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 20152016 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.

AEP’s weather-normalized retail sales volumes for the thirdfirst quarter of 2017 decreased by 1.2% from the first quarter of 2016, decreased by 0.5% from the thirdpartially due to 2016 being a leap year and including one additional day in comparison to 2017. AEP’s first quarter of 2015. AEP’s third quarter 20162017 industrial sales decreased 2.6%0.2% compared to the thirdfirst quarter of 2015 primarily due to decreased2016. The results were mixed by industry despite growth in sales to customers in the manufacturing sector. Weather-normalized residential sales increased by 1.2%oil and commercial sales decreased by 0.5% in the third quarter of 2016, respectively, from the third quarter of 2015.

In September 2016, AEP signed an agreement to sell Darby, Gavin, Lawrenceburg and Waterford Plants (“Disposition Plants”) totaling 5,3265,329 MWs of competitive generation for approximately $2.2 billion to a nonaffiliated party. The sale is subject to regulatory approvalsclosed in January 2017 for approximately $2.2 billion. The net proceeds from the FERC, the IURC and federal clearance pursuant to the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR). In October 2016, the Federal Trade Commission granted the sale early termination of the HSR waiting period thereby satisfying the HSR conditions to close the transaction. As of September 30, 2016, the net book value of these assets, including related materials and supplies inventory and CWIP, was $1.8 billion. AEP expects to receive net proceeds oftransaction were approximately $1.2 billion in cash after taxes, repayment of debt retirementassociated with these assets and transaction fees. AEP is evaluating options to invest these proceeds, including reinvestmentfees, which resulted in regulated businesses and renewable energy projects and additional debt retirement. The sale is expected to close in the first quarter of 2017. Anan after tax gain of approximately $150 million is expected from the sale subject$127 million. AEP primarily used these proceeds to inventory true-ups, income taxreduce outstanding debt and other adjustments.invest in its regulated businesses including transmission, and contracted renewable projects.

The assets and liabilities included in the sale transaction have been recorded as Assets Held for Sale and Liabilities Held for Sale, respectively, on the balance sheet as of September 30,December 31, 2016. See “Assets and Liabilities Held for Sale” section of Note 6 for additional information.

Management continues to evaluate potential alternatives for the remaining merchant generation assets. These potential alternatives may include, but are not limited to, propose restructuring of Ohio electricity regulations to allow certain of these assets to be acquired by OPCo for the benefit of its customers, 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 close in the second quarter of 2017, subject to FERC approval and are not expected to have a material impact on net income, cash flows and 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. AEP is also continuing a separate strategic review and evaluating alternatives related to the 48 MW Racine Hydroelectric Plant. 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.

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 has formedutilizes two new subsidiaries within the Generation & Marketing segment to further develop its renewable portfolio.  AEP OnSite Partners, LLC works directly with wholesale and large retail customers to provide tailored solutions based upon market knowledge, technology innovations and deal structuring which may include distributed solar, wind, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other forms of cost reducing energy technologies.  AEP OnSite Partners, LLC pursues projects where a suitable termed agreement is entered into with a credit-worthy counterparty.  AEP Renewables, LLC develops and/or acquires large scale renewable generation projects that are backed with long-term contracts with credit-worthy counterparties. These subsidiaries have approximately 4 MW106 MWs of renewable generation projects in operation and 56 MW23 MWs of renewable generation projects under construction with an estimated financial commitment of approximately $119$235 million. As of September 30, 2016, $49March 31, 2017, $200 million of costs have been incurred related to these projects.

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 MW)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 September 30, 2016,March 31, 2017, the net book value of Turk Plant was $1.5 billion, before cost of removal, including materials and supplies inventory and CWIP. 

If SWEPCo cannot ultimately recover its investment and expenses related to the Turk Plant, it could reduce future net income and cash flows and impact financial condition.

In 2012, SWEPCo initiatedMarch 2016, a proceedingcontested stipulation agreement related to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share of the Turk Plant. In February 2013, a settlementPPA rider application was modified and approved by the LPSC that increased SWEPCo’s Louisiana total ratesPUCO. The approved PPA rider is subject to audit and review by approximately $2 million annually, effective March 2013. The March 2013 base rates arethe PUCO. Consistent with the terms of a modified and approved stipulation agreement, and based upon a 10%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 cost recovery(e) the addition of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund. The settlement also provided that the LPSC would review base rates in 2014 and 2015 and that SWEPCo would recover non-fuel Turk Plant costsvarious new riders, including a Distribution Technology Rider and a full weighted-average costRenewable Resource Rider.

If OPCo is ultimately not permitted to fully collect all components of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million, primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. A hearing at the LPSC related to the Turk Plant prudence review is scheduled for March 2017. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment,its ESP rates, it could reduce future net income and cash flows and impact financial condition. See the “2012 Louisiana Formula Rate Filing”“Ohio Electric Security Plan Filings” section of Note 4.

Office of Utility Consumer Counselor (OUCC) and TNCother parties filed applicationstestimony with the PUCTIURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and FERC that requested approvallimitations on other costs related to merge TCC and TNC into AEP Utilities, Inc. Upon merger, AEP Utilities, Inc. will change its name to AEP Texas Inc. The proposed merger would be effective December 31, 2016. The applications proposed no changes to current TCC and TNC rates.legal issues involving the Rockport lease. A hearing at the PUCTIURC was held in August 2016. In September 2016,March 2017.

