This report made by AEP and its Registrant Subsidiariesthe 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 20142015 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, we undertakemanagement 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:

OurAEP’s weather-normalized retail sales volumes for the third quarter of 2015 increased2016 decreased by 0.9%0.5% from the third quarter of 2014. Our2015. AEP’s third quarter 20152016 industrial sales increased 0.7%decreased 2.6% compared to the third quarter of 20142015 primarily due to increaseddecreased sales to customers in oil and gas related sectors.the manufacturing sector. Weather-normalized commercial and residential sales increased 1.3%by 1.2% and 0.8%commercial sales decreased by 0.5% in the third quarter of 2015,2016, respectively, from the third quarter of 2014.2015.

AEP’s weather-normalized retail sales volumes for the nine months ended September 30, 2015 increased 0.1%2016 decreased by 0.4% compared to the nine months ended September 30, 2014. Industrial2015. AEP’s industrial sales volumes increased 0.8%for the nine months ended September 30, 2016 decreased 1.9% compared to 2014, while weather-normalizedthe nine months ended September 30, 2015 primarily due to decreased sales to customers in the manufacturing sector. Weather-normalized residential and commercial sales increased by 1.0%. Weather-normalized residential sales decreased 1.1% in comparison0.5% and 0.4%, respectively, for the nine months ended September 30, 2016 compared to nine months ended September 30, 2015.

In March 2016, a contested stipulation agreement related to the first nine months of 2014.

In March 2016, a group of merchant generation fleetowners filed a complaint at the FERC against PJM seeking revisions to the Minimum Offer Price Rule (MOPR) in PJM’s tariff. Although the complaint requested the FERC act in advance of the May 2016 Base Residual Auction for the 2019/2020 delivery year, the complaint is still pending without a decision from the FERC. If approved as proposed, the revised MOPR could affect future bidding behavior for units with cost recovery mechanisms.

In April 2016, the FERC issued an order granting a January 2016 complaint filed against AGR and AEGCo's Lawrenceburg Plant, bothOPCo.  The FERC order rescinded the waivers of which operatethe FERC’s affiliate rules as to the affiliate PPA between AGR and OPCo.  As a result, AGR and OPCo cannot implement the affiliate PPA without the FERC review, in PJM as well asaccordance with FERC’s rules governing affiliate transactions.  As a purchased power agreementresult of the April 2016 FERC order, management does not intend to pursue the affiliate PPA.

In May 2016, OPCo filed an application for rehearing with the PUCO related to certain aspects of the March 2016 PUCO order. The application included a 54.7% interestproposed OVEC-only PPA Rider that included an option for the rider to be bypassable. The proposed OVEC-only PPA Rider included (a) the elimination of the PUCO-imposed customer-specific rate impact cap of 5% through May 2018, (b) modifications to proportionately decrease the amount of the potential customer credits and (c) the inclusion of PJM capacity performance penalties within the PPA rider. Also in May 2016, intervenors filed applications for rehearing with the PUCO opposing the modified and approved stipulation agreement.

Consistent with the terms of the modified and approved stipulation agreement, in May 2016, OPCo filed an amended ESP that proposed to extend the ESP through May 2024. The amended ESP included (a) an extension of the PPA rider, which includes only OPCo’s entitlements to its ownership percentage of OVEC, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the Oklaunion Plant which operatesJune 2015 - May 2018 ESP, (d) proposed increases in ERCOT.  Potential alternatives may include, but arerate caps related to OPCo’s Distribution Investment Rider and (e) the addition of various new riders, including a Generation Resource Rider. Based upon a September 2016 PUCO order, OPCo will refile its ESP extension application and supporting testimony in November 2016.

If OPCo is ultimately not limitedpermitted to continued ownershipfully collect all components of the merchant generation fleet, executing a purchased power agreement with a regulated affiliate for certain merchant generation units in Ohio, a spin-off of the merchant generation fleet or a sale of the merchant generation fleet.  We have not made a decision regarding the potential alternatives, nor have we set a specific time frame for a decision.  Certain of these alternatives could result in a loss whichits ESP rates, it could reduce future net income and cash flowflows and impact financial condition. See “Ohio Electric Security Plan Filings” section of Note 4.

If the PUCO determines after rehearing that the additional PIRR carrying charges are not recoverable, it could reduce future net income and cash flows and impact financial condition.

