UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For The Transition Period from ____ to ____

AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.

GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.

 

FORWARD-LOOKING INFORMATION

This report made by the Registrants contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.  Many forward-looking statements appear in “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the 20162017 Annual Report, but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook.  These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected.  Forward-looking statements in this document are presented as of the date of this document.  Except to the extent required by applicable law, management undertakes no obligation to update or revise any forward-looking statement.  Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:

Investors should note that the Registrants announce material financial information in SEC filings, press releases and public conference calls. Based on guidance from the SEC, the Registrants may use the Investors section of AEP’s website (www.aep.com) to communicate with investors about the Registrants. It is possible that the financial and other information posted there could be deemed to be material information. The information on AEP’s website is not part of this report.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

Customer Demand

AEP’s weather-normalized retail sales volumes for the first quarter of 2017 decreased2018 increased by 1.2%1.5% from the first quarter of 2016, partially due to 2016 being a leap year and including one additional day in comparison to 2017. AEP’s first quarter 20172018 industrial sales decreased 0.2%volumes increased 2.5% compared to the first quarter of 2016.2017. The results were mixed by industry despite growth in industrial sales to customers in oilwas spread across most industries and gas related sectors.most operating companies. Weather-normalized residential and commercial sales decreased 2.3%increased 1.4% and 0.9%0.5% in the first quarter of 2017,2018, respectively, from the first quarter of 2016.2017.

Merchant Generation Assets

In September 2016, AEP signed an agreement to sell Darby, Gavin, Lawrenceburg and Waterford Plants (“Disposition Plants”) totaling 5,329 MWs of competitive generation to a nonaffiliated party. The sale closed in January 2017 for approximately $2.2 billion. The net proceeds from the transaction were approximately $1.2 billion in cash after taxes, repayment of debt associated with these assets and transaction fees, which resulted in an after tax gain of approximately $127$129 million. AEP primarily used these proceeds to reduce outstanding debt and invest in its regulated businesses including transmission, and contracted renewable projects.

Management continues to evaluate potential alternatives for the remaining merchant generation assets. These potential alternatives may include, but are not limited to, transfer or sale of AEP’s ownership interests, or a wind down of merchant coal-fired generation fleet operations. In February 2017, AEP signed an agreement to sell its 25.4% ownership share of Zimmer Plant to Dynegy Corporation. Simultaneously, AEP signed an agreement to purchase Dynegy Corporation’s 40% ownership share of Conesville Plant, Unit 4. The transactions are expected to closeclosed in the second quarter of 2017 subject to FERC approval and aredid not expected to have a material impact on net income, cash flows andor financial condition.  The assets and liabilities of Zimmer Plant have been recorded as Assets Held for Sale and Liabilities Held for Sale on AEP’s balance sheet as of March 31, 2017.

In December 2017, AEP is also continuing a separate strategic review and evaluating alternatives relatedsigned an amendment to the 48 MW Racine Hydroelectric Plant.Cardinal Station Agreement with Buckeye Power Incorporated, which terminates certain commercial arrangements between the parties and transitions management oversight and administrative support of the Cardinal facility from AEP to Buckeye Power Incorporated.  The amendment required approval from Rural Utilities Service and the FERC, which were obtained in February 2018. The new amendment became effective March 2018 and did not have a material impact on net income, cash flows or financial condition.

Management continues to evaluate potential alternatives for its remaining merchant generation assets. These potential alternatives may include, but are not limited to, transfer or sale of AEP’s ownership interests or a wind down of merchant coal-fired generation fleet operations. Management has not set a specific time frame for a decision on these assets. These alternatives could result in additional losses which could reduce future net income and cash flows and impact financial condition.

Merchant Renewable Generation Portfolio

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

AEP utilizes two subsidiariescontinues to develop its renewable portfolio within the Generation & Marketing segment to further develop its renewable portfolio.  AEP OnSite Partners, LLC workssegment.  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.  AEP OnSite Partners, LLC pursues projects where a suitable termed agreement is entered into with a credit-worthy counterparty.  AEP Renewables, LLCGeneration & Marketing also develops and/or acquires large scale renewable generation projects that are backed with long-term contracts with credit-worthy counterparties. Thesecontracts.  As of March 31, 2018, subsidiaries within AEP’s Generation & Marketing segment have approximately 106400 MWs of contracted renewable generation projects in operation and 23operation.  In addition, as of March 31, 2018, these subsidiaries have approximately 10 MWs of new renewable generation projects under construction with total estimated capital costs of $26 million related to these projects.

