Rate Matters

12 Months Ended

Dec. 31, 2016

Rate Matters

RATE MATTERS

The disclosures in this note apply to all Registrants unless indicated otherwise.

The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions.  Rate matters can have a material impact on net income, cash flows and possibly financial condition.  The Registrants’ recent significant rate orders and pending rate filings are addressed in this note.

APCo and WPCo Rate Matters (Applies to AEP and APCo)

2016 West Virginia Expanded Net Energy Cost Filing

In June 2016, the WVPSC approved a settlement agreement related to APCo and WPCo’s combined annual ENEC filing. The settlement agreement included $38 million ($30 million related to APCo) of additional ENEC revenues and $17 million ($14 million related to APCo) in construction surcharges annually for two years, effective July 2016. Additionally, APCo and WPCo agreed that a general rate case will not be filed before April 2018.

West Virginia Deferred Base Rate Increase

In May 2015, the WVPSC issued an order on APCo and WPCo’s combined base rate case. The order included a delayed billing of $25 million ($22 million related to APCo) of the annual base rate increase to residential customers until July 2016. In June 2016, the WVPSC issued an order that approved recovery of the total deferred billing, including carrying charges through June 2018, totaling $29 million ($27 million related to APCo). Recovery was approved over two years, effective July 2016. Additionally, at the end of the two-year amortization, any over/under-recovery of the delayed billing will be included in the annual ENEC filing. The WVPSC also approved implementation of the prospective $25 million base rate increase effective July 2016.

2015 Virginia Regulatory Asset Proceeding

In 2015, the Virginia SCC initiated a proceeding to address the treatment of APCo’s authorized regulatory assets. In September 2016, the Virginia SCC issued an order that approved the continued recovery through amortization of certain regulatory assets established prior to the period of frozen rates pursuant to the amended Virginia law (see “Virginia Legislation Affecting Biennial Reviews” below).

Virginia Legislation Affecting Biennial Reviews

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’s financial statements adequately address the impact of these amendments. The amendments 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.

In February 2016, certain APCo industrial customers filed a petition with the Virginia SCC requesting the issuance of a declaratory order that finds the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, directs APCo to make biennial review filings beginning in 2016. In July 2016, the Virginia SCC issued an order that denied the petition. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition.

ETT Rate Matters (Applies to AEP)

ETT Interim Transmission Rates

Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. During a 2015 open meeting at the PUCT, ETT committed to file a base rate case by February 2017. In January 2017, the PUCT approved ETT’s request to suspend the base rate case filing and decrease ETT’s annual revenue requirement by $46 million, effective March 2017. As of December 31, 2016, AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $591 million based upon interim rate increases received from 2009 through 2016. A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. Management is unable to determine a range of potential losses that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters (Applies to AEP and I&M)

Indiana Amended PJM Settlement Agreement

In November 2016, the IURC issued an order that approved an amended settlement agreement between I&M and certain intervenors.  This agreement amends a previously approved 2014 settlement agreement that addresses the recovery of 43.5% of certain transmission expenses through the Indiana PJM rider through 2017.

The amended agreement allows I&M to recover 100% of the Indiana jurisdictional share of these transmission expenses not recovered through base rates through the Indiana PJM rider, subject to a $109 million cap for the period January 2017 through June 2018. Beginning July 2018, I&M will be allowed to recover 100% of the Indiana jurisdictional share of these transmission expenses through the Indiana PJM rider, without a cap, until the issue is addressed by the IURC in a future proceeding, subject to the condition that I&M files a base rate case on or before January 2018. The amended agreement also provides for deferral of incremental vegetation management expenses over the period January 2017 through June 2018.  Any vegetation management expenses deferred would reduce the cap for the transmission expenses described above. As part of the amended settlement, I&M agreed that it will not file a base rate case before July 2017 and will not implement new base rates prior to July 2018.

Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR)

In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO_x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million, excluding AFUDC, to be shared equally between I&M and AEGCo.  The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year life and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. 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 limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC is scheduled for March 2017.

KGPCo Rate Matters (Applies to AEP)

Kingsport Base Rate Case

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.

OPCo Rate Matters (Applies to AEP and OPCo)

Ohio Global Settlement

In February 2017, the PUCO approved a settlement agreement (Global Settlement) filed by OPCo in December 2016. The parties to the Global Settlement include OPCo, the PUCO staff and various intervenors. The Global Settlement resolves all remaining open issues on remand from the Ohio Supreme Court in OPCo’s 2009 - 2011 and June 2012 - May 2015 ESP filings, including issues related to carrying charges on the PIRR and issues related to the RSR capacity charges. It also resolves all open issues in OPCo’s 2009, 2014 and 2015 SEET filings and 2009, 2012 and 2013 Fuel Adjustment Clause Audits.

The significant components of the Global Settlement include:

Remands Related to the PIRR

All applicable parties participating in this settlement will withdraw their pending applications for rehearing of the PUCO order that allowed for the reinstatement of the equity portion of the WACC rate on previously deferred fuel balances. As part of the Global Settlement, the PIRR rate to be collected from customers through December 2018 will be reduced by $97 million.

Remands Related to the RSR

Beginning January 2017, OPCo will be entitled to collect $388 million in RSR revenues over a total of 30 months, subject to true up at the end of the collection period in June 2019. Current RSR rates will continue until the new RSR rates are approved. The Global Settlement resolves the issues related to the non-deferral portion of RSR collections and the impact of the appropriate energy credit on capacity charges. In December 2016, OPCo recorded an increase in Regulatory Assets on the balance sheets for the deferral of $83 million in RSR capacity costs and $14 million in related debt carrying charges with a corresponding decrease in expense in Generation Deferrals and an increase in Carrying Costs Income, respectively, on the statements of income.

For the year ended December 31, 2016, AEP recorded approximately $97 million in RSR capacity deferrals and related carrying charges to the following line items on the statements of income:

	AEP
	(in millions)
Fuel and Other Consumables Used for Electric Generation	$	(19.0	)
Purchased Electricity for Resale	(19.9		)
Other Operation	(15.7		)
Depreciation and Amortization	(42.1		)
Total Decrease in RSR Expenses	$	(96.7	)

As of December 31, 2016, OPCo’s total RSR under-recovery balance, including carrying charges, was $299 million.

Remands Related to the SEET

As part of the Global Settlement,$20 million will be returned to customers over a 12-month period commencing within 45 days of the final PUCO order adopting the Global Settlement. The Global Settlement states that this obligation has no precedential effect on OPCo’s SEET methodology. In addition, the parties agreed that earnings were not significantly excessive in 2015. In December 2016, OPCo accrued $20 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the issues related to the 2014 and 2015 SEET proceedings.

Fuel Adjustment Clause Proceedings

OPCo will refund $100 million paid by SSO customers from August 2012 - May 2015 related to OVEC and Lawrenceburg purchases. In December 2016, OPCo accrued $100 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the claimed recovery of fixed fuel costs through both the FAC and the approved capacity charges. This refund will be a one-time credit that will be applied the earlier of either 45 days after the final non-appealable order from the PUCO adopting the Global Settlement, or the December 2017 billing cycle.

Ohio Electric Security Plan Filings

2009 – 2011 ESP

The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018.

