AMERICAN ELECTRIC POWER COMPANY, INC. EXECUTIVE OVERVIEW
COVID-19
InMarch 2020 , COVID-19 was declared a pandemic by theWorld Health Organization and theCenters for Disease Control and Prevention . Its rapid spread around the world and throughoutthe United States prompted many countries, includingthe United States , to institute restrictions on travel, public gatherings and certain business operations. These restrictions significantly disrupted economic activity in AEP's service territory and could reduce future demand for energy, particularly from commercial and industrial customers. Although AEP cannot predict the severity or duration of the impact of the COVID-19 pandemic, AEP currently anticipates a 3.4% reduction in weather-normalized retail sales volume in 2020 as compared to the prior year. During the first half of 2020, AEP experienced a reduction in weather-normalized retail sales volume of 3.1% as compared to the first half of 2019 primarily driven by a 6.6% decrease in the industrial customer class and a 5.0% decrease in the commercial customer class offset by an increase in demand of 1.9% from the residential customer class. The reduction in weather-normalized retail sales volume of 3.1% did not result in a significant decrease in the corresponding retail margins for the six months ended 2020 as the increase in higher margin residential sales volumes partially offset the decreases in the industrial and commercial sales volumes. Furthermore, the rate design for certain industrial customers includes demand provisions designed to cover the fixed portion of utility costs minimizing the impact of the fluctuations in usage on revenues. AEP's load forecast is highly dependent on many factors including, but not limited to, the extent and duration of the stay at home restrictions, the speed and strength of economic recovery and the extent and duration of the second wave of COVID-19 infection. If the severity of the economic disruption increases, AEP's future results of operations, financial condition, and cash flows could be further adversely impacted. See Customer Demand for additional information. During the first quarter of 2020, AEP's electric operating companies informed both retail customers and state regulators that disconnections for non-payment were temporarily suspended. Disconnections were reinstated inJuly 2020 inMichigan andOklahoma . Disconnections are anticipated to be reinstated starting in August or September of 2020 inTennessee ,Texas (applies to SWEPCo jurisdiction only),Louisiana ,Virginia , WestVirginia, Ohio , andIndiana . Current continuing adverse economic conditions may result in the inability of customers to pay for electric service, which could affect revenue recognition and the collectability of accounts receivable. During the second quarter of 2020, the Registrants reviewed current collections experience with historical trends, specifically reviewing metrics such as customer receivables and cash collections, days sales outstanding, daily customer deposits, and aging summaries. In addition, the Registrants reviewed historical loss information generally comprised of a rolling 12-month average, in conjunction with a qualitative assessment of elements that impact the collectability of receivables, such as changes in economic factors, regulatory matters, industry trends, customer credit factors, payment options and programs available to customers. Based on this review, AEP's accounts receivable aging was negatively impacted primarily due to the suspension of the customer disconnects. AEP currently does not expect the deterioration in aging to have a material adverse impact on the Registrants' allowance for uncollectible accounts based on considerations of the recent impacts of COVID-19 and past trends during times of economic instability. Management will continue to monitor developments affecting suspensions of disconnections and its impact on customer collections. Further deterioration in AEP's ability to collect from its customers could significantly impact AEP's future results of operations, financial conditions, and cash flows. InMay 2020 , AEP Credit amended its receivables securitization agreement to increase the eligibility criteria related to aged receivable requirements for the participating affiliated utility subsidiaries in response to the COVID-19 pandemic. As ofJune 30, 2020 , the affiliated utility subsidiaries are in compliance with all requirements under the agreement. To the extent that an affiliated utility subsidiary is deemed ineligible under the agreement, receivables would no longer be purchased by the bank conduits and the Registrants would need to rely on additional sources of funding for operation and working capital, which may adversely impact liquidity. 1 -------------------------------------------------------------------------------- The Registrants have worked with their state commissions to achieve deferral authority for increased costs incurred due to COVID-19. The majority of these jurisdictions have provided deferral authority for incremental COVID-19 costs including uncollectible expense. Initial COVID-19 orders for deferrals have yet to be issued byKentucky andTennessee . If any costs related to COVID-19 are not recoverable, it could reduce future net income and cash flows and impact financial condition. The effects of the continued COVID-19 pandemic and related government responses could also include extended disruptions to supply chains, reduced labor availability, reduced dispatch for certain generation assets and a prolonged reduction in economic activity. These effects could have a variety of adverse impacts to the Registrants, including their ability to operate their facilities. As ofJune 30, 2020 , there were no material adverse impacts to the Registrants' operations and supplier contracts due to COVID-19. AEP will continue to monitor developments affecting facility operations and will take additional actions necessary in order to mitigate adverse impacts to the Registrants' future results of operations, financial condition, and cash flows.
In addition, the economic disruptions caused by COVID-19 could also adversely
impact the impairment risks for certain long-lived assets, equity method
investments and goodwill. AEP evaluated these impairment considerations and
determined that no such impairments occurred as of
Market volatility and reduction in collections coupled with longer collection periods due to the expansion of customer payment arrangements could reduce cash from operations and cause an adverse impact to liquidity. During the first six months of 2020, AEP increased its liquidity position to mitigate the market and the collections risk due to COVID-19. The Registrants' access to funding was limited for a period of time during the first quarter and therefore AEP entered into a$1 billion 364-day term loan to reduce reliance on commercial paper and help mitigate potential future liquidity risks. In addition, for the first six months of 2020, AEP issued approximately$2.4 billion in long-term debt. As ofJune 30, 2020 , AEP's available liquidity is$2.9 billion . Management believes the Registrants have adequate liquidity under existing credit facilities. In the first quarter of 2020, AEP shifted capital expenditures of$500 million out of 2020 into future periods to further mitigate adverse liquidity impacts. In the second quarter of 2020, AEP reinstated$100 million of capital expenditures back into 2020. To the extent that future access to the capital markets or the cost of funding is adversely affected by COVID-19, future results of operations, financial condition, and cash flows may be adversely impacted. InMarch 2020 ,President Trump signed into law legislation referred to as the "Coronavirus Aid, Relief, and Economic Security Act" (the CARES Act). The CARES Act includes tax relief provisions such as: (a) an Alternative Minimum Tax (AMT) Credit Refund, (b) a 5-year net operating losses (NOL) carryback from years 2018-2020 and (c) delayed payment of employer payroll taxes. InMay 2020 , the House passed the "Health and Economic Recovery Omnibus Emergency Solutions Act" (the HEROES Act) pending decision by theSenate . If enacted, the HEROES Act would disallow NOL carrybacks to any tax year beginning beforeJanuary 1, 2018 . As ofJune 30, 2020 , AEP has a$20 million AMT credit refund recognized in anticipation of a refund from theU.S. Treasury . Management is evaluating the ability to recover taxes paid in 2014 under the 5-year NOL carryback provision. The Registrants currently expect to defer payments of the employer share of payroll taxes for the periodMarch 27, 2020 throughDecember 31, 2020 and pay 50% of the obligation byDecember 31, 2021 and the remaining 50% byDecember 31, 2022 . The Registrants are taking steps to mitigate the potential risks to customers, suppliers and employees posed by the spread of COVID-19. The Registrants have updated and implemented a company-wide pandemic plan to address specific aspects of COVID-19. This plan guides emergency response, business continuity, and the precautionary measures AEP is taking on behalf of its employees and the public. The Registrants have taken extra precautions for employeeswho work in the field and for employeeswho work in their facilities, and have implemented work from home policies where appropriate. The Registrants will continue to monitor developments affecting both their workforce and customers, and will take additional precautions that management determines are necessary in order to mitigate the impacts. AEP continues to focus on providing safe, uninterrupted service to its customers, which includes the implementation of strong physical and cyber-security measures to ensure that its systems remain functional with a partially remote workforce. As ofJune 30, 2020 , there has been no material adverse impact to the Registrants' business operations and customer service due to remote work. Management will continue to review 2 -------------------------------------------------------------------------------- and modify plans as conditions change. Despite efforts to manage these impacts to the Registrants, the ultimate impact of COVID-19 also depends on factors beyond management's knowledge or control, including the duration and severity of this outbreak as well as third-party actions taken to contain its spread and mitigate its public health effects. Therefore, management cannot estimate the potential future impact to financial position, results of operations and cash flows, but the impacts could be material.
Customer Demand
AEP's weather-normalized retail sales volumes for the second quarter of 2020 decreased by 5.9% from the second quarter of 2019. Weather-normalized residential sales increased by 6.2% in the second quarter of 2020 from the second quarter of 2019. AEP's second quarter 2020 industrial sales volumes decreased by 12.4% compared to the second quarter of 2019. The decline in industrial sales was spread across many industries. Weather-normalized commercial sales decreased 10.1% in the second quarter of 2020 from the second quarter of 2019. AEP's weather-normalized retail sales volumes for the six months endedJune 30, 2020 decreased by 3.1% compared to the six months endedJune 30, 2019 . Weather-normalized residential sales increased by 1.9% for the six months endedJune 30, 2020 compared to the six months endedJune 30, 2019 . AEP's industrial sales volumes for the six months endedJune 30, 2020 decreased 6.6% compared to the six months endedJune 30, 2019 . The decline in industrial sales was spread across many industries. Weather-normalized commercial sales decreased 5% for the six months endedJune 30, 2020 compared to the six months endedJune 30, 2019 . As a result of the impact of COVID-19, AEP revised its forecast for 2020 weather-normalized retail sales volumes inApril 2020 from the forecast presented in the 2019 10-K. In 2020, AEP currently anticipates weather-normalized retail sales volumes will decrease by 3.4%. AEP expects industrial class sales volumes to decrease by 8% in 2020, while weather-normalized residential sales volumes are projected to increase by 3%. Finally, AEP currently projects weather-normalized commercial sales volumes to decrease by 5.6%. [[Image Removed: aep-20200630_g1.jpg]] (a)Percentage change for the year endedDecember 31, 2019 as compared to the year endedDecember 31, 2018 . (b)As presented in the 2019 AEP 10-K: Forecasted percentage change for the year endedDecember 31, 2020 compared to the year endedDecember 31, 2019 . (c)Revised for the impact of COVID-19: Forecasted percentage change for the year endedDecember 31, 2020 compared to the year endedDecember 31, 2019 . 3 --------------------------------------------------------------------------------
Regulatory Matters AEP's public utility subsidiaries are involved in rate and regulatory proceedings at theFERC and their state commissions. Depending on the outcomes, these rate and regulatory proceedings can have a material impact on results of operations, cash flows and possibly financial condition. AEP is currently involved in the following key proceedings. See Note 4 - Rate Matters for additional information. •2017-2019 Virginia Triennial Review - InMarch 2020 , APCo submitted its 2017-2019Virginia triennial earnings review filing and base rate case with the Virginia SCC as required by state law. APCo requested a$65 million annual increase in base rates based upon a proposed 9.9% ROE. Triennial reviews are subject to an earnings test, which provides that 70% of any earnings in excess of 70 basis points above APCo's Virginia SCC authorized ROE would be refunded to customers. In such case, the Virginia SCC could also lower APCo'sVirginia retail base rates on a prospective basis.Virginia law provides that costs associated with asset impairments of retired coal generation assets, or automated meters, or both, which a utility records as an expense, shall be attributed to the test periods under review in a triennial review proceeding, and be deemed recovered. In 2015, APCo retired the Sporn Plant, theKanawha River Plant , the Glen Lyn Plant, Clinch River Unit 3 and the coal portions of Clinch River Units 1 and 2 (collectively, the retired coal-fired generation assets). The net book value of these plants at the retirement date was$93 million before cost of removal, including materials and supplies inventory and ARO balances. Based on management's interpretation ofVirginia law and more certainty regarding APCo's triennial revenues, expenses and resulting earnings upon reaching the end of the three-year review period, APCo recorded a pretax expense of$93 million related to its previously retired coal-fired generation assets inDecember 2019 . As a result, management deems these costs to be substantially recovered by APCo during the triennial review period. Inclusive of the$93 million expense associated with APCo'sVirginia jurisdictional retired coal-fired generation assets, APCo calculated itsVirginia earnings for the triennial period to be below the authorized ROE range. InJuly 2020 , a certain intervenor filed testimony asserting that APCo had a revenue surplus of$23 million for its filed rate year based upon the intervenor's recommended ROE of 8.75%. In addition, this intervenor contends APCo's earned return for the Triennial period was 11.12%, which equates to$59 million in earnings (subject to 70% refund provision described above) above the top of the ROE range on a revenue basis. This intervenor also filed a separate legal memorandum opposing the inclusion of the 2019 expensing of the retired coal-fired generation assets from APCo's 2017-2019 earnings test results. See "2017-2019 Virginia Triennial Review" section of Note 4 for a full listing of proposed adjustments and disallowances by intervenors. •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. InJuly 2018 , theTexas Third Court of Appeals reversed the PUCT's judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. InJanuary 2019 , SWEPCo and the PUCT filed petitions for review with theTexas Supreme Court . In the fourth quarter of 2019 and first quarter of 2020, SWEPCo and various intervenors filed briefs with theTexas Supreme Court . As ofJune 30, 2020 , the net book value of Turk Plant was$1.4 billion , before cost of removal, including materials and supplies inventory and CWIP. SWEPCo'sTexas jurisdictional share of the Turk Plant investment is approximately 33%. •InJuly 2019 , clean energy legislation (HB 6) which offers incentives for power-generating facilities with zero or reduced carbon emissions was signed into law by theOhio Governor. HB 6 phased out current energy efficiency including lost shared savings revenues of$26 million annually and renewable mandates no later than 2020 and after 2026, respectively. HB 6 also provided for the recovery of existing renewable energy contracts on a bypassable basis through 2032 and included a provision for recovery of OVEC costs through 2030 which will be allocated to all electric distribution utilities on a non-bypassable basis. OPCo's Inter-Company Power Agreement for OVEC terminates inJune 2040 . InJuly 2020 , an investigation led by theU.S. Attorney's Office resulted in a federal grand jury indictment of the Speaker of theOhio House of Representatives ,Larry Householder , four other individuals, and Generation Now, an entity registered as a 4 -------------------------------------------------------------------------------- 501(c)(4) social welfare organization, in connection with a racketeering conspiracy involving the adoption of HB 6. In light of the allegations in the indictment, proposed legislation has been introduced that would repeal HB 6. The outcome of theU.S. Attorney's Office investigation and its impact on HB 6 is not known. If the provisions of HB 6 were to be eliminated, it is unclear whether and in what form theOhio General Assembly would pass new legislation addressing similar issues. Management is currently unable to predict the outcome of the proposed legislation and will continue to monitor the legislative process. To the extent that OPCo is unable to recover the costs of renewable energy contracts on a bypassable basis by the end of 2032, recover costs of OVEC after 2030 or fully recover energy efficiency costs through 2020 it could reduce future net income and cash flows and impact financial condition. •InApril 2020 , the Virginia Clean Economy Act was signed into law by theVirginia Governor and became effective inJuly 2020 . The law includes the following requirements: (a)Virginia electric utilities to retire no later than 2045 all electric generating units located inVirginia that emit carbon as a by-product, (b) APCo to produce 100% of the company's power to serveVirginia customers from renewable sources by 2050 with increasing percentages of mandatory renewable energy sources each year and (c)Virginia electric utilities to achieve increasing annual energy efficiency savings from 2022-2025 using 2019 as the base year. This law also provides that if the Virginia SCC finds in any triennial review that revenue reductions related to energy efficiency programs approved and deployed since the utility's previous triennial review have caused the utility to earn more than 70 basis points below its authorized rate of return, the Virginia SCC shall order increases to the utility's rates necessary to recover such revenue reductions. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
Utility Rates and Rate Proceedings
The Registrants file rate cases with their regulatory commissions in order to establish fair and appropriate electric service rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Registrants' current and future results of operations, cash flows and financial position.