In July 2017, APCo submitted filings with the Virginia SCC and the WVPSC requesting regulatory approval to acquire two wind generation facilities totaling approximately 225 MWs of wind generation. The wind generating facilities are located in West Virginia and Ohio and, if approved, are anticipated to be in-service in the second half of 2019. APCo will assume ownership of the facilities at or near the anticipated in-service date. APCo currently plans to sell the Renewable Energy Certificates associated with the generation from these facilities. In December 2017, the WVPSC staff and an industrial intervenor filed testimony in West Virginia and the Virginia SCC staff filed testimony in Virginia arguing that APCo’s forecast of natural gas and energy prices was too high and, with the exception of the WVPSC staff’s recommended approval of the facility located in West Virginia, did not support approval of APCo’s acquisition of the facilities. In January 2018, APCo filed supplemental testimony with the WVPSC to address changes in the economics of the wind projects as a result of Tax Reform. A hearing at the WVPSC was held in March 2018 and briefs were filed in April 2018. The WVPSC staff, the industrial intervenor and the Consumer Advocate Division of the Public Service Commission all recommended that the WVPSC deny APCO’s request for approval of the wind farms. Also in April 2018, the Virginia SCC denied APCo’s application to acquire the two wind generation facilities. APCo filed a petition for reconsideration with the Virginia SCC, which was denied.

In July 2017, PSO and SWEPCo submitted filings with the OCC, LPSC, APSC and PUCT requesting various regulatory approvals needed for the companies to proceed with the Wind Catcher Project. The Wind Catcher Project includes the acquisition of a wind generation facility, totaling approximately 2,000 MWs of wind generation, and the construction of a generation interconnection tie-line totaling approximately 380 miles. Total investment for the project is estimated financial commitmentto be $4.5 billion and will serve both retail and FERC wholesale load. PSO and SWEPCo will have a 30% and 70% ownership share, respectively, in these assets. The wind generating facility is located in Oklahoma and, if approved by all state commissions, is anticipated to be in-service by the end of 2020. In July 2017, the LPSC approved SWEPCo’s request for an exemption to the Market Based Mechanism. In August 2017 and December 2017, the OCC denied the Oklahoma Attorney General’s respective August and December 2017 motions to dismiss. Also in December 2017, the companies filed a request at the FERC to transfer the wind generation facility to PSO and SWEPCo upon its construction by a third party, which was approved in April 2018. The transfer remains subject to the approval of the project at the respective state commissions. Parties’ testimony filed in the Oklahoma, Texas and Louisiana dockets generally opposes the companies’ request. In February 2018, the ALJ in Oklahoma recommended that PSO’s request for preapproval of future recovery of Wind Catcher Project costs be denied. In March 2018, oral arguments were held before three Oklahoma Commissioners regarding the ALJ report and parties agreed to waive the 240 day statutory deadline for an order to continue the discussions. A non-unanimous settlement agreement was filed in Arkansas in

In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. As rebuilding efforts continue, AEP Texas’ total costs related to this storm are not yet final. AEP Texas’ current estimated cost is approximately $235 million.$325 million to $375 million, including capital expenditures. AEP Texas has a PUCT approved catastrophe reserve which allows for the deferral of incremental storm expenses as a regulatory asset, and currently recovers approximately $1 million annually through base rates. As of March 31, 2017, $2002018, the total balance of AEP Texas’ catastrophe reserve deferral is $129 million, inclusive of approximately $105 million of net incremental storm expenses related to Hurricane Harvey. As of March 31, 2018, AEP Texas has recorded approximately $186 million of capital expenditures related to Hurricane Harvey. Also, as of March 31, 2018, AEP Texas has received $10 million in insurance proceeds, which were applied to the regulatory asset and property, plant and equipment. Management, in conjunction with the insurance adjusters, is reviewing all damages to determine the extent of coverage for additional insurance reimbursement. Any future insurance recoveries received will also be applied to, and will offset, the regulatory asset and property, plant and equipment, as applicable. Management believes the amount recorded as a regulatory asset is probable of recovery and AEP Texas is currently evaluating recovery options for the regulatory asset, including securitization. The standard process for storm cost recovery in Texas requires two filings with the PUCT. Management expects the first filing by the end of third quarter of 2018. If the ultimate costs of the incident are not recovered by insurance or through the regulatory process, it would have beenan adverse effect on future net income, cash flows and financial condition.