In 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a WACC rate. In 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and remanded the matter back to the PUCO for reinstatement of the WACC rate. In June 2016, the PUCO approved OPCo’s proposed increase to the PIRR rates, in accordance with the Supreme Court of Ohio ruling. The increase to PIRR rates included $146 million in additional carrying charges and the recovery of $40 million in additional under-recovered fuel costs resulting from a decrease in customer demand. The increase is effective July 2016 through December 2018. In July 2016, intervenors filed requests for rehearing with the PUCO, which the PUCO granted in August 2016. In December 2016, OPCo filed a Global Settlement with the PUCO related to this issue. See “Ohio Global Settlement” section above.

June 2012 – May 2015 ESP Including Capacity Charge

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 July 2012, the PUCO issued an order in a separate capacity proceeding requiring OPCo to charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day.  The OPCo RPM price collected from CRES providers, which included reserve margins, was approximately $34/MW day through May 2014 and $150/MW day from June 2014 through May 2015. In April 2016, the Supreme Court of Ohio issued two opinions related to the deferral of OPCo’s capacity charges. In one of the opinions, the Supreme Court of Ohio ruled that the PUCO must reconsider an energy credit that was used to determine OPCo’s authorized capacity deferral threshold of $188.88/MW day during the August 2012 through May 2015 period. The PUCO reduced OPCo’s authorized capacity deferral threshold to $188.88/MW day largely due to an offset for an energy credit of $147.41/MW day. The Supreme Court of Ohio directed the PUCO to substantively address OPCo’s arguments that the $147.41/MW day credit was overstated by approximately $100/MW day due to various inaccuracies affecting input data and assumptions. See “Ohio Global Settlement” section above.

As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012.  The RSR was collected from customers at $3.50/MWh through May 2014 and at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. In April 2015, the PUCO issued an order that modified and approved OPCo’s July 2014 application to collect the unrecovered portion of the deferred capacity costs. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00/MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance. As of December 31, 2016, OPCo’s net deferred capacity costs balance was $202 million, including debt carrying costs, and was recorded in Regulatory Assets on the balance sheets. In April 2016, the second Supreme Court of Ohio opinion rejected a portion of OPCo’s RSR revenues collected during the period September 2012 through May 2015 and directed the PUCO to reduce OPCo’s deferred capacity costs by these previously collected RSR revenues. The Supreme Court of Ohio was not able to determine the amount of the reduction to OPCo’s deferred capacity costs and remanded the issue to the PUCO to determine the appropriate reduction. As directed by the PUCO, in May 2016, OPCo submitted revised RSR tariffs that reflect the RSR being collected subject to refund. See “Ohio Global Settlement” section above.

In April 2016, the Supreme Court of Ohio also ruled favorably on OPCo’s cross-appeal regarding a previously PUCO-imposed SEET threshold under the ESP and remanded this issue to the PUCO. See “Ohio Global Settlement” section above and “Significantly Excessive Earnings Test Filings” section below.

In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings.

In 2014, the PUCO denied all rehearing requests, 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, and 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. See “2012 and 2013 Fuel Adjustment Clause Audits” section below.

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, (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, and due to the interrelated nature of the two Supreme Court of Ohio opinions that directly relate to OPCo’s deferred capacity costs, 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. 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 December 2016, OPCo filed a Global Settlement with the PUCO related to these issues. See “Ohio Global Settlement” section above.

June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024

In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a PPA rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets.

In February 2015, the PUCO issued an order approving OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo’s and various intervenors’ requests for rehearing related to the May 2015 order. In November 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments and denied the remaining requests for rehearing. In January 2017, the PUCO granted intervenors requests for rehearing that oppose the PPA rider as well as the amended DIR caps.

In May 2015, OPCo filed an amended PPA application that (a) included OPCo’s OVEC contractual entitlement (OVEC PPA), (b) addressed the PPA requirements set forth in the PUCO’s February 2015 order and (c) included the 2,671 MWs to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units (Affiliate PPA).

In March 2016, a contested stipulation agreement related to the PPA rider application was modified and approved by the PUCO. The approved PPA rider is effective April 2016 through May 2024, subject to audit and review by the PUCO. The stipulation agreement, as approved, included (a) an Affiliate PPA between OPCo and AGR to be included in the PPA rider, (b) OPCo’s OVEC PPA to be included in the PPA rider, (c) potential additional contingent customer credits of up to $100 million to be included in the PPA rider over the final four years of the PPA rider and (d) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions.

In April 2016, the FERC issued an order granting a January 2016 complaint filed against AGR and OPCo.  The FERC order rescinded the waivers of the 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 accordance with FERC’s rules governing affiliate transactions.  As a result 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 proposed OVEC-only PPA Rider to recover the net margin after sales through PJM and 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 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. In November 2016, the PUCO issued an order on rehearing that approved recovery of the OVEC-related net margin incurred from June 2016 through the term of the PPA rider and the modification to reduce the customer credits to $15 million as requested by OPCo. The PUCO rejected OPCo’s request to eliminate both the 5% rate impact cap and the inclusion of the capacity performance penalties within the PPA rider. In January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC-only PPA and stated that the stipulation agreement approved in March 2016 does not provide customers with rate stability.

OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO makes unacceptable modifications to the stipulation, including modifications as part of the pending rehearing.

Consistent with the terms of the modified and approved stipulation agreement, and based upon a September 2016 PUCO order, in November 2016, OPCo refiled its amended ESP extension application and supporting testimony. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.

Significantly Excessive Earnings Test Filings

Background

Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric distribution utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk.

2009 SEET Filing

In 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project.

In September 2013, a proposed second phase of OPCo’s gridSMART^® (gridSMART^® Phase II) program was filed with the PUCO which included a proposed project to satisfy the PUCO 2009 SEET directive. In April 2016, a stipulation agreement related to the gridSMART^® Phase II program was filed with the PUCO. As part of the stipulation agreement, OPCo will invest at least $20 million over a six-year period for the installation of Volt VAR Optimization (VVO) technology on selected circuits throughout OPCo’s service territory. All parties to the stipulation agree that OPCo’s proposed VVO investment resolves OPCo’s outstanding obligation for renewable or similar investment associated with the PUCO’s 2009 SEET directive. As a part of the December 2016 Global Settlement, OCC agreed to no longer contest the gridSMART^® Phase II stipulation. In February 2017, the PUCO approved the gridSMART^® Phase II stipulation agreement. See “Ohio Global Settlement” section above.

2014 and 2015 SEET Filings

The PUCO established an annual SEET earnings threshold of 12% during the June 2012 - May 2015 ESP period. In May 2013, OPCo filed a cross appeal with the Supreme Court of Ohio, asserting that the SEET threshold was not based on the earnings of comparable publicly traded companies as originally required by the SEET statute.

In April 2016, the Supreme Court of Ohio agreed with OPCo’s cross-appeal assertion that a 12% SEET threshold was not based on the applicable Ohio SEET statute. The Supreme Court of Ohio reversed the 12% threshold and remanded this issue to the PUCO.

