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, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in AEPTCo’s 2016 Annual Report included within AEPTCo’s Registration Statement, 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

AEP’s weather-normalized retail sales volumes for the second quarter of 20172018 increased by 0.7% compared to second quarter of 2016. AEP’s second quarter 2017 industrial sales increased by 3.3%2.0% compared to the second quarter of 2016.2017. AEP’s second quarter 2018 industrial sales increased by 3.0% compared to the second quarter of 2017. The growth in industrial sales was spread across many industries and most operating companies. Weather-normalized residential sales increased 0.6%2.1% in the second quarter of 20172018 compared to the second quarter of 2016.2017. Weather-normalized commercial sales decreasedincreased by 1.9%0.7% in the second quarter of 20172018 compared to the second quarter of 2016.2017.

AEP’s weather-normalized retail sales volumes for the six months ended June 30, 2017 decreased2018 increased by 0.2%1.7% compared to the six months ended June 30, 2016, partially due to 2016 being a leap year and including one additional day in comparison to 2017. AEP’s industrial sales volumes for the six months ended June 30, 20172018 increased 1.6%2.8% compared to the six months ended June 30, 2016 primarily due to2017. The growth in industrial sales to customers in the manufacturing sector.was spread across many industries and most operating companies. Weather-normalized residential and commercial sales decreased 1.0%increased 1.7% and 1.4%0.6%, respectively, for the six months ended June 30, 20172018 compared to the six months ended June 30, 2016.2017.

In September 2016, AEP signed an agreementJuly 2017, PSO and SWEPCo submitted filings with the OCC, LPSC, APSC and PUCT requesting various regulatory approvals needed for the companies to sell Darby, Gavin, Lawrenceburg and Waterford Plants (“Disposition Plants”)proceed with the Wind Catcher Project. The Wind Catcher Project includes the acquisition of a wind generation facility, totaling 5,329approximately 2,000 MWs of competitivewind generation, and the construction of a generation interconnection tie-line totaling approximately 350 miles. Total investment for the project is estimated to be $4.5 billion and will serve both retail and FERC wholesale load. PSO and SWEPCo will have 30% and 70% ownership shares, respectively, in these assets. The wind generation facility is located in Oklahoma and, if approved by all state commissions, is anticipated to be in-service by the end of 2020. 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 nonaffiliated party. The sale closedrequest at the FERC to transfer the wind generation facility to PSO and SWEPCo upon its construction by a third party, which was approved in January 2017 for approximately $2.2 billion. The net proceeds from the transaction were approximately $1.2 billion in cash after taxes, repayment of debt associated with these assets and transaction fees, which resulted in an after tax gain of approximately $129 million. AEP primarily used these proceeds to reduce outstanding debt and invest in its regulated businesses including transmission, and contracted renewable projects.

In February 2017, AEP signed2018, an 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 settlement discussions. A non-unanimous settlement agreement was filed in Arkansas in February 2018, a unanimous settlement was filed in April 2018 in Louisiana and a non-unanimous settlement was filed in April 2018 in Oklahoma. An amendment to sell its 25.4% ownership sharethe Joint Stipulation in Oklahoma was filed in May 2018 to include additional parties to the non-unanimous settlement. A separate Joint Stipulation and settlement agreement was reached between PSO and two other parties. The settlement agreements and the companies’ rebuttal testimony filed in Oklahoma, Texas, Arkansas and Louisiana, generally contain certain commitments of Zimmer PlantPSO and SWEPCo, including a most favored nation clause, a cap on the cost of the investment, guarantees of qualification for production tax credits, minimum annual production from the project and a net benefits guarantee for ten years. In addition, PSO and SWEPCo committed in each jurisdiction to Dynegy Corporation. Simultaneously, AEP signed an agreementthe timely filing of a base rate case to purchase Dynegy Corporation’s 40% ownership shareshorten the duration of Conesville Plant, Unit 4. The transactions closedcost recovery through a temporary mechanism. In May 2018, the APSC approved SWEPCo’s petition to proceed with the Wind Catcher Project. In June 2018, the LPSC approved SWEPCo’s petition to proceed with the Wind Catcher Project. In July 2018, a hearing on the settlement agreements presented in the secondPSO case was held before the three OCC Commissioners. Also in July 2018, representatives from SWEPCo and AEPSC presented oral arguments before the three PUCT Commissioners. Rulings by the PUCT and OCC are expected in the third quarter of 2017 and did not have a material impact on net income, cash flows and financial condition.