The following tables show the Registrants' completed and pending base rate case proceedings in 2020. See Note 4 - Rate Matters for additional information.
Completed Base Rate Case Proceedings
Approved Revenue Approved New Rates
Company Jurisdiction Requirement Increase (Decrease) ROE Effective
(in millions)
I&M Michigan $ 36.4 (a) 9.86% February 2020
I&M Indiana 77.4 (b) 9.7% March 2020
AEP Texas Texas (40.0) 9.4% June 2020
(a)In January 2020 , the MPSC issued an order approving a stipulation and
settlement agreement. See "2019 Michigan Base Rate Case" section of Note 4 Rate
Matters in the 2019 Annual Report for additional information.
(b)This increase will be phased in through January 2021 with an approximate $44
million annual increase in base rates effective March 2020 and the full $77
million annual increase effective January 2021 . The order rejected I&M's
proposed re-allocation of capacity costs related to the loss of a significant
FERC wholesale contract, which will negatively impact I&M's annual pretax
earnings by approximately $20 million starting June 2020 .
5
--------------------------------------------------------------------------------Pending Base Rate Case Proceedings
Commission Staff/
Filing Requested Revenue Requested Intervenor Range of
Company Jurisdiction Date Requirement Increase ROE Recommended ROE
(in millions)
APCo Virginia March 2020 $ 64.9 9.9% 8.75% (a)
OPCo Ohio June 2020 42.3 10.15% (b)
KPCo Kentucky June 2020 65.0 10% (c)
(a)In July 2020 , Intervenor testimony was filed. Testimony from Virginia Staff
must be filed by mid-August 2020 .
(b)In June 2020 , OPCo filed a request with the PUCO for a 60-day temporary delay
of the normal rate case proceeding due to the COVID-19 pandemic.
(c)Commission Staff/Intervenor direct testimony to be filed by October 2020 .
Renewable Generation
The growth of AEP's renewable generation portfolio reflects the company's strategy to diversify generation resources to provide clean energy options to customers that meet both their energy and capacity needs.
Contracted Renewable Generation Facilities
AEP continues to develop its renewable portfolio within the Generation & Marketing segment. Activities include working directly with wholesale and large retail customers to provide tailored solutions based upon market knowledge, technology innovations and deal structuring which may include distributed solar, wind, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other forms of cost reducing energy technologies. The Generation & Marketing segment also develops and/or acquires large scale renewable generation projects that are backed with long-term contracts with creditworthy counterparties. As ofJune 30, 2020 , subsidiaries within AEP's Generation & Marketing segment had approximately 1,423 MWs of contracted renewable generation projects in-service. In addition, as ofJune 30, 2020 , these subsidiaries had approximately 160 MWs of renewable generation projects under construction with total estimated capital costs of$235 million related to these projects.
Regulated Renewable Generation Facilities
InJuly 2019 , PSO and SWEPCo submitted filings before their respective commissions for the approval to acquire the North Central Wind Energy Facilities, comprised of threeOklahoma wind facilities totaling 1,485 MWs, on a fixed cost turn-key basis at completion. PSO will own 45.5% and SWEPCo will own 54.5% of the project, which will cost approximately$2 billion . Under priorIRS guidance establishing the "Continuity Safe Harbor" for purposes of the federal PTC, two wind facilities, totaling 1,286 MWs, would have qualified for 80% of the federal PTC with year-end 2021 in-service dates and the third wind facility (199 MWs) would have qualified for 100% of the PTC with a year-end 2020 in-service date. InMay 2020 , theIRS issued a notice extending the "Continuity Safe Harbor" deadlines for qualifying renewable energy projects that began construction in 2016 and 2017 by one year as many projects are facing supply chain and other project development delays borne by COVID-19. Under theMay 2020 IRS notice, qualifying renewable energy projects that began construction in 2016 and 2017 and which are placed in-service by the end of 2021 and 2022, respectively, will satisfy the Continuous Efforts Safe Harbor. As a result of this change by theIRS , the three North Central Wind Energy Facilities projects each have an additional year to achieve commercial operations under the "Continuity Safe Harbor," should there be a delay in the development of the projects. 6 -------------------------------------------------------------------------------- InFebruary 2020 , the OCC approved PSO's settlement agreement. InMay 2020 , the APSC approved the settlement agreement as filed, with the exception that SWEPCo use its formula rate rider to recover its costs rather than the requested rider. Also inMay 2020 , the LPSC approved the settlement agreement as filed. Both the APSC and LPSC approved the flex-up option, agreeing to acquire theTexas portion, which the PUCT denied inJuly 2020 . With having regulatory approval and theIRS extension of the "Continuity Safe Harbor," PSO and SWEPCo are proceeding with the full 1,485MW development of these three projects.
Hydroelectric Generation
Evaluating Sale of Hydroelectric Generation
InMarch 2020 , management placed 10 hydroelectric generation plants under study for a potential sale. InApril 2020 , the Virginia Clean Economy Act was signed into law by theVirginia Governor. The new law will provide renewable credits to APCo for its existing hydroelectric generation plants. As a result of the new law, management removed the three APCo hydroelectric generation plants (London ,Marmet andWinfield ) from the list of plants identified for potential sale. The table below shows the net book value of each plant, including CWIP and materials and supplies, before cost of removal of the remaining plants included in the study. Net Book Value as of June Net Maximum Year Plant or First Owner Plant Name Units State 30, 2020 Capacity (MWs) Unit Commissioned (in millions) AGR Racine 2 OH $ 57.9 48 1982 I&M Berrien Springs 12 MI 7.7 6 1908 I&M Buchanan 10 MI 5.0 3 1919 I&M Constantine 4 MI 2.6 1 1921 I&M Elkhart 3 IN 5.5 3 1913 I&M Mottville 4 MI 2.8 2 1923 I&M Twin Branch Hydro 8 IN 7.0 5 1904 Total $ 88.5 68 If management decides to proceed with the sale of these plants,FERC approval would be required. In addition, for all plants, except forRacine , state commission approval would be required. Management currently estimates that any potential sale of these plants would not be completed until late 2020 at the earliest. There is no assurance that management will be able to sell any of these plants.
During the second quarter of 2019, theDolet Hills Power Station initiated a seasonal operating schedule. InJanuary 2020 , in accordance with the terms of SWEPCo's settlement of its base rate review filed with the APSC, management announced that SWEPCo will seek regulatory approval to retire theDolet Hills Power Station by the end of 2026. DHLC provides 100% of the fuel supply toDolet Hills Power Station . After careful consideration of current economic conditions, and particularly for the benefit of their customers, management of SWEPCo and CLECO determined DHLC would not proceed developing additionalOxbow Lignite Company (Oxbow) mining areas for future lignite extraction and ceased extraction of lignite at the mine inMay 2020 . Based on these actions, management revised the estimated useful life of DHLC's and Oxbow's assets to coincide with the date at which extraction was discontinued and the date at which delivery of lignite is expected to cease inSeptember 2021 . Management also revised the useful life of theDolet Hills Power Station toSeptember 2021 based on the remaining estimated fuel supply available for continued seasonal operation. InMarch 2020 , primarily due to the revision in the useful life of DHLC, SWEPCo recorded a revision to increase estimated ARO liabilities by$21 million . InApril 2020 , SWEPCo and CLECO jointly filed a notification letter to the LPSC providing notice of the cessation of lignite mining. 7 --------------------------------------------------------------------------------
Fuel costs incurred by theDolet Hills Power Station are recoverable by SWEPCo through active fuel clauses. Under the Lignite Mining Agreement, DHLC bills SWEPCo its proportionate share of incurred lignite extraction and associated mining-related costs as fuel is delivered. As ofJune 30, 2020 , DHLC has unbilled lignite inventory and fixed costs of$94 million that will be billed to SWEPCo prior to the closure of theDolet Hills Power Station . In 2009, SWEPCo acquired interests in Oxbow, which owns mineral rights and leases land. Under a Joint Operating Agreement pertaining to the Oxbow mineral rights and land leases, Oxbow bills SWEPCo its proportionate share of incurred costs. As ofJune 30, 2020 , Oxbow has unbilled fixed costs of$11 million that will be billed to SWEPCo prior to the closure of theDolet Hills Power Station . DHLC and Oxbow have billed SWEPCo$49 million for lignite deliveries fromApril 2020 throughJune 2020 , which primarily includes accelerated depreciation and amortization of fixed costs. Additional operational and land-related costs are expected to be incurred by DHLC and Oxbow and billed to SWEPCo prior to the closure of theDolet Hills Power Station and recovered through fuel clauses.
If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
FERC Transmission ROE Methodology
InNovember 2019 , theFERC issued Opinion No. 569, which adopted a revised methodology for determining whether an existing base ROE is just and reasonable under Federal Power Act and determined the base ROE for MISO's transmission-owning members should be reduced from 12.38% to 9.88%. InMay 2020 ,FERC issued Opinion 569-A, granting rehearing on several issues. Opinion 569, as modified by Opinion 569-A, results in a revised ROE methodology that relies on three financial models. The financial models used to establish a composite zone of reasonableness are the: (a) discounted cash flow model, (b) capital asset pricing model and (c) risk premium model. Order 569-A determined the base ROE for MISO's transmission-owning members should be 10.02% (10.52% inclusive of the RTO incentive adder of 0.5%). Management believes FERC Opinion Nos. 569 and 569-A change the expectation of a four-model framework proposed byFERC in 2018 and vetted widely inFERC 2019 Notice of Inquiry regarding base ROE policy. Management does not believe this ruling will have a material impact on financial results for its MISO transmission owning subsidiaries. In the second quarter of 2019,FERC approved settlement agreements establishing base ROEs of 9.85% (10.35% inclusive of RTO incentive adder of 0.5%) and 10% (10.5% inclusive of RTO incentive adder of 0.5%) for AEP's PJM and SPP transmission-owning subsidiaries, respectively. InMarch 2020 , as a follow-up to its 2019 Notice of Inquiry regarding transmission incentives policy,FERC issued a Notice of Proposed Rulemaking and requested comments byJuly 2020 . AEP has filed comments and will monitor this proceeding.