In June 2015 and May 2016, OPCo submitted its SEET filings for 2014 and 2015, respectively, with the PUCO. In August 2016, intervenors filed testimony recommending a revenue refund of approximately $20 million for 2014 and no refund for 2015 based upon a new approach to determine significantly excessive earnings that has not been previously approved by the PUCO. In September 2016, OPCo and the PUCO staff filed a stipulation agreement with the PUCO stating that no significantly excessive earnings occurred for 2014 or 2015. In September 2016, intervenors filed testimony opposing the stipulation agreement. See “Ohio Global Settlement” section above.

2016 SEET Filing

OPCo expects to submit its 2016 SEET filing in the second quarter of 2017.  OPCo’s 2016 SEET provision was determined by excluding the gain on the deferral of RSR costs related to the Global Settlement. In addition, refunds to customers included in the Global Settlement relating to the SEET remands and fuel adjustment clause proceedings were excluded from the determination of the 2016 SEET provision. Management believes its financial statements adequately address the impact of 2016 SEET requirements.  If the PUCO adopts a different 2016 SEET methodology, it could reduce future net income and cash flows and impact financial condition.

2009 Fuel Adjustment Clause Audit

In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statements of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. See “Ohio Global Settlement” section above.

2012 and 2013 Fuel Adjustment Clause Audits

In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the “June 2012 - May 2015 ESP Including Capacity Charge” and “Ohio Global Settlement” sections above.

Ormet

Ormet, a large aluminum company, had a contract to purchase power from OPCo. In OPCo’s 2009 - 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues. Through September 2009, the last month of the interim arrangement, OPCo had approximately $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s filing to approve recovery of the deferral under the interim agreement. Of the $64 million in deferred FAC costs, approximately 50% was related to Columbus Southern Power Company (CSPCo) and 50% related to OPCo, prior to the merger of CSPCo into OPCo in December 2011. CSPCo’s portion of these deferred fuel costs has been recovered as a result of the previous collections of CSPCo fuel costs from ratepayers and the PUCO’s 2013 order to apply CSPCo’s 2010 excessive earnings to offset CSPCo’s final deferred fuel balance. OPCo’s share of Ormet deferred fuel costs continues to be recovered through OPCo’s PIRR.

The Ohio Global Settlement discussed above, approved by the PUCO in February 2017, includes the resolution of the 2009, 2012 and 2013 Fuel Adjustment Clause Audits together with the finalization of the PIRR.  The resolution of those cases effectively makes the risk of non-recovery of the Ormet deferrals remote.

PSO Rate Matters (Applies to AEP and PSO)

2015 Oklahoma Base Rate Case

In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million. The request consisted 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 included a proposed return on common equity of 10.5%. The $44 million increase related to environmental investments was proposed to be effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls were 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 December 31, 2016, PSO had incurred costs of $181 million and $44 million, including AFUDC, for Northeastern Plant, Unit 3 and Comanche Plant, respectively. In January 2016, PSO implemented an interim annual base rate increase of $75 million, subject to refund.

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, 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 sheets related to the net book value of Northeastern Plant, Unit 4. These regulatory assets are pending regulatory approval.

In November 2016 and December 2016, the OCC issued orders that approved a net annual revenue increase of $19 million based upon a 9.5% return on common equity. The orders also included (a) approval to defer incurred costs related to PSO’s environmental compliance plan until those costs are included in base rates, (b) no determination related to the return of and return on the post-retirement remaining net book value of Northeastern Plant, Unit 4 since the April 2016 retirement was outside of the test year, (c) approval to include environmental consumable costs in the FAC (d) the continued depreciation of Northeastern Plant, Units 3 and 4 through 2040 (no accelerated depreciation) and (e) altered the system reliability rider by eliminating the expense portion of the rider and setting the capital portion of the rider at the December 2016 plant balance and approved recovery of deferred expenses and return on the capital balance incurred prior to the effective date of new tariffs in January 2017. Additionally, the orders stated that the cost recovery of new PPAs related to replacement power resulting from the retirement of Northeastern Plant, Unit 4 will be addressed in a future FAC proceeding. Effective December 2016, interim rates were terminated and the refund of over collections began and will be completed no later than October 2017. In accordance with the final order, updated rates and tariffs went into effect in January 2017.

If any of these costs, including a return on Northeastern Plant, Unit 4, are ultimately not recoverable, it could reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters (Applies to AEP and SWEPCo)

2012 Texas Base Rate Case

In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2.

Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million. In 2014, intervenors filed appeals of that order with the Texas District Court and SWEPCo intervened in those appeals. A hearing at the Texas District Court is scheduled for March 2017.

If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition.

2016 Texas Base Rate Case

In December 2016, SWEPCo filed a base rate request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. The annual increase includes approximately (a) $34 million related to additional environmental controls to comply with Federal EPA mandates, (b) $25 million for additional generation, transmission and distribution investments and increased operating costs, (c) $8 million related to transmission cost recovery within SWEPCo’s regional transmission organization and (d) $2 million in additional vegetation management.

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

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant. In February 2013, a settlement was approved by the LPSC. The settlement increased SWEPCo’s Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually.  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. The rates are subject to refund based on the prudence review of the Turk Plant. The settlement also provided that the LPSC would review base rates in 2014 and 2015 and that SWEPCo would 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 June 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.

2014 Louisiana Formula Rate Filing

In 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC.  The filing included a $5 million annual increase, which was effective August 2014.  SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million. This additional increase reflects the cost of incremental generation used to serve Louisiana customers in 2015 due to the expiration of a purchased power agreement attributable to Louisiana customers.  In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015, subject to staff review of the cost of service and prudence review of the Turk Plant. In July 2016, the LPSC approved a settlement agreement related to the staff review of the cost of service. A portion of the rates remain subject to refund based on the prudence review of the Turk Plant. See “2012 Louisiana Formula Rate Filing” above. Management believes its financial statements adequately address the impact of this settlement agreement. 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.

2015 Louisiana Formula Rate Filing

In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC.  The filing included a $14 million annual increase, which was effective August 2015.  This increase is subject to LPSC staff review and is subject to refund.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Welsh Plant - Environmental Impact

Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could cost a total of approximately $850 million, excluding AFUDC. As of December 31, 2016, SWEPCo had incurred costs of $397 million, including AFUDC, and had remaining contractual construction obligations of $11 million related to these projects.  As part of this investment, in 2016 SWEPCo completed construction of environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $370 million, excluding AFUDC.  Management continues to evaluate the impact of environmental rules and related project cost estimates. In March 2016, SWEPCo filed a request with the APSC to recover $69 million in environmental costs related to the Arkansas retail jurisdictional share of Welsh Plant, Units 1 and 3, which was approved by the APSC in August 2016. SWEPCo began recovering the Arkansas jurisdictional share of these costs in March 2016, subject to review in the next filed base rate proceeding. In September 2016, SWEPCo filed an additional request to increase the Arkansas retail jurisdictional share of the environmental investment by $10 million, for a total of $79 million. SWEPCo implemented the increase in September 2016. In December 2016, the LPSC approved deferral of certain expenses related to environmental controls installed at Welsh Plant, until these investments are put into base rates. The eligible Welsh Plant deferrals through December 31, 2016 are $8 million, excluding $5 million of unrecognized equity, subject to review by the LPSC, and include a WACC return on environmental investments and the related depreciation expense and taxes. SWEPCo will seek recovery of its project costs from customers at the state commissions and the FERC.

