | $ | 1,103.4 | | | $ | 378.2 | | | $ | 436.6 | | | $ | 15.5 | | | $ | (367.8) | | | $ | 3,826.5 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Net Income (Loss) | $ | 228.8 | | | $ | 153.7 | | | $ | 169.6 | | | $ | 46.5 | | | $ | (24.8) | | | $ | — | | | $ | 573.8 | |
| | | | | | | | | | | | | |
| |
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| Six Months Ended June 30, 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 | $ | 5,241.8 | | | $ | 2,539.0 | | | $ | 162.5 | | | $ | 1,263.9 | | | $ | 25.1 | | | $ | — | | | $ | 9,232.3 | |
Other Operating Segments | 94.1 | | | 9.4 | | | 627.7 | | | 15.0 | | | 19.3 | | | (765.5) | | | — | |
Total Revenues | $ | 5,335.9 | | | $ | 2,548.4 | | | $ | 790.2 | | | $ | 1,278.9 | | | $ | 44.4 | | | $ | (765.5) | | | $ | 9,232.3 | |
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Net Income (Loss) | $ | 602.5 | | | $ | 317.6 | | | $ | 316.4 | | | $ | 181.9 | | | $ | (179.5) | | | $ | — | | | $ | 1,238.9 | |
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| Six Months Ended June 30, 2021 |
| 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 | $ | 4,729.1 | | | $ | 2,171.9 | | | $ | 174.3 | | | $ | 1,024.2 | | | $ | 8.1 | | | $ | — | | | $ | 8,107.6 | |
Other Operating Segments | 68.8 | | | 19.6 | | | 580.9 | | | 46.6 | | | 20.3 | | | (736.2) | | | — | |
Total Revenues | $ | 4,797.9 | | | $ | 2,191.5 | | | $ | 755.2 | | | $ | 1,070.8 | | | $ | 28.4 | | | $ | (736.2) | | | $ | 8,107.6 | |
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Net Income (Loss) | $ | 500.2 | | | $ | 268.1 | | | $ | 342.8 | | | $ | 84.7 | | | $ | (43.2) | | | $ | — | | | $ | 1,152.6 | |
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| | June 30, 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 (d) | | $ | 48,926.6 | | | $ | 22,444.5 | | | $ | 14,472.1 | | | $ | 5,202.3 | | | $ | 6,566.0 | | (b) | $ | (6,750.2) | | (c) | $ | 90,861.3 | |
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| | December 31, 2021 |
| | 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 (d) | | $ | 46,974.2 | | | $ | 21,120.2 | | | $ | 13,873.3 | | | $ | 4,263.6 | | | $ | 5,846.5 | | (b) | $ | (4,409.1) | | (c) | $ | 87,668.7 | |
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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 “Disposition of KPCo and KTCo” section of Note 6 for additional information.
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| 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: | |
| | |
| | |
| | |
| | |
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|
External Customers | $ | 2,453.8 |
| | $ | 1,149.7 |
| | $ | 45.1 |
| | $ | 441.5 |
| | $ | 14.6 |
| | $ | — |
| | $ | 4,104.7 |
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Other Operating Segments | 28.4 |
| | 23.6 |
| | 133.4 |
| | 24.0 |
| | 16.7 |
| | (226.1 | ) | | — |
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Total Revenues | $ | 2,482.2 |
| | $ | 1,173.3 |
| | $ | 178.5 |
| | $ | 465.5 |
| | $ | 31.3 |
| | $ | (226.1 | ) | | $ | 4,104.7 |
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Income (Loss) from Continuing Operations | $ | 297.3 |
| | $ | 144.0 |
| | $ | 76.5 |
| | $ | 33.7 |
| | $ | 5.2 |
| | $ | — |
| | $ | 556.7 |
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Loss from Discontinued Operations, Net of Tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Net Income (Loss) | $ | 297.3 |
| | $ | 144.0 |
| | $ | 76.5 |
| | $ | 33.7 |
| | $ | 5.2 |
| | $ | — |
| | $ | 556.7 |
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| 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: | |
| | |
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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 | ) | | — |
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Total Revenues | $ | 2,556.3 |
| | $ | 1,275.6 |
| | $ | 132.4 |
| | $ | 859.4 |
| | $ | 24.8 |
| | $ | (196.3 | ) | | $ | 4,652.2 |
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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 | ) |
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| 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: | |
| | |
| | |
| | |
| | |
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|
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 |
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Income (Loss) from Continuing Operations | $ | 639.2 |
| | $ | 374.3 |
| | $ | 278.3 |
| | $ | 246.3 |
| | $ | (11.0 | ) | | $ | — |
| | $ | 1,527.1 |
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Loss from Discontinued Operations, Net of Tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Net Income (Loss) | $ | 639.2 |
| | $ | 374.3 |
| | $ | 278.3 |
| | $ | 246.3 |
| | $ | (11.0 | ) | | $ | — |
| | $ | 1,527.1 |
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| 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: | |
| | |
| | |
| | |
| | |
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|
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 |
|
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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 |
|
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| | 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 |
|
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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 |
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Long-term Debt Due Within One Year: | | | | | | | | | | | | | | |
Non-Affiliated | | $ | 1,107.2 |
| | $ | 703.4 |
| | $ | — |
| | $ | 0.1 |
| | $ | 548.6 |
| | $ | — |
| | $ | 2,359.3 |
|
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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 |
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| | 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 |
|
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Assets Held for Sale | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,951.2 |
| | $ | — |
| | $ | — |
| | $ | 1,951.2 |
|
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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 |
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Long-term Debt Due Within One Year: | | | | | | | | | | | | | | |
Non-Affiliated | | $ | 1,519.9 |
| | $ | 309.4 |
| | $ | — |
| | $ | 500.1 |
| | $ | 548.6 |
| | $ | — |
| | $ | 2,878.0 |
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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 |
|
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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 ninesix months ended SeptemberJune 30, 20172022 and 20162021 and reportable segment balance sheet information as of SeptemberJune 30, 20172022 and December 31, 2016. These amounts include certain estimates2021.
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| Three Months Ended June 30, 2022 |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| (in millions) |
Revenues from: | | | | | | | |
External Customers | $ | 77.3 | | | $ | — | | | $ | — | | | $ | 77.3 | |
Sales to AEP Affiliates | 287.1 | | | — | | | — | | | 287.1 | |
| | | | | | | |
Total Revenues | $ | 364.4 | | | $ | — | | | $ | — | | | $ | 364.4 | |
| | | | | | | |
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| | | | | | | |
| | | | | | | |
| | | | | | | |
Net Income | $ | 118.4 | | | $ | 0.1 | | (a) | $ | — | | | $ | 118.5 | |
| | | | | | | |
| Three Months Ended June 30, 2021 |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| (in millions) |
Revenues from: | | | | | | | |
External Customers | $ | 84.1 | | | $ | — | | | $ | — | | | $ | 84.1 | |
Sales to AEP Affiliates | 281.4 | | | — | | | — | | | 281.4 | |
| | | | | | | |
Total Revenues | $ | 365.5 | | | $ | — | | | $ | — | | | $ | 365.5 | |
| | | | | | | |
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| | | | | | | |
| | | | | | | |
Net Income | $ | 148.5 | | | $ | 0.1 | | (a) | $ | — | | | $ | 148.6 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2022 |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| (in millions) |
Revenues from: | | | | | | | |
External Customers | $ | 162.3 | | | $ | — | | | $ | — | | | $ | 162.3 | |
Sales to AEP Affiliates | 602.5 | | — | | | — | | | 602.5 | |
| | | | | | | |
Total Revenues | $ | 764.8 | | | $ | — | | | $ | — | | | $ | 764.8 | |
| | | | | | | |
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| | | | | | | |
| | | | | | | |
| | | | | | | |
Net Income | $ | 273.8 | | | $ | 0.1 | | (a) | $ | — | | | $ | 273.9 | |
| | | | | | | |
| Six Months Ended June 30, 2021 |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| (in millions) |
Revenues from: | | | | | | | |
External Customers | $ | 160.1 | | | $ | — | | | $ | — | | | $ | 160.1 | |
Sales to AEP Affiliates | 567.0 | | — | | | — | | | 567.0 | |
Other Revenues | 0.1 | | | — | | | — | | | 0.1 | |
Total Revenues | $ | 727.2 | | | $ | — | | | $ | — | | | $ | 727.2 | |
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Net Income | $ | 300.2 | | | $ | 0.1 | | (a) | $ | — | | | $ | 300.3 | |
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| June 30, 2022 |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| (in millions) |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
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Total Assets (d) | $ | 13,152.5 | | | $ | 4,928.4 | | (b) | $ | (4,991.1) | | (c) | $ | 13,089.8 | |
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| December 31, 2021 |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| (in millions) |
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Total Assets (d) | $ | 12,564.3 | | | $ | 4,389.5 | | (b) | $ | (4,429.4) | | (c) | $ | 12,524.4 | |
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(a)Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos.
(b)Includes the elimination of AEPTCo Parent’s investments in State Transcos.
(c)Primarily relates to the elimination of Notes Receivable from the State Transcos.
(d)Amount includes Assets Held for Sale on the balance sheet. See “Disposition of KPCo and allocations where necessary.KTCo” section of Note 6 for additional information.
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| | | | | | | | | | | | | | | |
| 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 |
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| 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 |
|
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Interest Income | $ | — |
| | $ | 14.0 |
| | $ | (13.9 | ) | (a) | $ | 0.1 |
|
Interest Expense | 11.0 |
| | 13.9 |
| | (13.9 | ) | (a) | 11.0 |
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Income Tax Expense | 26.4 |
| | — |
| | — |
| | 26.4 |
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Equity Earnings in State Transcos | — |
| | 52.3 |
| | (52.3 | ) | (b) | — |
|
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Net Income | $ | 52.3 |
| | $ | 52.4 |
| | $ | (52.3 | ) | (b) | $ | 52.4 |
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| 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 |
|
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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 |
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Equity Earnings in State Transcos | — |
| | 224.0 |
| | (224.0 | ) | (b) | — |
|
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Net Income | $ | 224.0 |
| | $ | 224.3 |
| | $ | (224.0 | ) | (b) | $ | 224.3 |
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| 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 |
|
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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 |
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Equity Earnings in State Transcos | — |
| | 153.0 |
| | (153.0 | ) | (b) | — |
|
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Net Income | $ | 153.0 |
| | $ | 153.0 |
| | $ | (153.0 | ) | (b) | $ | 153.0 |
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| 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 |
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Notes Receivable - Affiliated | $ | — |
| | $ | 2,500.0 |
| | $ | (2,500.0 | ) | (c) | $ | — |
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Total Assets | $ | 6,455.2 |
| | $ | 5,010.8 |
| | $ | (4,917.1 | ) | (d) | $ | 6,548.9 |
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Total Long-term Debt | $ | 2,475.6 |
| | $ | 2,574.4 |
| | $ | (2,500.0 | ) | (c) | $ | 2,550.0 |
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| 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 |
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Total Transmission Property – Net | $ | 4,954.6 |
| | $ | — |
| | $ | — |
| | $ | 4,954.6 |
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Notes Receivable - Affiliated | $ | — |
| | $ | 1,950.0 |
| | $ | (1,950.0 | ) | (c) | $ | — |
|
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Total Assets | $ | 5,337.5 |
| | $ | 3,947.8 |
| | $ | (3,935.5 | ) | (d) | $ | 5,349.8 |
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Total Long-term Debt | $ | 1,932.0 |
| | $ | 1,950.0 |
| | $ | (1,950.0 | ) | (c) | $ | 1,932.0 |
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(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
SeptemberJune 30, 20172022
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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 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Primary Risk Exposure | | Unit of Measure | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in millions) |
Commodity: | | | | | | | | | | | | | | | | |
Power | | MWhs | | 283.9 | | | — | | | 39.7 | | | 8.4 | | | 2.6 | | | 8.3 | | | 5.6 | |
| | | | | | | | | | | | | | | | |
Natural Gas | | MMBtus | | 47.8 | | | — | | | — | | | — | | | — | | | — | | | 2.7 | |
Heating Oil and Gasoline | | Gallons | | 5.9 | | | 1.5 | | | 0.8 | | | 0.6 | | | 1.2 | | | 0.7 | | | 0.8 | |
Interest Rate | | USD | | $ | 108.6 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | |
Interest Rate on Long-term Debt | | USD | | $ | 1,150.0 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
December 31, 20162021
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Primary Risk Exposure | | Unit of Measure | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in millions) |
Commodity: | | | | | | | | | | | | | | | | |
Power | | MWhs | | 287.9 | | | — | | | 33.1 | | | 13.6 | | | 2.7 | | | 11.9 | | | 3.4 | |
| | | | | | | | | | | | | | | | |
Natural Gas | | MMBtus | | 34.1 | | | — | | | — | | | — | | | — | | | 1.3 | | | 5.1 | |
Heating Oil and Gasoline | | Gallons | | 7.4 | | | 1.9 | | | 1.1 | | | 0.7 | | | 1.5 | | | 0.8 | | | 1.0 | |
Interest Rate | | USD | | $ | 116.5 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | |
Interest Rate on Long-term Debt | | USD | | $ | 950.0 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | |
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| | | | | | | | | | | | | | | | | | | | | | | | | | |
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 $1.1 billion and $263 million as of June 30, 2022 and December 31, 2021, respectively. AEP netted cash collateral paid to third-parties against short-term and long-term risk management liabilities in the amounts of $0 and $3 million as of June 30, 2022 and December 31, 2021, respectively. The netted cash collateral from third-parties against short-term and long-term risk management assets and netted cash collateral paid to third partiesthird-parties against short-term and long-term risk management liabilities were immaterial for the Registrant Subsidiaries as follows:of June 30, 2022 and December 31, 2021.