In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. In 2013, this ruling was generally upheld in PUCO rehearing orders.

In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report with the PUCO for the period August 2012 through May 2015. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo’s $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report.

In June 2016, OPCo filed a request with the PUCO that requested a consolidated procedural schedule to resolve interrelated proceedings including (a) OPCo’s deferral of capacity costs for the period August 2012 through May 2015, we(b) the implementation of OPCo’s RSR and (c) the concerns related to the recovery of fixed fuel costs through both the FAC and the approved capacity charges. As part of the filing, OPCo requested that its net deferred capacity costs balance as of May 31, 2015 increase by $157 million, including carrying charges through September 2016. This net increase consists of a $327 million decrease due to the non-deferral portion of the RSR collections and an increase of $484 million for the correction of the energy credit. Recovery of the $157 million was requested to be effective October 2016 through December 2018. Additionally, OPCo filed testimony supporting the position that double recovery of fixed fuel costs could not have occurred because OPCo was unable to fully recover its capacity costs, which included fixed fuel costs, even with a corrected energy credit.

In September 2016, AEP signed an agreement to sell our commercial barge transportation subsidiary, AEPRO,Darby, Gavin, Lawrenceburg and Waterford Plants (“Disposition Plants”) totaling 5,326 MWs of competitive generation for approximately $2.2 billion to a nonaffiliated party. The sale of AEPRO is subject to regulatory approval includingapprovals from the FERC, the IURC and federal clearance pursuant to the Hart-Scott-Rodino Antitrust Improvements Act of 1976.  Upon close1976 (HSR). In October 2016, the Federal Trade Commission granted the sale early termination of the sale,HSR waiting period thereby satisfying the nonaffiliated party will acquire AEPRO by purchasing allHSR conditions to close the transaction. As of September 30, 2016, the common stocknet book value of these assets, including related materials and supplies inventory and CWIP, was $1.8 billion. AEP Resources, Inc., the parent companyexpects to receive net proceeds of AEPRO.  The nonaffiliated party will assume certain assets and liabilities of AEPRO, excluding the equity method investment in International Marine Terminals (IMT) which is a bulk commodity transfer facility jointly owned with Kinder Morgan L.P. "C", pension and benefit assets and liabilities and debt obligations.  We expect to net approximately $400 million$1.2 billion in cash after taxes, debt retirement and transaction fees. AEP is evaluating options to invest these proceeds, including reinvestment in regulated businesses and renewable energy projects and additional debt retirement. The sale is expected to close in the fourthfirst quarter of 2015.2017. An after tax gain ranging fromof approximately $100 million to $150 million is expected from the sale subject to working capitalinventory true-ups, income tax and other adjustments.

AEPRO'sThe assets and liabilities included in the sale transaction have been recorded as Assets Held for Sale and Liabilities Held for Sale, respectively, on our condensedthe balance sheetssheet as of September 30, 20152016. See “Assets and December 31, 2014. The results of operations of AEPRO have been classified as Discontinued Operations on our condensed statements of income. See "AEPRO (AEP River Operations Segment)"Liabilities Held for Sale” section of Note 6 for additional information.

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) 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, and through SWEPCo’s wholesale customers under FERC-based rates. As of September 30, 2016, 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 initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share of the Turk Plant. In February 2013, a settlement was approved by the LPSC that increased SWEPCo'sSWEPCo’s Louisiana total rates by approximately $2 million annually, effective March 2013. The March 2013 base rates are based upon a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund. The settlement also provided that the LPSC willwould review base rates in 2014 and 2015 and that SWEPCo willwould recover non-fuel Turk Plant costs and a full weighted-average cost 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, it could reduce future net income and cash flows and impact financial condition. See the “2012 Louisiana Formula Rate Filing” section of Note 4.

In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million, which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 of Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on common equity of 10.5% to be effective in January 2016, except for the2016. The proposed $44 million forincrease related to environmental investments which iswas effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls gowere placed in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million, excluding AFUDC. As of September 30, 2016, PSO had incurred costs of $180 million and $43 million, including AFUDC, for Northeastern Plant, Unit 3 and Comanche Plant, respectively.