Merchant Portion of Turk Plant

SWEPCo constructed the Turk Plant, a base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012 and is included in the Vertically Integrated Utilities segment. SWEPCo owns 73% (440 MWs) of the Turk Plant and operates the facility.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%). Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN. In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN. This share of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the wholesale market. Approximately 80% of the Turk Plant investment is recovered under cost-based rate recovery in Texas, Louisiana (subject to prudence review) and through SWEPCo’s wholesale customers under FERC-based rates. As of March 31, 2017,2018, the net book value of Turk Plant was $1.5 billion, before cost of removal, including materials and supplies inventory and CWIP.

In March 2016, a contestedApril 2017, the LPSC approved an uncontested stipulation agreement relatedthat SWEPCo filed for its formula rate plan for test year 2015.  The filing included a net annual increase not to the PPA rider applicationexceed $31 million, which was modifiedeffective May 2017 and approved by the PUCO.includes SWEPCo’s Louisiana jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls which were placed in service in 2016. The approved PPA ridernet annual increase is subject to audit and review byrefund. In October 2017, SWEPCo filed testimony in Louisiana supporting the PUCO. Consistent with the terms of a modified and approved stipulation agreement, and based upon a September 2016 PUCO order, in November 2016, OPCo refiled its amended ESP extension application and supporting testimony. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s Distribution Investment Rider (DIR) and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider.

OfficeFebruary 2018, an intervenor filed for rehearing recommending that the reduced corporate federal income tax rate be reflected in lower purchased power expense related to the Rockport UPA. In February 2018, the KPSC issued an order granting rehearing of Utility Consumer Counselor (OUCC) and other partiesthese items, with an exception for the capital structure adjustments, which was denied by the KPSC.

In December 2016, SWEPCo filed testimonya request with the IURC.PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a return on common equity of 9.6%, effective May 2017. The OUCC recommendedfinal order also included (a) approval to recover the Texas jurisdictional share of environmental investments placed in service, as of June 30, 2016, at various plants, including Welsh Plant, Units 1 and 3, (b) approval of the CPCN but also stated that any decision regarding recovery of, any under-depreciatedbut no return on, the Texas jurisdictional share of the net book value of Welsh Plant, Unit 2, (c) approval of $2 million additional vegetation management expenses and (d) the rejection of SWEPCo’s proposed transmission cost recovery mechanism.

In March 2018, new Virginia legislation impacting investor-owned utilities was enacted, effective July 1, 2018, that will: (a) on a one-time basis, require APCo to exclude $10 million of fuel expenses from the July 2018 over/under calculation, (b) reduce APCo’s base rates by $50 million annually no later than July 30, 2018, on an interim basis and subject to true-up, to reflect the lower federal income tax rate due to retirement should be fully investigated in aTax Reform, (c) require APCo to file its next generation and distribution base rate case notby March 31, 2020 using 2017, 2018 and 2019 test years (“triennial review”), (d) require an adjustment in a tracker or other abbreviated proceeding. The other parties recommended either denial ofAPCo’s base rates on April 1, 2019 to reflect actual annual reductions in corporate income taxes due to Tax Reform, (e) require APCo to obtain approval from the CPCN or approval of the CPCNVirginia SCC for energy efficiency programs with conditions including a cap on the amount of SCRprojected costs allowed to be recovered in the rideraggregate of at least $140 million over the 10-year period from July 1, 2018 through July 1, 2028 and limitations on other costs related(f) require APCo to legal issues involving the Rockport lease. A hearingconstruct and/or acquire solar generation facilities in Virginia of at the IURC was held in March 2017.

FERC Transmission Complaint - AEP’s PJM Participants

In October 2016, severalseven parties filed a joint complaint withat the FERC that statesalleged the base return on common equity used by various AEP affiliatesAEP’s transmission owning subsidiaries within PJM in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint.  In November 2017, a FERC order set the matter for hearing and settlement procedures.  In March 2018, AEP’s transmission owning

In June 2017, several parties filed a complaint at the FERC that states the base return on common equity used by AEP’s transmission owning subsidiaries within SPP in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36%, effective upon the date of the complaint. In November 2017, a FERC order set the matter for hearing and settlement procedures. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.