If
AFUDC Waiver
InJune 2020 ,FERC granted a temporary waiver providing utilities the option to elect to modify the existing AFUDC rate calculations in response to the COVID-19 pandemic. As a result of the waiver, the AFUDC formula for the 12-month period starting withMarch 2020 may be calculated using the simple average of the actual historical short-term debt balances for 2019, instead of current period short-term balances. All other aspects of the AFUDC formula remained unchanged. AEP subsidiaries including certain Registrant Subsidiaries elected to apply the waiver inJuly 2020 . The impact of the waiver is immaterial on the Registrants' financial statements for the three and six months endedJune 30, 2020 . 8 --------------------------------------------------------------------------------
LITIGATION In the ordinary course of business, AEP is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases that have a probable likelihood of loss if the loss can be estimated. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition. See Note 4 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies for additional information.
Rockport Plant Litigation
In 2013, theWilmington Trust Company filed a complaint in theU.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it would be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration inDecember 2022 . The terms of the consent decree allow the installation of environmental emission control equipment, repowering, refueling or retirement of the unit. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. TheNew York court granted a motion to transfer this case to theU.S. District Court for the Southern District of Ohio . AEGCo and I&M sought and were granted dismissal by theU.S. District Court for the Southern District of Ohio of certain of the plaintiffs' claims, including claims for compensatory damages, breach of contract, breach of the implied covenant of good faith and fair dealing and indemnification of costs. Plaintiffs voluntarily dismissed the surviving claims that AEGCo and I&M failed to exercise prudent utility practices with prejudice, and the court issued a final judgment. The plaintiffs subsequently filed an appeal in theU.S. Court of Appeals for the Sixth Circuit . In 2017, theU.S. Court of Appeals for the Sixth Circuit issued an opinion and judgment affirming the district court's dismissal of the owners' breach of good faith and fair dealing claim as duplicative of the breach of contract claims, reversing the district court's dismissal of the breach of contract claims and remanding the case for further proceedings. Thereafter, AEP filed a motion with theU.S. District Court for the Southern District of Ohio in the original NSR litigation, seeking to modify the consent decree. The district court granted the owners' unopposed motion to stay the lease litigation to afford time for resolution of AEP's motion to modify the consent decree. The consent decree was modified based on an agreement among the parties inJuly 2019 . The district court's stay expired inFebruary 2020 , but the court later extended the stay throughAugust 13, 2020 . See "Modification of the NSR Litigation Consent Decree" section below for additional information. Management 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, management cannot determine a range of potential losses that is reasonably possible of occurring.
Patent Infringement Complaint
InJuly 2019 , Midwest Energy Emissions Corporation andMES Inc. (collectively, the plaintiffs) filed a patent infringement complaint against various parties, includingAEP Texas , AGR,Cardinal Operating Company and SWEPCo (collectively, the AEP Defendants). The complaint alleges that the AEP Defendants infringed two patents owned by the plaintiffs by using specific processes for mercury control at certain coal-fired generating stations. The complaint seeks injunctive relief and damages. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring. 9 --------------------------------------------------------------------------------
Claims Challenging Transition of American Electric Power System Retirement Plan to Cash Balance Formula
The American Electric Power System Retirement Plan (the Plan) has received a letter written on behalf of four participants (the Claimants) making a claim for additional plan benefits and purporting to advance such claims on behalf of a class. When the Plan's benefit formula was changed in the year 2000, AEP provided a special provision for employees hired beforeJanuary 1, 2001 , allowing them to continue benefit accruals under the then benefit formula for a full 10 years alongside of the new cash balance benefit formula then being implemented. Employeeswho were hired on or afterJanuary 1, 2001 accrued benefits only under the new cash balance benefit formula. The Claimants have asserted claims 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 (ADEA); and (c) the company failed to provide required notice regarding the changes to the Plan. AEP has responded to the Claimants providing a reasoned explanation for why each of their claims have been denied. The denial of those claims was appealed to the AEP System Retirement Plan Appeal Committee and the Committee upheld the denial of claims. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring.
ENVIRONMENTAL ISSUES
AEP has a substantial capital investment program and incurs additional operational costs to comply with environmental control requirements. Additional investments and operational changes will be made in response to existing and anticipated requirements to reduce emissions from fossil generation and in response to rules governing the beneficial use and disposal of coal combustion by-products, clean water and renewal permits for certain water discharges. AEP is engaged in litigation about environmental issues, was notified of potential responsibility for the clean-up of contaminated sites and incurred costs for disposal of SNF and future decommissioning of the nuclear units. AEP, along with other parties, challenged some of the FederalEPA requirements. Management is engaged in the development of possible future requirements including the items discussed below. Management believes that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals. AEP will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances. If AEP cannot recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.
Environmental Controls Impact on the Generating Fleet
The rules and proposed environmental controls discussed below will have a material impact on AEP System generating units. Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance. As ofJune 30, 2020 , the AEP System had generating capacity of approximately 24,700 MWs, of which approximately 12,600 MWs were coal-fired. Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on fossil generation. Based upon management estimates, AEP's future investment to meet these existing and proposed requirements ranges from approximately$500 million to$1 billion through 2026. The cost estimates will change depending on the timing of implementation and whether the FederalEPA provides flexibility in finalizing proposed rules or revising certain existing requirements. The cost estimates will also change based on: (a) potential state rules that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) actual performance of the pollution control technologies installed, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors. In addition, management continues to evaluate the economic feasibility of environmental investments on regulated and competitive plants. 10 --------------------------------------------------------------------------------
Modification of the New Source Review Litigation Consent Decree
In 2007, theU.S. District Court for the Southern District of Ohio approved a consent decree between AEP subsidiaries in the eastern area of the AEP System and theDepartment of Justice , the FederalEPA , eight northeastern states and other interested parties to settle claims that the AEP subsidiaries violated the NSR provisions of the CAA when they undertook various equipment repair and replacement projects over a period of nearly 20 years. The consent decree's terms include installation of environmental control equipment on certain generating units, a declining cap on SO2 and NOx emissions from the AEP System and various mitigation projects. In 2017, AEP filed a motion with the district court seeking to modify the consent decree to eliminate an obligation to install future controls atRockport Plant, Unit 2 if AEP does not acquire ownership of that unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. The other parties to the consent decree opposed AEP's motion. The district court granted AEP's request to delay the deadline to install Selective Catalytic Reduction (SCR) technology at Rockport Plant, Unit 2 untilJune 2020 . Construction of the SCR technology was completed byJune 1, 2020 , testing was conducted, and the unit was released for dispatch onJune 5, 2020 . InMay 2019 , the parties filed a proposed order to modify the consent decree. The proposed order requires AEP to enhance the dry sorbent injection (DSI) system on both units at the Rockport Plant by the end of 2020, and meet 30-day rolling average emission rates for SO2 and NOx at the combined stack for the Rockport Plant beginning in 2021. Total SO2 emissions from the Rockport Plant are limited to 10,000 tons per year beginning in 2021 and reduce to 5,000 tons per year when Rockport Plant, Unit 1 retires in 2028. The proposed modification was approved by the district court and became effective inJuly 2019 . As part of the modification to the consent decree, I&M agreed to provide an additional$7.5 million to citizens' groups and the states for environmental mitigation projects. As joint owners in the Rockport Plant, the$7.5 million payment was shared between AEGCo and I&M based on the joint ownership agreement.
The CAA establishes a comprehensive program to protect and improve the nation's air quality and control sources of air emissions. The states implement and administer many of these programs and could impose additional or more stringent requirements. The primary regulatory programs that continue to drive investments in AEP's existing generating units include: (a) periodic revisions to NAAQS and the development of SIPs to achieve any more stringent standards, (b) implementation of the regional haze program by the states and the FederalEPA , (c) regulation of hazardous air pollutant emissions under MATS, (d) implementation and review of CSAPR and (e) the FederalEPA 's regulation of greenhouse gas emissions from fossil generation under Section 111 of the CAA. Notable developments in significant CAA regulatory requirements affecting AEP's operations are discussed in the following sections.
National Ambient Air Quality Standards
The FederalEPA issued new, more stringent NAAQS for PM in 2012 and ozone in 2015. The FederalEPA is currently reviewing both of these standards. A proposed rule to retain the existing PM standards was released inApril 2020 . The existing standards for NO2 and SO2 were retained after review by the FederalEPA in 2018 and 2019, respectively. Implementation of these standards is underway. The FederalEPA finalized non-attainment designations for the 2015 ozone standard in 2018. The FederalEPA confirmed that for states included in the CSAPR program, there are no additional interstate transport obligations, as all areas of the country are expected to attain the 2008 ozone standard before 2023. Challenges to the 2015 ozone standard and the FederalEPA 's determination that CSAPR satisfies certain states' interstate transport obligations were filed in theU.S. Court of Appeals for the District of Columbia Circuit . InAugust 2019 , the court upheld the 2015 primary ozone standard, but remanded the secondary welfare-based standard for further review. The court 11 -------------------------------------------------------------------------------- vacated the FederalEPA 's determination that CSAPR fulfilled the states' interstate transport obligations, because the FederalEPA 's modeling analysis did not demonstrate that all significant contributions would be eliminated by the attainment deadlines for downwind states. Any further changes will require additional rulemaking. Management cannot currently predict the nature, stringency or timing of additional requirements for AEP's facilities based on the outcome of these activities.
Regional Haze
The FederalEPA issued aClean Air Visibility Rule (CAVR), detailing how the CAA's requirement that certain facilities install best available retrofit technology (BART) would address regional haze in federal parks and other protected areas. BART requirements apply to certain power plants. CAVR will be implemented through SIPs or FIPs. In 2017, the FederalEPA revised the rules governing submission of SIPs to implement the visibility programs, including a provision that postpones the due date for the next comprehensive SIP revisions until 2021. Petitions for review of the final rule revisions have been filed in theU.S. Court of Appeals for the District of Columbia Circuit . The FederalEPA initially disapproved portions of theArkansas regional haze SIP, but has approved a revised SIP and all of SWEPCo's affected units are in compliance with the relevant requirements. The FederalEPA also disapproved portions of theTexas regional haze SIP. In 2017, the FederalEPA finalized a FIP that allows participation in the CSAPR ozone season program to satisfy the NOx regional haze obligations for electric generating units inTexas . Additionally, the FederalEPA finalized an intrastate SO2 emissions trading program based on CSAPR allowance allocations. A challenge to the FIP was filed in theU.S. Court of Appeals for the Fifth Circuit and the case is pending the FederalEPA 's reconsideration of the final rule. InAugust 2018 , the FederalEPA proposed to affirm its 2017 FIP approval. InNovember 2019 , in response to comment, the FederalEPA proposed revisions to the intrastate trading program. The FederalEPA finalized the intrastate trading program inJuly 2020 . Management supports the intrastate trading program as a compliance alternative to source-specific controls.
Cross-State Air Pollution Rule
In 2011, the FederalEPA issued CSAPR as a replacement for theClean Air Interstate Rule , a regional trading program designed to address interstate transport of emissions that contributed significantly to downwind non-attainment with the 1997 ozone and PM NAAQS. CSAPR relies on SO2 and NOx allowances and individual state budgets to compel further emission reductions from electric utility generating units. Interstate trading of allowances is allowed on a restricted sub-regional basis. Petitions to review the CSAPR were filed in theU.S. Court of Appeals for the District of Columbia Circuit . In 2015, the court found that the FederalEPA over-controlled the SO2 and/or NOx budgets of 14 states. The court remanded the rule to the FederalEPA for revision consistent with the court's opinion while CSAPR remained in place. In 2016, the FederalEPA issued a final rule, the CSAPR Update, to address the remand and to incorporate additional changes necessary to address the 2008 ozone standard. The CSAPR Update significantly reduced ozone season budgets in many states and discounted the value of banked CSAPR ozone season allowances beginning with the 2017 ozone season. In 2019, the appeals court remanded the CSAPR Update to the FederalEPA because it determined the FederalEPA had not properly considered the attainment dates for downwind areas in establishing its partial remedy, and should have considered whether there were available measures to control emissions from sources other than generating units. Any further changes to the CSAPR rule will require additional rulemaking. 12 --------------------------------------------------------------------------------
Mercury and Other Hazardous Air Pollutants (HAPs) Regulation
In 2012, the FederalEPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants. The rule established unit-specific emission rates for units burning coal on a 30-day rolling average basis for mercury, PM (as a surrogate for particles of non-mercury metals) and hydrogen chloride (as a surrogate for acid gases). In addition, the rule proposed work practice standards for controlling emissions of organic HAPs and dioxin/furans, with compliance required within three years. Management obtained administrative extensions for up to one year at several units to facilitate the installation of controls or to avoid a serious reliability problem.