|
| | | | | | | | | | | | | | | | |
| | 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
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 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 (d) | | $ | 1,655.3 | | | $ | 522.5 | | | $ | — | | | $ | 2,177.8 | | | $ | (1,724.3) | | | $ | 453.5 | |
Long-term Risk Management Assets | | 625.1 | | | 171.6 | | | 4.4 | | | 801.1 | | | (636.2) | | | 164.9 | |
Total Assets | | 2,280.4 | | | 694.1 | | | 4.4 | | | 2,978.9 | | | (2,360.5) | | | 618.4 | |
| | | | | | | | | | | | |
Current Risk Management Liabilities (e) | | 1,198.2 | | | 13.5 | | | 19.5 | | | 1,231.2 | | | (1,051.5) | | | 179.7 | |
Long-term Risk Management Liabilities | | 449.6 | | | 4.8 | | | 80.1 | | | 534.5 | | | (222.5) | | | 312.0 | |
Total Liabilities | | 1,647.8 | | | 18.3 | | | 99.6 | | | 1,765.7 | | | (1,274.0) | | | 491.7 | |
| | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) (f) | | $ | 632.6 | | | $ | 675.8 | | | $ | (95.2) | | | $ | 1,213.2 | | | $ | (1,086.5) | | | $ | 126.7 | |
Fair Value of Derivative Instruments
September 30, 2017 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2021 |
| | Risk Management Contracts | | Hedging Contracts | | Gross Amounts of Risk Management Assets/ Liabilities Recognized | | Gross Amounts Offset in the Statement of Financial Position (b) | | Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) |
Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Interest Rate (a) | | | |
| | (in millions) |
Current Risk Management Assets (d) | | $ | 513.4 | | | $ | 176.0 | | | $ | 1.2 | | | $ | 690.6 | | | $ | (496.2) | | | $ | 194.4 | |
Long-term Risk Management Assets | | 370.5 | | | 89.1 | | | — | | | 459.6 | | | (192.6) | | | 267.0 | |
Total Assets | | 883.9 | | | 265.1 | | | 1.2 | | | 1,150.2 | | | (688.8) | | | 461.4 | |
| | | | | | | | | | | | |
Current Risk Management Liabilities (e) | | 395.7 | | | 40.9 | | | — | | | 436.6 | | | (361.2) | | | 75.4 | |
Long-term Risk Management Liabilities | | 243.9 | | | 16.7 | | | 38.1 | | | 298.7 | | | (68.4) | | | 230.3 | |
Total Liabilities | | 639.6 | | | 57.6 | | | 38.1 | | | 735.3 | | | (429.6) | | | 305.7 | |
| | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 244.3 | | | $ | 207.5 | | | $ | (36.9) | | | $ | 414.9 | | | $ | (259.2) | | | $ | 155.7 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 |
|
AEP Texas | | | | | | | | | | | | | | | | | | | | |
| | June 30, 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 | | $ | 1.6 | | | $ | (1.4) | | | $ | 0.2 | |
Long-term Risk Management Assets | | — | | | — | | | — | |
Total Assets | | 1.6 | | | (1.4) | | | 0.2 | |
| | | | | | |
Current Risk Management Liabilities | | — | | | — | | | — | |
Long-term Risk Management Liabilities | | — | | | — | | | — | |
Total Liabilities | | — | | | — | | | — | |
| | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 1.6 | | | $ | (1.4) | | | $ | 0.2 | |
| | | | | | | | | | | | | | | | | | | | |
| | December 31, 2021 |
| | 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 | | $ | 0.6 | | | $ | (0.6) | | | $ | — | |
Long-term Risk Management Assets | | — | | | — | | | — | |
Total Assets | | 0.6 | | | (0.6) | | | — | |
| | | | | | |
Current Risk Management Liabilities | | — | | | — | | | — | |
Long-term Risk Management Liabilities | | — | | | — | | | — | |
Total Liabilities | | — | | | — | | | — | |
| | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 0.6 | | | $ | (0.6) | | | $ | — | |
APCo
Fair Value of Derivative Instruments | | | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 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 | | $ | 82.0 | | | | | | | $ | (2.3) | | | $ | 79.7 | |
Long-term Risk Management Assets | | 0.6 | | | | | | | (0.6) | | | — | |
Total Assets | | 82.6 | | | | | | | (2.9) | | | 79.7 | |
| | | | | | | | | | |
Current Risk Management Liabilities | | 1.6 | | | | | | | (1.6) | | | — | |
Long-term Risk Management Liabilities | | 0.6 | | | | | | | (0.6) | | | — | |
Total Liabilities | | 2.2 | | | | | | | (2.2) | | | — | |
| | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) (f) | | $ | 80.4 | | | | | | | $ | (0.7) | | | $ | 79.7 | |
September 30, 2017
| | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2021 |
| | | | | | | | | | |
| | | | | | | | | | |
| | 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 | | $ | 47.5 | | | | | | | $ | (5.5) | | | $ | 42.0 | |
Long-term Risk Management Assets | | 0.2 | | | | | | | (0.2) | | | — | |
Total Assets | | 47.7 | | | | | | | (5.7) | | | 42.0 | |
| | | | | | | | | | |
Current Risk Management Liabilities | | 7.2 | | | | | | | (6.4) | | | 0.8 | |
Long-term Risk Management Liabilities | | 0.2 | | | | | | | (0.2) | | | — | |
Total Liabilities | | 7.4 | | | | | | | (6.6) | | | 0.8 | |
| | | | | | | | | | |
Total MTM Derivative Contract Net Assets | | $ | 40.3 | | | | | | | $ | 0.9 | | | $ | 41.2 | |
|
| | | | | | | | | | | | |
| | 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 | | | | | | | | | | | | | | | | | | | | |
| | June 30, 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 | | $ | 11.4 | | | $ | (1.5) | | | $ | 9.9 | |
Long-term Risk Management Assets | | 0.4 | | | (0.4) | | | — | |
Total Assets | | 11.8 | | | (1.9) | | | 9.9 | |
| | | | | | |
Current Risk Management Liabilities | | 1.0 | | | (1.0) | | | — | |
Long-term Risk Management Liabilities | | 0.4 | | | (0.4) | | | — | |
Total Liabilities | | 1.4 | | | (1.4) | | | — | |
| | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) (f) | | $ | 10.4 | | | $ | (0.5) | | | $ | 9.9 | |
September 30, 2017
| | | | | | | | | | | | | | | | | | | | |
| | December 31, 2021 |
| | 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 | | $ | 11.1 | | | $ | (7.8) | | | $ | 3.3 | |
Long-term Risk Management Assets | | 0.2 | | | (0.2) | | | — | |
Total Assets | | 11.3 | | | (8.0) | | | 3.3 | |
| | | | | | |
Current Risk Management Liabilities | | 14.8 | | | (9.8) | | | 5.0 | |
Long-term Risk Management Liabilities | | 0.2 | | | (0.2) | | | — | |
Total Liabilities | | 15.0 | | | (10.0) | | | 5.0 | |
| | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | (3.7) | | | $ | 2.0 | | | $ | (1.7) | |
|
| | | | | | | | | | | | |
| | 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 | | | | | | | | | | | | | | | | | | | | |
| | June 30, 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 | | $ | 2.4 | | | $ | (1.1) | | | $ | 1.3 | |
Long-term Risk Management Assets | | — | | | — | | | — | |
Total Assets | | 2.4 | | | (1.1) | | | 1.3 | |
| | | | | | |
Current Risk Management Liabilities | | 0.1 | | | (0.1) | | | — | |
Long-term Risk Management Liabilities | | 49.6 | | | — | | | 49.6 | |
Total Liabilities | | 49.7 | | | (0.1) | | | 49.6 | |
| | | | | | |
Total MTM Derivative Contract Net Liabilities (f) | | $ | (47.3) | | | $ | (1.0) | | | $ | (48.3) | |
September 30, 2017
| | | | | | | | | | | | | | | | | | | | |
| | December 31, 2021 |
| | 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 | | $ | 0.5 | | | $ | (0.5) | | | $ | — | |
Long-term Risk Management Assets | | — | | | — | | | — | |
Total Assets | | 0.5 | | | (0.5) | | | — | |
| | | | | | |
Current Risk Management Liabilities | | 6.7 | | | — | | | 6.7 | |
Long-term Risk Management Liabilities | | 85.8 | | | — | | | 85.8 | |
Total Liabilities | | 92.5 | | | — | | | 92.5 | |
| | | | | | |
Total MTM Derivative Contract Net Liabilities | | $ | (92.0) | | | $ | (0.5) | | | $ | (92.5) | |
|
| | | | | | | | | | | | |
| | 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 | | | | | | | | | | | | | | | | | | | | |
| | June 30, 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 | | $ | 66.3 | | | $ | (1.7) | | | $ | 64.6 | |
Long-term Risk Management Assets | | — | | | — | | | — | |
Total Assets | | 66.3 | | | (1.7) | | | 64.6 | |
| | | | | | |
Current Risk Management Liabilities | | 1.1 | | | (1.1) | | | — | |
Long-term Risk Management Liabilities | | — | | | — | | | — | |
Total Liabilities | | 1.1 | | | (1.1) | | | — | |
| | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) (f) | | $ | 65.2 | | | $ | (0.6) | | | $ | 64.6 | |
September 30, 2017
| | | | | | | | | | | | | | | | | | | | |
| | December 31, 2021 |
| | 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 | | $ | 12.4 | | | $ | (0.3) | | | $ | 12.1 | |
Long-term Risk Management Assets | | — | | | — | | | — | |
Total Assets | | 12.4 | | | (0.3) | | | 12.1 | |
| | | | | | |
Current Risk Management Liabilities | | 3.7 | | | — | | | 3.7 | |
Long-term Risk Management Liabilities | | — | | | — | | | — | |
Total Liabilities | | 3.7 | | | — | | | 3.7 | |
| | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 8.7 | | | $ | (0.3) | | | $ | 8.4 | |
|
| | | | | | | | | | | | |
| | 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 | | | | | | | | | | | | | | | | | | | | |
| | June 30, 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 | | $ | 47.1 | | | $ | (1.7) | | | $ | 45.4 | |
Long-term Risk Management Assets | | — | | | — | | | — | |
Total Assets | | 47.1 | | | (1.7) | | | 45.4 | |
| | | | | | |
Current Risk Management Liabilities | | 0.9 | | | (0.9) | | | — | |
Long-term Risk Management Liabilities | | — | | | — | | | — | |
Total Liabilities | | 0.9 | | | (0.9) | | | — | |
| | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) (f) | | $ | 46.2 | | | $ | (0.8) | | | $ | 45.4 | |
| | | | | | | | | | | | | | | | | | | | |
| | December 31, 2021 |
| | 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 | | $ | 10.1 | | | $ | (0.3) | | | $ | 9.8 | |
Long-term Risk Management Assets | | 1.1 | | | — | | | 1.1 | |
Total Assets | | 11.2 | | | (0.3) | | | 10.9 | |
| | | | | | |
Current Risk Management Liabilities | | 2.1 | | | — | | | 2.1 | |
Long-term Risk Management Liabilities | | — | | | — | | | — | |
Total Liabilities | | 2.1 | | | — | | | 2.1 | |
| | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 9.1 | | | $ | (0.3) | | | $ | 8.8 | |
(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 Derivative Instrumentsrisk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”
September(c)All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position.
(d)Amount excludes Risk Management Assets of $13.6 million and $6 million as of June 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
2022 and December 31, 20162021, respectively, classified as Assets Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(e)Amount excludes Risk Management Liabilities of $0 and $0.1 million as of June 30, 2022 and December 31, 2021, respectively, classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(f)Increase in amounts as of June 30, 2022 are primarily due to increases in commodity prices for power and natural gas and an increase in value of FTRs.
|
| | | | | | | | | | | | |
| | 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 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) | There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. |
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 June 30, 2022 |
Location of Gain (Loss) | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Vertically Integrated Utilities Revenues | | $ | 0.1 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | |
Generation & Marketing Revenues | | 121.0 | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Purchased Electricity for Resale | | 0.9 | | | — | | | 0.7 | | | — | | | — | | | 0.1 | | | — | |
Other Operation | | 1.7 | | | 0.5 | | | 0.2 | | | 0.2 | | | 0.3 | | | 0.2 | | | 0.3 | |
Maintenance | | 2.4 | | | 0.7 | | | 0.4 | | | 0.2 | | | 0.4 | | | 0.3 | | | 0.4 | |
Regulatory Assets (a) | | 21.4 | | | 0.1 | | | 0.1 | | | 0.3 | | | 21.0 | | | — | | | (0.1) | |
Regulatory Liabilities (a) | | 110.4 | | | — | | | 21.6 | | | 1.5 | | | 1.6 | | | 39.0 | | | 36.9 | |
Total Gain on Risk Management Contracts (b) | | $ | 257.9 | | | $ | 1.3 | | | $ | 23.0 | | | $ | 2.2 | | | $ | 23.3 | | | $ | 39.6 | | | $ | 37.5 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | Three Months Ended June 30, 2021 |
Location of Gain (Loss) | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Vertically Integrated Utilities Revenues | | $ | 0.1 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | |
Generation & Marketing Revenues | | 16.5 | | | — | | | — | | | — | | | — | | | — | | | — | |
Electric Generation, Transmission and Distribution Revenues | | — | | | — | | | 0.1 | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Purchased Electricity for Resale | | 0.6 | | | — | | | 0.5 | | | 0.1 | | | — | | | — | | | — | |
Other Operation | | 0.7 | | | 0.2 | | | 0.1 | | | 0.1 | | | 0.1 | | | 0.1 | | | 0.1 | |
Maintenance | | 0.8 | | | 0.3 | | | 0.1 | | | — | | | 0.1 | | | — | | | 0.1 | |
Regulatory Assets (a) | | (7.0) | | | — | | | — | | | (5.1) | | | (1.2) | | | — | | | 0.5 | |
Regulatory Liabilities (a) | | 55.1 | | | 0.2 | | | 11.3 | | | 3.4 | | | 2.2 | | | 15.0 | | | 19.6 | |
Total Gain (Loss) on Risk Management Contracts | | $ | 66.8 | | | $ | 0.7 | | | $ | 12.1 | | | $ | (1.5) | | | $ | 1.2 | | | $ | 15.1 | | | $ | 20.3 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | Six Months Ended June 30, 2022 |
Location of Gain (Loss) | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Vertically Integrated Utilities Revenues | | $ | 0.1 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | |
Generation & Marketing Revenues | | 273.3 | | | — | | | — | | | — | | | — | | | — | | | — | |
Electric Generation, Transmission and Distribution Revenues | | — | | | — | | | 0.1 | | | (0.1) | | | — | | | — | | | — | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Purchased Electricity for Resale | | 2.4 | | | — | | | 2.1 | | | — | | | — | | | 0.1 | | | — | |
Other Operation | | 2.3 | | | 0.7 | | | 0.2 | | | 0.3 | | | 0.4 | | | 0.3 | | | 0.4 | |
Maintenance | | 3.2 | | | 0.9 | | | 0.5 | | | 0.3 | | | 0.5 | | | 0.4 | | | 0.5 | |
Regulatory Assets (a) | | 45.0 | | | 0.1 | | | — | | | (1.3) | | | 44.9 | | | 3.6 | | | (2.2) | |
Regulatory Liabilities (a) | | 146.9 | | | 0.9 | | | 20.2 | | | 3.2 | | | 1.6 | | | 51.7 | | | 57.8 | |
Total Gain on Risk Management Contracts (b) | | $ | 473.2 | | | $ | 2.6 | | | $ | 23.1 | | | $ | 2.4 | | | $ | 47.4 | | | $ | 56.1 | | | $ | 56.5 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | Six Months Ended June 30, 2021 |
Location of Gain (Loss) | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Vertically Integrated Utilities Revenues | | $ | 0.3 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | |
Generation & Marketing Revenues | | 16.1 | | | — | | | — | | | — | | | — | | | — | | | — | |
Electric Generation, Transmission and Distribution Revenues | | — | | | — | | | 0.3 | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Purchased Electricity for Resale | | 1.0 | | | — | | | 0.9 | | | 0.1 | | | — | | | — | | | — | |
Other Operation | | 1.0 | | | 0.3 | | | 0.1 | | | 0.1 | | | 0.2 | | | 0.1 | | | 0.1 | |
Maintenance | | 1.3 | | | 0.4 | | | 0.2 | | | 0.1 | | | 0.2 | | | 0.1 | | | 0.2 | |
Regulatory Assets (a) | | (0.6) | | | — | | | — | | | (6.0) | | | 5.4 | | | — | | | 1.3 | |
Regulatory Liabilities (a) | | 77.1 | | | 0.6 | | | 14.7 | | | 0.2 | | | 5.1 | | | 26.2 | | | 25.8 | |
Total Gain (Loss) on Risk Management Contracts | | $ | 96.2 | | | $ | 1.3 | | | $ | 16.2 | | | $ | (5.5) | | | $ | 10.9 | | | $ | 26.4 | | | $ | 27.4 | |
(a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the Three Months Ended Septemberbalance sheets.
(b)Increase in amounts for the three and six months ended June 30, 20172022 are primarily due to increases in commodity prices for power and natural gas and an increase 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 |
| | June 30, 2022 | | December 31, 2021 | | June 30, 2022 | | December 31, 2021 |
| | (in millions) |
Long-term Debt (a) (b) | | $ | (886.8) | | | $ | (952.3) | | | $ | 57.7 | | | $ | (8.5) | |
(a)Amounts included on the balance sheets within Long-term Debt Due within One Year and Long-term Debt, respectively.
(b)Amounts include $(42) million and $(46) million as of June 30, 2022 and December 31, 2021, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued.
The pretax effects of fair value hedge accounting on income were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2022 | | 2021 | | 2022 | | 2021 |
| (in millions) |
Gain (Loss) on Interest Rate Contracts: | | | | | | | |
Fair Value Hedging Instruments (a) | $ | (17.6) | | | $ | 9.5 | | | $ | (62.4) | | | $ | (23.7) | |
Fair Value Portion of Long-term Debt (a) | 17.6 | | | (9.5) | | | 62.4 | | | 23.7 | |
(a)Gain (Loss) is included in Interest Expense on the statements of income.
In June 2020, AEP terminated a $500 million notional amount interest rate swap resulting in the discontinuance of the hedging gains (losses):relationship. A gain of $57 million on the fair value of the hedging instrument was settled in cash and recorded within operating activities on the statements of cash flows. Subsequent to the discontinuation of hedge accounting, the remaining adjustment to the carrying amount of the hedged item of $57 million will be amortized on a straight line basis through November 2027 in Interest Expense on the statements of income.
|
| | | | | | | | | | | | | | | |
| 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 the three and nine months ended September 30, 2017 and 2016, hedge ineffectiveness was immaterial.