As of December 31, 2016, the net book value of Welsh Plant, Units 1 and 3 was $633 million, before cost of removal, including materials and supplies inventory and CWIP.  In April 2016, Welsh Plant, Unit 2 was retired. Upon retirement, $76 million was reclassified as Regulatory Assets on the balance sheets related to the net book value of Welsh Plant, Unit 2 and the related asset retirement obligation costs. In SWEPCo’s 2016 Texas Base Rate Case, SWEPCo requested recovery of the Texas jurisdictional share (approximately 33%) of the net book value of Welsh Plant, Unit 2 through 2042, the remaining life of Welsh Plant, Unit 3. Management will seek recovery of the remaining Welsh Plant, Unit 2 retirement-related regulatory assets in future rate proceedings.

If any of these costs are not recoverable, including retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.

AEP Texas Rate Matters (Applies to AEP)

TCC and TNC Merger

Effective December 31, 2016, TCC and TNC merged into AEP Utilities, Inc., as approved by the FERC and the PUCT in September 2016 and December 2016, respectively. Upon merger, AEP Utilities, Inc. changed its name to AEP Texas Inc., but maintained TCC’s and TNC’s respective customer rates. The PUCT ordered certain post-merger conditions which included a) the sharing of certain interest rate savings with customers 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.

AEP Texas Distribution Cost Recovery Factor (DCRF)

In July 2016, the PUCT approved settlement agreements between TCC, TNC and intervenors related to requests for DCRF riders to allow recovery of eligible net distribution investments. The settlement agreement included an annual revenue requirement of $56 million ($45 million for the TCC division and $11 million for the TNC division), effective September 2016. Amounts approved are subject to refund based upon a prudence review of the investments in AEP Texas’ next base rate case.

FERC Rate Matters (Applies to AEP, APCo, I&M and OPCo)

PJM Transmission Rates

In June 2016, PJM transmission owners, including the AEP East Companies, and various state commissions filed a settlement agreement with the FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. In July 2016, certain parties filed comments at the FERC contesting the settlement agreement. Upon final FERC approval, PJM would implement a transmission enhancement charge adjustment through the PJM OATT, billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms.

FERC Transmission Complaint and Proposed Modifications to Transmission Rates

In October 2016, several parties filed a joint complaint with the FERC claiming that the base return on common equity used by various AEP affiliates 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 2016, AEP affiliates filed an application with the FERC to modify the FERC formula transmission rate calculation, including adjustments for certain tax issues and a shift from historical to estimated expenses with a proposed effective date of January 1, 2017. The rates will be implemented based upon the date provided in the pending FERC order, subject to refund. Management believes its financial statements adequately address the impact of the complaint and the proposed modifications to AEP’s transmission rates in PJM. 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.

Other Rate Matters (Applies to AEP, PSO and SWEPCo)

SPP OATT Upgrade Costs

Under the SPP OATT, costs of sponsor-funded transmission upgrades may be recovered, in part, from SPP customers whose transmission service is dependent upon capacity enabled by the upgrades. Prior to 2016, SPP had not charged its customers any amounts attributable to these upgrades. In November 2016, SPP billed transmission service customers, including PSO and SWEPCo, for upgrade costs incurred since 2008. SPP then credited the qualifying transmission upgrade owners, including SWEPCo, for the use of these upgrades. In 2016, PSO and SWEPCo recognized a net unfavorable impact of approximately $3 million and $4 million, respectively, related to the OATT upgrade costs.

Appalachian Power Co [Member]

Rate Matters

RATE MATTERS

The disclosures in this note apply to all Registrants unless indicated otherwise.

The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions.  Rate matters can have a material impact on net income, cash flows and possibly financial condition.  The Registrants’ recent significant rate orders and pending rate filings are addressed in this note.

APCo and WPCo Rate Matters (Applies to AEP and APCo)

2016 West Virginia Expanded Net Energy Cost Filing

In June 2016, the WVPSC approved a settlement agreement related to APCo and WPCo’s combined annual ENEC filing. The settlement agreement included $38 million ($30 million related to APCo) of additional ENEC revenues and $17 million ($14 million related to APCo) in construction surcharges annually for two years, effective July 2016. Additionally, APCo and WPCo agreed that a general rate case will not be filed before April 2018.

West Virginia Deferred Base Rate Increase

In May 2015, the WVPSC issued an order on APCo and WPCo’s combined base rate case. The order included a delayed billing of $25 million ($22 million related to APCo) of the annual base rate increase to residential customers until July 2016. In June 2016, the WVPSC issued an order that approved recovery of the total deferred billing, including carrying charges through June 2018, totaling $29 million ($27 million related to APCo). Recovery was approved over two years, effective July 2016. Additionally, at the end of the two-year amortization, any over/under-recovery of the delayed billing will be included in the annual ENEC filing. The WVPSC also approved implementation of the prospective $25 million base rate increase effective July 2016.

2015 Virginia Regulatory Asset Proceeding

In 2015, the Virginia SCC initiated a proceeding to address the treatment of APCo’s authorized regulatory assets. In September 2016, the Virginia SCC issued an order that approved the continued recovery through amortization of certain regulatory assets established prior to the period of frozen rates pursuant to the amended Virginia law (see “Virginia Legislation Affecting Biennial Reviews” below).

Virginia Legislation Affecting Biennial Reviews

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’s financial statements adequately address the impact of these amendments. The amendments 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.

In February 2016, certain APCo industrial customers filed a petition with the Virginia SCC requesting the issuance of a declaratory order that finds the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, directs APCo to make biennial review filings beginning in 2016. In July 2016, the Virginia SCC issued an order that denied the petition. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition.

ETT Rate Matters (Applies to AEP)

ETT Interim Transmission Rates

Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. During a 2015 open meeting at the PUCT, ETT committed to file a base rate case by February 2017. In January 2017, the PUCT approved ETT’s request to suspend the base rate case filing and decrease ETT’s annual revenue requirement by $46 million, effective March 2017. As of December 31, 2016, AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $591 million based upon interim rate increases received from 2009 through 2016. A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. Management is unable to determine a range of potential losses that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters (Applies to AEP and I&M)

Indiana Amended PJM Settlement Agreement

In November 2016, the IURC issued an order that approved an amended settlement agreement between I&M and certain intervenors.  This agreement amends a previously approved 2014 settlement agreement that addresses the recovery of 43.5% of certain transmission expenses through the Indiana PJM rider through 2017.

The amended agreement allows I&M to recover 100% of the Indiana jurisdictional share of these transmission expenses not recovered through base rates through the Indiana PJM rider, subject to a $109 million cap for the period January 2017 through June 2018. Beginning July 2018, I&M will be allowed to recover 100% of the Indiana jurisdictional share of these transmission expenses through the Indiana PJM rider, without a cap, until the issue is addressed by the IURC in a future proceeding, subject to the condition that I&M files a base rate case on or before January 2018. The amended agreement also provides for deferral of incremental vegetation management expenses over the period January 2017 through June 2018.  Any vegetation management expenses deferred would reduce the cap for the transmission expenses described above. As part of the amended settlement, I&M agreed that it will not file a base rate case before July 2017 and will not implement new base rates prior to July 2018.

Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR)

In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO_x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million, excluding AFUDC, to be shared equally between I&M and AEGCo.  The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year life and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. 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 limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC is scheduled for March 2017.

KGPCo Rate Matters (Applies to AEP)

Kingsport Base Rate Case

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.

OPCo Rate Matters (Applies to AEP and OPCo)

Ohio Global Settlement

In February 2017, the PUCO approved a settlement agreement (Global Settlement) filed by OPCo in December 2016. The parties to the Global Settlement include OPCo, the PUCO staff and various intervenors. The Global Settlement resolves all remaining open issues on remand from the Ohio Supreme Court in OPCo’s 2009 - 2011 and June 2012 - May 2015 ESP filings, including issues related to carrying charges on the PIRR and issues related to the RSR capacity charges. It also resolves all open issues in OPCo’s 2009, 2014 and 2015 SEET filings and 2009, 2012 and 2013 Fuel Adjustment Clause Audits.

The significant components of the Global Settlement include:

Remands Related to the PIRR

All applicable parties participating in this settlement will withdraw their pending applications for rehearing of the PUCO order that allowed for the reinstatement of the equity portion of the WACC rate on previously deferred fuel balances. As part of the Global Settlement, the PIRR rate to be collected from customers through December 2018 will be reduced by $97 million.

Remands Related to the RSR

Beginning January 2017, OPCo will be entitled to collect $388 million in RSR revenues over a total of 30 months, subject to true up at the end of the collection period in June 2019. Current RSR rates will continue until the new RSR rates are approved. The Global Settlement resolves the issues related to the non-deferral portion of RSR collections and the impact of the appropriate energy credit on capacity charges. In December 2016, OPCo recorded an increase in Regulatory Assets on the balance sheets for the deferral of $83 million in RSR capacity costs and $14 million in related debt carrying charges with a corresponding decrease in expense in Generation Deferrals and an increase in Carrying Costs Income, respectively, on the statements of income.

For the year ended December 31, 2016, AEP recorded approximately $97 million in RSR capacity deferrals and related carrying charges to the following line items on the statements of income:

	AEP
	(in millions)
Fuel and Other Consumables Used for Electric Generation	$	(19.0	)
Purchased Electricity for Resale	(19.9		)
Other Operation	(15.7		)
Depreciation and Amortization	(42.1		)
Total Decrease in RSR Expenses	$	(96.7	)

As of December 31, 2016, OPCo’s total RSR under-recovery balance, including carrying charges, was $299 million.

Remands Related to the SEET

As part of the Global Settlement,$20 million will be returned to customers over a 12-month period commencing within 45 days of the final PUCO order adopting the Global Settlement. The Global Settlement states that this obligation has no precedential effect on OPCo’s SEET methodology. In addition, the parties agreed that earnings were not significantly excessive in 2015. In December 2016, OPCo accrued $20 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the issues related to the 2014 and 2015 SEET proceedings.

Fuel Adjustment Clause Proceedings

OPCo will refund $100 million paid by SSO customers from August 2012 - May 2015 related to OVEC and Lawrenceburg purchases. In December 2016, OPCo accrued $100 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the claimed recovery of fixed fuel costs through both the FAC and the approved capacity charges. This refund will be a one-time credit that will be applied the earlier of either 45 days after the final non-appealable order from the PUCO adopting the Global Settlement, or the December 2017 billing cycle.

Ohio Electric Security Plan Filings

2009 – 2011 ESP

The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018.

In 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a WACC rate. In 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and remanded the matter back to the PUCO for reinstatement of the WACC rate. In June 2016, the PUCO approved OPCo’s proposed increase to the PIRR rates, in accordance with the Supreme Court of Ohio ruling. The increase to PIRR rates included $146 million in additional carrying charges and the recovery of $40 million in additional under-recovered fuel costs resulting from a decrease in customer demand. The increase is effective July 2016 through December 2018. In July 2016, intervenors filed requests for rehearing with the PUCO, which the PUCO granted in August 2016. In December 2016, OPCo filed a Global Settlement with the PUCO related to this issue. See “Ohio Global Settlement” section above.

June 2012 – May 2015 ESP Including Capacity Charge

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 July 2012, the PUCO issued an order in a separate capacity proceeding requiring OPCo to charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day.  The OPCo RPM price collected from CRES providers, which included reserve margins, was approximately $34/MW day through May 2014 and $150/MW day from June 2014 through May 2015. In April 2016, the Supreme Court of Ohio issued two opinions related to the deferral of OPCo’s capacity charges. In one of the opinions, the Supreme Court of Ohio ruled that the PUCO must reconsider an energy credit that was used to determine OPCo’s authorized capacity deferral threshold of $188.88/MW day during the August 2012 through May 2015 period. The PUCO reduced OPCo’s authorized capacity deferral threshold to $188.88/MW day largely due to an offset for an energy credit of $147.41/MW day. The Supreme Court of Ohio directed the PUCO to substantively address OPCo’s arguments that the $147.41/MW day credit was overstated by approximately $100/MW day due to various inaccuracies affecting input data and assumptions. See “Ohio Global Settlement” section above.

As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012.  The RSR was collected from customers at $3.50/MWh through May 2014 and at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. In April 2015, the PUCO issued an order that modified and approved OPCo’s July 2014 application to collect the unrecovered portion of the deferred capacity costs. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00/MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance. As of December 31, 2016, OPCo’s net deferred capacity costs balance was $202 million, including debt carrying costs, and was recorded in Regulatory Assets on the balance sheets. In April 2016, the second Supreme Court of Ohio opinion rejected a portion of OPCo’s RSR revenues collected during the period September 2012 through May 2015 and directed the PUCO to reduce OPCo’s deferred capacity costs by these previously collected RSR revenues. The Supreme Court of Ohio was not able to determine the amount of the reduction to OPCo’s deferred capacity costs and remanded the issue to the PUCO to determine the appropriate reduction. As directed by the PUCO, in May 2016, OPCo submitted revised RSR tariffs that reflect the RSR being collected subject to refund. See “Ohio Global Settlement” section above.

In April 2016, the Supreme Court of Ohio also ruled favorably on OPCo’s cross-appeal regarding a previously PUCO-imposed SEET threshold under the ESP and remanded this issue to the PUCO. See “Ohio Global Settlement” section above and “Significantly Excessive Earnings Test Filings” section below.

In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings.

In 2014, the PUCO denied all rehearing requests, 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, and 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. See “2012 and 2013 Fuel Adjustment Clause Audits” section below.

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, (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, and due to the interrelated nature of the two Supreme Court of Ohio opinions that directly relate to OPCo’s deferred capacity costs, 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. 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 December 2016, OPCo filed a Global Settlement with the PUCO related to these issues. See “Ohio Global Settlement” section above.

June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024

In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a PPA rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets.

In February 2015, the PUCO issued an order approving OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo’s and various intervenors’ requests for rehearing related to the May 2015 order. In November 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments and denied the remaining requests for rehearing. In January 2017, the PUCO granted intervenors requests for rehearing that oppose the PPA rider as well as the amended DIR caps.