In 2014, the
In 2015, theU.S. Supreme Court reversed the decision of theU.S. Court of Appeals for the District of Columbia Circuit . The court remanded the MATS rule to the FederalEPA to consider costs in determining whether to regulate emissions of HAPs from power plants. In 2016, the FederalEPA issued a supplemental finding concluding that, after considering the costs of compliance, it was appropriate and necessary to regulate HAP emissions from coal and oil-fired units. Petitions for review of the FederalEPA 's determination were filed in theU.S. Court of Appeals for the District of Columbia Circuit . In 2018, the FederalEPA released a revised finding that the costs of reducing HAP emissions to the level in the current rule exceed the benefits of those HAP emission reductions. The FederalEPA also determined that there are no significant changes in control technologies and the remaining risks associated with HAP emissions do not justify any more stringent standards. Therefore, the FederalEPA proposed to retain the current MATS standards without change. InApril 2020 , the FederalEPA released a final rule adopting the conclusions set forth in the proposal and retaining the existing MATS standards.
Climate Change, CO2 Regulation and Energy Policy
In 2015, the FederalEPA published the final CO2 emissions standards for new, modified and reconstructed fossil generating units, and final guidelines for the development of state plans to regulate CO2 emissions from existing sources, known as the Clean Power Plan (CPP). In 2016, theU.S. Supreme Court issued a stay of the final CPP, including all of the deadlines for submission of initial or final state plans until a final decision is issued by theU.S. Court of Appeals for the District of Columbia Circuit and theU.S. Supreme Court considers any petition for review. In 2017, the President issued an Executive Order directing the FederalEPA to reconsider the CPP and the associated standards for new sources. The FederalEPA filed a motion to hold the challenges to the CPP in abeyance pending reconsideration. InSeptember 2019 , following the FederalEPA 's repeal of the CPP and promulgation of a replacement rule, theCourt of Appeals for the District of Columbia Circuit dismissed the challenges. InJuly 2019 , the FederalEPA finalized the Affordable Clean Energy (ACE) rule to replace the CPP with new emission guidelines for regulating CO2 from existing sources. ACE establishes a framework for states to adopt standards of performance for utility boilers based on heat rate improvements for such boilers. The final rule applies to generating units that commenced construction prior toJanuary 2014 , generate greater than 25 MWs, have a baseload rating above 250 MMBtu per hour and burn coal for more than 10% of the annual average heat input over the preceding three calendar years, with certain exceptions. States must establish standards of performance for each affected facility in terms of pounds of CO2 emitted per MWh, based on certain heat rate improvement measures and the degree of emission reduction achievable through each applicable measure, together with consideration of certain site-specific factors and the unit's remaining useful life. Information collection and rulemaking activities are underway in several states. State plans are required to be submitted in 2022, and the FederalEPA has up to two years to review and approve a plan or disapprove it and adopt a federal plan. The final ACE rule has been challenged in the courts. 13 -------------------------------------------------------------------------------- In 2018, the FederalEPA filed a proposed rule revising the standards for new sources and determined that partial carbon capture and storage is not the best system of emission reduction because it is not available throughout theU.S. and is not cost-effective. Management continues to actively monitor these rulemaking activities. AEP has taken action to reduce and offset CO2 emissions from its generating fleet. AEP expects CO2 emissions from its operations to continue to decline due to the retirement of some of its coal-fired generation units, and actions taken to diversify the generation fleet and increase energy efficiency where there is regulatory support for such activities. The majority of the states where AEP has generating facilities passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements that can assist in reducing carbon emissions. InApril 2020 ,Virginia enacted clean energy legislation to allow the state to participate in theRegional Greenhouse Gas Initiative, require the retirement of all fossil-fueled generation by 2045 and require 100% renewable energy to be provided toVirginia customers by 2050. Management is taking steps to comply with these requirements, including increasing wind and solar installations, purchasing renewable power and broadening AEP System's portfolio of energy efficiency programs. InSeptember 2019 , AEP announced new intermediate and long-term CO2 emission reduction goals, based on the output of the company's integrated resource plans, which take into account economics, customer demand, grid reliability and resiliency, regulations and the company's current business strategy. The intermediate goal is a 70% reduction from 2000 CO2 emission levels from AEP generating facilities by 2030; the long-term goal is to surpass an 80% reduction of CO2 emissions from AEP generating facilities from 2000 levels by 2050. AEP's total estimated CO2 emissions in 2019 were approximately 58 million metric tons, a 65% reduction from AEP's 2000 CO2 emissions. AEP has made significant progress in reducing CO2 emissions from its power generation fleet and expects its emissions to continue to decline. AEP's aspirational emissions goal is zero CO2 emissions by 2050. Technological advances, including energy storage, will determine how quickly AEP can achieve zero emissions while continuing to provide reliable, affordable power for customers. Federal and state legislation or regulations that mandate limits on the emission of CO2 could result in significant increases in capital expenditures and operating costs, which in turn, could lead to increased liquidity needs and higher financing costs. Excessive costs to comply with future legislation or regulations might force AEP to close some coal-fired facilities, which could possibly lead to impairment of assets.
Coal Combustion Residual (CCR) Rule
In 2015, the FederalEPA published a final rule to regulate the disposal and beneficial re-use of CCR, including fly ash and bottom ash created from coal-fired generating units and FGD gypsum generated at some coal-fired plants. The rule applies to active CCR landfills and surface impoundments at operating electric utility or independent generation facilities. The rule imposes construction and operating obligations, including location restrictions, liner criteria, structural integrity requirements for impoundments, operating criteria and additional groundwater monitoring requirements to be implemented on a schedule spanning an approximate four-year implementation period. In 2018, some of AEP's facilities were required to begin monitoring programs to determine if unacceptable groundwater impacts will trigger future corrective measures. Based on additional groundwater data, further studies to design and assess appropriate corrective measures have been undertaken at two facilities. In a challenge to the final 2015 rule, the parties initially agreed to settle some of the issues. In 2018, theU.S. Court of Appeals for the District of Columbia Circuit addressed or dismissed the remaining issues in its decision vacating and remanding certain provisions of the 2015 rule. The provisions addressed by the court's decision, including changes to the provisions for unlined impoundments and legacy sites, will be the subject of further rulemaking consistent with the court's decision. Prior to the court's decision, the FederalEPA issued theJuly 2018 rule that modifies certain compliance deadlines and other requirements in the 2015 rule. InDecember 2018 , challengers filed a motion for partial stay or vacatur of theJuly 2018 rule. On the same day, the FederalEPA filed a motion for partial remand of theJuly 2018 rule. The court granted the FederalEPA 's motion. InNovember 2019 , the FederalEPA proposed revisions to implement the 14 -------------------------------------------------------------------------------- court's decision regarding the timing for closure of unlined surface impoundments along with impoundments not meeting the required distance from an aquifer. The comment period closed inJanuary 2020 . InDecember 2019 , the FederalEPA proposed a federal permit program, implementing the Water Infrastructure Improvements for the Nation Act, that would apply in states that do not have an approved CCR program. Other utilities and industrial sources have been engaged in litigation with environmental advocacy groupswho claim that releases of contaminants from wells, CCR units, pipelines and other facilities to groundwaters that have a hydrologic connection to a surface water body represent an "unpermitted discharge" under the CWA. Two cases were accepted by theU.S. Supreme Court for further review of the scope of CWA jurisdiction. InApril 2020 , the Supreme Court issued an opinion remanding one of these cases to the Ninth Circuit based on its determination that discharges from an injection well that make their way to thePacific Ocean through ground water may require a permit if the distance traveled through ground water, length of time to reach the surface water and other factors make it "functionally equivalent" to a direct discharge from a point source. The second case was also remanded to the lower court. Prior to theSupreme Court's decision, the FederalEPA opened a rulemaking docket to solicit information to determine whether it should provide additional clarification of the scope of CWA permitting requirements for discharges to groundwater, and issued an interpretive statement finding that discharges to groundwater are not subject to NPDES permitting requirements under the CWA. Management is unable to predict the impact of these developments on AEP's facilities. Because AEP currently uses surface impoundments and landfills to manage CCR materials at generating facilities, significant costs will be incurred to upgrade or close and replace these existing facilities and conduct any required remedial actions. Closure and post-closure costs have been included in ARO in accordance with the requirements in the final rule. Additional ARO revisions will occur on a site-by-site basis if groundwater monitoring activities conclude that corrective actions are required to mitigate groundwater impacts, which could include costs to remove ash from some unlined units. InMarch 2020 ,Virginia's Governor signed House Bill 443 (HB 443), effectiveJuly 2020 , requiring APCo to close certain ash disposal units at the retiredGlen Lyn Station by removal of all coal combustion material. As a result, inJune 2020 , APCo recorded a$199 million revision to increase estimatedGlen Lyn Station ash disposal ARO liabilities. The closure is required to be completed within 15 years from the start of the excavation process. HB 443 provides for the recovery of all costs associated with closure by removal through theVirginia environmental rate adjustment clause (E-RAC). APCo may begin recovering these costs through the E-RAC beginningJuly 1, 2022 . APCo is permitted to record carrying costs on the unrecovered balance of closure costs at a weighted average cost of capital approved by the Virginia SCC. HB 443 also allows any closure costs allocated to non-Virginia jurisdictional customers, but not collected from such non-Virginia jurisdictional customers, to be recovered fromVirginia jurisdictional customers through the E-RAC.
If removal of ash is required without providing similar assurances of cost
recovery in regulated jurisdictions, it would impose significant additional
operating costs on AEP, which could lead to increased financing costs and
liquidity needs. Other units in
Clean Water Act Regulations
In 2014, the FederalEPA issued a final rule setting forth standards for existing power plants that is intended to reduce mortality of aquatic organisms impinged or entrained in the cooling water. The rule was upheld on review by theU.S. Court of Appeals for the Second Circuit . Compliance timeframes are established by the permit agency through each facility's NPDES permit as those permits are renewed and have been incorporated into permits at several AEP facilities. Additional AEP facilities are reviewing these requirements as their wastewater discharge permits are renewed and making appropriate adjustments to their intake structures. 15 -------------------------------------------------------------------------------- In 2015, the FederalEPA issued a final rule revising effluent limitation guidelines for generating facilities. The rule established limits on FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater to be imposed as soon as possible afterNovember 2018 and no later thanDecember 2023 . These requirements would be implemented through each facility's wastewater discharge permit. The rule was challenged in theU.S. Court of Appeals for the Fifth Circuit . In 2017, the FederalEPA announced its intent to reconsider and potentially revise the standards for FGD wastewater and bottom ash transport water. The FederalEPA postponed the compliance deadlines for those wastewater categories to be no earlier than 2020, to allow for reconsideration. InApril 2019 , the Fifth Circuit vacated the standards for landfill leachate and legacy wastewater, and remanded them to the FederalEPA for reconsideration. InNovember 2019 , the FederalEPA proposed revisions to the guidelines for existing generation facilities. The comment period ended inJanuary 2020 . Management is assessing technology additions and retrofits to comply with the rule and the impacts of the FederalEPA 's recent actions on facilities' wastewater discharge permitting. In 2015, the FederalEPA and theU.S. Army Corps of Engineers jointly issued a final rule to clarify the scope of the regulatory definition of "waters ofthe United States " in light of recentU.S. Supreme Court cases. Various parties challenged the 2015 rule in different U.S. District Courts, which resulted in a patchwork of applicability of the 2015 rule and its predecessor. InDecember 2018 , the FederalEPA and theU.S. Army Corps of Engineers proposed a replacement rule. InSeptember 2019 , the FederalEPA repealed the 2015 rule. The final replacement rule was published in theFederal Register inApril 2020 and became effective inJune 2020 . The final rule limits the scope of CWA jurisdiction to four categories of waters, and clarifies exclusions for ground water, ephemeral streams, artificial ponds and waste treatment systems. Challenges to the final rule and requests for a preliminary injunction have been brought by states and other groups in multiple U.S. District Courts. At this time, none of the jurisdictions in which AEP operates are impacted by a stay. Management is monitoring these various proceedings but is unable to predict the actions of the various courts. InApril 2020 , theU.S. District Court for the District of Montana issued a decision vacating theU.S. Army Corps of Engineers' (Corps) General Nationwide Permit 12 (NWP 12), which provides standard conditions governing linear utility projects in streams, wetlands and other waters ofthe United States having minimal adverse environmental impacts. The Court found that in reissuing NWP 12 in 2017, the Corps failed to comply with Section 7 of the Endangered Species Act (ESA), which requires the Corps to consult with theU.S. Fish and Wildlife Service regarding potential impacts on endangered species. The Court remanded the permit back to the Corps to complete itsESA consultation, and also enjoined the Corps from authorizing any dredge or fill activities under NWP 12 pending completion of the consultation process.The Department of Justice filed a motion to stay the injunction and tailor the remedy imposed by the Court. InMay 2020 , the Court revised its order lifting the injunction for non-oil and gas pipeline construction activities and routine maintenance, inspection and repair activities on existing NWP 12 projects.The Department of Justice appealed the Court's decision to theCourt of Appeals for the Ninth Circuit and moved for stay pending appeal, which was denied. InJune 2020 , theDepartment of Justice submitted an application to theU.S. Supreme Court requesting a stay of the District Court's Order, and the Court granted the request with respect to all oil and gas pipelines except theKeystone Pipeline . Management is monitoring the litigation and evaluating other permitting alternatives, but is currently unable to predict the impact of future proceedings on current and planned projects. 16 --------------------------------------------------------------------------------
RESULTS OF OPERATIONS SEGMENTS AEP's primary business is the generation, transmission and distribution of electricity. Within itsVertically 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:
•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 of electricity for sale to retail and wholesale
customers through assets owned and operated by
AEP Transmission Holdco
•Development, construction and operation of transmission facilities through investments in AEPTCo. These investments haveFERC -approved returns on equity. •Development, construction and operation of transmission facilities through investments in AEP's transmission-only joint ventures. These investments have PUCT-approved orFERC -approved returns on equity.