Accounting for Cash Flow Hedging Strategies (Applies to AEP, APCo, I&M, PSO and SWEPCo)
For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the 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 ninesix months ended SeptemberJune 30, 20172022 and 2016,2021, 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 ninesix months ended SeptemberJune 30, 2017 and 2016,2022 AEP applied cash flow hedging to outstanding interest rate derivatives.derivatives and the Registrant Subsidiaries did not. During the three and ninesix months ended SeptemberJune 30, 20172021, AEP and 2016, the Registrant Subsidiaries did not applyAPCo applied cash flow hedging to outstanding interest rate derivatives.derivatives and the other Registrant Subsidiaries did 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
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 2022 | | December 31, 2021 |
| | Commodity | | Interest Rate | | Commodity | | Interest Rate |
| | (in millions) |
AOCI Gain (Loss) Net of Tax | | $ | 533.6 | | | $ | (10.8) | | | $ | 163.7 | | | $ | (21.3) | |
Portion Expected to be Reclassed to Net Income During the Next Twelve Months | | 402.1 | | | (2.3) | | | 106.7 | | | (3.3) | |
|
| | | | | | | | | | | | | | | | |
| | 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 SeptemberJune 30, 20172022 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 123 months.105 months and 102 months for commodity and interest rate hedges, respectively.
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 2022 | | December 31, 2021 |
| | 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 | | $ | (0.8) | | | $ | (0.8) | | | $ | (1.3) | | | $ | (1.1) | |
APCo | | 7.1 | | | 0.8 | | | 7.5 | | | 0.8 | |
I&M | | (5.9) | | | (1.3) | | | (6.7) | | | (1.6) | |
| | | | | | | | |
| | | | | | | | |
SWEPCo | | 1.2 | | | 0.2 | | | 1.2 | | | 0.1 | |
|
| | | | | | | | | | | | | | | | |
| | 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.
Credit-Risk-Related Contingent Features
Collateral Triggering Events
Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo)
A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. 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 $7 million and $9 million as of June 30, 2022 and December 31, 2021, respectively. The RegistrantsRegistrant Subsidiaries had immaterialno derivative contracts with collateral triggering events in a net liability position as of SeptemberJune 30, 20172022 and December 31, 2016.2021.
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 $99 million and $40 million as of June 30, 2022 and December 31, 2021, respectively. There was no cash collateral posted as of June 30, 2022 and December 31, 2021, respectively. If a cross-acceleration provision would have been triggered, settlement at fair value would have been required. The Registrant Subsidiaries had no derivative contracts with cross-acceleration provisions outstanding as of June 30, 2022 and December 31, 2021.
Cross-Default Triggers (Applies to AEP, APCo, I&M 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 $228 million and $76 million as of June 30, 2022 and December 31, 2021, respectively, after considering contractual netting arrangements, (b) the amount that the exposure has been reduced by casharrangements. Cash collateral posted as of June 30, 2022 and (c) ifDecember 31, 2021 was not material. If a cross-default provision would have been triggered, settlement at fair value would have been required. The Registrant Subsidiaries’ derivative contracts with cross-default provisions outstanding as of June 30, 2022 and December 31, 2021 were not material.
Warrants Held in Investee (Applies to AEP)
AEP holds an investment in ChargePoint, which completed an initial public offering (IPO) in February 2021 via a reverse merger with a public special purpose acquisition company. AEP’s interests in ChargePoint consisted of a noncontrolling equity interest of common shares, which were accounted for at their fair value of $21 million as of June 30, 2022, and common share warrants. AEP recorded unrealized loss of $9 million and $8 million associated with the settlement amount that would be required after considering contractual netting arrangements:common shares for the three and six months ended June 30, 2022 and unrealized gains of $11 million and $38 million for the three and six months ended June 30, 2021, respectively, presented in Other Income (Expense) on AEP’s statements of income.
Management has determined the common share warrants are derivative instruments based on the accounting guidance for “Derivatives and Hedging”. As of June 30, 2022 and December 31, 2021, the warrants were valued at
|
| | | | | | | | | | | | |
| | 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 | | — |
| | — |
| | — |
|
$11 million and $15 million, respectively, and were recorded in Deferred Charges and Other Noncurrent Assets on AEP’s balance sheets. AEP recognized an unrealized loss of $4 million and $4 million associated with the warrants for the three and six months ended June 30, 2022, respectively, and an unrealized gain (loss) of $4 million and $(6) million for the three and six months ended June 30, 2021, respectively, presented in Other Income (Expense) on AEP’s statements of income.
Management utilized a Black-Scholes options pricing model to value the warrants as of June 30, 2022 and December 31, 2021. There was an observable publicly traded stock price to use in the Black-Scholes options pricing model, which resulted in the warrants being categorized as Level 2 as of June 30, 2022 and December 31, 2021. The common shares are categorized as Level 1 based on the observable publicly traded stock price. See “Fair Value Measurements of Financial Assets and Liabilities” section of Note 10 for additional information.
|
| | | | | | | | | | | | |
| | 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:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 2022 | | December 31, 2021 |
Company | | Book Value | | Fair Value | | Book Value | | Fair Value |
| | (in millions) |
AEP (a)(b)(c) | | $ | 35,459.4 | | | $ | 33,197.5 | | | $ | 33,454.5 | | | $ | 37,564.7 | |
AEP Texas | | 6,128.2 | | | 5,730.5 | | | 5,180.8 | | | 5,663.8 | |
AEPTCo | | 4,885.6 | | | 4,438.1 | | | 4,343.9 | | | 4,968.2 | |
APCo | | 4,927.2 | | | 4,907.8 | | | 4,938.9 | | | 6,037.1 | |
I&M | | 3,228.7 | | | 3,072.2 | | | 3,195.0 | | | 3,748.0 | |
OPCo | | 2,969.4 | | | 2,679.0 | | | 2,968.5 | | | 3,437.5 | |
PSO | | 2,413.8 | | | 2,236.2 | | | 1,913.5 | | | 2,163.7 | |
SWEPCo | | 3,393.4 | | | 3,045.6 | | | 3,395.2 | | | 3,792.9 | |
|
| | | | | | | | | | | | | | | | | | |
| | 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 $923 million and $1.7 billion as of June 30, 2022 and December 31, 2021, 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. |
(b)The book value amounts exclude Long-term Debt of $1.1 billion and $1.1 billion as of June 30, 2022 and December 31, 2021, respectively, classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(c)The fair value amounts exclude Long-term Debt of $1.1 billion and $1.2 billion as of June 30, 2022 and December 31, 2021, respectively, related to KPCo. See “Disposition of KPCo and KTCo” 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:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 2022 |
| | | | Gross | | Gross | | |
| | | | Unrealized | | Unrealized | | Fair |
Other Temporary Investments and Restricted Cash | | Cost | | Gains | | Losses | | Value |
| | (in millions) |
Restricted Cash (a) | | $ | 45.9 | | | $ | — | | | $ | — | | | $ | 45.9 | |
Other Cash Deposits | | 13.4 | | | — | | | — | | | 13.4 | |
Fixed Income Securities – Mutual Funds (b) | | 146.6 | | | — | | | (6.2) | | | 140.4 | |
Equity Securities – Mutual Funds | | 17.1 | | | 21.1 | | | — | | | 38.2 | |
Total Other Temporary Investments and Restricted Cash | | $ | 223.0 | | | $ | 21.1 | | | $ | (6.2) | | | $ | 237.9 | |
| | | | | | | | | | | | December 31, 2021 |
| | 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) | | $ | 48.0 | | | $ | — | | | $ | — | | | $ | 48.0 | |
Other Cash Deposits | | Other Cash Deposits | | 10.0 | | | — | | | — | | | 10.0 | |
Fixed Income Securities – Mutual Funds (b) | | 103.9 |
| | — |
| | (0.7 | ) | | 103.2 |
| Fixed Income Securities – Mutual Funds (b) | | 154.3 | | | 0.5 | | | — | | | 154.8 | |
Equity Securities – Mutual Funds | | 16.8 |
| | 17.8 |
| | — |
| | 34.6 |
| Equity Securities – Mutual Funds | | 19.7 | | | 35.9 | | | — | | | 55.6 | |
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 | | $ | 232.0 | | | $ | 36.4 | | | $ | — | | | $ | 268.4 | |
|
| | | | | | | | | | | | | | | | |
| | 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.
| |
(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 June 30, | | Six Months Ended June 30, |
| 2022 | | 2021 | | 2022 | | 2021 |
| (in millions) |
Proceeds from Investment Sales | $ | 11.1 | | | $ | 3.6 | | | $ | 15.0 | | | $ | 9.1 | |
Purchases of Investments | 0.8 | | | 12.4 | | | 1.6 | | | 13.1 | |
Gross Realized Gains on Investment Sales | 3.3 | | | 1.1 | | | 3.6 | | | 1.2 | |
Gross Realized Losses on Investment Sales | 0.4 | | | — | | | 0.5 | | | — | |
|
| | | | | | | | | | | | | | | |
| 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:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| June 30, 2022 | | December 31, 2021 |
| | | Gross | | Other-Than- | | | | Gross | | Other-Than- |
| Fair | | Unrealized | | Temporary | | Fair | | Unrealized | | Temporary |
| Value | | Gains | | Impairments | | Value | | Gains | | Impairments |
| (in millions) |
Cash and Cash Equivalents | $ | 16.6 | | | $ | — | | | $ | — | | | $ | 84.7 | | | $ | — | | | $ | — | |
Fixed Income Securities: | | | | | | | | | | | |
United States Government | 1,139.5 | | | 5.3 | | | (14.7) | | | 1,156.4 | | | 66.3 | | | (7.9) | |
Corporate Debt | 62.3 | | | (4.2) | | | (6.0) | | | 76.7 | | | 6.7 | | | (2.1) | |
State and Local Government | 7.1 | | | 0.1 | | | (0.1) | | | 7.3 | | | 0.4 | | | (0.1) | |
Subtotal Fixed Income Securities | 1,208.9 | | | 1.2 | | | (20.8) | | | 1,240.4 | | | 73.4 | | | (10.1) | |
Equity Securities - Domestic (a) | 2,055.3 | | | 1,405.0 | | | — | | | 2,541.9 | | | 1,901.3 | | | — | |
Spent Nuclear Fuel and Decommissioning Trusts | $ | 3,280.8 | | | $ | 1,406.2 | | | $ | (20.8) | | | $ | 3,867.0 | | | $ | 1,974.7 | | | $ | (10.1) | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 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 | ) |
(a)Amount reported as Gross Unrealized Gains includes unrealized gains of $1.4 billion and $1.9 billion and unrealized losses of $11 million and $4 million as of June 30, 2022 and December 31, 2021, respectively.
The following table provides the securities activity within the decommissioning and SNF trusts:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) |
Proceeds from Investment Sales | | $ | 736.4 | | | $ | 802.7 | | | $ | 1,229.9 | | | $ | 1,122.7 | |
Purchases of Investments | | 745.5 | | | 812.8 | | | 1,253.2 | | | 1,149.7 | |
Gross Realized Gains on Investment Sales | | 10.9 | | | 83.3 | | | 16.7 | | | 88.7 | |
Gross Realized Losses on Investment Sales | | 17.9 | | | 1.3 | | | 25.1 | | | 5.5 | |
|
| | | | | | | | | | | | | | | | |
| | 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$1.2 billion and $938 million$1.2 billion as of SeptemberJune 30, 20172022 and December 31, 2016,2021, respectively. The base cost of equity securities was $586$650 million and $592$641 million as of SeptemberJune 30, 20172022 and December 31, 2016,2021, respectively.
The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of SeptemberJune 30, 20172022 was as follows:
| | | | | |
| Fair Value of Fixed |
| Income Securities |
| (in millions) |
Within 1 year | $ | 356.2 | |
After 1 year through 5 years | 398.5 | |
After 5 years through 10 years | 248.0 | |
After 10 years | 206.2 | |
Total | $ | 1,208.9 | |
|
| | | |
| 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
SeptemberJune 30, 20172022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Other Temporary Investments and Restricted Cash | | | | | | | | | | |
Restricted Cash | | $ | 45.9 | | | $ | — | | | $ | — | | | $ | — | | | $ | 45.9 | |
Other Cash Deposits (a) | | — | | | — | | | — | | | 13.4 | | | 13.4 | |
Fixed Income Securities – Mutual Funds | | 140.4 | | | — | | | — | | | — | | | 140.4 | |
Equity Securities – Mutual Funds (b) | | 38.2 | | | — | | | — | | | — | | | 38.2 | |
Total Other Temporary Investments and Restricted Cash | | 224.5 | | | — | | | — | | | 13.4 | | | 237.9 | |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (d) (i) | | 26.8 | | | 1,795.9 | | | 439.4 | | | (2,342.2) | | | (80.1) | |
Cash Flow Hedges: | | | | | | | | | | |
Commodity Hedges (c) | | — | | | 727.8 | | | 39.3 | | | (73.0) | | | 694.1 | |
Interest Rate Hedges | | — | | | 4.4 | | | — | | | — | | | 4.4 | |
| | | | | | | | | | |
Total Risk Management Assets | | 26.8 | | | 2,528.1 | | | 478.7 | | | (2,415.2) | | | 618.4 | |
| | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | |
Cash and Cash Equivalents (e) | | 9.0 | | | — | | | — | | | 7.6 | | | 16.6 | |
Fixed Income Securities: | | | | | | | | | | |
United States Government | | — | | | 1,139.5 | | | — | | | — | | | 1,139.5 | |
Corporate Debt | | — | | | 62.3 | | | — | | | — | | | 62.3 | |
State and Local Government | | — | | | 7.1 | | | — | | | — | | | 7.1 | |
Subtotal Fixed Income Securities | | — | | | 1,208.9 | | | — | | | — | | | 1,208.9 | |
Equity Securities – Domestic (b) | | 2,055.3 | | | — | | | — | | | — | | | 2,055.3 | |
Total Spent Nuclear Fuel and Decommissioning Trusts | | 2,064.3 | | | 1,208.9 | | | — | | | 7.6 | | | 3,280.8 | |
| | | | | | | | | | |
Other Investments (h) | | 20.8 | | | 11.1 | | | — | | | — | | | 31.9 | |
| | | | | | | | | | |
Total Assets | | $ | 2,336.4 | | | $ | 3,748.1 | | | $ | 478.7 | | | $ | (2,394.2) | | | $ | 4,169.0 | |
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (d) (j) | | $ | 12.2 | | | $ | 1,410.1 | | | $ | 207.3 | | | $ | (1,255.8) | | | $ | 373.8 | |
Cash Flow Hedges: | | | | | | | | | | |
Commodity Hedges (c) | | — | | | 90.3 | | | 1.0 | | | (73.0) | | | 18.3 | |
Interest Rate Hedges | | — | | | 0.2 | | | — | | | — | | | 0.2 | |
Fair Value Hedges | | — | | | 99.4 | | | — | | | — | | | 99.4 | |
Total Risk Management Liabilities | | $ | 12.2 | | | $ | 1,600.0 | | | $ | 208.3 | | | $ | (1,328.8) | | | $ | 491.7 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | 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, 20162021
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Other Temporary Investments and Restricted Cash | | | | | | | | | | |
Restricted Cash | | $ | 48.0 | | | $ | — | | | $ | — | | | $ | — | | | $ | 48.0 | |
Other Cash Deposits (a) | | — | | | — | | | — | | | 10.0 | | | 10.0 | |
Fixed Income Securities – Mutual Funds | | 154.8 | | | — | | | — | | | — | | | 154.8 | |
Equity Securities – Mutual Funds (b) | | 55.6 | | | — | | | — | | | — | | | 55.6 | |
Total Other Temporary Investments and Restricted Cash | | 258.4 | | | — | | | — | | | 10.0 | | | 268.4 | |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (f) (i) | | 7.4 | | | 648.5 | | | 226.3 | | | (642.4) | | | 239.8 | |
Cash Flow Hedges: | | | | | | | | | | |
Commodity Hedges (c) | | — | | | 242.9 | | | 19.2 | | | (41.7) | | | 220.4 | |
| | | | | | | | | | |
Fair Value Hedges | | — | | | 1.2 | | | — | | | — | | | 1.2 | |
Total Risk Management Assets | | 7.4 | | | 892.6 | | | 245.5 | | | (684.1) | | | 461.4 | |
| | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | |
Cash and Cash Equivalents (e) | | 77.7 | | | — | | | — | | | 7.0 | | | 84.7 | |
Fixed Income Securities: | | | | | | | | | | |
United States Government | | — | | | 1,156.4 | | | — | | | — | | | 1,156.4 | |
Corporate Debt | | — | | | 76.7 | | | — | | | — | | | 76.7 | |
State and Local Government | | — | | | 7.3 | | | — | | | — | | | 7.3 | |
Subtotal Fixed Income Securities | | — | | | 1,240.4 | | | — | | | — | | | 1,240.4 | |
Equity Securities – Domestic (b) | | 2,541.9 | | | — | | | — | | | — | | | 2,541.9 | |
Total Spent Nuclear Fuel and Decommissioning Trusts | | 2,619.6 | | | 1,240.4 | | | — | | | 7.0 | | | 3,867.0 | |
| | | | | | | | | | |
Other Investments (h) | | 28.8 | | | 14.9 | | | — | | | — | | | 43.7 | |
| | | | | | | | | | |
Total Assets | | $ | 2,914.2 | | | $ | 2,147.9 | | | $ | 245.5 | | | $ | (667.1) | | | $ | 4,640.5 | |
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (f) (j) | | $ | 5.3 | | | $ | 485.0 | | | $ | 147.6 | | | $ | (383.2) | | | $ | 254.7 | |
Cash Flow Hedges: | | | | | | | | | | |
Commodity Hedges (c) | | — | | | 54.0 | | | 0.6 | | | (41.7) | | | 12.9 | |