In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million, will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4, in April 2016, which would be recovered through the FAC. In April 2016, Northeastern Plant, Unit 4 was retired. Upon retirement, $87 million was reclassified as Regulatory Assets on the balance sheet related to the net book value of Northeastern Plant, Unit 4. These regulatory assets are pending regulatory approval.

In October 2015, testimony was filed by OCC staffJune 2016, an Administrative Law Judge (ALJ) issued a report related to PSO’s base rate case filing and intervenors with recommendations that included increases to base rates and/or the proposed environmental rider ranging from $10 million to $31 million, based upon returnssubsequently provided an additional supplemental report in August 2016. The ALJ recommended a 9.25% return on common equity ranging from 8.75% to 9.3%,equity. The ALJ found that PSO’s environmental compliance plan is prudent and increases to depreciation expense ranging from $23 million to $46 million. Additionally, recommendations by certain intervenors included (a) noprovided for cost recovery of PSO’sthe investment in this case with a recommended investment cap of $210 million on environmental controls installed at Northeastern Plant, Unit 3 environmental controls, (b) no recovery of3. Additionally, the plant balances at the time the units are retired in 2016 and 2026, (c) denial of returns on the book values after the retirement dates, or to be set at only the cost of debt, and (d) the disallowance of the capacity costs associated with the PPAs. Additionally, certain intervenors did not support anALJ recommendations included (a) a $14 million increase in depreciation expense, for the(b) continued depreciation of Northeastern Plant, Units 3 and 4 through 2040 (no accelerated depreciation), (c) return of, but no return on, the remaining net book value of Northeastern Plant, Unit 4, (d) elimination of the rider to permit costrecover advanced metering starting in December 2016, without inclusion in base rates and (e) elimination of the system reliability rider through consolidation in base rates, without addressing a transition for recovery by Unit 3’s 2026 retirement date asof rider costs, including deferred costs. The estimated annual revenue increase resulting from the proposals called for no change in existing cost recovery by 2040. Hearings atALJ recommendations is approximately $47 million.

In June and September 2016, PSO, the OCC are scheduled for December 2015. staff, the Attorney General and intervenors filed exceptions to the ALJ reports. The OCC staff filed exceptions that supported the full recovery of Northeastern Plant, Unit 4, including a return, and recommended a $32 million increase in annual revenues. An order from the OCC is anticipated in the fourth quarter of 2016.

If any of these costs, including a return on Northeastern Plant, Unit 4, are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “2015 Oklahoma Base Rate Case"Case” section of Note 4.

In September 2015,January 2016, KGPCo filed a request with the TRA to increase base rates by $12 million annually based upon a proposed return on common equity of 10.66%. In August 2016, the TRA approved a settlement agreement that included an $8 million annual increase in base rates with the new rates expected to be implemented by Julya 9.85% return on common equity effective September 2016. See the “2015 Kingsport Base Rate Case" section of Note 4.

In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo'sAPCo’s financial statements adequately address the impact of these amendments. The new law providesamendments provide that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA.

AGR is required to offer all of its available generation capacity in the PJM Reliability Pricing Model (RPM) auction, which is conducted three years in advance of the delivery year.

In June 2015, FERC approved PJM’s proposal to create a new Capacity Performance (CP) product, intended to improve generator performance and reliability during emergency events by allowing higher offers into the RPM auction and imposing greater charges for non-performance during emergency events. PJM will procureprocured approximately 80% CP and 20% Base Capacity for the June 2018 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 the third quarter of 2015, PJM conducted the two transition auctions. The transition auctions allowed generators, including AGR, to re-offer cleared capacity that qualifies as CP. Shown below are the results of the two transition auctions:

AGR cleared 7,169MW at $134/MW-day for the June 2016 through May 2017 period, replacing the original auction clearing price of $59.37/MW-day. AGR cleared 6,495MW for the June 2017 through May 2018 period at $151.50/MW-day, replacing the original auction clearing price of $120/MW-day.

In August 2015, PJM held its first Base Residual Auctionbase residual auction implementing CP rules for the June 2018 through May 2019 period. PJM cleared approximately 81% of the capacity for the June 2018 through May 2019 period as CP and 19% as Base Capacity. 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 period:and June 2019 through May 2020 periods:

The FERC order exempted Fixed Resource Requirement (FRR) entities, including APCo, I&M, KPCo and WPCo, from the CP rules through the delivery period ending May 2019. Beginning in June 2018 through May 2019, period. In July 2015, AEP filed a request seeking rehearing of the FERC order approvingFRR entities are subject to CP and will continue to advocate for further improvements through the PJM stakeholder process.rules.