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 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 creditworthy 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 June 30, 2018, subsidiaries within AEP’s Generation & Marketing segment have approximately 120400 MWs of contracted renewable generation projects in operation and 56operation.  In addition, as of June 30, 2018, these subsidiaries have approximately 7 MWs of new renewable generation projects under construction with antotal estimated financial commitmentcapital costs of approximately $317 million. As$16 million related to these projects.

In January 2018, AEP admitted a nonaffiliate as a member of Desert Sky Wind Farm LLC and Trent Wind Farm LLC (collectively “the LLCs”) to own and repower Desert Sky and Trent.  The nonaffiliated member contributed full turbine sets to each project in exchange for a 20.1% interest in the LLCs. AEP’s 79.9% share of the LLCs, or 248 MWs, represents $232 million of additional estimated capital, of which $185 million has been incurred and placed into service as property, plant and equipment as of June 30, 2017, $221 million2018. AEP is subject to a put and a call option after certain conditions are met, either of capital costs have been incurred related to these projects.which would liquidate the nonaffiliated member’s interest. See Note 13 - Variable Interest Entities for additional information.

Regulated Renewable Generation Facilities

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 MWMWs of wind generation. 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 May 2018, the WVPSC also denied APCo’s application to acquire the two wind generation facilities.

The Registrants expect the mechanism and time period to provide the benefits of Tax Reform to customers will continue to vary by jurisdiction. Tax Reform did not have a material impact on net income in the second quarter of 2018 and is not expected to have a material impact on future net income. However, the Registrants anticipate a decrease in future cash flows primarily due to the elimination of bonus depreciation, the reduction in the federal tax rate from 35% to 21% and the flow back of Excess ADIT. Further, the Registrants expect that access to capital markets will be sufficient to satisfy any liquidity needs that result from any such decrease in future cash flows.

Management continues to evaluate potential alternatives for its remaining merchant coal generation assets. These potential alternatives may include, but are not limited to, transfer or sale of AEP’s ownership interests or a wind generating facilitiesdown 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.

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 locatednot yet final. AEP Texas’ current estimated cost is approximately $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 of storm costs annually through base rates. As of June 30, 2018, the total balance of AEP Texas’ catastrophe reserve deferral is approximately $145 million, inclusive of approximately $121

million of incremental storm expenses recorded as a regulatory asset related to Hurricane Harvey. As of June 30, 2018, AEP Texas has recorded approximately $199 million of capital expenditures related to Hurricane Harvey. Also, as of June 30, 2018, AEP Texas has received $10 million in West Virginiainsurance proceeds, which were applied to the regulatory asset and Ohioproperty, plant and ifequipment. 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 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 will request securitization of the regulatory asset. The standard process for securitization of storm cost recovery in Texas requires two filings with the PUCT. Management expects that AEP Texas will make the first filing by the end of the third quarter of 2018. If the ultimate costs of the incident are not recovered by insurance or through the regulatory process, it would have an adverse effect on future net income, cash flows and financial condition.

In April 2018, the PUCO issued an order approving the ESP extension through May 2024 which includes: (a) an extension of the OVEC PPA rider, (b) a 10% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved are anticipatedin the June 2015 - May 2018 ESP, (d) rate caps related to OPCo’s DIR ranging from $215 million to $290 million for the periods 2018 through 2021, (e) the addition of various new riders, including a Smart City Rider and a Renewable Generation Rider, (f) a decrease in annual depreciation rates, effective June 1, 2018, based on a depreciation study using data through December 2015 and (g) amortization of approximately $24 million annually beginning June 2018 of OPCo’s excess distribution accumulated depreciation reserve, which was $239 million as of December 31, 2015. Upon the issuance of the PUCO order, OPCo stopped recording $39 million in annual amortization in June 2018, which was previously approved to end in December 2018 in accordance with PUCO’s December 2011 OPCo distribution base rate case order. OPCo and intervenors agreed that OPCo can request in future proceedings a change in meter depreciation rates due to retired meters pursuant to the smart grid Phase 2 project. DIR rate caps will be in-servicereset in OPCo’s next distribution base rate case which must be filed by June 2020.