| | | | | | | | | | |
Fair Value Hedges | | — | | | 38.1 | | | — | | | — | | | 38.1 | |
Total Risk Management Liabilities | | $ | 5.3 | | | $ | 577.1 | | | $ | 148.2 | | | $ | (424.9) | | | $ | 305.7 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | 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
SeptemberJune 30, 20172022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Restricted Cash for Securitized Funding | | $ | 27.1 | | | $ | — | | | $ | — | | | $ | 2.6 | | | $ | 29.7 | |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) | | — | | | 1.6 | | | — | | | (1.4) | | | 0.2 | |
| | | | | | | | | | |
Total Assets | | $ | 27.1 | | | $ | 1.6 | | | $ | — | | | $ | 1.2 | | | $ | 29.9 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | 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 |
|
December 31, 2021
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Restricted Cash for Securitized Funding | | $ | 30.4 | | | $ | — | | | $ | — | | | $ | — | | | $ | 30.4 | |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) | | — | | | 0.6 | | | — | | | (0.6) | | | — | |
| | | | | | | | | | |
Total Assets | | $ | 30.4 | | | $ | 0.6 | | | $ | — | | | $ | (0.6) | | | $ | 30.4 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
APCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Restricted Cash for Securitized Funding | | $ | 16.2 | | | $ | — | | | $ | — | | | $ | — | | | $ | 16.2 | |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | — | | | 1.4 | | | 81.2 | | | (2.9) | | | 79.7 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Total Assets | | $ | 16.2 | | | $ | 1.4 | | | $ | 81.2 | | | $ | (2.9) | | | $ | 95.9 | |
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.6 | | | $ | 1.6 | | | $ | (2.2) | | | $ | — | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
December 31, 20162021
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Restricted Cash for Securitized Funding | | $ | 17.6 | | | $ | — | | | $ | — | | | $ | — | | | $ | 17.6 | |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | — | | | 5.8 | | | 42.0 | | | (5.8) | | | 42.0 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Total Assets | | $ | 17.6 | | | $ | 5.8 | | | $ | 42.0 | | | $ | (5.8) | | | $ | 59.6 | |
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 7.2 | | | $ | 0.3 | | | $ | (6.7) | | | $ | 0.8 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | 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
SeptemberJune 30, 20172022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.9 | | | $ | 10.8 | | | $ | (1.8) | | | $ | 9.9 | |
| | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | |
Cash and Cash Equivalents (e) | | 9.0 | | | — | | | — | | | 7.6 | | | 16.6 | |
Fixed Income Securities: | | | | | | | | | | |
United States Government | | — | | | 1,139.5 | | | — | | | — | | | 1,139.5 | |
Corporate Debt | | — | | | 62.3 | | | — | | | — | | | 62.3 | |
State and Local Government | | — | | | 7.1 | | | — | | | — | | | 7.1 | |
Subtotal Fixed Income Securities | | — | | | 1,208.9 | | | — | | | — | | | 1,208.9 | |
Equity Securities - Domestic (b) | | 2,055.3 | | | — | | | — | | | — | | | 2,055.3 | |
Total Spent Nuclear Fuel and Decommissioning Trusts | | 2,064.3 | | | 1,208.9 | | | — | | | 7.6 | | | 3,280.8 | |
| | | | | | | | | | |
Total Assets | | $ | 2,064.3 | | | $ | 1,209.8 | | | $ | 10.8 | | | $ | 5.8 | | | $ | 3,290.7 | |
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.3 | | | $ | 1.0 | | | $ | (1.3) | | | $ | — | |
December 31, 2021
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 3.8 | | | $ | 7.6 | | | $ | (8.1) | | | $ | 3.3 | |
| | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | |
Cash and Cash Equivalents (e) | | 77.7 | | | — | | | — | | | 7.0 | | | 84.7 | |
Fixed Income Securities: | | | | | | | | | | |
United States Government | | — | | | 1,156.4 | | | — | | | — | | | 1,156.4 | |
Corporate Debt | | — | | | 76.7 | | | — | | | — | | | 76.7 | |
State and Local Government | | — | | | 7.3 | | | — | | | — | | | 7.3 | |
Subtotal Fixed Income Securities | | — | | | 1,240.4 | | | — | | | — | | | 1,240.4 | |
Equity Securities - Domestic (b) | | 2,541.9 | | | — | | | — | | | — | | | 2,541.9 | |
Total Spent Nuclear Fuel and Decommissioning Trusts | | 2,619.6 | | | 1,240.4 | | | — | | | 7.0 | | | 3,867.0 | |
| | | | | | | | | | |
Total Assets | | $ | 2,619.6 | | | $ | 1,244.2 | | | $ | 7.6 | | | $ | (1.1) | | | $ | 3,870.3 | |
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 6.7 | | | $ | 8.3 | | | $ | (10.0) | | | $ | 5.0 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | 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
June 30, 2022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 1.1 | | | $ | — | | | $ | 0.2 | | | $ | 1.3 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Liabilities: | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | — | | | $ | 48.4 | | | $ | 1.2 | | | $ | 49.6 | |
December 31, 20162021
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.5 | | | $ | — | | | $ | (0.5) | | | $ | — | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Liabilities: | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (g) | | $ | — | | | $ | — | | | $ | 92.5 | | | $ | — | | | $ | 92.5 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | 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
SeptemberJune 30, 20172022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.7 | | | $ | 65.6 | | | $ | (1.7) | | | $ | 64.6 | |
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | — | | | $ | 1.1 | | | $ | (1.1) | | | $ | — | |
December 31, 2021
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.3 | | | $ | 12.2 | | | $ | (0.4) | | | $ | 12.1 | |
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 3.7 | | | $ | 0.1 | | | $ | (0.1) | | | $ | 3.7 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | 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
June 30, 2022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.8 | | | $ | 46.3 | | | $ | (1.7) | | | $ | 45.4 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | — | | | $ | 0.9 | | | $ | (0.9) | | | $ | — | |
December 31, 20162021
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.3 | | | $ | 11.0 | | | $ | (0.4) | | | $ | 10.9 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 2.1 | | | $ | 0.1 | | | $ | (0.1) | | | $ | 2.1 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Restricted Cash for Securitized Funding (a) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 27.2 |
| | $ | 27.2 |
|
| | | | | | | | | | |
Risk Management Assets | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (g) | | — |
| | 0.4 |
| | — |
| | (0.2 | ) | | 0.2 |
|
| | | | | | | | | | |
Total Assets | | $ | — |
| | $ | 0.4 |
| | $ | — |
| | $ | 27.0 |
| | $ | 27.4 |
|
| | | | | | | | | | |
Liabilities: | | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | |
Risk Management Liabilities | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | — |
| | $ | 119.0 |
| | $ | — |
| | $ | 119.0 |
|
PSO
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2017
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Risk Management Assets | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | — |
| | $ | 4.8 |
| | $ | (0.1 | ) | | $ | 4.7 |
|
| | | | | | | | | | |
Liabilities: | | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | |
Risk Management Liabilities | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | — |
| | $ | 0.1 |
| | $ | (0.1 | ) | | $ | — |
|
PSO
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2016
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Risk Management Assets | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | 0.2 |
| | $ | 0.7 |
| | $ | (0.1 | ) | | $ | 0.8 |
|
SWEPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2017
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Cash and Cash Equivalents (a) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2.2 |
| | $ | 2.2 |
|
| | | | | | | | | | |
Risk Management Assets | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (g) | | — |
| | 0.1 |
| | 13.3 |
| | (0.2 | ) | | 13.2 |
|
| | | | | | | | | | |
Total Assets | | $ | — |
| | $ | 0.1 |
| | $ | 13.3 |
| | $ | 2.0 |
| | $ | 15.4 |
|
| | | | | | | | | | |
Liabilities: | | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | |
Risk Management Liabilities | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | 0.1 |
| | $ | 0.2 |
| | $ | (0.2 | ) | | $ | 0.1 |
|
SWEPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2016
|
| | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
| | | | | | | | | | |
Cash and Cash Equivalents (a) | | $ | 8.7 |
| | $ | — |
| | $ | — |
| | $ | 1.6 |
| | $ | 10.3 |
|
| | | | | | | | | | |
Risk Management Assets | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (g) | | — |
| | 0.3 |
| | 0.8 |
| | (0.2 | ) | | 0.9 |
|
| | | | | | | | | | |
Total Assets | | $ | 8.7 |
| | $ | 0.3 |
| | $ | 0.8 |
| | $ | 1.4 |
| | $ | 11.2 |
|
| | | | | | | | | | |
Liabilities: | | |
| | |
| | |
| | |
| | |
|
| | | | | | | | | | |
Risk Management Liabilities | | |
| | |
| | |
| | |
| | |
|
Risk Management Commodity Contracts (c) (g) | | $ | — |
| | $ | 0.3 |
| | $ | 0.1 |
| | $ | (0.1 | ) | | $ | 0.3 |
|
| |
(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. |
| |
(b) | Amounts represent publicly traded equity securities and equity-based mutual funds. |
| |
(c) | Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ |
| |
(d) | The 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. |
| |
(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, 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. |
| |
(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 SeptemberHedging.’’
(d)The June 30, 20172022 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $9 million in 2022 and 2016.$6 million in periods 2023-2025; Level 2 matures $114 million in 2022, $257 million in periods 2023-2025, $11 million in periods 2026-2027 and $3 million in periods 2028-2033; Level 3 matures $125 million in 2022, $106 million in periods 2023-2025, $17 million in periods 2026-2027 and $(2) million in periods 2028-2033. Risk management commodity contracts are substantially comprised of power contracts.
(e)Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
(f)The December 31, 2021 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $1 million in 2022 and $1 million in periods 2023-2025; Level 2 matures $42 million in 2022, $109 million in periods 2023-2025, $10 million in periods 2026-2027 and $3 million in periods 2028-2033; Level 3 matures $82 million in 2022, $10 million in periods 2023-2025, $9 million in periods 2026-2027 and $(17) million in periods 2028-2033. Risk management commodity contracts are substantially comprised of power contracts.
(g)Substantially comprised of power contracts for the Registrant Subsidiaries.
(h)See “Warrants Held in Investee” section of Note 9 for additional information.
(i)Amount excludes Risk Management Assets of $13.6 million and $6 million as of June 30, 2022 and December 31, 2021, respectively, classified as Assets Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(j)Amount excludes Risk Management Liabilities of $0 and $0.1 million as of June 30, 2022 and December 31, 2021, respectively, classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Three Months Ended June 30, 2022 | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Balance as of March 31, 2022 | | $ | 81.5 | | | $ | 6.6 | | | $ | 1.0 | | | $ | (68.5) | | | $ | 6.5 | | | $ | 15.7 | |
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | 38.6 | | | 5.7 | | | (0.3) | | | 0.9 | | | 11.9 | | | 19.9 | |
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | (16.8) | | | — | | | — | | | — | | | — | | | — | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) | | 5.7 | | | — | | | — | | | — | | | — | | | — | |
Settlements | | (69.3) | | | (12.4) | | | (0.7) | | | — | | | (18.4) | | | (27.9) | |
Transfers into Level 3 (d) (e) | | 2.4 | | | — | | | — | | | — | | | — | | | — | |
Transfers out of Level 3 (e) | | 5.8 | | | — | | | — | | | — | | | — | | | — | |
Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | 234.7 | | | 79.7 | | | 9.8 | | | 19.2 | | | 64.5 | | | 37.7 | |
Assets and Liabilities Held for Sale related to KPCo (g) | | (12.2) | | | — | | | — | | | — | | | — | | | — | |
Balance as of June 30, 2022 | | $ | 270.4 | | | $ | 79.6 | | | $ | 9.8 | | | $ | (48.4) | | | $ | 64.5 | | | $ | 45.4 | |
| | | | | | | | | | | | |
Three Months Ended June 30, 2021 | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Balance as of March 31, 2021 | | $ | 41.8 | | | $ | 6.6 | | | $ | 0.7 | | | $ | (104.0) | | | $ | 5.5 | | | $ | 0.5 | |
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | 18.6 | | | 6.2 | | | 0.4 | | | 1.7 | | | 4.8 | | | 3.1 | |
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | (10.6) | | | — | | | — | | | — | | | — | | | — | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) | | 15.4 | | | — | | | — | | | — | | | — | | | — | |
Settlements | | (34.5) | | | (13.0) | | | (1.2) | | | 0.6 | | | (10.3) | | | (4.5) | |
Transfers into Level 3 (d) (e) | | (0.8) | | | — | | | — | | | — | | | — | | | — | |
Transfers out of Level 3 (e) | | (19.1) | | | — | | | — | | | — | | | — | | | — | |
Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | 90.4 | | | 36.8 | | | 7.4 | | | (3.7) | | | 22.9 | | | 15.5 | |
Balance as of June 30, 2021 | | $ | 101.2 | | | $ | 36.6 | | | $ | 7.3 | | | $ | (105.4) | | | $ | 22.9 | | | $ | 14.6 | |
| | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
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 |
|
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 |
|
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) | | 14.8 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | (24.3 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Settlements | | (49.2 | ) | | (16.2 | ) | | (8.4 | ) | | 1.2 |
| | (6.9 | ) | | (7.6 | ) |
Transfers into Level 3 (d) (e) | | 5.7 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Transfers out of Level 3 (e) | | 0.2 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | (9.3 | ) | | (1.9 | ) | | (0.7 | ) | | (9.1 | ) | | (1.9 | ) | | 4.5 |
|
Balance as of September 30, 2017 | | $ | 45.0 |
| | $ | 29.4 |
| | $ | 10.2 |
| | $ | (138.5 | ) | | $ | 4.7 |
| | $ | 13.1 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Six Months Ended June 30, 2022 | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Balance as of December 31, 2021 | | $ | 97.3 | | | $ | 41.7 | | | $ | (0.7) | | | $ | (92.5) | | | $ | 12.1 | | | $ | 10.9 | |
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | 68.1 | | | 3.0 | | | 3.7 | | | 2.4 | | | 24.2 | | | 32.5 | |
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | (35.7) | | | — | | | — | | | — | | | — | | | — | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) | | 22.5 | | | — | | | — | | | — | | | — | | | — | |
Settlements | | (149.0) | | | (44.7) | | | (3.0) | | | 1.4 | | | (36.3) | | | (41.0) | |
Transfers into Level 3 (d) (e) | | 4.4 | | | — | | | — | | | — | | | — | | | — | |
Transfers out of Level 3 (e) | | 9.6 | | | — | | | — | | | — | | | — | | | — | |
Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | 260.9 | | | 79.6 | | | 9.8 | | | 40.3 | | | 64.5 | | | 43.0 | |
Assets and Liabilities Held for Sale related to KPCo (g) | | (7.7) | | | — | | | — | | | — | | | — | | | — | |
Balance as of June 30, 2022 | | $ | 270.4 | | | $ | 79.6 | | | $ | 9.8 | | | $ | (48.4) | | | $ | 64.5 | | | $ | 45.4 | |
| | | | | | | | | | | | |
Six Months Ended June 30, 2021 | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Balance as of December 31, 2020 | | $ | 113.3 | | | $ | 19.3 | | | $ | 2.1 | | | $ | (110.3) | | | $ | 10.3 | | | $ | 1.6 | |
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | 78.3 | | | 38.9 | | | 0.4 | | | 0.1 | | | 16.1 | | | 9.5 | |
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | (66.8) | | | — | | | — | | | — | | | — | | | — | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) | | 18.5 | | | — | | | — | | | — | | | — | | | — | |
Settlements | | (110.6) | | | (58.4) | | | (2.6) | | | 4.9 | | | (26.4) | | | (12.0) | |
Transfers into Level 3 (d) (e) | | (0.2) | | | — | | | — | | | — | | | — | | | — | |
Transfers out of Level 3 (e) | | (25.6) | | | — | | | — | | | — | | | — | | | — | |
Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | 94.3 | | | 36.8 | | | 7.4 | | | (0.1) | | | 22.9 | | | 15.5 | |
Balance as of June 30, 2021 | | $ | 101.2 | | | $ | 36.6 | | | $ | 7.3 | | | $ | (105.4) | | | $ | 22.9 | | | $ | 14.6 | |
(a)Included in revenues on the statements of income.