Modifications to AEP EastAEP’s SPP Transmission Companies Rates

In November 2016, certain AEP affiliatesOctober 2017, AEP’s transmission owning subsidiaries within SPP filed an application withat the FERC to modify the PJMSPP OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to estimated expenses, with a proposed effective date of January 1, 2017.projected expenses.  The filing proposed that themodified SPP OATT formula rates would be implementedare based upon the date provided in the resulting FERC order.on projected 2018 calendar year financial activity and projected plant balances. In MarchDecember 2017, the FERC accepted the proposed modifications effective January 1, 2017,2018, subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017, the AEP East Transmission Companies implemented the modified PJM OATT formula rates subject to refund which are based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these revised ratescosts are not recoverable, it could reduce future net income and cash flows and impact financial condition.

In September 2017, ETEC and NTEC filed a complaint at the FERC that states the base return on common equity used by SWEPCo in calculating their power supply formula rates is excessive and should be reduced from 11.1% to 8.41%, effective upon the date of the complaint. In November 2017, a FERC order set the matter for hearing and settlement procedures. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.

Welsh Plant - Environmental Impact

Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could cost a total of approximately $850 million, excluding AFUDC. As of March 31, 2017,2018, SWEPCo had incurred costs of $398$399 million, including AFUDC, and had remaining contractual construction obligations of $10 million related to these projects.  Management continues to evaluate the impact of environmental rules and related project cost estimates. As of March 31, 2017,2018, the total net book value of Welsh Plant, Units 1 and 3 was $630$625 million, before cost of removal, including materials and supplies inventory and CWIP. 

In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas filed base rate proceeding. In December 2016,April 2017, the LPSC approved deferralrecovery of certain expenses$131 million in investments related to theits Louisiana jurisdictional share of environmental controls installed at Welsh Plant, until these investments are included in base rates. Theeffective May 2017. SWEPCo’s approved Louisiana jurisdictional share of Welsh Plant deferrals through March 31, 2017 weredeferrals: (a) are $11 million, excluding $6 million of unrecognized equity as of March 31, 2018, (b) is subject to review by the LPSC, and include(c) includes a weighted average cost of capital (WACC)WACC return on environmental investments and the related depreciation expense and taxes. In January 2018, SWEPCo has sought recovery ofreceived written approval from the PUCT to recover its project costs from retail customers at the state commissionsin its 2016 Texas base rate case and is recovering these costs from wholesale customers through theirSWEPCo’s FERC-approved agreements.

If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See “Welsh Plant - Environmental Impact” section of Note 4 for additional information.

Westinghouse Electric Company Bankruptcy Filing

In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the USU.S. Bankruptcy Code.  It intends to reorganize, not cease business operations. However, it is in the early stages of the bankruptcy process and it is unclear whether the company can successfully reorganize. Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication and ongoing engineering projects.  The most significant of these relate to Cook Plant fuel fabrication.  I&M is evaluating how thisAs part of the reorganization, affects these contracts.  Westinghouse has stated that it intendsthe bankruptcy court approved Westinghouse’s sale of its nuclear business to continue performance onBrookfield WEC Holdings, a nonaffiliated third party. Pursuant to the sale, Brookfield will assume all of I&M’s contracts but given the importance of upcoming dateswith Westinghouse. The sale is subject to regulatory approvals and is expected to close in the fuel fabrication process for Cook Plant, and their vital part in Cook Plant’s ongoing operations, I&M has approached Westinghouse and expects to make a filing with the bankruptcy court to seek to avoid any interruptions to that service.  In the unlikely event Westinghouse rejects I&M’s contracts, or is unable to reorganize or sell its profitable businesses in the bankruptcy, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services.third quarter of 2018.

LITIGATION

In the ordinary course of business, AEP is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases that have a probable likelihood of loss if the loss can be estimated.  For details on the regulatory proceedings and pending litigation see Note 4 - Rate Matters, Note 6 - Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2016 Annual Report. Additionally, see Note 4 -– Rate Matters and Note 5 -– Commitments, Guarantees and Contingencies included herein.Contingencies. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

Rockport Plant Litigation

In July 2013, the Wilmington Trust Company filed a complaint in the U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022.  The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit.  The plaintiffs further allege that the defendants’ actions constitute breach of the lease and participation agreement.  The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs.  The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M.

In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims, including the dismissal without prejudice of plaintiffs’ claims seeking compensatory damages. Several claims remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. In November 2015, AEGCo and I&M filed a motion to strike the plaintiffs’ motion for partial judgment and filed a motion to dismiss the case for failure to state a claim.