In the ordinary course of business, we areAEP is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, wemanagement cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. We assessManagement assesses the probability of loss for each contingency and accrueaccrues a liability for cases that have a probable likelihood of loss if the loss can be estimated. For details on ourthe 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 20142015 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 plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement.  The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff.  The New York court granted oura 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’plaintiff’s claims. Several claims remain,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. PlaintiffsThe plaintiff subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. We will continueIn November 2015, AEGCo and I&M filed a motion to defend againststrike the plaintiff’s 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. Weclaims with prejudice and the court subsequently entered a final judgment. In May 2016, Plaintiffs filed a notice of appeal on whether AEGCo and

I&M are in breach of certain contract provisions that Plaintiffs allege operate to protect the Plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing Plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. This matter is currently pending before the U.S. Court of Appeals for the Sixth Circuit. 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 20142015 Annual Report. WeAEP 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 we areAEP 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.  We continueManagement continues to evaluate the impact of these rules, project scope and technology available to achieve compliance. As of September 30, 2015,2016, the AEP System had a total generating capacity of approximately 32,10031,000 MWs, of which approximately 18,20016,000 MWs are coal-fired.  We continueManagement continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on ourthe fossil generating facilities. Based upon ourmanagement estimates, AEP’s investment to meet these proposed requirements ranges from approximately $2.8 billion to $3.3$3.4 billion through 2020. These amounts2025. Management continues to evaluate the impact of the merchant fleet operations on this range. The estimates include investments to convert some of ourthe 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.  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 ourthe 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, we aremanagement is continuing to evaluate the economic feasibility of environmental investments on both regulated and nonregulatedcompetitive plants.

In May 2015, we retired the following plants or units of plants:plants were retired:

As of September 30, 2015,2016, the net book value of the AGR units listed above was zero.  The net book value before cost of removal, including related materials and supplies inventory and CWIP balances, of the regulated plants in the table above has beenwas approved for recovery, except for $147$144 million which is pendingmanagement plans to seek regulatory approval.

Subject to the factors listed above and based upon our continuing evaluation, we intend to retireIn April 2016, AEP retired the following units of plants during 2016:plants:

As of September 30, 2015, the net book value of the PSO and SWEPCo units listed above before cost of removal, including related materials and supplies inventory and CWIP balances, was $177 million. Volatility in fuel prices, pending environmental rules and other market factors could also have an adverse impact on the accounting evaluation of the recoverability of the net book values of coal-fired units. For Northeastern Station, Unit 4 and Welsh Plant, Unit 2, we are seeking regulatory recovery of remaining net book values.

In October 2015, KPCo obtained permits following the KPSC’s approval to convert its 278 MW Big Sandy Plant, Unit 1 was $110 million.to natural gas. Big Sandy Plant, Unit 1 began operations as a natural gas unit in May 2016.

We are also in the process of obtainingAPCo obtained permits following the Virginia SCCSCC’s and WVPSC'sWVPSC’s approval for the conversion of APCo'sto convert its 470 MW Clinch River Plant, Units 1 and 2 to natural gas. In Septemberthe third and fourth quarters of 2015, weAPCo retired the coal-related assets of Clinch River Plant, Units 1 and 2. Of the coal-relatedretired coal related assets retired in September 2015, $14 million is pending regulatory approval. We expect to begin operations as a natural gas unit in the first quarter of 2016 for Clinch River

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.

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 Federal EPA issued the final maximum achievable control technology (MACT) standards for coal and oil-fired power plants in 2012.2012, but the rule was remanded to the Federal EPA upon further review. The Federal EPA issued a supplemental finding, received comments and affirmed its decision on the MACT standards for power plants. That decision has been challenged in the courts but the rule remains in effect. See “Mercury and Other Hazardous Air Pollutants (HAPs) Regulation” section below.