(b)Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c)Included in cash flow hedges on the statements of comprehensive income.
(d)Represents existing assets or liabilities that were previously categorized as Level 2.
(e)Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
(f)Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These changes in fair value are recorded as regulatory liabilities for net gains and as regulatory assets for net losses or accounts payable.
(g)Amount represents Risk Management Assets classified as Assets Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
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 |
|
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 |
|
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) | | 12.3 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | (34.4 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Settlements | | (37.1 | ) | | (17.9 | ) | | (5.0 | ) | | 0.9 |
| | (0.7 | ) | | (4.4 | ) |
Transfers into Level 3 (d) (e) | | 13.1 |
| | 0.1 |
| | — |
| | — |
| | — |
| | — |
|
Transfers out of Level 3 (e) | | (10.0 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | (29.0 | ) | | 0.9 |
| | 2.2 |
| | (95.3 | ) | | 0.3 |
| | 0.3 |
|
Balance as of September 30, 2016 | | $ | 98.4 |
| | $ | (7.1 | ) | | $ | 4.5 |
| | $ | (109.1 | ) | | $ | 1.1 |
| | $ | 1.3 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
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 |
|
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 |
|
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) | | 37.2 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | (29.5 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Settlements | | (49.7 | ) | | (18.9 | ) | | (7.1 | ) | | 5.1 |
| | (3.8 | ) | | (6.8 | ) |
Transfers into Level 3 (d) (e) | | 16.1 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Transfers out of Level 3 (e) | | (9.1 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | 40.1 |
| | 29.7 |
| | 10.5 |
| | (23.6 | ) | | 4.7 |
| | 13.2 |
|
Balance as of September 30, 2017 | | $ | 45.0 |
| | $ | 29.4 |
| | $ | 10.2 |
| | $ | (138.5 | ) | | $ | 4.7 |
| | $ | 13.1 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
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 |
|
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 |
|
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) | | 45.5 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | (16.7 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Settlements | | (67.1 | ) | | (36.2 | ) | | (10.3 | ) | | 4.0 |
| | 0.4 |
| | (8.4 | ) |
Transfers into Level 3 (d) (e) | | 11.2 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Transfers out of Level 3 (e) | | 1.1 |
| | 0.1 |
| | 0.1 |
| | — |
| | — |
| | — |
|
Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | (64.6 | ) | | (8.2 | ) | | 3.4 |
| | (127.2 | ) | | 1.1 |
| | 1.2 |
|
Balance as of September 30, 2016 | | $ | 98.4 |
| | $ | (7.1 | ) | | $ | 4.5 |
| | $ | (109.1 | ) | | $ | 1.1 |
| | $ | 1.3 |
|
| |
(a) | Includes both affiliated and nonaffiliated transactions. |
| |
(b) | Included in revenues on the statements of income. |
| |
(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
SeptemberJune 30, 20172022
AEP | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Significant | | Input/Range |
| Fair Value | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | 255.9 | | | $ | 196.2 | | | Discounted Cash Flow | | Forward Market Price (a) | | $ | 2.10 | | | $ | 156.49 | | | $ | 46.67 | |
Natural Gas Contracts | 8.2 | | | — | | | Discounted Cash Flow | | Forward Market Price (b) | | 2.95 | | | 6.06 | | | 5.07 | |
FTRs (d) (e) | 214.6 | | | 12.1 | | | Discounted Cash Flow | | Forward Market Price (a) | | (42.04) | | | 28.45 | | | 0.05 | |
| | | | | | | | | | | | | |
Total | $ | 478.7 | | | $ | 208.3 | | | | | | | | | | | |
December 31, 2021
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Significant | | Input/Range |
| Fair Value | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
Energy Contracts (f) | $ | 164.4 | | | $ | 135.2 | | | Discounted Cash Flow | | Forward Market Price (a) | | $ | 10.30 | | | $ | 76.70 | | | $ | 37.11 | |
Natural Gas Contracts | 3.6 | | | — | | | Discounted Cash Flow | | Forward Market Price (b) | | 3.11 | | | 4.02 | | | 3.47 | |
FTRs (g) (h) | 77.5 | | | 13.0 | | | Discounted Cash Flow | | Forward Market Price (a) | | (23.93) | | | 26.38 | | | 0.86 | |
| | | | | | | | | | | | | |
Total | $ | 245.5 | | | $ | 148.2 | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | 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
June 30, 2022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
| | | | | | | | | | | | | |
FTRs | $ | 81.2 | | | $ | 1.6 | | | Discounted Cash Flow | | Forward Market Price | | $ | (3.41) | | | $ | 20.58 | | | $ | 2.04 | |
| | | | | | | | | | | | | |
December 31, 20162021
AEP | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | — | | | $ | 0.3 | | | Discounted Cash Flow | | Forward Market Price | | $ | 32.20 | | | $ | 56.54 | | | $ | 44.77 | |
FTRs | 42.0 | | | — | | | Discounted Cash Flow | | Forward Market Price | | (0.30) | | | 26.38 | | | 2.63 | |
Total | $ | 42.0 | | | $ | 0.3 | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | 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
SeptemberJune 30, 20172022
APCo | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
| | | | | | | | | | | | | |
FTRs | $ | 10.8 | | | $ | 1.0 | | | Discounted Cash Flow | | Forward Market Price | | $ | 0.13 | | | $ | 17.15 | | | $ | 1.20 | |
| | | | | | | | | | | | | |
December 31, 2021
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | — | | | $ | 0.2 | | | Discounted Cash Flow | | Forward Market Price | | $ | 32.20 | | | $ | 56.54 | | | $ | 44.77 | |
FTRs | 7.6 | | | 8.1 | | | Discounted Cash Flow | | Forward Market Price | | (5.45) | | | 17.78 | | | (0.12) | |
Total | $ | 7.6 | | | $ | 8.3 | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | 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
June 30, 2022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | — | | | $ | 48.4 | | | Discounted Cash Flow | | Forward Market Price | | $ | 2.10 | | | $ | 156.49 | | | $ | 45.89 | |
| | | | | | | | | | | | | |
December 31, 20162021
APCo | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | — | | | $ | 92.5 | | | Discounted Cash Flow | | Forward Market Price | | $ | 14.26 | | | $ | 52.98 | | | $ | 30.68 | |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | 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
SeptemberJune 30, 20172022
I&M | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
FTRs | $ | 65.6 | | | $ | 1.1 | | | Discounted Cash Flow | | Forward Market Price | | $ | (34.40) | | | $ | 15.50 | | | $ | (7.48) | |
December 31, 2021
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
FTRs | $ | 12.2 | | | $ | 0.1 | | | Discounted Cash Flow | | Forward Market Price | | $ | (18.39) | | | $ | 1.87 | | | $ | (2.57) | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | 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
June 30, 2022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
Natural Gas Contracts | $ | 8.2 | | | $ | — | | | Discounted Cash Flow | | Forward Market Price (b) | | $ | 4.95 | | | $ | 6.06 | | | $ | 5.56 | |
FTRs | 38.1 | | | 0.9 | | | Discounted Cash Flow | | Forward Market Price (a) | | (34.40) | | | 15.50 | | | (7.48) | |
Total | $ | 46.3 | | | $ | 0.9 | | | | | | | | | | | |
December 31, 20162021
I&M | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
Natural Gas Contracts | $ | 3.6 | | | $ | — | | | Discounted Cash Flow | | Forward Market Price (b) | | $ | 3.11 | | | $ | 4.02 | | | $ | 3.47 | |
FTRs | 7.4 | | | 0.1 | | | Discounted Cash Flow | | Forward Market Price (a) | | (18.39) | | | 1.87 | | | (2.57) | |
Total | $ | 11.0 | | | $ | 0.1 | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | 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 |
| | | | | | |
| | |
| | |
(a)Represents market prices in dollars per MWh.
(b)Represents market prices in dollars per MMBtu.
(c)The weighted average is the product of the forward market price of the underlying commodity and volume weighted by term.
(d)Amount excludes Risk Management Assets of $13.7 million classified as Assets Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
Significant Unobservable Inputs(e)Amount excludes Risk Management Liabilities of $0.2 million classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
September 30, 2017(f)Amount excludes Risk Management Liabilities of $0.1 million classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
OPCo(g)Amount excludes Risk Management Assets of $6 million classified as Assets Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(h)Amount excludes Risk Management Liabilities of $0.5 million classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information. |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | 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 SeptemberJune 30, 20172022 and December 31, 2016:2021:
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 20172022 and 2016,2021, 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 June 30, 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 | | 1.3 | % | | 0.7 | % | | 2.9 | % | | (1.0) | % | | (1.3) | % | | 1.0 | % | | 3.9 | % | | 2.5 | % |
Tax Reform Excess ADIT Reversal | | (7.1) | % | | (2.1) | % | | 0.3 | % | | (20.4) | % | | (17.2) | % | | (7.8) | % | | (19.2) | % | | (5.2) | % |
Production and Investment Tax Credits | | (6.1) | % | | (0.6) | % | | — | % | | — | % | | (3.4) | % | | — | % | | (32.2) | % | | (19.8) | % |
Flow Through | | (0.1) | % | | 0.2 | % | | 0.4 | % | | (1.4) | % | | (1.2) | % | | 0.2 | % | | 0.3 | % | | — | % |
AFUDC Equity | | (1.1) | % | | (1.4) | % | | (2.3) | % | | (1.5) | % | | (1.3) | % | | (0.7) | % | | (0.4) | % | | (0.5) | % |
| | | | | | | | | | | | | | | | |
Discrete Tax Adjustments | | 0.3 | % | | — | % | | — | % | | (6.0) | % | | — | % | | — | % | | — | % | | 0.8 | % |
Other | | 1.1 | % | | 0.1 | % | | 0.1 | % | | (0.2) | % | | 1.3 | % | | 0.1 | % | | 0.5 | % | | (0.1) | % |
Effective Income Tax Rate | | 9.3 | % | | 17.9 | % | | 22.4 | % | | (9.5) | % | | (2.1) | % | | 13.8 | % | | (26.1) | % | | (1.3) | % |
| | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, 2021 |
| | 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 | | 0.8 | % | | (0.4) | % | | 2.6 | % | | 0.9 | % | | 1.6 | % | | 0.7 | % | | 4.4 | % | | 1.9 | % |
Tax Reform Excess ADIT Reversal | | (9.1) | % | | (7.9) | % | | 0.3 | % | | (11.8) | % | | (20.4) | % | | (8.6) | % | | (20.1) | % | | (1.9) | % |
Production and Investment Tax Credits | | (4.7) | % | | (0.3) | % | | — | % | | — | % | | (3.3) | % | | — | % | | (6.8) | % | | (1.4) | % |
Flow Through | | 0.4 | % | | 0.4 | % | | 0.4 | % | | 3.3 | % | | (5.8) | % | | 1.0 | % | | 0.8 | % | | 0.5 | % |
AFUDC Equity | | (1.2) | % | | (0.9) | % | | (1.7) | % | | (0.5) | % | | (2.2) | % | | (0.9) | % | | (0.7) | % | | (0.8) | % |
Parent Company Loss Benefit | | — | % | | (0.7) | % | | (1.7) | % | | 1.0 | % | | (1.7) | % | | — | % | | — | % | | (1.9) | % |
Discrete Tax Adjustments | | 2.9 | % | | — | % | | — | % | | — | % | | — | % | | — | % | | (2.6) | % | | — | % |
Other | | (0.5) | % | | (0.2) | % | | (0.1) | % | | — | % | | (0.5) | % | | (0.1) | % | | (0.1) | % | | (1.2) | % |
Effective Income Tax Rate | | 9.6 | % | | 11.0 | % | | 20.8 | % | | 13.9 | % | | (11.3) | % | | 13.1 | % | | (4.1) | % | | 16.2 | % |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
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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 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Six Months Ended June 30, 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 | | 1.4 | % | | 0.5 | % | | 2.7 | % | | 1.5 | % | | 0.4 | % | | 0.9 | % | | 3.5 | % | | 2.4 | % |
Tax Reform Excess ADIT Reversal | | (6.8) | % | | (2.0) | % | | 0.3 | % | | (11.0) | % | | (17.2) | % | | (7.8) | % | | (18.6) | % | | (5.1) | % |
Production and Investment Tax Credits | | (7.1) | % | | (0.4) | % | | — | % | | — | % | | (2.3) | % | | — | % | | (31.4) | % | | (20.8) | % |
Flow Through | | 0.1 | % | | 0.2 | % | | 0.3 | % | | 0.6 | % | | (1.6) | % | | 0.6 | % | | 0.3 | % | | (0.2) | % |
AFUDC Equity | | (1.0) | % | | (1.1) | % | | (1.9) | % | | (1.0) | % | | (0.9) | % | | (0.6) | % | | (0.5) | % | | (0.5) | % |
| | | | | | | | | | | | | | | | |
Discrete Tax Adjustments | | (0.2) | % | | — | % | | — | % | | (2.6) | % | | — | % | | — | % | | — | % | | 0.5 | % |
Other | | 0.5 | % | | (0.1) | % | | 0.2 | % | | — | % | | 0.4 | % | | (0.1) | % | | 0.3 | % | | — | % |
Effective Income Tax Rate | | 7.9 | % | | 18.1 | % | | 22.6 | % | | 8.5 | % | | (0.2) | % | | 14.0 | % | | (25.4) | % | | (2.7) | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | Six Months Ended June 30, 2021 |
| | 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 | | 1.6 | % | | 0.3 | % | | 2.7 | % | | 2.4 | % | | 1.4 | % | | 0.7 | % | | 4.4 | % | | 0.3 | % |
Tax Reform Excess ADIT Reversal | | (9.1) | % | | (7.9) | % | | 0.3 | % | | (15.7) | % | | (19.0) | % | | (9.1) | % | | (19.9) | % | | (4.3) | % |
Production and Investment Tax Credits | | (5.1) | % | | (0.3) | % | | — | % | | — | % | | (2.3) | % | | — | % | | (6.6) | % | | (3.7) | % |
Flow Through | | 0.3 | % | | 0.3 | % | | 0.3 | % | | 2.2 | % | | (3.0) | % | | 1.1 | % | | 0.8 | % | | (0.2) | % |
AFUDC Equity | | (1.1) | % | | (1.1) | % | | (1.7) | % | | (0.9) | % | | (1.0) | % | | (1.0) | % | | (0.7) | % | | (0.6) | % |
Parent Company Loss Benefit | | — | % | | (0.4) | % | | (1.8) | % | | (1.4) | % | | (2.1) | % | | — | % | | — | % | | (0.8) | % |
Discrete Tax Adjustments | | 1.7 | % | | — | % | | — | % | | — | % | | — | % | | (1.8) | % | | (2.8) | % | | — | % |
Other | | (0.2) | % | | — | % | | — | % | | 0.1 | % | | (0.3) | % | | (0.1) | % | | — | % | | (0.4) | % |
Effective Income Tax Rate | | 9.1 | % | | 11.9 | % | | 20.8 | % | | 7.7 | % | | (5.3) | % | | 10.8 | % | | (3.8) | % | | 11.3 | % |
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 subject to U.S.originally filed federal examinationreturn has expired for tax years before 2011. The IRS examination2016 and earlier. In the third quarter of years 2011, 2012 and 2013 started in April 2014.2019, AEP and subsidiaries received a Revenue Agents Reportelected to amend the 2014 through 2017 federal returns. In the first quarter of 2020, the IRS notified AEP that it was beginning an examination of these amended returns, including the net operating loss carryback to 2015 that originated in April 2016, completing the 2011 through 20132017 return. As of June 30, 2022, the IRS has not issued any proposed adjustment and has accepted the 2014 amended return as filed. AEP has agreed to extend the statute of limitations on the 2017 tax return to December 31, 2022 to allow time for the audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to be completed and the Congressional Joint Committee on Taxation for approval. The Joint Committee referredto approve 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 upon final resolution are expected to materially impact net income.associated refund claim.