Generation & Marketing
•Competitive generation in
The remainder of AEP's activities are presented as Corporate and Other. While
not considered a reportable segment, Corporate and Other primarily includes the
purchasing of receivables from certain AEP utility subsidiaries, Parent's
guarantee revenue received from affiliates, investment income, interest income
and interest expense and other nonallocated costs.
The following discussion of AEP's results of operations by operating segment
includes an analysis of Gross Margin, which is a non-GAAP financial measure.
Gross Margin includes Total Revenues less the costs of Fuel and Other
Consumables Used for Electric Generation as well as Purchased Electricity for
Resale and Amortization of Generation Deferrals as presented in the Registrants
statements of income as applicable. Under the various state utility rate making
processes, these expenses are generally reimbursable directly from and billed to
customers. As a result, they do not typically impact Operating Income or
Earnings Attributable to AEP Common Shareholders. Management believes that Gross
Margin provides a useful measure for investors and other financial statement
users to analyze AEP's financial performance in that it excludes the effect on
Total Revenues caused by volatility in these expenses. Operating Income, which
is presented in accordance with GAAP in AEP's statements of income, is the most
directly comparable GAAP financial measure to the presentation of Gross Margin.
AEP's definition of Gross Margin may not be directly comparable to similarly
titled financial measures used by other companies.
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The following table presents Earnings (Loss) Attributable to AEP Common
Shareholders by segment:
Three Months Ended Six Months Ended
June 30, June 30,
2020 2019 2020 2019
(in millions) (in millions)
Vertically Integrated Utilities $ 255.9 $ 177.7 $ 501.2 $ 480.1
Transmission and Distribution Utilities 139.5 131.4 255.7 287.9
AEP Transmission Holdco 91.5 154.5 232.1 278.7
Generation & Marketing 65.9 9.4 94.3 49.5
Corporate and Other (32.0) (11.7) (67.3) (62.1)
Earnings Attributable to AEP Common
Shareholders $ 520.8 $ 461.3 $ 1,016.0 $ 1,034.1
AEP CONSOLIDATED
Second Quarter of 2020 Compared to Second Quarter of 2019
Earnings Attributable to AEP Common Shareholders increased from
•A planned decrease in Other Operation and Maintenance expenses. •Favorable rate proceedings in AEP's various jurisdictions.
Six Months Ended
Earnings Attributable to AEP Common Shareholders decreased from
•A decrease in weather-related usage. •A one-time reversal of a regulatory provision in 2019.
These decreases were partially offset by:
•Favorable rate proceedings in AEP's various jurisdictions. •A planned decrease in Other Operation and Maintenance expenses.
AEP's results of operations by operating segment are discussed below.
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--------------------------------------------------------------------------------VERTICALLY INTEGRATED UTILITIES
Three Months Ended Six Months Ended
June 30, June 30,
Vertically Integrated Utilities 2020 2019 2020 2019
(in millions)
Revenues $ 2,092.0 $
2,123.8
582.1 699.6 1,253.3 1,556.0
Gross Margin 1,509.9 1,424.2 3,065.4 2,971.1
Other Operation and Maintenance 624.6 684.1 1,315.9 1,374.2
Depreciation and Amortization 393.3 359.0 775.0 715.3
Taxes Other Than Income Taxes 117.5 113.2 234.6 229.2
Operating Income 374.5 267.9 739.9 652.4
Other Income 1.4 2.2 3.0 3.5
Allowance for Equity Funds Used During
Construction 9.0 16.0 17.2 26.7
Non-Service Cost Components of Net Periodic
Benefit Cost 17.1 16.8 34.0 33.8
Interest Expense (141.8) (143.0) (286.3) (282.0)
Income Before Income Tax Expense (Benefit) and
Equity Earnings 260.2 159.9 507.8 434.4
Income Tax Expense (Benefit) 4.6 (18.1) 6.7 (46.5)
Equity Earnings of Unconsolidated Subsidiary 0.7 0.8 1.5 1.5
Net Income 256.3 178.8 502.6 482.4
Net Income Attributable to Noncontrolling
Interests 0.4 1.1 1.4 2.3
Earnings Attributable to AEP Common
Shareholders $ 255.9 $ 177.7 $ 501.2 $ 480.1
Summary of KWh Energy Sales for Vertically Integrated Utilities
Six Months Ended
Three Months Ended June 30, June 30,
2020 2019 2020 2019
(in millions of KWhs)
Retail:
Residential 6,976 6,315 15,238 15,531
Commercial 5,150 5,710 10,516 11,343
Industrial 7,699 8,865 16,174 17,410
Miscellaneous 511 547 1,041 1,093
Total Retail 20,336 21,437 42,969 45,377
Wholesale (a) 4,924 4,826 8,542 10,630
Total KWhs 25,260 26,263 51,511 56,007
(a)Includes Off-system Sales, municipalities and cooperatives, unit power and other wholesale customers.
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Heating degree days and cooling degree days are metrics commonly used in the
utility industry as a measure of the impact of weather on revenues. In general,
degree day changes in the eastern region have a larger effect on revenues than
changes in the western region due to the relative size of the two regions and
the number of customers within each region.
Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities
Six Months Ended
Three Months Ended June 30, June 30,
2020 2019 2020 2019
(in degree days)
Eastern Region
Actual - Heating (a) 212 99 1,453 1,670
Normal - Heating (b) 137 142 1,748 1,737
Actual - Cooling (c) 324 378 337 379
Normal - Cooling (b) 337 333 342 338
Western Region
Actual - Heating (a) 49 26 698 967
Normal - Heating (b) 34 35 901 901
Actual - Cooling (c) 673 651 724 662
Normal - Cooling (b) 700 699 728 727
(a)Heating degree days are calculated on a 55 degree temperature base. (b)Normal Heating/Cooling represents the thirty-year average of degree days. (c)Cooling degree days are calculated on a 65 degree temperature base.
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--------------------------------------------------------------------------------Second Quarter of 2020 Compared to Second Quarter of 2019
Reconciliation of Second Quarter of 2019 to Second Quarter of 2020
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
Second Quarter of 2019 $ 177.7
Changes in Gross Margin:
Retail Margins 46.9
Margins from Off-system Sales (3.5)
Transmission Revenues 45.7
Other Revenues (3.4)
Total Change in Gross Margin 85.7
Changes in Expenses and Other:
Other Operation and Maintenance 59.5
Depreciation and Amortization (34.3)
Taxes Other Than Income Taxes (4.3)
Other Income (0.8)
Allowance for Equity Funds Used During Construction (7.0)
Non-Service Cost Components of Net Periodic Pension Cost 0.3
Interest Expense 1.2
Total Change in Expenses and Other 14.6
Income Tax Expense (22.7)
Equity Earnings of Unconsolidated Subsidiary (0.1)
Net Income Attributable to Noncontrolling Interests 0.7
Second Quarter of 2020 $ 255.9 The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:
•Retail Margins increased$47 million primarily due to the following: •A$19 million increase in weather-normalized retail margins driven by a$48 million increase in the residential customer class partially offset by a$28 million decrease in the commercial and industrial customer classes. •A$17 million increase in weather-related usage primarily in the eastern region and primarily in the residential class. •The effect of rate proceedings in AEP's service territories which included: •A$13 million increase at SWEPCo primarily due to rider increases in all jurisdictions and a base rate revenue increase inArkansas . •An$8 million increase at I&M primarily due to theIndiana andMichigan base rate cases, partially offset by a decrease in revenue riders. This increase was partially offset in other expense items below. •A$6 million increase due to a decrease in customer refunds related to Tax Reform. This increase was partially offset in Income Tax Expense below. •A$6 million increase in deferred fuel at APCo primarily due to the timing of recoverable PJM expenses. This increase was offset in other expense items below. •A$5 million increase at APCo and WPCo due to the WVPSC's approval of the Mitchell Plant surcharge effectiveJanuary 2020 . These increases were partially offset by: •A$19 million decrease in weather-normalized margins for wholesale customers primarily at I&M. •A$5 million decrease in revenue from rate riders at PSO. This decrease was partially offset in other expense items below. 21 -------------------------------------------------------------------------------- •Margins from Off-system Sales decreased$4 million due to WPCo's historical merchant portion ofMitchell Plant moving to base rates beginningJanuary 2020 and weaker market prices for energy in the RTOs which caused a significant decrease in sales volume and margins. •Transmission Revenues increased$46 million primarily due to the following: •A$36 million increase at SWEPCo as a result of the annual transmission formula rate true-up. This increase was partially offset by an increase in transmission expenses in SPP. •A$10 million increase at SWEPCo due to continued investment in transmission projects.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses decreased$60 million primarily due to the following: •A$30 million decrease in employee-related expenses. •A$27 million decrease in plant outage and maintenance expenses primarily at APCo, KPCo and PSO. •An$18 million decrease due to PJM transmission services including the annual formula rate true-up. •A$13 million decrease due to the capitalization of previously expensed North Central Wind Energy Facilities costs at SWEPCo and PSO. These decreases were partially offset by: •A$28 million increase due to SPP transmission services including the annual formula rate true-up. •A$12 million increase due to storms at KPCo and APCo. •Depreciation and Amortization expenses increased$34 million primarily due to a higher depreciable base and increased depreciation rates approved at I&M and SWEPCo. This increase was partially offset in Retail Margins above. •Allowance forEquity Funds Used During Construction decreased$7 million primarily due to a decrease in the AFUDC base primarily at I&M and APCo. •Income Tax Expense increased$23 million primarily due to an increase in pretax book income. 22 --------------------------------------------------------------------------------
Six Months Ended
Reconciliation of Six Months Ended
Earnings Attributable to AEP Common Shareholders from
(in millions)
Six Months Ended June 30, 2019 $ 480.1
Changes in Gross Margin:
Retail Margins 52.8
Margins from Off-system Sales (8.7)
Transmission Revenues 51.8
Other Revenues (1.6)
Total Change in Gross Margin 94.3
Changes in Expenses and Other:
Other Operation and Maintenance 58.3
Depreciation and Amortization (59.7)
Taxes Other Than Income Taxes (5.4)
Other Income (0.5)
Allowance for Equity Funds Used During Construction (9.5)
Non-Service Cost Components of Net Periodic Pension Cost 0.2
Interest Expense (4.3)
Total Change in Expenses and Other (20.9)
Income Tax Expense (53.2)
Net Income Attributable to Noncontrolling Interests 0.9
Six Months Ended June 30, 2020 The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:
•Retail Margins increased$53 million primarily due to the following: •A$20 million increase in deferred fuel at APCo primarily due to the timing of recoverable PJM expenses. This increase was offset in other expense items below. •A$16 million increase due to a decrease in customer refunds related to Tax Reform. This increase was partially offset in Income Tax Expense below. •A$14 million increase due to the impact of the 2019 WVPSC order which required APCo and WPCo to offset Excess ADIT not subject to normalization requirements against the deferred fuel under-recovery balance in 2019. •The effect of rate proceedings in AEP's service territories which included: •A$32 million increase at I&M primarily due to theIndiana andMichigan base rate cases. This increase was partially offset in other expense items below. •A$21 million increase at SWEPCo primarily due to rider increases in all jurisdictions and a base rate revenue increase inArkansas . •A$10 million increase at PSO due to new base rates implemented inApril 2019 . •A$10 million increase at APCo due to a base rate increase inWest Virginia that was partially offset in Depreciation and Amortization expenses below. •A$10 million increase at APCo and WPCo due to the WVPSC's approval of the Mitchell Plant surcharge effectiveJanuary 1, 2020 . 23 -------------------------------------------------------------------------------- These increases were partially offset by: •A$44 million decrease in weather-related usage primarily in the eastern region and primarily in the residential class. •A$23 million decrease in weather-normalized margins for wholesale contracts primarily at I&M. •A$9 million decrease in weather-normalized retail margins driven by a$51 million decrease in the commercial and industrial classes partially offset by a$44 million increase in the residential customer class. •A$6 million decrease in revenue from rate riders at PSO. This decrease was partially offset in other expense items below. •Margins from Off-system Sales decreased$9 million due to WPCo's historical merchant portion ofMitchell Plant moving to base rates beginningJanuary 2020 and weaker market prices for energy in the RTOs which caused a significant decrease in sales volume and margins. •Transmission Revenues increased$52 million primarily due to the following: •A$36 million increase at SWEPCo as a result of the annual transmission formula rate true-up. This increase was partially offset by an increase in transmission expenses in SPP. •A$16 million increase at SWEPCo due to continued investment in transmission projects.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses decreased$58 million primarily due to the following: •A$40 million decrease in plant outage and maintenance expenses primarily at APCo, WPCo, AEGCo and PSO. •A$39 million decrease in employee-related expenses. •A$10 million decrease due to the capitalization of previously expensed North Central Wind Energy Facilities costs at SWEPCo and PSO. •A$7 million decrease due to PJM transmission services including the annual formula rate true-up. •A$7 million decrease due to an increasedNuclear Electric Insurance Limited distribution in 2020. These decreases were partially offset by: •A$33 million increase due to SPP transmission services including the annual formula rate true-up. •An$11 million increase due to storms at KPCo and APCo •Depreciation and Amortization expenses increased$60 million primarily due to a higher depreciable base and increased depreciation rates approved at APCo, I&M and SWEPCo. This increase was partially offset in Retail Margins above. •Taxes Other Than Income Taxes increased$5 million primarily due to the following: •A$5 million increase at APCo and WPCo inWest Virginia business and occupational taxes. •A$4 million increase in property taxes driven by an increase in utility plant. These increases were partially offset by: •A$3 million decrease in payroll taxes. •Allowance forEquity Funds Used During Construction decreased$10 million primarily driven byFERC audit findings recorded in 2019 and a decrease in the AFUDC base primarily at I&M and APCo. •Interest Expense increased$4 million primarily due to higher long-term debt balances at APCo. •Income Tax Expense increased$53 million primarily due to a decrease in amortization of Excess ADIT, an increase in pretax book income and a decrease in favorable flow-through tax benefits. The decrease in amortization of Excess ADIT is partially offset above in Gross Margin and Other Operation and Maintenance expenses. 24 --------------------------------------------------------------------------------
TRANSMISSION AND DISTRIBUTION UTILITIES
Three Months Ended Six Months Ended
June 30, June 30,
Transmission and Distribution Utilities 2020 2019 2020 2019
(in millions)
Revenues $ 1,034.5 $ 1,045.7 $ 2,141.4 $ 2,267.7
Purchased Electricity 147.5 163.7 338.9 393.4
Amortization of Generation Deferrals - 24.1 - 56.5
Gross Margin 887.0 857.9 1,802.5 1,817.8
Other Operation and Maintenance 351.9 410.4 719.1 816.3
Depreciation and Amortization 207.0 193.4 421.5 377.1
Taxes Other Than Income Taxes 141.8 139.9 288.0 285.4
Operating Income 186.3 114.2 373.9 339.0
Interest and Investment Income 0.4 1.8 1.1 3.1
Carrying Costs Income 0.6 0.2 1.0 0.4
Allowance for Equity Funds Used During
Construction 7.7 5.6 14.7 12.5
Non-Service Cost Components of Net Periodic
Benefit Cost 7.4 7.5 14.7 15.1
Interest Expense (72.2) (45.2) (143.6) (107.2)
Income Before Income Tax Expense (Benefit) 130.2 84.1 261.8 262.9
Income Tax Expense (Benefit) (9.3) (47.3) 6.1 (25.0)
Net Income 139.5 131.4 255.7 287.9
Net Income Attributable to Noncontrolling
Interests - - - -
Earnings Attributable to AEP Common Shareholders $ 139.5 $ 131.4 $ 255.7 $ 287.9
Summary of KWh Energy Sales for Transmission and Distribution Utilities
Three Months Ended Six Months Ended
June 30, June 30,
2020 2019 2020 2019
(in millions of KWhs)
Retail:
Residential 6,299 5,799 12,599 12,346
Commercial 5,559 6,232 11,432 11,850
Industrial 5,148 5,864 11,056 11,635
Miscellaneous 180 196 362 372
Total Retail (a) 17,186 18,091 35,449 36,203
Wholesale (b) 455 440 845 1,078
Total KWhs 17,641 18,531 36,294 37,281
(a)Represents energy delivered to distribution customers. (b)Primarily Ohio's contractually obligated purchases of OVEC power sold to PJM.
25
--------------------------------------------------------------------------------
Heating degree days and cooling degree days are metrics commonly used in the
utility industry as a measure of the impact of weather on revenues. In general,
degree day changes in the eastern region have a larger effect on revenues than
changes in the western region due to the relative size of the two regions and
the number of customers within each region.
Summary of Heating and Cooling Degree Days for Transmission and Distribution
Utilities
Three Months Ended Six Months Ended
June 30, June 30,
2020 2019 2020 2019
(in degree days)
Eastern Region
Actual - Heating (a) 292 114 1,765 2,006
Normal - Heating (b) 182 189 2,080 2,066
Actual - Cooling (c) 314 303 317 304
Normal - Cooling (b) 301 298 304 301
Western Region
Actual - Heating (a) 6 3 97 180
Normal - Heating (b) 3 3 188 190
Actual - Cooling (d) 936 970 1,167 1,092
Normal - Cooling (b) 933 934 1,058 1,057
(a)Heating degree days are calculated on a 55 degree temperature base.
(b)Normal Heating/Cooling represents the thirty-year average of degree days.
(c)Eastern Region cooling degree days are calculated on a 65 degree temperature
base.
(d)Western Region cooling degree days are calculated on a 70 degree temperature
base.
26
--------------------------------------------------------------------------------Second Quarter of 2020 Compared to Second Quarter of 2019
Reconciliation of Second Quarter of 2019 to Second Quarter of 2020
Earnings Attributable to AEP Common Shareholders fromTransmission and Distribution Utilities (in millions) Second Quarter of 2019$ 131.4 Changes in Gross Margin: Retail Margins 28.0 Margins from Off-system Sales (16.5) Transmission Revenues 4.0 Other Revenues 13.6 Total Change in Gross Margin 29.1 Changes in Expenses and Other: Other Operation and Maintenance 58.5 Depreciation and Amortization (13.6) Taxes Other Than Income Taxes (1.9) Interest and Investment Income (1.4) Carrying Costs Income 0.4 Allowance for Equity Funds Used During Construction 2.1 Non-Service Cost Components of Net Periodic Benefit Cost (0.1) Interest Expense (27.0) Total Change in Expenses and Other 17.0 Income Tax Expense (38.0) Second Quarter of 2020$ 139.5 The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows: •Retail Margins increased$28 million primarily due to the following: •A$61 million net increase in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below. •A$13 million increase in rider revenues inOhio associated with the DIR. This increase was partially offset in other expense items below. •A$5 million increase in revenues associated withOhio smart grid riders. This increase was partially offset in other expense items below. These increases were partially offset by: •A$10 million decrease in Ohio Deferred Asset Phase-In-Recovery Rider revenues which ended in the second quarter of 2019. This decrease was offset in Depreciation and Amortization expenses below. •A$10 million decrease in weather-normalized margins primarily in the commercial class partially offset by the residential class. •A$9 million decrease due to the OVEC PPA Rider which was replaced by the Legacy Generation Resource Rider (LGRR). This decrease was offset in Margins from Off-system Sales and Other Revenues below. •A$7 million net decrease in margin inOhio for the Rate Stability Rider including associated amortizations which ended in the third quarter of 2019. •A$7 million decrease due to refunds of Excess ADIT not subject to normalization requirements inTexas . This decrease was offset in Income Tax Expense below. •A$5 million decrease due to a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset in Other Operation and Maintenance expenses below. 27 -------------------------------------------------------------------------------- •Margins from Off-system Sales decreased$17 million primarily due to the following: •A$20 million decrease inTexas primarily due to lowerOklaunion Power Station PPA revenues. This decrease was offset in Other Operation and Maintenance expenses below. This decrease was partially offset by: •A$7 million increase inOhio primarily due to higher OVEC PPA deferrals. This increase was offset in Retail Margins above. •Transmission Revenues increased$4 million primarily due to the following: •A$10 million increase inOhio due to the annual transmission formula rate true-up. •A$10 million increase due to recovery of increased transmission investment inERCOT . This increase was partially offset by: •A$17 million decrease inTexas due to a one-time credit to transmission customers as a result of Tax Reform and the most recent base rate case. This decrease was offset in Income Tax Expense below. •Other Revenues increased$14 million primarily due to securitization revenue inTexas . This increase was offset below in Depreciation and Amortization expenses and in Interest Expense.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses decreased$59 million primarily due to the following: •A$67 million decrease due to prior year partial amortization of theAEP Texas Storm Restoration Securitization regulatory asset as a result of theAEP Texas Storm Cost Securitization financing order issued by the PUCT inJune 2019 . This decrease was offset in Income Tax Expense below. •A$34 million decrease in PJM expenses primarily related to the annual transmission formula rate true-up. •A$17 million decrease due to the revision of the Oklaunion Power Station ARO. This decrease was offset in Margins for Off-System Sales above. •A$5 million decrease due to a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset in Retail Margins above. These decreases were partially offset by: •A$66 million increase in PJM expenses that were fully recovered in rate riders/trackers in Gross Margin above. •A$3 million increase in remittedUniversal Service Fund (USF) surcharge payments to theOhio Department of Development to fund an energy assistance program for qualifiedOhio customers. This increase was offset in Retail Margins above. •Depreciation and Amortization expenses increased$14 million primarily due to the following: •A$7 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets. •A$7 million increase in securitization amortizations inTexas . This increase was offset in Other Revenues above and in Interest Expense below. •A$5 million increase due to lower deferred equity amortizations associated with the Deferred Asset Phase-In-Recovery Rider inOhio which ended in the second quarter of 2019. •A$3 million increase inOhio recoverable DIR depreciation expense. This increase was partially offset in Retail Margins above. These increases were partially offset by: •A$10 million decrease in amortizations associated with the Deferred Asset Phase-In-Recovery Rider inOhio which ended in the second quarter of 2019. This decrease was offset in Retail Margins above. •Interest Expense increased$27 million primarily due to the prior year deferral of previously recorded interest expense approved for the recovery as a result of the Texas Storm Cost Securitization financing order issued by the PUCT inJune 2019 . •Income Tax Expense increased$38 million primarily due to the prior year amortization of Excess ADIT not subject to normalization requirements as approved in the Texas Storm Cost Securitization financing order issued by the PUCT in 2019 and an increase in pretax book income. This increase was partially offset in Gross Margins and Other Operation and Maintenance Expenses above. 28 --------------------------------------------------------------------------------
Six Months Ended
Reconciliation of Six Months Ended
Earnings Attributable to AEP Common Shareholders from
(in millions)
Six Months Ended June 30, 2019 $ 287.9
Changes in Gross Margin:
Retail Margins (46.1)
Margins from Off-system Sales (15.9)
Transmission Revenues 15.9
Other Revenues 30.8
Total Change in Gross Margin (15.3)
Changes in Expenses and Other:
Other Operation and Maintenance 97.2
Depreciation and Amortization (44.4)
Taxes Other Than Income Taxes (2.6)
Interest and Investment Income (2.0)
Carrying Costs Income 0.6
Allowance for Equity Funds Used During Construction 2.2
Non-Service Cost Components of Net Periodic Benefit Cost (0.4)
Interest Expense (36.4)
Total Change in Expenses and Other 14.2
Income Tax Expense (31.1)