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

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.  The effective date of the final rule was April 16, 2012 and compliance was required within three years. The final rule contains a slightly less stringent PM limit for existing sources than the original proposal and the revised rule provides alternative work practice standards for operators during start-up and shut down periods.  We haveManagement obtained a one-year administrative extension at several units to facilitate the installation of controls or to avoid a serious reliability problem. In addition, the Federal EPA issued an enforcement policy describing the circumstances under which an administrative consent order might be issued to provide a fifth year for the installation of controls or completion of reliability upgrades. We remain concerned about the availability of compliance extensions, the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines and the lack of coordination among the Mercury and Air Toxics Standards (MATS) schedule and other environmental requirements.

Petitions for administrative reconsideration and judicial review of the final rule were filed.  In 2012, the Federal EPA published a notice announcing that it would accept comments on its reconsideration of certain issues related to the new source standards, including clarification of the requirements that apply during periods of start-up and shut down, measurement issues and the application of variability factors that may have an impact on the level of the standards.  The Federal EPA issued revisions to the new source standards consistent with the proposed rule, except the start-up and shut down provisions in March 2013. A final rule on reconsideration was issued in 2014 and a proposed rule containing technical corrections was issued in early 2015. 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 and remanded the MATSMercury and Air Toxics Standards (MATS) rule for further proceedings consistent with itsthe 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 case hasFederal 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 remanded tofiled in the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings consistent with the U.S. Supreme Court’s decision. We will continue to evaluate the impact of this decision and until further action by the U.S. Court of Appeals for the District of Columbia Circuit, theCircuit. The rule remains in place.effect.

The Federal EPA also published proposed “model” rules that can be adopted by the states that would allow sources within “trading ready” state programs to trade, bank or sell

In 2010,April 2015, the Federal EPA published a proposedfinal 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 proposed rule contained two alternative proposals.  One proposal would impose federal hazardous waste disposal and management standards on these materials and another would allow states to retain primary authority to regulate the beneficial re-use and disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management.  Both proposals would impose stringent requirements for the construction of new coal ash landfills and existing unlined surface impoundments.

In February 2014, the Federal EPA completed a risk evaluation of the beneficial uses of coal fly ash in concrete and FGD gypsum in wallboard and concluded that the Federal EPA supports these beneficial uses.  Currently, approximately 40% of the coal ash and other residual products from ourAEP’s generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses.  Encapsulated beneficial uses are not materially impacted by the new rule but additional demonstrations may be required to continue land applications in significant amounts except in road construction projects.

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) 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. Briefs by the various parties are due during the fourth quarter of 2016.

In addition, the Federal EPA developed revised effluent limitation guidelines for electricity generating facilities.  A pre-publication copy of the final rule was announced and made availableissued in SeptemberNovember 2015. The rule has been challenged in the U.S. Court of Appeals for the Fifth Circuit. Industry petitioners, including SWEPCo, have filed a joint motion for reconsideration of the single judge order denying the motion to complete the administrative record. In addition to other requirements, in the final rule the Federal EPA establishes limits on flue gas desulfurization wastewater, zero discharge for fly ash and bottom ash transport water and flue gas mercury control wastewater. Compliance with the final ruleThe applicability of these requirements is 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. We continueManagement continues to review the final rule in detail to evaluate whether our plants are currently meeting the proposed limitations, what technologies have been incorporated into our long-range plansassess technology additions and what additional costs might be incurred.retrofits.

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: 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." We believe” Management believes that clarity and efficiency in the permitting process is needed. We remainManagement remains concerned that the rule introduces new concepts and could subject more of ourAEP’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 we are members.AEP is a member. The U.S. Court of AppealAppeals for the Sixth Circuit has 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 and proceeded to issue a case management order for the merits of the case. In September 2016, the case management order was held in abeyance pending the court’s ruling on the outstanding motions to complete the administrative record. In October 2016, the U.S. Court of Appeals for the Sixth Circuit issued an order granting in part and denying in part the motions to complete the record. Following this order, a revised case management order was issued scheduling briefing to be completed by March 2017. No date for oral argument has been set.

OurAEP’s primary business is the generation, transmission and distribution of electricity.  Within ourits Vertically Integrated Utilities segment, weAEP centrally dispatchdispatches generation assets and manage ourmanages 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.

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

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 River Operations

Earnings (Loss) Attributable to AEP Common Shareholders increaseddecreased from $493income of $518 million in 20142015 to $519a loss of $766 million in 20152016 primarily due to:

These increasesdecreases were partially offset by:

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

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

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

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

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