A 2016 SEET hearing was held in April 2018 and management expects to receive an order in the second half of 2019. APCo will assume ownership2018. While management believes that OPCo’s adjusted 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s proposed SEET adjustments, including treatment of the facilities atGlobal Settlement issues described above, adjust the comparable risk group or nearadopt a different 2016 SEET threshold. If the anticipated in-service date. APCo currently plans to sell the Renewable Energy Certificates associated with the generation from these facilities.PUCO orders a refund of 2016 OPCo earnings, it could negatively affect future SEET filings, reduce future net income and cash flows and impact financial condition. See “2016 SEET Filing” section of Note 4 for additional information.

In March 2018, the IURC issued an order approving: (a) the CPCN, (b) the $274 million estimated cost of the SCR, excluding AFUDC, (c) deferral of the Indiana jurisdictional ownership share of costs, including investment carrying costs, (d) depreciation of the SCR asset over 10 years and (e) recovery of these assets. The wind generating facility is located in Oklahomacosts using an I&M Indiana rider.

In April 2018, a group of intervenors filed a Petition for Reconsideration and if approved by all state commissionsRehearing of the March 2018 IURC order.  In June 2018, the IURC denied the Petition for Reconsideration and the FERC, is anticipated to be in-service by the end of 2020. Rehearing.

In July 2017, I&M filed a request with the LPSC approved SWEPCo’s requestIURC for an exemptiona $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to a temporary offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the Market Based Mechanism.timing of estimated in-service dates of certain capital expenditures.  The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Plant Life Cycle Management Project.

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 June 30, 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 December 2016, OPCo recordedApril 2017, the LPSC approved an uncontested stipulation agreement that SWEPCo filed for its formula rate plan for test year 2015.  The filing included a 2016 SEET provision of $58net annual increase not to exceed $31 million, based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings. Inwhich was effective May 2017 OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group. Although management believes that OPCo’s 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s SEET treatment of the Global Settlement issues described above or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could reduce future net income and cash flows and impact financial condition. See “2016 SEET Filing” section of Note 4.

In JuneApril 2018, SWEPCo filed its formula rate plan for test year 2017 KPCo filed a request with the KPSC forLPSC.  The filing included a $66net $28 million annual increase, which will be effective August 2018. The increase included SWEPCo’s jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls. The filing also included a reduction in the federal income tax rate due to Tax Reform.

In July 2018, SWEPCo made a supplemental filing to its formula rate plan with the LPSC to reduce the requested annual increase to $18 million. The difference between SWEPCo’s requested $28 million annual increase and the $18 million annual increase in Kentucky base rates based upon a proposed 10.31%the supplemental filing is primarily the result of the return on common equity with the increaseof Excess ADIT benefits to be implemented no later than January 2018. The proposed increase includes: (a) lost load since KPCo last changed base rates in July 2015, (b) incremental costs related to OATT charges from PJM not currently recovered from retail ratepayers, (c) increased depreciation expense including updated Big Sandy, Unit 1 depreciation rates using a proposed retirement date of 2031, (d) recovery of other Big Sandy, Unit 1 generation costs currently recovered through a retail rider and (e) incremental purchased power costs. Additionally, KPCo requested a $4 million annual increase in environmental surcharge revenues. customers.

If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

In October 2016, severalseven parties filed a joint complaint withat the FERC that statesalleged the base return on common equity used by various eastern 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.

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 estimatedprojected expenses.  The modified SPP OATT formula rates are based on projected 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 modified PJM OATT formula rates were implemented, subject to refund, based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could total approximately $850$550 million, excluding AFUDC. As of June 30, 2017,2018, SWEPCo had incurred costs of $398$399 million, including AFUDC, related to these projects.  Management continues to evaluate the impact of environmental rules and related project cost estimates. As of June 30, 2017,2018, the total net book value of Welsh Plant, Units 1 and 3 was $628$624 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 April 2017, the LPSC approved SWEPCo’s recovery of $131 million in investments related to Louisiana’sits Louisiana jurisdictional share of environmental costs,controls installed at Welsh Plant, effective May 2017. SWEPCo has sought recoverySWEPCo’s approved Louisiana jurisdictional share of its project costs from retail customers atWelsh Plant deferrals: (a) are $11 million, excluding $6 million of unrecognized equity as of June 30, 2018, (b) is subject to review by the PUCTLPSC and is recovering these costs from wholesale customers through their FERC-approved agreements. (c) includes a WACC return on environmental investments and the related depreciation expense and taxes. See “2017 Louisiana Formula Rate Filing” and “2018 Louisiana Formula Rate Filing” disclosures above.