In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, plaintiffs filed an appeal in the U.S. Court of Appeals for the Sixth Circuit on whether

In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions which had dismissed certain of plaintiffs’ claims for breach of contract. The U.S. Court of Appeals for the Sixth Circuit determined that the district court erred in holding that the modification to the consent decree was permitted under the terms of the lease agreementcontract and remandedremanding the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. In April 2017, AEGCo and I&M intend to filefiled a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit. TheCircuit, which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reverses the district court’s dismissal of certain of the owners’ claims under the lease agreements, vacates the denial of the owners’ motion for partial summary judgment and remands the case to the district court had previouslyfor further proceedings.  The amended opinion and judgment also affirms the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims and removes the instruction to the district court in the original opinion to enter summary judgment in favor of the owners.

Management will continue to defend against the claims. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature. In addition,premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages. As a result,damages, management is unable to determine a range of potential losses that are reasonably possible of occurring.

ENVIRONMENTAL ISSUES

AEP is engaged in litigation about environmental issues, was notified of potential responsibility for the clean-up of contaminated sites and incurred costs for disposal of SNF and future decommissioning of the nuclear units.  AEP, along with various industry groups, affected states and other parties challenged some of the Federal EPA requirements in court.  Management is also engaged in the development of possible future requirements including the items discussed below.  Management believes that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

See a complete discussion of these matters in the “Environmental Issues” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2016 Annual Report. AEP will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances.  If AEP is unable to recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sectionsbelow will have a material impact on the generating units in the AEP System.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of March 31, 2017,2018, the AEP System had a total generating capacity of approximately 25,600 MWs, of which approximately 13,500 MWs are coal-fired.  Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on the fossil generating facilities. Based upon management estimates, AEP’s investment to meet these existing and proposed requirements ranges from approximately $4.3$2.1 billion to $4.9$2.7 billion between 2012 andthrough 2025.

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in finalizing proposed rules or reviewing and revising certain existing requirements.  The cost estimates will also change based on: (a) the states’ implementation of these regulatory programs, including the potential for state implementation plans (SIPs) or federal implementation plans (FIPs) that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on the units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.  In addition, management is continuing to evaluate the economic feasibility of environmental investments on both regulated and competitive plants.

The table below represents the plants or units of plants retired in 2016 and 2015 with a remaining net book value. As of March 31, 2017,2018, the net book value before cost of removal, including related materials and supplies inventory and CWIP balances, of the units listed below was approved for recovery, except for $333$218 million. Management will seekis seeking or plans towill seek recovery of the remaining net book value of the remaining assets$218 million in future rate proceedings.

In January 2017, Dayton Power and Light Company announced the future retirement of the 2,308 MW Stuart Plant, Units 1-4. The retirement is scheduled for June 2018. Stuart Plant, Units 1-4 are operated by Dayton Power and Light Company and are jointly owned by AGR and nonaffiliated entities. AGR owns 600 MWs of the Stuart Plant, Units 1-4. As of March 31, 2017,2018, AGR’s net book value of the Stuart Plant, Units 1-4 was zero.

To the extent existing generation assets and the cost of new equipment and converted facilities are not recoverable, it could materially reduce future net income and cash flows and impact financial condition.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions. The states implement and administer many of these programs and could impose additional or more stringent requirements. The primary regulatory programs that continue to drive investments in AEP’s existing generating units include: (a) periodic revisions to the National Ambient Air Quality Standards (NAAQS) and the development of SIPs to achieve any more stringent standards; (b) implementation of the regional haze program by the states and the Federal EPA; (c) regulation of hazardous air pollutant emissions under the Mercury and Air Toxics Standards (MATS) Rule; (d) implementation and review of the Cross-State Air Pollution Rule (CSAPR), a FIP designed to eliminate significant contributions from sources in upwind states to nonattainment or maintenance areas in downwind states and (e) the Federal EPA’s regulation of greenhouse gas emissions from fossil-fueled electric generating units under Section 111 of the CAA.

In March 2017, President Trump issued a series of executive orders designed to allow the Federal EPA to review and take appropriate action to revise or rescind regulatory requirements that place undue burdens on affected entities, including specific orders directing the Federal EPA to review rules that unnecessarily burden the production and use of energy. The Federal EPA published notice and an opportunity to comment on how to identify such requirements and what steps can be taken to reduce or eliminate such burdens. Future changes that result from this effort may affect AEP’s compliance plans.

Regional Haze

The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) will address regional haze in federal parks and other protected areas.  BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants.  CAVR will be implemented through SIPs or, if SIPs are not adequate or are not developed on schedule, through FIPs.  In January 2017, the Federal EPA 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 the U.S. Court of Appeals for the District of Columbia Circuit.