Six Months Ended June 30, 2020 The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows: •Retail Margins decreased$46 million primarily due to the following: •A$58 million decrease due to a reversal of a regulatory provision inOhio in the first quarter of 2019. •A$23 million decrease in Ohio Deferred Asset Phase-In-Recovery Rider revenues which ended in the second quarter of 2019. This decrease was offset in Depreciation and Amortization expenses below. •A$15 million net decrease in margin inOhio for the Rate Stability Rider including associated amortizations which ended in the third quarter of 2019. •A$14 million decrease due to the OVEC PPA Rider which was replaced by the Legacy Generation Resource Rider (LGRR). This decrease was offset in Margins from Off-system Sales and Other Revenues below. •A$7 million decrease due to refunds of Excess ADIT not subject to normalization requirements inTexas . This decrease was offset in Income Tax Expense below. •A$6 million decrease in revenues associated with a vegetation management rider inOhio . This decrease was offset in Other Operation and Maintenance expenses below. •A$5 million decrease due to a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset in Other Operation and Maintenance expenses below. 29 -------------------------------------------------------------------------------- These decreases were partially offset by: •A$30 million increase in rider revenues inOhio associated with the DIR. This increase was partially offset in other expense items below. •A$22 million net increase in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below. •A$12 million increase in revenues associated withOhio smart grid riders. This increase was partially offset in other expense items below. •A$10 million increase in revenues inOhio associated with the USF. This increase was offset in Other Operation and Maintenance expenses below. •A$6 million increase inTexas revenues associated with the Transmission Cost Recovery Factor revenue rider. This decrease was partially offset by a decrease in Other Operation and Maintenance expenses below. •Margins from Off-system Sales decreased$16 million primarily due to the following: •A$20 million decrease inTexas primarily due to lowerOklaunion Power Station PPA revenues. This decrease was offset in Other Operation and Maintenance expenses below. •A$9 million decrease in sales inOhio due to lower market prices and decreased sales volumes in 2020. This decrease was offset in Retail Margins above. This decrease was partially offset by: •A$14 million increase inOhio due to higher OVEC PPA deferrals. This increase was offset in Retail Margins above. •Transmission Revenues increased$16 million primarily due to the following: •A$22 million increase primarily due to recovery of increased transmission investment inERCOT . •A$10 million increase inOhio due to the annual transmission formula rate true-up. This increase was partially offset by: •A$17 million decrease inTexas due to a one-time credit to transmission customers as a result of Tax Reform and the most recent base rate case. This decrease was offset in Income Tax Expense below. •Other Revenues increased$31 million primarily due to the following: •A$19 million increase in securitization revenue inTexas . This increase was offset in Depreciation and Amortization expenses and in Interest Expense below. •A$9 million increase inOhio primarily due to third-party LGRR revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins above.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses decreased$97 million primarily due to the following: •A$67 million decrease due to prior year partial amortization of theAEP Texas Storm Restoration Securitization regulatory asset as a result of theAEP Texas Storm Cost Securitization financing order issued by the PUCT inJune 2019 . This decrease was offset in Income Tax Expense below. •A$40 million decrease in PJM expenses primarily related to the annual transmission formula rate true-up. •A$17 million decrease due to the revision of the Oklaunion Power Station ARO. This decrease was offset in Margins for Off-System Sales above. •A$5 million decrease due to a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset in Retail Margins above. These decreases were partially offset by: •A$25 million increase in PJM expenses that were fully recovered in rate riders/trackers in Gross Margin above. •A$10 million increase in remitted USF surcharge payments to theOhio Department of Development to fund an energy assistance program for qualifiedOhio customers. This increase was offset in Retail Margins above. 30 -------------------------------------------------------------------------------- •Depreciation and Amortization expenses increased$44 million primarily due to the following: •A$22 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets. •A$19 million increase in securitization amortizations inTexas . This increase was offset in Other Revenues above and in Interest Expense below. •A$10 million increase due to lower deferred equity amortizations associated with the Deferred Asset Phase-In-Recovery Rider inOhio which ended in the second quarter of 2019. •An$8 million increase inOhio recoverable DIR depreciation expense. This increase was partially offset in Retail Margins above. •A$5 million increase in recoverable smart grid expense inOhio . This increase was offset in Retail Margins above. These increases were partially offset by: •A$21 million decrease in amortizations associated with the Deferred Asset Phase-In-Recovery Rider inOhio which ended in the second quarter of 2019. This decrease was offset in Retail Margins above. •Taxes Other Than Income Taxes increased$3 million primarily due to the following: •An$8 million increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates. This increase was partially offset by: •A$3 million decrease in excise taxes due to lower demand in 2020 inOhio . This decrease was offset in Retail Margins above. •Interest Expense increased$36 million primarily due to the following: •A$19 million increase due to the deferral of previously recorded interest expense approved for recovery as a result of the Texas Storm Cost Securitization financing order issued by the PUCT inJune 2019 . •A$14 million increase due to higher long-term debt balances. •Income Tax Expense increased$31 million primarily due to the prior year amortization of Excess ADIT not subject to normalization requirements as approved in the Texas Storm Cost Securitization financing order issued by the PUCT in 2019. This increase was partially offset in Gross Margins and Other Operation and Maintenance Expenses above. 31 -------------------------------------------------------------------------------- AEP TRANSMISSION HOLDCO Three Months Ended Six Months Ended June 30, June 30, AEP Transmission Holdco 2020 2019 2020 2019 (in millions) Transmission Revenues$ 249.7 $ 278.9 $ 559.9 $ 535.3 Other Operation and Maintenance 25.9 22.9 55.8 45.2 Depreciation and Amortization 61.1 44.6 119.2 86.4 Taxes Other Than Income Taxes 51.8 43.5 103.7 86.1 Operating Income 110.9 167.9 281.2 317.6 Interest and Investment Income 1.5 0.8 2.4 1.5 Allowance for Equity Funds Used During Construction 18.4 28.8 34.6 40.1 Non-Service Cost Components of Net Periodic Benefit Cost 0.5 0.7 1.0 1.3 Interest Expense (34.2) (23.0) (65.0) (46.0) Income Before Income Tax Expense and Equity Earnings 97.1 175.2 254.2 314.5 Income Tax Expense 24.7 38.4 63.1 70.3 Equity Earnings of Unconsolidated Subsidiary 19.8 18.6 42.7 36.4 Net Income 92.2 155.4 233.8 280.6 Net Income Attributable to Noncontrolling Interests 0.7 0.9 1.7 1.9
Earnings Attributable to AEP Common Shareholders
Summary of Investment in Transmission Assets for AEP Transmission Holdco
As of June 30,
2020 2019
(in millions)
Plant in Service $ 9,333.7 $ 7,447.3
Construction Work in Progress 1,660.5 1,883.1
Accumulated Depreciation and Amortization 508.2 350.2
Total Transmission Property, Net $ 10,486.0 $ 8,980.2
32
--------------------------------------------------------------------------------Second Quarter of 2020 Compared to Second Quarter of 2019
Reconciliation of Second Quarter of 2019 to Second Quarter of 2020
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
Second Quarter of 2019 $ 154.5
Changes in Transmission Revenues:
Transmission Revenues (29.2)
Total Change in Transmission Revenues (29.2)
Changes in Expenses and Other:
Other Operation and Maintenance (3.0)
Depreciation and Amortization (16.5)
Taxes Other Than Income Taxes (8.3)
Interest and Investment Income 0.7
Allowance for Equity Funds Used During Construction (10.4)
Non-Service Cost Components of Net Periodic Pension Cost (0.2)
Interest Expense (11.2)
Total Change in Expenses and Other (48.9)
Income Tax Expense 13.7
Equity Earnings of Unconsolidated Subsidiary 1.2
Net Income Attributable to Noncontrolling Interests 0.2
Second Quarter of 2020 $ 91.5 The major components of the decrease in transmission revenues, which consists of wholesale sales to affiliates and nonaffiliates, were as follows:
•Transmission Revenues decreased$29 million primarily due to the following: •A$62 million decrease as a result of the affiliated annual transmission formula rate true-up which is offset in Other Operation and Maintenance expense across the other Registrant subsidiaries. •A$17 million decrease as a result of the non-affiliated annual transmission formula rate true-up. These decreases were partially offset by: •A$50 million increase due to continued investment in transmission assets.
Expenses and Other and Income Tax Expense changed between years as follows:
•Depreciation and Amortization expenses increased$17 million primarily due to a higher depreciable base. •Taxes Other Than Income Taxes increased$8 million primarily due to higher property taxes as a result of increased transmission investment. •Allowance forEquity Funds Used During Construction decreased$10 million primarily due to the following: •A$12 million decrease driven by the favorable impact of aFERC settlement agreement recorded in 2019. •A$2 million decrease due to lower CWIP. These decreases were partially offset by: •A$4 million increase driven byFERC audit findings recorded in 2019. •Interest Expense increased$11 million primarily due to higher long-term debt balances. •Income Tax Expense decreased$14 million primarily due to lower pretax book income. 33 --------------------------------------------------------------------------------
Six Months Ended
Reconciliation of Six Months Ended
2020
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
Six Months Ended June 30, 2019 $ 278.7
Changes in Transmission Revenues:
Transmission Revenues 24.6
Total Change in Transmission Revenues 24.6
Changes in Expenses and Other:
Other Operation and Maintenance (10.6)
Depreciation and Amortization (32.8)
Taxes Other Than Income Taxes (17.6)
Interest and Investment Income 0.9
Allowance for Equity Funds Used During Construction (5.5)
Non-Service Cost Components of Net Periodic Pension Cost (0.3)
Interest Expense (19.0)
Total Change in Expenses and Other (84.9)
Income Tax Expense 7.2
Equity Earnings of Unconsolidated Subsidiary 6.3
Net Income Attributable to Noncontrolling Interests 0.2
Six Months Ended June 30, 2020 $ 232.1
The major components of the increase in transmission revenues, which consists of
wholesale sales to affiliates and nonaffiliates, were as follows:
•Transmission Revenues increased $25 million primarily due to the following:
•A $104 million increase due to continued investment in transmission assets.
This increase was partially offset by the following:
•A $62 million decrease as a result of the affiliated annual transmission
formula rate true-up which is offset in Other Operation and Maintenance expense
across the other Registrant subsidiaries.
•A $17 million decrease as a result of the non-affiliated annual transmission
formula rate true-up.
Expenses and Other, Income Tax Expense and Equity Earnings of Unconsolidated
Subsidiary changed between years as follows:
•Other Operation and Maintenance expenses increased $11 million primarily due to
the following:
•A $5 million increase in employee-related expenses.
•A $4 million increase in rent expense.
•Depreciation and Amortization expenses increased $33 million primarily due to a
higher depreciable base.
•Taxes Other Than Income Taxes increased $18 million primarily due to higher
property taxes as a result of increased transmission investment.
•Allowance for Equity Funds Used During Construction decreased $6 million
primarily due to the following:
•A $12 million decrease driven by the favorable impact of a FERC settlement
agreement recorded in 2019.
•A $6 million decrease due to lower CWIP.
These decreases were partially offset by:
•A $13 million increase driven by FERC audit findings recorded in 2019.
•Interest Expense increased $19 million primarily due to higher long-term debt
balances.
•Income Tax Expense decreased $7 million primarily due to lower pretax book
income.
•Equity Earnings of Unconsolidated Subsidiary increased $6 million primarily due
to higher pretax equity earnings at PATH-WV.