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 filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made formonitoring and continues to evaluate the potential liabilities resulting from such challengesimpact of federal legislation and that the ultimate resolution of these audits will not materially impact net income. The Registrants are no longer subject tocorresponding state local or non-U.S. income tax examinations by tax authorities for years before 2009.conformity.
State Tax Legislation (Applies to AEP, APCo, I&M and OPCo)
Legislation was enacted in the state of Illinois in July 2017 increasing 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 falling 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 impact net income, cash flows or financial condition.
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 six months ended June 30, 2022.
Long-term Debt Outstanding (Applies to AEP)
The following table details long-term debt outstanding:outstanding, net of issuance costs and premiums or discounts:
| | | | | | | | | | | | | | |
Type of Debt | | June 30, 2022 | | December 31, 2021 |
| | (in millions) |
Senior Unsecured Notes | | $ | 28,855.6 | | | $ | 27,497.3 | |
Pollution Control Bonds | | 1,804.4 | | | 1,804.5 | |
Notes Payable | | 242.9 | | | 211.3 | |
Securitization Bonds | | 549.4 | | | 603.5 | |
Spent Nuclear Fuel Obligation (a) | | 281.8 | | | 281.3 | |
Junior Subordinated Notes (b) | | 2,375.4 | | | 2,373.0 | |
Other Long-term Debt | | 1,349.9 | | | 683.6 | |
Total Long-term Debt Outstanding | | 35,459.4 | | | 33,454.5 | |
Long-term Debt Due Within One Year (c) | | 2,476.7 | | | 2,153.8 | |
Long-term Debt (d) | | $ | 32,982.7 | | | $ | 31,300.7 | |
(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 $325 million and $329 million as of June 30, 2022 and December 31, 2021, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.
(b)See “Equity Units” section below for additional information.
(c)Amount excludes $415 million and $200 million as of June 30, 2022 and December 31, 2021, respectively, of Long-term Debt Due Within One Year classified as Liabilities Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(d)Amount excludes $688 million and $903 million as of June 30, 2022 and December 31, 2021, respectively, of Long-term Debt classified as Liabilities Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
|
| | | | | | | | | |
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 |
| |
Notes Payable | | 224.5 |
| | 326.9 |
| |
Securitization Bonds | | 1,449.4 |
| | 1,705.0 |
| |
Spent Nuclear Fuel Obligation (a) | | 267.9 |
| | 266.3 |
| |
Other Long-term Debt | | 1,128.9 |
| | 1,606.9 |
| |
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) |
| |
(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. |
| |
(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 ninesix months of 20172022 are shown in the tables below:following tables:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Principal | | Interest | | |
Company | | Type of Debt | | Amount (a) | | Rate | | Due Date |
Issuances: | | | | (in millions) | | (%) | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
AEP Texas | | Other Long-term Debt | | $ | 200.0 | | | Variable | | 2025 |
AEP Texas | | Senior Unsecured Notes | | 500.0 | | | 4.70 | | 2032 |
AEP Texas | | Senior Unsecured Notes | | 500.0 | | | 5.25 | | 2052 |
AEPTCo | | Senior Unsecured Notes | | 550.0 | | | 4.50 | | 2052 |
APCo | | Pollution Control Bonds | | 104.4 | | | 3.75 | | 2042 |
| | | | | | | | |
I&M | | Notes Payable | | 72.8 | | | 3.44 | | 2026 |
| | | | | | | | |
PSO | | Other Long-term Debt | | 500.0 | | | Variable | | 2022 |
| | | | | | | | |
| | | | | | | | |
Non-Registrant: | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Transource Energy | | Other Long-term Debt | | 5.0 | | | Variable | | 2023 |
WPCo | | Other Long-term Debt | | 165.0 | | | Variable | | 2024 |
WPCo | | Pollution Control Bonds | | 65.0 | | | 3.00 | | 2027 |
Total Issuances | | | | $ | 2,662.2 | | | | | |
(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.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Principal | | Interest | | |
Company | | Type of Debt | | Amount Paid | | Rate | | Due Date |
Retirements and Principal Payments: | | | | (in millions) | | (%) | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
AEP Texas | | Other Long-term Debt | | $ | 200.0 | | | Variable | | 2022 |
AEP Texas | | Securitization Bonds | | 30.6 | | | 2.85 | | 2024 |
AEP Texas | | Securitization Bonds | | 11.4 | | | 2.06 | | 2025 |
| | | | | | | | |
| | | | | | | | |
APCo | | Pollution Control Bonds | | 104.4 | | | 2.63 | | 2022 |
APCo | | Securitization Bonds | | 12.7 | | | 2.01 | | 2023 |
| | | | | | | | |
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| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
I&M | | Notes Payable | | 2.3 | | | Variable | | 2022 |
I&M | | Notes Payable | | 1.3 | | | Variable | | 2022 |
I&M | | Notes Payable | | 6.1 | | | Variable | | 2023 |
I&M | | Notes Payable | | 7.2 | | | Variable | | 2024 |
| | | | | | | | |
I&M | | Notes Payable | | 12.6 | | | 0.93 | | 2025 |
I&M | | Notes Payable | | 9.0 | | | Variable | | 2025 |
I&M | | Notes Payable | | 1.1 | | | 3.44 | | 2026 |
| | | | | | | | |
| | | | | | | | |
I&M | | Other Long-term Debt | | 1.1 | | | 6.00 | | 2025 |
OPCo | | Other Long-term Debt | | 0.1 | | | 1.15 | | 2028 |
| | | | | | | | |
PSO | | Other Long-term Debt | | 0.3 | | | 3.00 | | 2027 |
| | | | | | | | |
| | | | | | | | |
SWEPCo | | Other Long-term Debt | | 1.5 | | | 4.68 | | 2028 |
SWEPCo | | Notes Payable | | 1.6 | | | 4.58 | | 2032 |
| | | | | | | | |
Non-Registrant: | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Transource Energy | | Senior Unsecured Notes | | 1.1 | | | 2.75 | | 2050 |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
WPCo | | Senior Unsecured Notes | | 113.0 | | | 3.36 | | 2022 |
WPCo | | Pollution Control Bonds | | 65.0 | | | 3.00 | | 2022 |
Total Retirements and Principal Payments | | | | $ | 582.4 | | | | | |
|
| | | | | | | | | | |
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 |
| | | |
|
| |
| |
|
Non-Registrant: | | | |
|
| |
| |
|
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 |
| |
| |
|
Long-term Debt Subsequent Event
| |
(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. |
|
| | | | | | | | | | |
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 |
| | | | | | | | |
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 |
| | | | |
In October 2017,July 2022, AEP Texas retired $400 million of Senior Unsecured Notes.
In July 2022, APCo issued $100 million of variable rate Other Long-term Debt due in 2023.
In July 2022, I&M retired $1$8 million of Notes Payable related to DCC Fuel.
In October 2017, AEP Texas retired $41July 2022, KPCo issued $75 million of 5.625% Pollution Control Bondsvariable rate Other Long-term Debt due in 2017.2023.
AsEquity Units (Applies to AEP)
2020 Equity Units
In August 2020, AEP issued 17 million Equity Units initially in the form of September 30, 2017, trustees held,corporate units, at a stated amount of $50 per unit, for a total stated amount of $850 million. Net proceeds from the issuance were approximately $833 million. The proceeds were used to support AEP’s overall capital expenditure plans.
Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 1.30% Junior Subordinated Notes (notes) due in 2025 and a forward equity purchase contract which settles after three years in 2023. The notes are expected to be remarketed in 2023, at which time the interest rate will reset at the then current market rate. Investors may choose to remarket their notes to receive the remarketing proceeds and use those funds to settle the forward equity purchase contract, or accept the remarketed debt and use other funds for the equity purchase. If the remarketing is unsuccessful, investors have the right to put their notes to AEP at a price equal to the principal. The Equity Units carry an annual distribution rate of 6.125%, which is comprised of a quarterly coupon rate of interest of 1.30% and a quarterly forward equity purchase contract payment of 4.825%.
Each forward equity purchase contract obligates the holder to purchase, and AEP to sell, for $50 a number of shares in common stock in accordance with the conversion ratios set forth below (subject to an anti-dilution adjustment):
•If the AEP common stock market price is equal to or greater than $99.95: 0.5003 shares per contract.
•If the AEP common stock market price is less than $99.95 but greater than $83.29: a number of shares per contract equal to $50 divided by the applicable market price. The holder receives a variable number of shares at $50.
•If the AEP common stock market price is less than or equal to $83.29: 0.6003 shares per contract.
A holder’s ownership interest in the notes is pledged to AEP to secure the holder’s obligation under the related forward equity purchase contract. If a holder of the forward equity purchase contract chooses at any time to no longer be a holder of the notes, such holder’s obligation under the forward equity purchase contract must be secured by a U.S. Treasury security which must be equal to the aggregate principal amount of the notes.
At the time of issuance, the $850 million of notes were recorded within Long-term Debt on the balance sheets. The present value of the purchase contract payments of $121 million were recorded in Deferred Credits and Other Noncurrent 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).
2019 Equity Units
In March 2019, AEP issued 16.1 million Equity Units initially in the form of corporate units, at a stated amount of $50 per unit, for a total stated amount of $805 million. Net proceeds from the issuance were approximately $785 million. The proceeds were used to support AEP’s overall capital expenditure plans including the acquisition of Sempra Renewables LLC.
Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 3.40% Junior Subordinated Notes (notes) due in 2024 and a forward equity purchase contract which settled after three years in 2022. In January 2022, AEP successfully remarketed the notes on behalf of holders of the corporate units and did not directly receive any proceeds therefrom. Instead, the holders of the corporate units used the debt remarketing proceeds to settle the forward equity purchase contract with AEP. The interest rate on the notes was reset to 2.031% with the maturity remaining in 2024. In March 2022, AEP $728issued 8,970,920 shares of AEP common stock and received proceeds totaling $805 million under the settlement of their reacquired Pollution Control Bonds. Of this total, $104 million, $50 million and $345 million relatedthe forward equity purchase contract. AEP common stock held in treasury was used to APCo, I&M and OPCo, respectively.settle the forward equity purchase contract.
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 0.5% of consolidated tangible net assets as of June 30, 2022. 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 SeptemberJune 30, 20172022 and December 31, 20162021 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 ninesix months ended SeptemberJune 30, 20172022 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 | | June 30, 2022 | | Limit | |
| | (in millions) |
AEP Texas | | $ | 348.8 | | | $ | 652.3 | | | $ | 208.1 | | | $ | 617.9 | | | $ | 634.1 | | | $ | 500.0 | | |
AEPTCo | | 480.2 | | | 137.0 | | | 274.2 | | | 13.3 | | | 103.8 | | (a) | 820.0 | | (b) |
APCo | | 404.0 | | | 20.8 | | | 148.7 | | | 19.8 | | | (329.8) | | | 500.0 | | |
I&M | | 159.1 | | | 22.5 | | | 91.9 | | | 21.9 | | | (28.0) | | | 500.0 | | |
OPCo | | 112.2 | | | 246.1 | | | 56.2 | | | 97.9 | | | 56.0 | | | 500.0 | | |
PSO | | 299.9 | | | 432.5 | | | 179.8 | | | 403.6 | | | (283.4) | | | 400.0 | | |
SWEPCo | | 261.6 | | | 156.6 | | | 226.6 | | | 109.7 | | | (213.2) | | | 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 excludes $2 million of Advances to Affiliates classified as Assets Held for Sale on the AEPTCo balance sheet. See “Dispositions of KPCo and KTCo” section of Note 6 for additional information.
| |
(a) | Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions. |
(b) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
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 SeptemberJune 30, 20172022 and December 31, 20162021 are included in Advances to Affiliates on SWEPCo’sthe subsidiaries’ balance sheets. ForThe Nonutility Money Pool participants’ activity for the ninesix months ended SeptemberJune 30, 2017, Mutual Energy SWEPCo, LP had2022 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 | | June 30, 2022 |
| (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 SeptemberJune 30, 20172022 and December 31, 20162021 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 ninesix months ended SeptemberJune 30, 2017 is2022 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 | | June 30, 2022 | | June 30, 2022 | | Borrowing Limit | |
(in millions) |
$ | 52.4 | | | $ | 141.8 | | | $ | 6.8 | | | $ | 62.0 | | | $ | 25.7 | | | $ | — | | | $ | 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:
| | | | | | | | | | | | | | |
| | Six Months Ended June 30, |
| | 2022 | | 2021 |
Maximum Interest Rate | | 2.11 | % | | 0.40 | % |
Minimum Interest Rate | | 0.10 | % | | 0.25 | % |
|
| | | | | | |
| | 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 Six Months Ended June 30, | | for Six Months Ended June 30, |
Company | | 2022 | | 2021 | | 2022 | | 2021 |
AEP Texas | | 0.90 | % | | 0.33 | % | | 1.48 | % | | 0.36 | % |
AEPTCo | | 0.93 | % | | 0.33 | % | | 1.49 | % | | 0.34 | % |
APCo | | 1.08 | % | | 0.28 | % | | 0.95 | % | | 0.36 | % |
I&M | | 0.92 | % | | 0.32 | % | | 0.96 | % | | 0.35 | % |
OPCo | | 0.83 | % | | 0.34 | % | | 1.20 | % | | 0.29 | % |
PSO | | 1.17 | % | | 0.34 | % | | 0.65 | % | | 0.28 | % |
SWEPCo | | 1.25 | % | | 0.32 | % | | 0.55 | % | | 0.38 | % |
|
| | | | | | | | | | | | |
| | 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:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Six Months Ended June 30, 2022 | | Six Months Ended June 30, 2021 |
| | 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 | | 2.11 | % | | 0.46 | % | | 0.98 | % | | 0.40 | % | | 0.25 | % | | 0.33 | % |
SWEPCo | | 2.11 | % | | 0.46 | % | | 0.98 | % | | 0.40 | % | | 0.25 | % | | 0.33 | % |
|
| | | | | | | | | |
| | 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 |
Six Months | | for Funds | | for Funds | | for Funds | | for Funds | | for Funds | | for Funds |
Ended | | Borrowed | | Borrowed | | Loaned | | Loaned | | Borrowed | | Loaned |
June 30, | | from AEP | | from AEP | to AEP | | to AEP | | from AEP | | to AEP |
2022 | | 2.11 | % | | 0.46 | % | | 2.11 | % | | 0.46 | % | | 1.02 | % | | 0.89 | % |
2021 | | 0.86 | % | | 0.25 | % | | 0.86 | % | | 0.25 | % | | 0.33 | % | | 0.33 | % |
|
| | | | | | | | | | | | | | | | | | |
| | 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 | % |
Short-term Debt (Applies to AEP and SWEPCo)AEP)
Outstanding short-term debt was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | June 30, 2022 | | December 31, 2021 |
| | | | 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 | | | 0.61 | % | | $ | 750.0 | | | 0.19 | % |
AEP | | Commercial Paper | | 880.0 | | | 2.02 | % | | 1,364.0 | | | 0.34 | % |
AEP | | Term Loan (c) | | 500.0 | | | 2.20 | % | | 500.0 | | | 0.81 | % |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | Total Short-term Debt | | $ | 2,130.0 | | | | | $ | 2,614.0 | | | |
|
| | | | | | | | | | | | | | | | |
| | | | 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.
| |
(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.
(c)In March 2022, AEP extended the maturity date of the original 364-Day Term Loan to August 2022.
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 expireswas amended in September 2021 to include a $125 million and a $625 million facility which expire in September 2023 and 2024, respectively. As of June 2019.30, 2022, the affiliated utility subsidiaries are in compliance with all requirements under the agreement.