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

In 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants.  The rule establishes unit-specific emission rates for units burning coal on a 30-day rolling average basis for mercury, PM (as a surrogate for particles of nonmercury metals) and hydrogen chloride (as a surrogate for acid gases).  In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans.  Compliance was required within three years. Management obtained administrative extensions for up to one year at several units to facilitate the installation of controls or to avoid a serious reliability problem.

In April 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied all of the petitions for review of the April 2012 final rule. Industry trade groups and several states filed petitions for further review in the U.S. Supreme Court and the court granted those petitions in November 2014.

In June 2015, the U.S. Supreme Court reversed the decision of the U.S. Court of Appeals for the District of Columbia Circuit. The U.S. Court of Appeals for the District of Columbia Circuit remanded the MATS rule for further proceedings consistent with the U.S. Supreme Court’s decision that the Federal EPA was unreasonable in refusing to consider costs in its determination whether to regulate emissions of HAPs from power plants. The Federal EPA issued notice of a supplemental finding concluding that it is appropriate and necessary to regulate HAP emissions from coal-fired and oil-fired units. Management submitted comments on the proposal. In April 2016, the Federal EPA affirmed its determination that regulation of HAPs from electric generating units is necessary and appropriate. Petitions for review of the Federal EPA’s April 2016 determination have been filed in the U.S. Court of Appeals for the District of Columbia Circuit. Oral argument was scheduled for May 2017, but in April 2017 the Federal EPA requested that oral argument be postponed to facilitate its review of the rule. The rule remains in effect.

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.  Management is taking steps to comply with these requirements, including increasing wind and solar installations and power purchases and broadening the AEP System’s portfolio of energy efficiency programs.

The Federal EPA also published proposed “model” rules that cancould be adopted by the states that would allow sources within “trading ready” state programs to trade, bank or sell allowances or credits issued by the states. These rules would also be the basis for any federal plan issued by the Federal EPA in a state that fails to submit or receive approval for a state plan. In June 2016, the Federal EPA issued a separate proposal for the Clean Energy Incentive Program (CEIP) that was included in the model rules.

The final rules are being challenged in the courts. In February 2016, the U.S. Supreme Court issued a stay on the final Clean Power Plan,CPP, including all of the deadlines for submission of initial or final state plans. The stay will remain in effect until a final decision is issued by the U.S. Court of Appeals for the District of Columbia Circuit and the U.S. Supreme Court considers any petition for review. In April 2017, the Federal EPA withdrew its previously issued proposals for model trading rules and a CEIP.

In March 2017, the Federal EPA filed in the U.S. Court of Appeals for the District of Columbia Circuit notice of 1)of: (a) an Executive Order from the President of the United States titled “Promoting Energy Independence and Economic Growth” directing the Federal EPA to review the Clean Power PlanCPP and related rules; 2)(b) the Federal EPA’s initiation of a review of the Clean Power PlanCPP and 3) if the Federal EPA determines appropriate,(c) a forthcoming rulemaking related to the Clean Power PlanCPP consistent with the Executive Order.Order, if the Federal EPA determines appropriate. In this same filing, the Federal EPA also presented a motion to hold the litigation in abeyance until 30 days after the conclusion of review andof any resulting rulemaking. The District of Columbia Circuit granted the Federal EPA’s motion in part and has requested periodic status reports. In AprilOctober 2017, the Federal EPA withdrewissued a proposed rule repealing the CPP and withdrawing the legal memoranda issued in connection with the rule. The Federal EPA has re-examined its legal interpretation of the “best system of emission reduction” and found that based on the statutory text, legislative history, use of similar terms elsewhere in the CAA and its own historic implementation of Section 111 that a narrower interpretation of the term limits it to those designs, processes, control technologies and other systems that can be applied directly to or at the source. Since the primary systems relied on in the CPP are not consistent with that interpretation, the Federal EPA proposes that the rule be withdrawn. The comment period on the proposed rulerepeal has been extended to April 2018. In December 2017, the Federal EPA issued an advanced notice of proposed rulemaking seeking information that should be considered by the Federal EPA in developing guidelines for state programs. Management is actively monitoring these rulemakings and participating in the development of any new guidelines.

Coal Combustion Residual Rule

In April 2015, the Federal EPA published a final rule to regulate the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants.  