In May 2015, OPCo filed an amended PPA application that (a) included OPCo’s OVEC contractual entitlement (OVEC PPA), (b) addressed the PPA requirements set forth in the PUCO’s February 2015 order and (c) included the 2,671 MWs to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units (Affiliate PPA).

In March 2016, a contested stipulation agreement related to the PPA rider application was modified and approved by the PUCO. The approved PPA rider is effective April 2016 through May 2024, subject to audit and review by the PUCO. The stipulation agreement, as approved, included (a) an Affiliate PPA between OPCo and AGR to be included in the PPA rider, (b) OPCo’s OVEC PPA to be included in the PPA rider, (c) potential additional contingent customer credits of up to $100 million to be included in the PPA rider over the final four years of the PPA rider and (d) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions.

In April 2016, the FERC issued an order granting a January 2016 complaint filed against AGR and OPCo.  The FERC order rescinded the waivers of the 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 accordance with FERC’s rules governing affiliate transactions.  As a result 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 proposed OVEC-only PPA Rider to recover the net margin after sales through PJM and 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 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. In November 2016, the PUCO issued an order on rehearing that approved recovery of the OVEC-related net margin incurred from June 2016 through the term of the PPA rider and the modification to reduce the customer credits to $15 million as requested by OPCo. The PUCO rejected OPCo’s request to eliminate both the 5% rate impact cap and the inclusion of the capacity performance penalties within the PPA rider. In January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC-only PPA and stated that the stipulation agreement approved in March 2016 does not provide customers with rate stability.

OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO makes unacceptable modifications to the stipulation, including modifications as part of the pending rehearing.

Consistent with the terms of the modified and approved stipulation agreement, and based upon a September 2016 PUCO order, in November 2016, OPCo refiled its amended ESP extension application and supporting testimony. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.

Significantly Excessive Earnings Test Filings

Background

Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric distribution utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk.

2009 SEET Filing

In 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project.

In September 2013, a proposed second phase of OPCo’s gridSMART^® (gridSMART^® Phase II) program was filed with the PUCO which included a proposed project to satisfy the PUCO 2009 SEET directive. In April 2016, a stipulation agreement related to the gridSMART^® Phase II program was filed with the PUCO. As part of the stipulation agreement, OPCo will invest at least $20 million over a six-year period for the installation of Volt VAR Optimization (VVO) technology on selected circuits throughout OPCo’s service territory. All parties to the stipulation agree that OPCo’s proposed VVO investment resolves OPCo’s outstanding obligation for renewable or similar investment associated with the PUCO’s 2009 SEET directive. As a part of the December 2016 Global Settlement, OCC agreed to no longer contest the gridSMART^® Phase II stipulation. In February 2017, the PUCO approved the gridSMART^® Phase II stipulation agreement. See “Ohio Global Settlement” section above.

2014 and 2015 SEET Filings

The PUCO established an annual SEET earnings threshold of 12% during the June 2012 - May 2015 ESP period. In May 2013, OPCo filed a cross appeal with the Supreme Court of Ohio, asserting that the SEET threshold was not based on the earnings of comparable publicly traded companies as originally required by the SEET statute.

In April 2016, the Supreme Court of Ohio agreed with OPCo’s cross-appeal assertion that a 12% SEET threshold was not based on the applicable Ohio SEET statute. The Supreme Court of Ohio reversed the 12% threshold and remanded this issue to the PUCO.

In June 2015 and May 2016, OPCo submitted its SEET filings for 2014 and 2015, respectively, with the PUCO. In August 2016, intervenors filed testimony recommending a revenue refund of approximately $20 million for 2014 and no refund for 2015 based upon a new approach to determine significantly excessive earnings that has not been previously approved by the PUCO. In September 2016, OPCo and the PUCO staff filed a stipulation agreement with the PUCO stating that no significantly excessive earnings occurred for 2014 or 2015. In September 2016, intervenors filed testimony opposing the stipulation agreement. See “Ohio Global Settlement” section above.

2016 SEET Filing

OPCo expects to submit its 2016 SEET filing in the second quarter of 2017.  OPCo’s 2016 SEET provision was determined by excluding the gain on the deferral of RSR costs related to the Global Settlement. In addition, refunds to customers included in the Global Settlement relating to the SEET remands and fuel adjustment clause proceedings were excluded from the determination of the 2016 SEET provision. Management believes its financial statements adequately address the impact of 2016 SEET requirements.  If the PUCO adopts a different 2016 SEET methodology, it could reduce future net income and cash flows and impact financial condition.

2009 Fuel Adjustment Clause Audit

In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statements of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. See “Ohio Global Settlement” section above.

2012 and 2013 Fuel Adjustment Clause Audits

In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the “June 2012 - May 2015 ESP Including Capacity Charge” and “Ohio Global Settlement” sections above.

Ormet

Ormet, a large aluminum company, had a contract to purchase power from OPCo. In OPCo’s 2009 - 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues. Through September 2009, the last month of the interim arrangement, OPCo had approximately $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s filing to approve recovery of the deferral under the interim agreement. Of the $64 million in deferred FAC costs, approximately 50% was related to Columbus Southern Power Company (CSPCo) and 50% related to OPCo, prior to the merger of CSPCo into OPCo in December 2011. CSPCo’s portion of these deferred fuel costs has been recovered as a result of the previous collections of CSPCo fuel costs from ratepayers and the PUCO’s 2013 order to apply CSPCo’s 2010 excessive earnings to offset CSPCo’s final deferred fuel balance. OPCo’s share of Ormet deferred fuel costs continues to be recovered through OPCo’s PIRR.

The Ohio Global Settlement discussed above, approved by the PUCO in February 2017, includes the resolution of the 2009, 2012 and 2013 Fuel Adjustment Clause Audits together with the finalization of the PIRR.  The resolution of those cases effectively makes the risk of non-recovery of the Ormet deferrals remote.

PSO Rate Matters (Applies to AEP and PSO)

2015 Oklahoma Base Rate Case

In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million. The request consisted 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 included a proposed return on common equity of 10.5%. The $44 million increase related to environmental investments was proposed to be effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls were 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 December 31, 2016, PSO had incurred costs of $181 million and $44 million, including AFUDC, for Northeastern Plant, Unit 3 and Comanche Plant, respectively. In January 2016, PSO implemented an interim annual base rate increase of $75 million, subject to refund.

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, 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 sheets related to the net book value of Northeastern Plant, Unit 4. These regulatory assets are pending regulatory approval.

In November 2016 and December 2016, the OCC issued orders that approved a net annual revenue increase of $19 million based upon a 9.5% return on common equity. The orders also included (a) approval to defer incurred costs related to PSO’s environmental compliance plan until those costs are included in base rates, (b) no determination related to the return of and return on the post-retirement remaining net book value of Northeastern Plant, Unit 4 since the April 2016 retirement was outside of the test year, (c) approval to include environmental consumable costs in the FAC (d) the continued depreciation of Northeastern Plant, Units 3 and 4 through 2040 (no accelerated depreciation) and (e) altered the system reliability rider by eliminating the expense portion of the rider and setting the capital portion of the rider at the December 2016 plant balance and approved recovery of deferred expenses and return on the capital balance incurred prior to the effective date of new tariffs in January 2017. Additionally, the orders stated that the cost recovery of new PPAs related to replacement power resulting from the retirement of Northeastern Plant, Unit 4 will be addressed in a future FAC proceeding. Effective December 2016, interim rates were terminated and the refund of over collections began and will be completed no later than October 2017. In accordance with the final order, updated rates and tariffs went into effect in January 2017.