Accounts receivable information for AEP Credit iswas as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2022 | | 2021 | | 2022 | | 2021 |
| | (dollars in millions) |
Effective Interest Rates on Securitization of Accounts Receivable | | 0.91 | % | | 0.19 | % | | 0.61 | % | | 0.20 | % |
Net Uncollectible Accounts Receivable Written-Off | | $ | 6.2 | | | $ | 5.8 | | | $ | 13.6 | | | $ | 15.1 | |
|
| | | | | | | | | | | | | | | | |
| | 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 |
|
| | | | | | | | | | | | | | |
| | June 30, 2022 | | December 31, 2021 |
| | (in millions) |
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts | | $ | 1,114.7 | | | $ | 995.2 | |
Short-term – Securitized Debt of Receivables | | 750.0 | | | 750.0 | |
Delinquent Securitized Accounts Receivable | | 44.0 | | | 57.9 | |
Bad Debt Reserves Related to Securitization | | 41.2 | | | 42.8 | |
Unbilled Receivables Related to Securitization | | 334.3 | | | 307.1 | |
|
| | | | | | | | |
| | 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 pending 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 | | June 30, 2022 | | December 31, 2021 |
| | (in millions) |
APCo | | $ | 150.3 | | | $ | 153.1 | |
I&M | | 193.0 | | | 156.9 | |
OPCo | | 441.1 | | | 392.7 | |
PSO | | 166.9 | | | 114.5 | |
SWEPCo | | 189.2 | | | 153.0 | |
|
| | | | | | | | |
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 June 30, | | Six Months Ended June 30, |
Company | | 2022 | | 2021 (a) | | 2022 | | 2021 (a) |
| | (in millions) |
APCo | | $ | 1.5 | | | $ | 1.2 | | | $ | 2.8 | | | $ | 2.4 | |
I&M | | 2.0 | | | 1.6 | | | 3.7 | | | 3.2 | |
OPCo | | 7.5 | | | (2.4) | | | 14.9 | | | (1.1) | |
PSO | | 1.3 | | | 0.6 | | | 2.2 | | | 1.3 | |
SWEPCo | | 1.5 | | | 1.3 | | | 2.8 | | | 2.8 | |
(a)In 2020, an increase in allowance for doubtful accounts was recognized in response to the anticipated impact of COVID-19 on the collectability of accounts receivable, which caused an increase in fees paid by the registrants. In 2021, due to higher than expected collections of accounts receivables, allowance for doubtful accounts was adjusted resulting in the issuance of credits to offset the higher fees previously paid.
|
| | | | | | | | | | | | | | | | |
| | 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 June 30, | | Six Months Ended June 30, |
Company | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) |
APCo | | $ | 339.0 | | | $ | 276.0 | | | $ | 754.5 | | | $ | 638.4 | |
I&M | | 502.4 | | | 463.3 | | | 1,015.8 | | | 942.1 | |
OPCo | | 693.3 | | | 597.8 | | | 1,409.9 | | | 1,199.1 | |
PSO | | 428.5 | | | 323.8 | | | 791.9 | | | 608.7 | |
SWEPCo | | 437.2 | | | 392.6 | | | 831.7 | | | 777.0 | |
|
| | | | | | | | | | | | | | | | |
| | 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. PROPERTY, PLANT AND EQUIPMENT
The disclosure in this note applies to AEP, PSO and SWEPCo.
Asset Retirement Obligations
The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, wind farms, solar farms and certain coal mining facilities. The discussion below summarizes significant changes to the Registrants ARO recorded in 2022 and should be read in conjunction with the Property, Plant and Equipment note within the 2021 Annual Report.
In March 2022, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Traverse during its development and construction. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Traverse assets in proportion to their undivided ownership interests. Traverse was placed in-service in March 2022. As a result, PSO and SWEPCo incurred additional ARO liabilities of $13 million and $15 million, respectively. See the “North Central Wind Energy Facilities” section of Note 6 for additional information. Additionally, in March 2022, SWEPCo recorded a $13 million revision due to an increase in estimated ash pond closure costs at the Pirkey Power Plant and the Welsh Plant. In June 2022, SWEPCo recorded a $16 million revision due to an increase in estimated reclamation costs at Sabine.
The following is a reconciliation of the aggregate carrying amounts of ARO for AEP, PSO and SWEPCo:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Company | | ARO as of December 31, 2021 | | Accretion Expense | | Liabilities Incurred | | Liabilities Settled | | Revisions in Cash Flow Estimates | | ARO as of June 30, 2022 |
| | (in millions) |
AEP (a)(b)(c)(d)(e) | | $ | 2,741.7 | | | $ | 54.8 | | | $ | 37.4 | | | $ | (16.5) | | | $ | 39.8 | | | $ | 2,857.2 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
PSO (a)(d) | | 57.6 | | | 1.9 | | | 12.8 | | | (0.5) | | | 1.9 | | | 73.7 | |
SWEPCo (a)(c)(d) | | 222.7 | | | 5.2 | | | 15.4 | | | (10.9) | | | 34.3 | | | 266.7 | |
(a)Includes ARO related to ash disposal facilities.
(b)Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.96 billion and $1.93 billion as of June 30, 2022 and December 31, 2021, respectively.
(c)Includes ARO related to Sabine and DHLC.
(d)Includes ARO related to asbestos removal.
(e)Includes $18 million and $18 million as of June 30, 2022 and December 31, 2021, respectively, of ARO classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
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 June 30, 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 | | $ | 979.3 | | | $ | 561.6 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 1,540.9 | |
Commercial Revenues | | 624.8 | | | 331.7 | | | — | | | — | | | — | | | — | | | 956.5 | |
Industrial Revenues | | 641.8 | | | 162.5 | | | — | | | — | | | — | | | — | | | 804.3 | |
Other Retail Revenues | | 52.9 | | | 12.8 | | | — | | | — | | | — | | | — | | | 65.7 | |
Total Retail Revenues | | 2,298.8 | | | 1,068.6 | | | — | | | — | | | — | | | — | | | 3,367.4 | |
| | | | | | | | | | | | | | |
Wholesale and Competitive Retail Revenues: | | | | | | | | | | | | | | |
Generation Revenues | | 188.3 | | | — | | | — | | | 83.0 | | | — | | | 0.1 | | | 271.4 | |
Transmission Revenues (a) | | 108.8 | | | 164.9 | | | 421.6 | | | — | | | — | | | (332.0) | | | 363.3 | |
Renewable Generation Revenues (b) | | — | | | — | | | — | | | 38.2 | | | — | | | (2.9) | | | 35.3 | |
Retail, Trading and Marketing Revenues (b) | | — | | | — | | | — | | | 408.3 | | | 1.3 | | | (2.3) | | | 407.3 | |
Total Wholesale and Competitive Retail Revenues | | 297.1 | | | 164.9 | | | 421.6 | | | 529.5 | | | 1.3 | | | (337.1) | | | 1,077.3 | |
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (c) | | 49.2 | | | 65.9 | | | 0.2 | | | 1.6 | | | 20.9 | | | (21.1) | | | 116.7 | |
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 2,645.1 | | | 1,299.4 | | | 421.8 | | | 531.1 | | | 22.2 | | | (358.2) | | | 4,561.4 | |
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (b) | | 3.3 | | | (4.6) | | | (43.0) | | | — | | | — | | | (13.1) | | | (57.4) | |
Other Revenues (b) (d) | | 0.1 | | | 6.8 | | | — | | | 128.5 | | | 2.3 | | | (2.0) | | | 135.7 | |
Total Other Revenues | | 3.4 | | | 2.2 | | | (43.0) | | | 128.5 | | | 2.3 | | | (15.1) | | | 78.3 | |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 2,648.5 | | | $ | 1,301.6 | | | $ | 378.8 | | | $ | 659.6 | | | $ | 24.5 | | | $ | (373.3) | | | $ | 4,639.7 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $334 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 Vertically Integrated Utilities was $5 million. The remaining affiliated amounts were immaterial.
(d)Generation & Marketing includes economic hedge activity.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, 2021 |
| | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other | | Reconciling Adjustments | | AEP Consolidated |
| | (in millions) |
Retail Revenues: | | | | | | | | | | | | | | |
Residential Revenues | | $ | 825.8 | | | $ | 495.1 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 1,320.9 | |
Commercial Revenues | | 536.9 | | | 285.0 | | | — | | | — | | | — | | | — | | | 821.9 | |
Industrial Revenues | | 552.5 | | | 102.9 | | | — | | | — | | | — | | | (0.2) | | | 655.2 | |
Other Retail Revenues | | 40.6 | | | 11.3 | | | — | | | — | | | — | | | — | | | 51.9 | |
Total Retail Revenues | | 1,955.8 | | | 894.3 | | | — | | | — | | | — | | | (0.2) | | | 2,849.9 | |
| | | | | | | | | | | | | | |
Wholesale and Competitive Retail Revenues: | | | | | | | | | | | | | | |
Generation Revenues | | 170.7 | | | — | | | — | | | 31.1 | | | — | | | — | | | 201.8 | |
Transmission Revenues (a) | | 78.5 | | | 139.6 | | | 355.9 | | | — | | | — | | | (284.8) | | | 289.2 | |
Renewable Generation Revenues (b) | | — | | | — | | | — | | | 20.2 | | | — | | | (0.4) | | | 19.8 | |
Retail, Trading and Marketing Revenues (c) | | — | | | — | | | — | | | 358.7 | | | (0.7) | | | (13.6) | | | 344.4 | |
Total Wholesale and Competitive Retail Revenues | | 249.2 | | | 139.6 | | | 355.9 | | | 410.0 | | | (0.7) | | | (298.8) | | | 855.2 | |
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (b) | | 44.4 | | | 43.0 | | | 2.8 | | | 2.0 | | | 14.0 | | | (26.6) | | | 79.6 | |
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 2,249.4 | | | 1,076.9 | | | 358.7 | | | 412.0 | | | 13.3 | | | (325.6) | | | 3,784.7 | |
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (b) | | 10.9 | | | 22.5 | | | 19.5 | | | — | | | — | | | (40.2) | | | 12.7 | |
Other Revenues (b) (d) | | 0.3 | | | 4.0 | | | — | | | 24.6 | | | 2.2 | | | (2.0) | | | 29.1 | |
Total Other Revenues | | 11.2 | | | 26.5 | | | 19.5 | | | 24.6 | | | 2.2 | | | (42.2) | | | 41.8 | |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 2,260.6 | | | $ | 1,103.4 | | | $ | 378.2 | | | $ | 436.6 | | | $ | 15.5 | | | $ | (367.8) | | | $ | 3,826.5 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $276 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 $13 million. The remaining affiliated amounts were immaterial.
(d)Generation & Marketing includes economic hedge activity.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, 2022 |
| | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Retail Revenues: | | | | | | | | | | | | | | |
Residential Revenues | | $ | 174.9 | | | $ | — | | | $ | 313.2 | | | $ | 195.2 | | | $ | 386.7 | | | $ | 185.2 | | | $ | 188.6 | |
Commercial Revenues | | 110.6 | | | — | | | 152.6 | | | 138.6 | | | 221.1 | | | 121.2 | | | 146.0 | |
Industrial Revenues | | 36.6 | | | — | | | 161.9 | | | 160.0 | | | 126.0 | | | 92.5 | | | 97.1 | |
Other Retail Revenues | | 9.5 | | | — | | | 20.2 | | | 1.2 | | | 3.4 | | | 25.8 | | | 4.4 | |
Total Retail Revenues | | 331.6 | | | — | | | 647.9 | | | 495.0 | | | 737.2 | | | 424.7 | | | 436.1 | |
| | | | | | | | | | | | | | |
Wholesale Revenues: | | | | | | | | | | | | | | |
Generation Revenues (a) | | — | | | — | | | 63.5 | | | 94.2 | | | — | | | 0.3 | | | 57.4 | |
Transmission Revenues (b) | | 143.8 | | | 406.1 | | | 40.8 | | | 8.7 | | | 21.1 | | | 9.1 | | | 39.3 | |
Total Wholesale Revenues | | 143.8 | | | 406.1 | | | 104.3 | | | 102.9 | | | 21.1 | | | 9.4 | | | 96.7 | |
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (c) | | 5.6 | | | 0.2 | | | 20.6 | | | 25.8 | | | 60.2 | | | 9.6 | | | 6.0 | |
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 481.0 | | | 406.3 | | | 772.8 | | | 623.7 | | | 818.5 | | | 443.7 | | | 538.8 | |
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (d) | | (2.2) | | | (41.9) | | | 0.8 | | | 7.3 | | | (2.4) | | | (0.8) | | | (2.2) | |
Other Revenues (d) | | — | | | — | | | — | | | — | | | 6.8 | | | — | | | — | |
Total Other Revenues | | (2.2) | | | (41.9) | | | 0.8 | | | 7.3 | | | 4.4 | | | (0.8) | | | (2.2) | |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 478.8 | | | $ | 364.4 | | | $ | 773.6 | | | $ | 631.0 | | | $ | 822.9 | | | $ | 442.9 | | | $ | 536.6 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $42 million primarily related to the PPA with KGPCo.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $330 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $19 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, 2021 |
| | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Retail Revenues: | | | | | | | | | | | | | | |
Residential Revenues | | $ | 128.5 | | | $ | — | | | $ | 268.0 | | | $ | 179.1 | | | $ | 366.8 | | | $ | 142.8 | | | $ | 149.9 | |
Commercial Revenues | | 95.4 | | | — | | | 132.4 | | | 127.0 | | | 189.6 | | | 93.2 | | | 127.1 | |
Industrial Revenues | | 29.7 | | | — | | | 147.7 | | | 143.7 | | | 73.2 | | | 68.6 | | | 91.1 | |
Other Retail Revenues | | 8.1 | | | — | | | 16.2 | | | 1.2 | | | 3.1 | | | 19.1 | | | 2.6 | |
Total Retail Revenues | | 261.7 | | | — | | | 564.3 | | | 451.0 | | | 632.7 | | | 323.7 | | | 370.7 | |
| | | | | | | | | | | | | | |
Wholesale Revenues: | | | | | | | | | | | | | | |
Generation Revenues (a) | | — | | | — | | | 75.1 | | | 88.3 | | | — | | | 6.7 | | | 20.5 | |
Transmission Revenues (b) | | 121.0 | | | 339.9 | | | 24.7 | | | 8.3 | | | 18.6 | | | 8.8 | | | 28.5 | |
Total Wholesale Revenues | | 121.0 | | | 339.9 | | | 99.8 | | | 96.6 | | | 18.6 | | | 15.5 | | | 49.0 | |
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (c) | | 12.4 | | | 2.9 | | | 8.0 | | | 37.0 | | | 30.5 | | | 3.9 | | | 5.2 | |
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 395.1 | | | 342.8 | | | 672.1 | | | 584.6 | | | 681.8 | | | 343.1 | | | 424.9 | |
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (d) | | 3.4 | | | 22.7 | | | 5.1 | | | (0.8) | | | 19.1 | | | 1.4 | | | 5.2 | |
Other Revenues (d) | | — | | | — | | | (0.2) | | | — | | | 4.0 | | | — | | | — | |
Total Other Revenues | | 3.4 | | | 22.7 | | | 4.9 | | | (0.8) | | | 23.1 | | | 1.4 | | | 5.2 | |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 398.5 | | | $ | 365.5 | | | $ | 677.0 | | | $ | 583.8 | | | $ | 704.9 | | | $ | 344.5 | | | $ | 430.1 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $28 million primarily related to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $272 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $13 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Six Months Ended June 30, 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 | | $ | 2,130.1 | | | $ | 1,162.2 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 3,292.3 | |
Commercial Revenues | | 1,197.7 | | | 621.4 | | | — | | | — | | | — | | | — | | | 1,819.1 | |
Industrial Revenues | | 1,204.8 | | | 295.8 | | | — | | | — | | | — | | | (0.4) | | | 1,500.2 | |
Other Retail Revenues | | 100.3 | | | 24.4 | | | — | | | — | | | — | | | — | | | 124.7 | |
Total Retail Revenues | | 4,632.9 | | | 2,103.8 | | | — | | | — | | | — | | | (0.4) | | | 6,736.3 | |
| | | | | | | | | | | | | | |
Wholesale and Competitive Retail Revenues: | | | | | | | | | | | | | | |
Generation Revenues | | 375.5 | | | — | | | — | | | 123.3 | | | — | | | 0.1 | | | 498.9 | |
Transmission Revenues (a) | | 214.1 | | | 319.8 | | | 836.1 | | | — | | | — | | | (693.8) | | | 676.2 | |
Renewable Generation Revenues (b) | | — | | | — | | | — | | | 60.6 | | | — | | | (3.7) | | | 56.9 | |
Retail, Trading and Marketing Revenues (c) | | — | | | — | | | — | | | 797.1 | | | 4.5 | | | (11.3) | | | 790.3 | |
Total Wholesale and Competitive Retail Revenues | | 589.6 | | | 319.8 | | | 836.1 | | | 981.0 | | | 4.5 | | | (708.7) | | | 2,022.3 | |
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (d) | | 110.8 | | | 119.7 | | | — | | | 10.2 | | | 34.8 | | | (39.7) | | | 235.8 | |
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 5,333.3 | | | 2,543.3 | | | 836.1 | | | 991.2 | | | 39.3 | | | (748.8) | | | 8,994.4 | |
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (b) | | 2.5 | | | (8.0) | | | (45.9) | | | — | | | — | | | (11.8) | | | (63.2) | |
Other Revenues (b) (e) | | 0.1 | | | 13.1 | | | — | | | 287.7 | | | 5.1 | | | (4.9) | | | 301.1 | |
| | | | | | | | | | | | | | |
Total Other Revenues | | 2.6 | | | 5.1 | | | (45.9) | | | 287.7 | | | 5.1 | | | (16.7) | | | 237.9 | |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 5,335.9 | | | $ | 2,548.4 | | | $ | 790.2 | | | $ | 1,278.9 | | | $ | 44.4 | | | $ | (765.5) | | | $ | 9,232.3 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $661 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 $11 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Corporate and Other was $19 million. The remaining affiliated amounts were immaterial.