The final rule became effective in October 2015. The Federal EPA regulates CCR are regulated as a non-hazardous solid waste by its issuance ofwastes and facilities managing CCR must meet new minimum federal solid waste management standards. The rule applies to new and existing active CCR landfills and CCR surface impoundments at operating electric utility or independent power production facilities. The rule imposes new and additional construction and operating obligations, including location restrictions, liner criteria, structural integrity requirements for impoundments, operating criteria and additional groundwater monitoring requirements to be implemented on a schedule spanning an approximate four year implementation period. ChallengesCertain records must be posted to the rule by industry associations of which AEP is a member are proceeding.publicly available internet site.

In December 2016, the U.S. Congress passed legislation authorizing states to submit programs to regulate CCR facilities, and the Federal EPA to approve such programs if they are no less stringent than the minimum federal standards. The Federal EPA may also enforce compliance with the minimum standards until a state program is approved or if states fail to adopt their own programs. In September 2017, the Federal EPA granted industry petitions to reconsider the CCR rule and asked that litigation regarding the rule be held in abeyance. The U.S. Court of Appeals for the District of Columbia Circuit heard oral argument in November 2017. In March 2018, the Federal EPA issued a proposed rule to modify certain provisions of the solid waste management standards and provide additional flexibility to facilities regulated under approved state programs. The comment period is open until the end of April 2018. Management supports the adoption of more flexible compliance alternatives subject to the Federal EPA or state oversight.

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 at some point in the future as the new rule is implemented. Management recorded a $95 million increase in asset retirement obligations in the second quarter of 2015 primarily due to the publication of the final rule. Management will continue to evaluate the rule’s impact on operations.

Clean Water Act (CWA) Regulations

In 2014, the Federal EPA issued a final rule setting forth standards for existing power plants that is intended to reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water.  Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress.  The final rule affects all plants withdrawing more than two million gallons of cooling water per day. The rule offers seven technology options to comply with the impingement standard and requires site-specific studies to determine appropriate entrainment compliance measures at facilities withdrawing more than 125 million gallons per day. Additional requirements may be imposed as a result of consultation with other federal agencies to protect threatened and endangered species and their habitats. Facilities with existing closed cycle recirculating cooling systems, as defined in the rule, are not expected to require any technology changes. Facilities subject to both the impingement standard and site-specific entrainment studies will typically be given at least three years to conduct and submit the results of those studies to the permit agency. Compliance timeframes will then be established by the permit agency through each facility’s National Pollutant Discharge Elimination System (NPDES)NPDES permit for installation of any required technology changes, as those permits are renewed over the next five to eight years. Petitions for review of the final rule were filed by industry and environmental groups and are currently pending in the U.S. Court of Appeals for the Second Circuit.

In addition, the Federal EPA developed revised effluent limitation guidelines for electricity generating facilities.  A final rule was issued in November 2015. The final rule establishes limits on flue gas desulfurizationFGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater to be imposed as soon as possible after November 2018 and no later than December 2023. These new requirements will be implemented through each facility’s wastewater discharge permit. The rule has been challenged in the U.S. Court of Appeals for the Fifth Circuit. In March 2017, industry associations filed a petition for reconsideration of the rule with the Federal EPA. In April 2017, the Federal EPA granted reconsideration of the rule and issued a stay of the rule’s future compliance deadlines.deadlines, which has now expired. In April 2017, the U.S. Court of Appeals for the Fifth Circuit granted a stay of the litigation for 120 days. In June 2017, the Federal EPA also issued a proposal to temporarily postpone certain compliance deadlines in the rule. A final rule revising the compliance deadlines for FGD wastewater and bottom ash transport water to be no earlier than 2020 was issued in September 2017. Management submitted comments supporting the proposed postponement. Management continues to assess technology additions and retrofits to comply with the rule and the impacts of the Federal EPA’s recent actions on facilities’ wastewater discharge permitting.