If any of these costs, including a return on Northeastern Plant, Unit 4, are ultimately not recoverable, it could reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters (Applies to AEP and SWEPCo)

2012 Texas Base Rate Case

In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2.

Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million. In 2014, intervenors filed appeals of that order with the Texas District Court and SWEPCo intervened in those appeals. A hearing at the Texas District Court is scheduled for March 2017.

If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition.

2016 Texas Base Rate Case

In December 2016, SWEPCo filed a base rate request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. The annual increase includes approximately (a) $34 million related to additional environmental controls to comply with Federal EPA mandates, (b) $25 million for additional generation, transmission and distribution investments and increased operating costs, (c) $8 million related to transmission cost recovery within SWEPCo’s regional transmission organization and (d) $2 million in additional vegetation management.

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

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant. In February 2013, a settlement was approved by the LPSC. The settlement increased SWEPCo’s Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually.  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. The rates are subject to refund based on the prudence review of the Turk Plant. The settlement also provided that the LPSC would review base rates in 2014 and 2015 and that SWEPCo would 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 June 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.

2014 Louisiana Formula Rate Filing

In 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC.  The filing included a $5 million annual increase, which was effective August 2014.  SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million. This additional increase reflects the cost of incremental generation used to serve Louisiana customers in 2015 due to the expiration of a purchased power agreement attributable to Louisiana customers.  In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015, subject to staff review of the cost of service and prudence review of the Turk Plant. In July 2016, the LPSC approved a settlement agreement related to the staff review of the cost of service. A portion of the rates remain subject to refund based on the prudence review of the Turk Plant. See “2012 Louisiana Formula Rate Filing” above. Management believes its financial statements adequately address the impact of this settlement agreement. 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.

2015 Louisiana Formula Rate Filing

In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC.  The filing included a $14 million annual increase, which was effective August 2015.  This increase is subject to LPSC staff review and is subject to refund.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Welsh Plant - Environmental Impact

Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could cost a total of approximately $850 million, excluding AFUDC. As of December 31, 2016, SWEPCo had incurred costs of $397 million, including AFUDC, and had remaining contractual construction obligations of $11 million related to these projects.  As part of this investment, in 2016 SWEPCo completed construction of environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $370 million, excluding AFUDC.  Management continues to evaluate the impact of environmental rules and related project cost estimates. In March 2016, SWEPCo filed a request with the APSC to recover $69 million in environmental costs related to the Arkansas retail jurisdictional share of Welsh Plant, Units 1 and 3, which was approved by the APSC in August 2016. SWEPCo began recovering the Arkansas jurisdictional share of these costs in March 2016, subject to review in the next filed base rate proceeding. In September 2016, SWEPCo filed an additional request to increase the Arkansas retail jurisdictional share of the environmental investment by $10 million, for a total of $79 million. SWEPCo implemented the increase in September 2016. In December 2016, the LPSC approved deferral of certain expenses related to environmental controls installed at Welsh Plant, until these investments are put into base rates. The eligible Welsh Plant deferrals through December 31, 2016 are $8 million, excluding $5 million of unrecognized equity, subject to review by the LPSC, and include a WACC return on environmental investments and the related depreciation expense and taxes. SWEPCo will seek recovery of its project costs from customers at the state commissions and the FERC.

As of December 31, 2016, the net book value of Welsh Plant, Units 1 and 3 was $633 million, before cost of removal, including materials and supplies inventory and CWIP.  In April 2016, Welsh Plant, Unit 2 was retired. Upon retirement, $76 million was reclassified as Regulatory Assets on the balance sheets related to the net book value of Welsh Plant, Unit 2 and the related asset retirement obligation costs. In SWEPCo’s 2016 Texas Base Rate Case, SWEPCo requested recovery of the Texas jurisdictional share (approximately 33%) of the net book value of Welsh Plant, Unit 2 through 2042, the remaining life of Welsh Plant, Unit 3. Management will seek recovery of the remaining Welsh Plant, Unit 2 retirement-related regulatory assets in future rate proceedings.

If any of these costs are not recoverable, including retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.

AEP Texas Rate Matters (Applies to AEP)

TCC and TNC Merger

Effective December 31, 2016, TCC and TNC merged into AEP Utilities, Inc., as approved by the FERC and the PUCT in September 2016 and December 2016, respectively. Upon merger, AEP Utilities, Inc. changed its name to AEP Texas Inc., but maintained TCC’s and TNC’s respective customer rates. The PUCT ordered certain post-merger conditions which included a) the sharing of certain interest rate savings with customers 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.

AEP Texas Distribution Cost Recovery Factor (DCRF)

In July 2016, the PUCT approved settlement agreements between TCC, TNC and intervenors related to requests for DCRF riders to allow recovery of eligible net distribution investments. The settlement agreement included an annual revenue requirement of $56 million ($45 million for the TCC division and $11 million for the TNC division), effective September 2016. Amounts approved are subject to refund based upon a prudence review of the investments in AEP Texas’ next base rate case.

FERC Rate Matters (Applies to AEP, APCo, I&M and OPCo)

PJM Transmission Rates

In June 2016, PJM transmission owners, including the AEP East Companies, and various state commissions filed a settlement agreement with the FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. In July 2016, certain parties filed comments at the FERC contesting the settlement agreement. Upon final FERC approval, PJM would implement a transmission enhancement charge adjustment through the PJM OATT, billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms.

FERC Transmission Complaint and Proposed Modifications to Transmission Rates

In October 2016, several parties filed a joint complaint with the FERC claiming that the base return on common equity used by various AEP affiliates 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 2016, AEP affiliates filed an application with the FERC to modify the FERC formula transmission rate calculation, including adjustments for certain tax issues and a shift from historical to estimated expenses with a proposed effective date of January 1, 2017. The rates will be implemented based upon the date provided in the pending FERC order, subject to refund. Management believes its financial statements adequately address the impact of the complaint and the proposed modifications to AEP’s transmission rates in PJM. 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.

Other Rate Matters (Applies to AEP, PSO and SWEPCo)

SPP OATT Upgrade Costs

Under the SPP OATT, costs of sponsor-funded transmission upgrades may be recovered, in part, from SPP customers whose transmission service is dependent upon capacity enabled by the upgrades. Prior to 2016, SPP had not charged its customers any amounts attributable to these upgrades. In November 2016, SPP billed transmission service customers, including PSO and SWEPCo, for upgrade costs incurred since 2008. SPP then credited the qualifying transmission upgrade owners, including SWEPCo, for the use of these upgrades. In 2016, PSO and SWEPCo recognized a net unfavorable impact of approximately $3 million and $4 million, respectively, related to the OATT upgrade costs.

Indiana Michigan Power Co [Member]

Rate Matters

RATE MATTERS

The disclosures in this note apply to all Registrants unless indicated otherwise.