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

In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the U.S. Bankruptcy Code.  It intends to reorganize, not cease business operations. However, it is in the early stages of the bankruptcy process and it is unclear whether the company can successfully reorganize. Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication and ongoing engineering projects.  The most significant of these relate to Cook Plant fuel fabrication.  I&M is evaluating how 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 (Brookfield), a nonaffiliated third party. Pursuant to the sale, Brookfield will assume all of I&M’s contracts but givenwith Westinghouse. The sale is subject to regulatory approvals by the importance of upcoming datesIURC and the MPSC 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 continues to work with Westinghouse in the bankruptcy proceedings to avoid any interruptions to that service. In the unlikely event Westinghouse rejects I&M’s contracts, or is unable to reorganize or sell its profitable businesses in the bankruptcy, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services.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.

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 willwould be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022.  The terms of the consent decree allow the installation of environmental emission control equipment, repowering 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&M sought and order granting the motion in part and denying the motion in part. The court dismissedwere granted dismissal of 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

In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions which had dismissedin part. In June 2017, on rehearing, the court of appeals issued an amended opinion reversing the district court’s dismissal of 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 agreement and remanded the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. In April 2017, AEGCo and I&M filed a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit, which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reverses the district court’s dismissal of certain of the owners’ claims under the lease agreements, vacatescontract, vacating the denial of the owners’plaintiffs’ motion for partial summary judgment and remandsremanding the case to the district court for further proceedings.  The amended opinion and judgment also affirmsaffirmed 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 removesremoved 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, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management is unable to determine a range of potential losses that are reasonably possible of occurring. In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio seeking to modify the consent decree to eliminate the obligation to install future controls at Rockport 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.

ENVIRONMENTAL ISSUES

AEP has a substantial capital investment program and is incurring additional operational costs to comply with environmental control requirements.  Additional investments and operational changes will need to be made in response to existing and anticipated requirements such as new CAA requirements to reduce emissions from fossil fuel-fired power plants, rules governing the beneficial use and disposal of coal combustion products,by-products, clean water rules and renewal permits for certain water discharges.

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

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

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 June 30, 2017,2018, the AEP System had a total generating capacity of approximately 25,600 MWs, of which approximately 13,500 MWs arewere coal-fired.  Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on the fossil generating facilities. Based upon management estimates, AEP’s investment to meet these existing and proposed requirements ranges from approximately $2.2$650 million to $1.5 billion to $2.8 billion between 2017 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, (g) the outcome of the pending motion to modify the NSR consent decree and (g)(h) 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 previously retired in 2016 and 2015 withthat have a remaining net book value. As of June 30, 2017,2018, the net book value before cost of removal, including related materials and supplies inventory, and CWIP balances, of the plants/units listed below was approved for recovery, except for $339$190 million. Management is seeking or will seek recovery of the remaining net book value associated with these plantsof $190 million in future rate proceedings.

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.

In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio seeking to modify the consent decree to eliminate an obligation to install future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree.  AEP has also soughtThe other parties to the consent decree opposed AEP’s motion. The district court granted AEP’s request to delay the existing deadline to install SCR technology at Rockport Plant, Unit 2 currently scheduleduntil June 2020.

AEP is seeking to modify the consent decree as a means to resolve or substantially narrow the issues in pending litigation with the owners of Rockport Plant, Unit 2. See “Rockport Plant Litigation” in Management’s Discussion and Analysis of Financial Condition and Results of Operations and in Note 5 - Commitments, Guarantees and Contingencies for additional information.

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;standards, (b) implementation of the regional haze program by the states and the Federal EPA;EPA, (c) regulation of hazardous air pollutant emissions under the Mercury and Air Toxics Standards (MATS) Rule;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.

Notable developments in significant CAA regulatory requirements affecting AEP’s operations are discussed in the following sections.

Most areas of the country were designated attainment or unclassifiable for the 2015 ozone standard in November 2017. The Federal EPA finalized nonattainment designations for the remaining areas in April and July 2018. The Federal EPA has also issued information to assist the states in developing plans that address their obligations under the interstate transport provisions of the CAA for the 2008 and 2015 ozone standards. The Federal EPA has 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. State implementation plans for the 2015 ozone standard are due in October 2018. The Federal EPA had requested a stay of proceedings in the U.S. Court of Appeals for the District of Columbia Circuit where challenges to the 2015 ozone standard are pending, to allow reconsideration of that standard by the new administration. The Federal EPA also announced a one-year delay

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) willwould 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.

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