In June 2015, the Federal EPA and the U.S. Army Corps of Engineers jointly issued a final rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases. The CWA provides for federal jurisdiction over “navigable waters” defined as “the waters of the United States.” This jurisdictional definition applies to all CWA programs, potentially impacting generation, transmission and distribution permitting and compliance requirements. Among those programs are:are permits for wastewater and storm water discharges, permits for impacts to wetlands and water bodies and oil spill prevention planning. The final definition continues to recognize traditional navigable waters of the U.S. as jurisdictional as well as certain exclusions. The rule also contains a number of new specific definitions and criteria for determining whether certain other waters are jurisdictional because of a “significant nexus.” Management believes that clarity and efficiency in the permitting process is needed. Management remains concerned that the rule introduces new concepts and could subject more of AEP’s operations to CWA jurisdiction, thereby increasing the time and complexity of permitting. The final rule is being challenged in both courts of appeal and district courts. Challengers include industry associations of which AEP is a member. The U.S. Court of Appeals for the Sixth Circuit granted a nationwide stay of the rule pending jurisdictional determinations. In February 2016, the U.S. Court of Appeals for the Sixth Circuit issued a decision holding that it has exclusive jurisdiction to decide the challenges to the “waters of the United States” rule. Industry, state and related associations have filed petitions for a rehearing of the jurisdictional decision. In April 2016, the U.S. Court of Appeals for the Sixth Circuit denied the petitions. In January 2017, the decision was appealed to the U.S. Supreme Court, which granted certiorari to review the jurisdictional issue. Oral argument was heard in October 2017. In January 2018, the U.S. Supreme Court ruled that challenges to the definition of “waters of the United States” must be filed in the federal district court, and remanded the case to the U.S. Court of Appeals for the Sixth Circuit with directions to dismiss the petitions for review for lack of jurisdiction. The stay has been lifted and the Sixth Circuit case has been dismissed. Challenges to the rule will proceed in federal district courts.

In March 2017, the Federal EPA published a notice of intent to review the rule and provide an advanced notice of a proposed rulemaking consistent with the Executive Order of the President of the United States directing the Federal EPA and U.S. Army Corps of Engineers to review and rescind or revise the rule. The U.S. Supreme Court deniedIn June 2017, the related motionagencies signed a notice of proposed rule to hold briefingrescind the definition of “waters of the United States” that was adopted in abeyance pending furtherJune 2015, and to re-codify the definition of that phrase as it existed immediately prior to that action. This action would effectively retain the status quo until a new rule is adopted by the agencies. The Federal EPA actions onand U.S. Army Corps of Engineers also finalized a new rule to extend the applicability date of the 2015 rule andby two years before the appeal onnationwide stay issued by the jurisdictional issue continues.U.S. Court of Appeals for the Sixth Circuit was lifted. Challenges to the applicability date rule have been filed by third parties in several federal district courts. Management will participate in further rulemaking activities.

AEP’s primary business is the generation, transmission and distribution of electricity.  Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

AEP’s reportable segments and their related business activities are outlined below:

Vertically Integrated Utilities

Transmission and Distribution Utilities

AEP Transmission Holdco

Generation & Marketing

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

The following discussion of AEP’s results of operations by operating segment includes an analysis of gross margin,Gross Margin, which is a non-GAAP financial measure. Gross marginMargin includes Total Revenues less the costs of Fuel and Other Consumables Used for Electric Generation as well as Purchased Electricity for Resale Generation Deferrals and Amortization of Generation Deferrals as presented in the Registrants statements of income as applicable. TheseUnder the various state utility rate making processes, these expenses are generally collectedreimbursable directly from customers through cost recovery mechanisms.and billed to customers. As such, management uses gross margina 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 internal reporting analysis asinvestors and other financial statement users to analyze AEP’s financial performance in that it excludes the fluctuations in revenueeffect on Total Revenues caused by changesvolatility in these expenses. Operating income,Income, which is presented in accordance with GAAP in AEP’s statements of income, is the most directly comparable GAAP financial measure to the presentation of gross margin.Gross Margin. AEP’s definition of gross marginGross Margin may not be directly comparable to similarly titled financial measures used by other companies.

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

First Quarter of 20172018 Compared to First Quarter of 20162017

Earnings Attributable to AEP Common Shareholders increaseddecreased from $501 million in 2016 to $592 million in 2017 to $454 million in 2018 primarily due to:

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

VERTICALLY INTEGRATED UTILITIES

Summary of KWh Energy Sales for Vertically Integrated Utilities

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

First Quarter of 20172018 Compared to First Quarter of 20162017

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

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

TRANSMISSION AND DISTRIBUTION UTILITIES

Summary of KWh Energy Sales for Transmission and Distribution Utilities

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

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

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

AEP TRANSMISSION HOLDCO

Summary of Net PlantInvestment in Service and CWIPTransmission Assets for AEP Transmission Holdco

 

Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco

(in millions)

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

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

GENERATION & MARKETING

Summary of MWhs Generated for Generation & Marketing

First Quarter of 20172018 Compared to First Quarter of 20162017

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:

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