(e)Generation & Marketing includes economic hedge activity.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Six Months Ended June 30, 2021 |
| | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other | | Reconciling Adjustments | | AEP Consolidated |
| | (in millions) |
Retail Revenues: | | | | | | | | | | | | | | |
Residential Revenues | | $ | 1,871.9 | | | $ | 1,043.2 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 2,915.1 | |
Commercial Revenues | | 1,023.1 | | | 524.2 | | | — | | | — | | | — | | | — | | | 1,547.3 | |
Industrial Revenues | | 1,036.5 | | | 188.6 | | | — | | | — | | | — | | | (0.4) | | | 1,224.7 | |
Other Retail Revenues | | 78.4 | | | 21.3 | | | — | | | — | | | — | | | — | | | 99.7 | |
Total Retail Revenues | | 4,009.9 | | | 1,777.3 | | | — | | | — | | | — | | | (0.4) | | | 5,786.8 | |
| | | | | | | | | | | | | | |
Wholesale and Competitive Retail Revenues: | | | | | | | | | | | | | | |
Generation Revenues | | 523.3 | | | — | | | — | | | 71.6 | | | — | | | — | | | 594.9 | |
Transmission Revenues (a) | | 167.5 | | | 270.1 | | | 716.3 | | | — | | | — | | | (584.1) | | | 569.8 | |
Renewable Generation Revenues (b) | | — | | | — | | | — | | | 42.6 | | | — | | | (1.1) | | | 41.5 | |
Retail, Trading and Marketing Revenues (c) | | — | | | — | | | — | | | 928.5 | | | 0.5 | | | (45.4) | | | 883.6 | |
Total Wholesale and Competitive Retail Revenues | | 690.8 | | | 270.1 | | | 716.3 | | | 1,042.7 | | | 0.5 | | | (630.6) | | | 2,089.8 | |
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (b) | | 86.7 | | | 95.1 | | | 7.4 | | | 3.5 | | | 22.6 | | | (47.8) | | | 167.5 | |
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 4,787.4 | | | 2,142.5 | | | 723.7 | | | 1,046.2 | | | 23.1 | | | (678.8) | | | 8,044.1 | |
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (b) | | 10.2 | | | 39.7 | | | 31.5 | | | — | | | — | | | (51.8) | | | 29.6 | |
Other Revenues (b) (d) | | 0.3 | | | 9.3 | | | — | | | 24.6 | | | 5.3 | | | (5.6) | | | 33.9 | |
Total Other Revenues | | 10.5 | | | 49.0 | | | 31.5 | | | 24.6 | | | 5.3 | | | (57.4) | | | 63.5 | |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 4,797.9 | | | $ | 2,191.5 | | | $ | 755.2 | | | $ | 1,070.8 | | | $ | 28.4 | | | $ | (736.2) | | | $ | 8,107.6 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $549 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 $45 million. The remaining affiliated amounts were immaterial.
(d)Generation & Marketing includes economic hedge activity.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Six Months Ended June 30, 2022 |
| | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Retail Revenues: | | | | | | | | | | | | | | |
Residential Revenues | | $ | 316.8 | | | $ | — | | | $ | 771.2 | | | $ | 427.0 | | | $ | 845.4 | | | $ | 351.1 | | | $ | 364.5 | |
Commercial Revenues | | 205.5 | | | — | | | 306.5 | | | 265.2 | | | 415.8 | | | 218.7 | | | 276.5 | |
Industrial Revenues | | 67.2 | | | — | | | 315.7 | | | 296.5 | | | 228.7 | | | 171.1 | | | 181.8 | |
Other Retail Revenues | | 17.7 | | | — | | | 40.8 | | | 2.5 | | | 6.7 | | | 47.0 | | | 6.8 | |
Total Retail Revenues | | 607.2 | | | — | | | 1,434.2 | | | 991.2 | | | 1,496.6 | | | 787.9 | | | 829.6 | |
| | | | | | | | | | | | | | |
Wholesale Revenues: | | | | | | | | | | | | | | |
Generation Revenues (a) | | — | | | — | | | 119.7 | | | 184.6 | | | — | | | 9.8 | | | 118.6 | |
Transmission Revenues (b) | | 276.9 | | | 806.4 | | | 81.9 | | | 17.5 | | | 42.9 | | | 18.7 | | | 74.5 | |
Total Wholesale Revenues | | 276.9 | | | 806.4 | | | 201.6 | | | 202.1 | | | 42.9 | | | 28.5 | | | 193.1 | |
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (c) | | 14.9 | | | (0.1) | | | 44.9 | | | 55.7 | | | 104.8 | | | 15.0 | | | 11.3 | |
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 899.0 | | | 806.3 | | | 1,680.7 | | | 1,249.0 | | | 1,644.3 | | | 831.4 | | | 1,034.0 | |
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (d) | | (3.5) | | | (41.5) | | | 0.1 | | | 7.3 | | | (4.5) | | | (0.9) | | | (2.6) | |
Other Revenues (d) | | — | | | — | | | 0.1 | | | (0.1) | | | 13.1 | | | — | | | — | |
Total Other Revenues | | (3.5) | | | (41.5) | | | 0.2 | | | 7.2 | | | 8.6 | | | (0.9) | | | (2.6) | |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 895.5 | | | $ | 764.8 | | | $ | 1,680.9 | | | $ | 1,256.2 | | | $ | 1,652.9 | | | $ | 830.5 | | | $ | 1,031.4 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $78 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $653 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $29 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Six Months Ended June 30, 2021 |
| | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Retail Revenues: | | | | | | | | | | | | | | |
Residential Revenues | | $ | 251.2 | | | $ | — | | | $ | 684.9 | | | $ | 392.7 | | | $ | 792.1 | | | $ | 279.6 | | | $ | 316.2 | |
Commercial Revenues | | 176.1 | | | — | | | 262.6 | | | 240.6 | | | 348.1 | | | 165.9 | | | 240.0 | |
Industrial Revenues | | 56.2 | | | — | | | 278.6 | | | 272.1 | | | 132.4 | | | 125.0 | | | 161.7 | |
Other Retail Revenues | | 14.9 | | | — | | | 33.1 | | | 2.6 | | | 6.3 | | | 34.8 | | | 4.9 | |
Total Retail Revenues | | 498.4 | | | — | | | 1,259.2 | | | 908.0 | | | 1,278.9 | | | 605.3 | | | 722.8 | |
| | | | | | | | | | | | | | |
Wholesale Revenues: | | | | | | | | | | | | | | |
Generation Revenues (a) | | — | | | — | | | 147.5 | | | 167.9 | | | — | | | (0.4) | | | 249.1 | |
Transmission Revenues (b) | | 233.0 | | | 685.1 | | | 58.9 | | | 16.6 | | | 37.1 | | | 18.2 | | | 57.4 | |
Total Wholesale Revenues | | 233.0 | | | 685.1 | | | 206.4 | | | 184.5 | | | 37.1 | | | 17.8 | | | 306.5 | |
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (c) | | 28.6 | | | 7.5 | | | 21.1 | | | 57.7 | | | 66.5 | | | 16.5 | | | 11.6 | |
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 760.0 | | | 692.6 | | | 1,486.7 | | | 1,150.2 | | | 1,382.5 | | | 639.6 | | | 1,040.9 | |
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (d) | | 2.7 | | | 34.6 | | | 7.3 | | | (1.9) | | | 37.0 | | | 1.0 | | | 5.3 | |
Other Revenues (d) | | — | | | — | | | — | | | — | | | 9.3 | | | — | | | — | |
Total Other Revenues | | 2.7 | | | 34.6 | | | 7.3 | | | (1.9) | | | 46.3 | | | 1.0 | | | 5.3 | |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 762.7 | | | $ | 727.2 | | | $ | 1,494.0 | | | $ | 1,148.3 | | | $ | 1,428.8 | | | $ | 640.6 | | | $ | 1,046.2 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $60 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $542 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $29 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.
Fixed Performance Obligations
The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of June 30, 2022. Fixed performance obligations primarily include wholesale transmission services, electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market. The Registrant Subsidiaries amounts shown in the table below include affiliated and nonaffiliated revenues.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Company | | 2022 | | 2023-2024 | | 2025-2026 | | After 2026 | | Total |
| | (in millions) |
AEP | | $ | 628.5 | | | $ | 175.8 | | | $ | 157.8 | | | $ | 96.9 | | | $ | 1,059.0 | |
AEP Texas | | 280.2 | | | — | | | — | | | — | | | 280.2 | |
AEPTCo | | 738.8 | | | — | | | — | | | — | | | 738.8 | |
APCo | | 100.2 | | | 33.8 | | | 25.5 | | | 11.5 | | | 171.0 | |
I&M | | 18.7 | | | 11.1 | | | 8.8 | | | 4.5 | | | 43.1 | |
OPCo | | 38.4 | | | 3.4 | | | — | | | — | | | 41.8 | |
PSO | | 6.4 | | | — | | | — | | | — | | | 6.4 | |
SWEPCo | | 21.2 | | | — | | | — | | | — | | | 21.2 | |
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 June 30, 2022 and December 31, 2021.
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 June 30, 2022 and December 31, 2021.
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 June 30, 2022 and December 31, 2021. 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 | | June 30, 2022 | | December 31, 2021 |
| | (in millions) |
AEP Texas | | $ | 0.1 | | | $ | 0.4 | |
AEPTCo | | 111.4 | | | 95.5 | |
APCo | | 62.5 | | | 117.8 | |
I&M | | 37.0 | | | 61.2 | |
OPCo | | 50.2 | | | 51.7 | |
PSO | | 31.8 | | | 18.8 | |
SWEPCo | | 38.2 | | | 24.7 | |
CONTROLS AND PROCEDURES
During the thirdsecond quarter of 2017,2022, 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 SeptemberJune 30, 2017,2022, 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 thirdsecond quarter of 20172022 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, 2021 includes a detailed discussion of risk factors. As of SeptemberJune 30, 2017, there have been no material changes to2022, the risk factors previously disclosed in AEPTCo’s Registration Statement. As of September 30, 2017, the risk factor appearing in AEP’s 20162021 Annual Report under the heading set forth below isare supplemented and updated as follows:
AEP is exposed to nuclear generation risk. (Applies to AEPSupply chain disruptions 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. AEPinflation could negatively impact operations 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.corporate strategy. (Applies to all Registrants)
Management expectsAEP’s operations and business plans depend on the global supply chain to procure the equipment, materials and other resources necessary to build and provide services in a safe and reliable manner. The delivery of components, materials, equipment and other resources that a growing portion ofare critical to AEP’s earningsbusiness operations and corporate strategy has been restricted by the current domestic and global supply chain upheaval. This has resulted in the future will be derived from transmission investments and activities. FERC policy currently favors the expansion and updatingshortage 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,critical items. International tensions, including the State Transcosramifications of regional conflict, could further exacerbate the global supply chain upheaval. These disruptions and shortages could adversely impact business operations and corporate strategy. The constraints in the supply chain could restrict the availability and delay the construction, maintenance or repair of items that operateare needed to support normal operations or are required to execute AEP’s corporate strategy for continued capital investment in SPP, in calculating formula transmission rates under the SPP OATT is excessiveutility equipment. These disruptions 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, itconstraints could reduce future net income and cash flows and impactpossibly harm AEP’s financial condition.
IfSupply chain disruptions have contributed to higher prices of components, materials, equipment and other needed commodities and these inflationary increases may continue in the FERC werefuture. While inflation in the United States has been relatively low in recent years, during 2021, the economy in the United States encountered a material level of inflation. The impact of COVID-19 continues to lowerincrease uncertainty in the rateoutlook of return it has authorized for AEP’s transmission investmentsnear-term economic activity, including whether inflation will continue and facilities, or if one or more states wereat what rate. AEP typically recovers increases in capital expenses from customers through rates in regulated jurisdictions. Failure to successfully limit FERC jurisdiction on recovery ofrecover increased capital costs on transmission investment and its return, it could reduce future net income and cash flows and negativelypossibly harm AEP’s financial condition. Increases in inflation raises costs for labor, materials and services, and failure to secure these on reasonable terms may adversely impact AEP’s financial condition.
Physical attacks or hostile cyber intrusions could severely impair operations, lead to the disclosure of confidentialinformation and damage AEP’s reputation.(Applies to all Registrants)
AEP and its regulated utility businesses face physical security and cybersecurity risks as the owner-operators of generation, transmission and/or distribution facilities and as participants in commodities trading. AEP and its regulated utility businesses own assets deemed as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run these facilities are not completely isolated from external networks. Parties that wish to disrupt the U.S. bulk power system or AEP operations could view these computer systems, software or networks as targets for cyber-attack. The Federal government has notified the owners and operators of critical infrastructure, such as AEP, that the conflict between Russia and Ukraine has increased the likelihood of a cyber-attack on such systems. In addition, the electric utility business requires the collection of sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss.
A security breach of AEP or its regulated utility businesses’ physical assets or information systems, interconnected entities in RTOs, or regulators could impact the operation of the generation fleet and/or reliability of the transmission and distribution system. AEP and its regulated utility businesses could be subject to financial harm associated with ransomware theft or inappropriate release of certain types of information, including sensitive customer, vendor, employee, trading or other confidential data. A successful cyber-attack on the systems that control generation, transmission, distribution or other assets could severely disrupt business operations, preventing service to customers or collection of revenues. The breach of certain business systems could affect the ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to AEP’s reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. AEP and its third-party vendors have been subject, and will likely continue to be subject, to attempts to gain unauthorized access to their technology systems and confidential data or to attempts to disrupt utility and related business operations. While there have been immaterial incidents of phishing, unauthorized access to technology systems, financial fraud, and disruption of remote access across the AEP System, there has been no material impact on business or operations from these attacks. However, AEP cannot guarantee that security efforts will detect or prevent breaches, operational incidents, or other breakdowns of technology systems and network infrastructure and cannot provide any assurance that such incidents will not have a material adverse effect in the future.
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 SeptemberJune 30, 2017.2022.
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: |
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AEP TEXAS‡ File No. 333-221643 | | |
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4 | | Company Order and Officer’s Certificate between AEP Texas Inc. and The Bank of New York Mellon Trust Company, N.A. as Trustee dated May 18, 2022 establishing terms of the 4.70% Senior Notes, Series K, due 2032 and the 5.25% Senior Notes, Series L, due 2052. | | |
AEPTCo‡ File No. 333-217143 | | |
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4 | | Company Order and Officer’s Certificate between AEP Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A. as Trustee dated June 9, 2022 establishing terms of the 4.50% Senior Notes, Series O, due 2052. | | |
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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 | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
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Exhibit | | Description | | AEP | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
1231(a) | | Computation of Consolidated Ratio of Earnings to Fixed Charges | | | | | | | | | | | | | | |
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.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
July 27, 2022