34
--------------------------------------------------------------------------------
GENERATION & MARKETING
Three Months Ended Six Months Ended
June 30, June 30,
Generation & Marketing 2020 2019 2020 2019
(in millions)
Revenues $ 376.9 $ 412.7 $ 815.5 $ 894.5
Fuel, Purchased Electricity and Other 298.5 330.7 658.8 714.0
Gross Margin 78.4 82.0 156.7 180.5
Other Operation and Maintenance 16.5 63.4 57.9 114.0
Depreciation and Amortization 17.9 15.6 35.6 28.5
Taxes Other Than Income Taxes 3.7 3.6 7.1 7.4
Operating Income (Loss) 40.3 (0.6) 56.1 30.6
Interest and Investment Income 1.2 1.8 2.2 4.1
Non-Service Cost Components of Net Periodic
Benefit Cost 3.8 3.7 7.7 7.4
Interest Expense (8.2) (7.2) (16.7) (11.0)
Income (Loss) Before Income Tax Benefit and
Equity Earnings (Loss) 37.1 (2.3) 49.3 31.1
Income Tax Benefit (21.0) (9.6) (33.4) (15.4)
Equity Earnings (Loss) of Unconsolidated
Subsidiaries 0.4 (2.1) 6.3 (2.1)
Net Income 58.5 5.2 89.0 44.4
Net Loss Attributable to Noncontrolling Interests (7.4) (4.2) (5.3) (5.1)
Earnings Attributable to AEP Common Shareholders $ 65.9 $ 9.4 $ 94.3 $ 49.5
Summary of MWhs Generated for Generation & Marketing
Three Months Ended Six Months Ended
June 30, June 30,
2020 2019 2020 2019
(in millions of MWhs)
Fuel Type:
Coal 1 1 2 2
Renewables 1 1 2 1
Total MWhs 2 2 4 3
35--------------------------------------------------------------------------------
Second Quarter of 2020 Compared to Second Quarter of 2019
Reconciliation of Second Quarter of 2019 to Second Quarter of 2020
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
Second Quarter of 2019 $ 9.4
Changes in Gross Margin:
Merchant Generation (16.5)
Renewable Generation 8.1
Retail, Trading and Marketing 4.8
Total Change in Gross Margin (3.6)
Changes in Expenses and Other:
Other Operation and Maintenance 46.9
Depreciation and Amortization (2.3)
Taxes Other Than Income Taxes (0.1)
Interest and Investment Income (0.6)
Non-Service Cost Components of Net Periodic Benefit Cost 0.1
Interest Expense (1.0)
Total Change in Expenses and Other 43.0
Income Tax Benefit 11.4
Equity Earnings (Loss) of Unconsolidated Subsidiaries 2.5
Net Loss Attributable to Noncontrolling Interests 3.2
Second Quarter of 2020 $ 65.9 The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, purchased electricity and certain cost of service for retail operations were as follows:
•Merchant Generation decreased$17 million primarily due to lower capacity revenues and energy margins in 2020 and the retirement of the Conesville Plant Units 5 and 6 in 2019 and Unit 4 in 2020. •Renewable Generation increased$8 million primarily due to the acquisition ofSempra Renewables LLC and new projects placed in-service. •Retail, Trading and Marketing increased$5 million due to higher trading and marketing activity, partially offset by lower retail margins.
Expenses and Other, Income Tax Benefit, Equity Earnings of (Loss) Unconsolidated Subsidiaries and Net Loss Attributable to Noncontrolling Interests changed between years as follows:
•Other Operation and Maintenance expenses decreased$47 million primarily due to the following: •A$19 million decrease related to the Oklaunion PPA withAEP Texas primarily due to an ARO revision. •A$14 million decrease due to the retirement of Conesville Plant Units 5 and 6 in 2019 and Unit 4 in 2020. •A$12 million decrease due to a gain recorded on the sale of land. •Depreciation and Amortization expenses increased$2 million due to a higher depreciable base from increased investments in renewable energy sources. •Income Tax Benefit increased$11 million primarily due to an increase in PTC. •Equity Earnings (Loss) of Unconsolidated Subsidiaries increased$3 million primarily due to theSempra Renewables LLC acquisition. •Net Loss Attributable to Noncontrolling Interests increased$3 million primarily due to theSempra Renewables LLC acquisition. 36 --------------------------------------------------------------------------------
Six Months Ended
Reconciliation of Six Months Ended
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
Six Months Ended June 30, 2019 $ 49.5
Changes in Gross Margin:
Merchant Generation (53.9)
Renewable Generation 21.4
Retail, Trading and Marketing 8.7
Total Change in Gross Margin (23.8)
Changes in Expenses and Other:
Other Operation and Maintenance 56.1
Depreciation and Amortization (7.1)
Taxes Other Than Income Taxes 0.3
Interest and Investment Income (1.9)
Non-Service Cost Components of Net Periodic Benefit Cost 0.3
Interest Expense (5.7)
Total Change in Expenses and Other 42.0
Income Tax Benefit 18.0
Equity Earnings (Loss) of Unconsolidated Subsidiaries 8.4
Net Loss Attributable to Noncontrolling Interests 0.2
Six Months Ended June 30, 2020 The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, purchased electricity and certain cost of service for retail operations were as follows:
•Merchant Generation decreased$54 million primarily due to the reduction of capacity revenues and energy margins in 2020 and the retirement of the Conesville Plant Units 5 and 6 in 2019 and Unit 4 in 2020. •Renewable Generation increased$21 million primarily due to theSempra Renewables LLC acquisition and other renewable projects placed in-service. •Retail, Trading and Marketing increased$9 million due to higher trading and marketing activity, partially offset by lower retail margins.
Expenses and Other, Income Tax Benefit and Equity Earnings (Loss) of Unconsolidated Subsidiaries changed between years as follows:
•Other Operation and Maintenance expenses decreased$56 million due to the following: •A$23 million decrease due to the retirement of Conesville Plant Units 5 and 6 in 2019 and Unit 4 in 2020. •A$19 million decrease related to the Oklaunion PPA withAEP Texas primarily due to an ARO revision. •A$15 million decrease due to a gain recorded on the sale of land. •Depreciation and Amortization expenses increased$7 million due to a higher depreciable base from increased investments in renewable energy sources. •Interest Expense increased$6 million primarily due to increased borrowing costs related to theSempra Renewables LLC acquisition. •Income Tax Benefit increased$18 million primarily due to an increase in PTC. •Equity Earnings (Loss) of Unconsolidated Subsidiaries increased$8 million primarily due to theSempra Renewables LLC acquisition. 37 --------------------------------------------------------------------------------
CORPORATE AND OTHER
Second Quarter of 2020 Compared to Second Quarter of 2019
Earnings Attributable to AEP Common Shareholders from Corporate and Other
decreased from a loss of
•A
This item was partially offset by:
•An
Six Months Ended
Earnings Attributable to AEP Common Shareholders from Corporate and Other
decreased from a loss of
•A$14 million increase in interest expense as a result of increased debt outstanding. •A$10 million increase in income tax expense due to an increase in consolidating tax adjustments and discrete items recorded in 2019. •A$6 million decrease in interest income due to a lower return on investments held by EIS.
These items were partially offset by:
•A
AEP SYSTEM INCOME TAXES
Second Quarter of 2020 Compared to Second Quarter of 2019
Income Tax Expense increased
Six Months Ended
Income Tax Expense increased
38
--------------------------------------------------------------------------------FINANCIAL CONDITION
AEP measures financial condition by the strength of its balance sheet and the liquidity provided by its cash flows.
LIQUIDITY AND CAPITAL RESOURCES
Debt and Equity Capitalization
June 30, 2020 December 31, 2019
(dollars in millions)
Long-term Debt, including amounts due within one year $ 28,775.4 55.2 % $ 26,725.5 54.1 %
Short-term Debt 3,076.6 5.9 2,838.3 5.7
Total Debt 31,852.0 61.1 29,563.8 59.8
AEP Common Equity 20,007.4 38.4 19,632.2 39.6
Noncontrolling Interests 270.8 0.5 281.0 0.6
Total Debt and Equity Capitalization $ 52,130.2 100.0 % $ 49,477.0 100.0 %
AEP's ratio of debt-to-total capital increased from 59.8% as of
Liquidity
Liquidity, or access to cash, is an important factor in determining AEP's financial stability. Management believes AEP has adequate liquidity under its existing credit facilities. As ofJune 30, 2020 , AEP had a$4 billion revolving credit facility to support its commercial paper program. Additional liquidity is available from cash from operations and a receivables securitization agreement. Management is committed to maintaining adequate liquidity. AEP generally uses short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged. Sources of long-term funding include issuance of long-term debt, leasing agreements, hybrid securities or common stock. There was increased volatility in the capital markets during the first quarter of 2020 resulting in higher commercial paper cost and limited access. To address these issues and the uncertainty around COVID-19, inMarch 2020 , AEP entered into a$1 billion 364-day Term Loan and borrowed the full amount. Net Available Liquidity
AEP manages liquidity by maintaining adequate external financing commitments. As
of
Amount Maturity
Commercial Paper Backup: (in millions)
Revolving Credit Facility $ 4,000.0 June 2022
364-Day Term Loan 1,000.0 March 2021
Cash and Cash Equivalents 348.8
Total Liquidity Sources 5,348.8
Less: AEP Commercial Paper Outstanding 1,403.5
364-Day Term Loan 1,000.0
Net Available Liquidity $ 2,945.3
AEP uses its commercial paper program to meet the short-term borrowing needs of
its subsidiaries. The program funds a Utility Money Pool , which funds AEP's
utility subsidiaries; a Nonutility Money Pool , which funds certain AEP
nonutility subsidiaries; and the short-term debt requirements of subsidiaries
that are not participating in either money pool for regulatory or operational
reasons, as direct borrowers. The maximum amount of commercial paper outstanding
during the first six months of 2020 was $3 billion . The weighted-average
interest rate for AEP's commercial paper during 2020 was 1.80%.
39
--------------------------------------------------------------------------------Other Credit Facilities An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under six uncommitted facilities totaling$405 million . The Registrants' maximum future payments for letters of credit issued under the uncommitted facilities as ofJune 30, 2020 was$192 million with maturities ranging fromJuly 2020 toJuly 2021 .
Securitized Accounts Receivables
AEP's receivables securitization agreement provides a commitment of
InMay 2020 , AEP Credit amended its receivables securitization agreement to increase the eligibility criteria related to aged receivable requirements for the participating affiliated utility subsidiaries in response to the COVID-19 pandemic. As ofJune 30, 2020 , the affiliated utility subsidiaries are in compliance with all requirements under the agreement. To the extent that an affiliated utility subsidiary is deemed ineligible under the agreement, receivables would no longer be purchased by the bank conduits and the Registrants would need to rely on additional sources of funding for operation and working capital, which may adversely impact liquidity.
Debt Covenants and Borrowing Limitations
AEP's credit agreements contain certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%. The method for calculating outstanding debt and capitalization is contractually-defined in AEP's credit agreements. Debt as defined in the revolving credit agreement excludes securitization bonds and debt of AEP Credit. As ofJune 30, 2020 , this contractually-defined percentage was 59.2%. Non-performance under these covenants could result in an event of default under these credit agreements. In addition, the acceleration of AEP's payment obligations, or the obligations of certain of AEP's major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of$50 million , would cause an event of default under these credit agreements. This condition also applies in a majority of AEP's non-exchange-traded commodity contracts and would similarly allow lenders and counterparties to declare the outstanding amounts payable. However, a default under AEP's non-exchange-traded commodity contracts would not cause an event of default under its credit agreements.
The revolving credit facility does not permit the lenders to refuse a draw on any facility if a material adverse change occurs.
Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders and AEP manages its borrowings to stay within those authorized limits. Equity Units InMarch 2019 , AEP issued 16.1 million Equity Units initially in the form of corporate units, at a stated amount of$50 per unit, for a total stated amount of$805 million . Net proceeds from the issuance were approximately$785 million . Each corporate unit represents a 1/20 undivided beneficial ownership interest in$1,000 principal amount of AEP's 3.40% Junior Subordinated Notes due in 2024 and a forward equity purchase contract which settles after three years in 2022. The proceeds from this issuance were used to support AEP's overall capital expenditure plans including the acquisition ofSempra Renewables LLC . See Note 12 - Financing Activities for additional information. 40 --------------------------------------------------------------------------------
Dividend Policy and Restrictions
The Board of Directors declared a quarterly dividend of$0.70 per share inJuly 2020 . Future dividends may vary depending upon AEP's profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. Parent's income primarily derives from common stock equity in the earnings of its utility subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. Management does not believe these restrictions will have any significant impact on its ability to access cash to meet the payment of dividends on its common stock. See "Dividend Restrictions" section of Note 12 for additional information. Credit Ratings AEP and its utility subsidiaries do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit downgrade, but its access to the commercial paper market may depend on its credit ratings. In addition, downgrades in AEP's credit ratings by one of the rating agencies could increase its borrowing costs. Counterparty concerns about the credit quality of AEP or its utility subsidiaries could subject AEP to additional collateral demands under adequate assurance clauses under its derivative and non-derivative energy contracts.
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