Beginning January 2013, SWEPCo’s formula rates, including the FERC issued an order approving the merger application. In October 2016, the ALJ issued a proposal for decision that recommends approvalLouisiana jurisdictional share (approximately 29%) of the merger provided certain post-merger conditions are imposed. The conditions recommended byTurk Plant, have been collected subject to refund pending the ALJ include a)outcome of a prudence review of the sharingTurk Plant investment, which was placed into service in December 2012.

A hearing at the LPSC related to the Turk Plant prudence review is scheduled for September 2017. If the LPSC orders refunds based upon the pending prudence review of certain interest rate savings with customersthe Turk Plant investment, it could reduce future net income and b) an annual credit to customers of approximately $630 thousand for savings resulting from an expected reduction in post-merger debt issuance costs, effective until the next base rate case. Management is evaluating the conditions recommended by the ALJ. A decision from the PUCT is expected in the fourth quarter of 2016.cash flows and impact financial condition.

In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by various AEP affiliates in calculating formula transmission rates under the PJM Open Access Transmission Tariff (OATT)OATT is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint. Management is reviewingbelieves its financial statements adequately address the filing and evaluating a response toimpact of the complaint. Management is unable to determine a range of potential losses, if any, that is reasonably possible of occurring. 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 JanuaryNovember 2016, KGPCocertain AEP affiliates filed a requestan application with the TRAFERC to increase basemodify the PJM 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. The filing proposed that the rates by $12 million annuallywould be implemented based upon athe date provided in the resulting FERC order. In March 2017, the FERC accepted the proposed returnmodifications effective January 1, 2017, 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 common equityprojected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of 10.66%. In August 2016, the TRA approved a settlement agreement that included an $8 million annual increase in base rates with a 9.85% return on common equity effective September 2016.

AGR is requiredManagement currently estimates that the investment necessary to offer allmeet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could cost a total of its available generation capacity inapproximately $850 million, excluding AFUDC. As of March 31, 2017, SWEPCo had incurred costs of $398 million, including AFUDC, and had remaining contractual construction obligations of $10 million related to these projects.  Management continues to evaluate the PJM Reliability Pricing Model (RPM) auction, which is conducted three years in advanceimpact of environmental rules and related project cost estimates. As of March 31, 2017, the delivery year.total net book value of Welsh Plant, Units 1 and 3 was $630 million, before cost of removal, including materials and supplies inventory and CWIP. 

In June 2015, FERC2016, as approved PJM’s proposalby the APSC, SWEPCo began recovering $79 million related to createthe Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas base rate proceeding. In December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant, until these investments are included in base rates. The Louisiana jurisdictional share of Welsh Plant deferrals through March 31, 2017 were $11 million, excluding $6 million of unrecognized equity, subject to review by the LPSC, and include a new Capacity Performance (CP) product, intended to improve generator performanceweighted average cost of capital (WACC) return on environmental investments and reliability during emergency events by allowing higher offers into the RPM auctionrelated depreciation expense and imposing greater charges for non-performance during emergency events. PJM procured approximately 80% CPtaxes. SWEPCo has sought recovery of its project costs from retail customers at the state commissions and 20% Base Capacity for the June 2018is recovering these costs from wholesale customers through May 2019 and June 2019 through May 2020 periods, while transitioning to 100% CP with the June 2020 through May 2021 period. FERC also approved transition incremental auctions to procure CP for the June 2016 through May 2017 and June 2017 through May 2018 periods.

In August 2015, PJM held its first base residual auction implementing CP rules for the June 2018 through May 2019 period. AGR cleared 7,209 MW at the CP auction price of $164.77/MW-day. The base residual auction for the June 2019 through May 2020 period was conducted in May 2016. AGR cleared 7,301 MW at the CP auction price of $100/MW-day. Shown below are the results for the June 2018 through May 2019 and June 2019 through May 2020 periods:

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 20152016 Annual Report. Additionally, see Note 4 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies included herein. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

In July 2013, the Wilmington Trust Company filed a complaint in 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 plaintiffplaintiffs further allegesallege that the defendants’ actions constitute breach of the lease and participation agreement.  The plaintiff seeksplaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff.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 plaintiff’s claims.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 plaintiffplaintiffs 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 plaintiff’splaintiffs’ 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, Plaintiffsplaintiffs filed a noticean appeal in the U.S. Court of appealAppeals for the Sixth Circuit on whether AEGCo and

AEGCo and I&M are in breach of certain contract provisions that Plaintiffsplaintiffs allege operate to protect the Plaintiffs’plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing Plaintiffs’plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. This matter is currently pending beforeIn 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 agreement and remanded the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. AEGCo and I&M intend to file a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit. ManagementThe district court had previously dismissed plaintiffs’ claims seeking compensatory relief as premature. In addition, plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages. As a result, management is unable to determine a range of potential losses that are reasonably possible of occurring.

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 20152016 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 sections 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 September 30, 2016,March 31, 2017, the AEP System had a total generating capacity of approximately 31,00025,600 MWs, of which approximately 16,00013,500 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 $2.8$4.3 billion to $3.4$4.9 billion throughbetween 2012 and 2025. Management continues to evaluate the impact of the merchant fleet operations on this range. The estimates include investments to convert some of the coal generation to natural gas.

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules.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.

In May 2015,The table below represents the following plants or units of plants were retired:

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.

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