The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions.  Rate matters can have a material impact on net income, cash flows and possibly financial condition.  The Registrants’ recent significant rate orders and pending rate filings are addressed in this note.

APCo and WPCo Rate Matters (Applies to AEP and APCo)

2016 West Virginia Expanded Net Energy Cost Filing

In June 2016, the WVPSC approved a settlement agreement related to APCo and WPCo’s combined annual ENEC filing. The settlement agreement included $38 million ($30 million related to APCo) of additional ENEC revenues and $17 million ($14 million related to APCo) in construction surcharges annually for two years, effective July 2016. Additionally, APCo and WPCo agreed that a general rate case will not be filed before April 2018.

West Virginia Deferred Base Rate Increase

In May 2015, the WVPSC issued an order on APCo and WPCo’s combined base rate case. The order included a delayed billing of $25 million ($22 million related to APCo) of the annual base rate increase to residential customers until July 2016. In June 2016, the WVPSC issued an order that approved recovery of the total deferred billing, including carrying charges through June 2018, totaling $29 million ($27 million related to APCo). Recovery was approved over two years, effective July 2016. Additionally, at the end of the two-year amortization, any over/under-recovery of the delayed billing will be included in the annual ENEC filing. The WVPSC also approved implementation of the prospective $25 million base rate increase effective July 2016.

2015 Virginia Regulatory Asset Proceeding

In 2015, the Virginia SCC initiated a proceeding to address the treatment of APCo’s authorized regulatory assets. In September 2016, the Virginia SCC issued an order that approved the continued recovery through amortization of certain regulatory assets established prior to the period of frozen rates pursuant to the amended Virginia law (see “Virginia Legislation Affecting Biennial Reviews” below).

Virginia Legislation Affecting Biennial Reviews

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’s financial statements adequately address the impact of these amendments. The amendments 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.

In February 2016, certain APCo industrial customers filed a petition with the Virginia SCC requesting the issuance of a declaratory order that finds the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, directs APCo to make biennial review filings beginning in 2016. In July 2016, the Virginia SCC issued an order that denied the petition. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition.

ETT Rate Matters (Applies to AEP)

ETT Interim Transmission Rates

Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. During a 2015 open meeting at the PUCT, ETT committed to file a base rate case by February 2017. In January 2017, the PUCT approved ETT’s request to suspend the base rate case filing and decrease ETT’s annual revenue requirement by $46 million, effective March 2017. As of December 31, 2016, AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $591 million based upon interim rate increases received from 2009 through 2016. A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. Management is unable to determine a range of potential losses that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters (Applies to AEP and I&M)

Indiana Amended PJM Settlement Agreement

In November 2016, the IURC issued an order that approved an amended settlement agreement between I&M and certain intervenors.  This agreement amends a previously approved 2014 settlement agreement that addresses the recovery of 43.5% of certain transmission expenses through the Indiana PJM rider through 2017.

The amended agreement allows I&M to recover 100% of the Indiana jurisdictional share of these transmission expenses not recovered through base rates through the Indiana PJM rider, subject to a $109 million cap for the period January 2017 through June 2018. Beginning July 2018, I&M will be allowed to recover 100% of the Indiana jurisdictional share of these transmission expenses through the Indiana PJM rider, without a cap, until the issue is addressed by the IURC in a future proceeding, subject to the condition that I&M files a base rate case on or before January 2018. The amended agreement also provides for deferral of incremental vegetation management expenses over the period January 2017 through June 2018.  Any vegetation management expenses deferred would reduce the cap for the transmission expenses described above. As part of the amended settlement, I&M agreed that it will not file a base rate case before July 2017 and will not implement new base rates prior to July 2018.

Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR)

In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO_x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million, excluding AFUDC, to be shared equally between I&M and AEGCo.  The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year life and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. 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 limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC is scheduled for March 2017.

KGPCo Rate Matters (Applies to AEP)

Kingsport Base Rate Case

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.

OPCo Rate Matters (Applies to AEP and OPCo)

Ohio Global Settlement

In February 2017, the PUCO approved a settlement agreement (Global Settlement) filed by OPCo in December 2016. The parties to the Global Settlement include OPCo, the PUCO staff and various intervenors. The Global Settlement resolves all remaining open issues on remand from the Ohio Supreme Court in OPCo’s 2009 - 2011 and June 2012 - May 2015 ESP filings, including issues related to carrying charges on the PIRR and issues related to the RSR capacity charges. It also resolves all open issues in OPCo’s 2009, 2014 and 2015 SEET filings and 2009, 2012 and 2013 Fuel Adjustment Clause Audits.

The significant components of the Global Settlement include:

Remands Related to the PIRR

All applicable parties participating in this settlement will withdraw their pending applications for rehearing of the PUCO order that allowed for the reinstatement of the equity portion of the WACC rate on previously deferred fuel balances. As part of the Global Settlement, the PIRR rate to be collected from customers through December 2018 will be reduced by $97 million.

Remands Related to the RSR

Beginning January 2017, OPCo will be entitled to collect $388 million in RSR revenues over a total of 30 months, subject to true up at the end of the collection period in June 2019. Current RSR rates will continue until the new RSR rates are approved. The Global Settlement resolves the issues related to the non-deferral portion of RSR collections and the impact of the appropriate energy credit on capacity charges. In December 2016, OPCo recorded an increase in Regulatory Assets on the balance sheets for the deferral of $83 million in RSR capacity costs and $14 million in related debt carrying charges with a corresponding decrease in expense in Generation Deferrals and an increase in Carrying Costs Income, respectively, on the statements of income.

For the year ended December 31, 2016, AEP recorded approximately $97 million in RSR capacity deferrals and related carrying charges to the following line items on the statements of income:

	AEP
	(in millions)
Fuel and Other Consumables Used for Electric Generation	$	(19.0	)
Purchased Electricity for Resale	(19.9		)
Other Operation	(15.7		)
Depreciation and Amortization	(42.1		)
Total Decrease in RSR Expenses	$	(96.7	)

As of December 31, 2016, OPCo’s total RSR under-recovery balance, including carrying charges, was $299 million.

Remands Related to the SEET

As part of the Global Settlement,$20 million will be returned to customers over a 12-month period commencing within 45 days of the final PUCO order adopting the Global Settlement. The Global Settlement states that this obligation has no precedential effect on OPCo’s SEET methodology. In addition, the parties agreed that earnings were not significantly excessive in 2015. In December 2016, OPCo accrued $20 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the issues related to the 2014 and 2015 SEET proceedings.

Fuel Adjustment Clause Proceedings

OPCo will refund $100 million paid by SSO customers from August 2012 - May 2015 related to OVEC and Lawrenceburg purchases. In December 2016, OPCo accrued $100 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the claimed recovery of fixed fuel costs through both the FAC and the approved capacity charges. This refund will be a one-time credit that will be applied the earlier of either 45 days after the final non-appealable order from the PUCO adopting the Global Settlement, or the December 2017 billing cycle.

Ohio Electric Security Plan Filings

2009 – 2011 ESP

The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018.

In 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a WACC rate. In 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and remanded the matter back to the PUCO for reinstatement of the WACC rate. In June 2016, the PUCO approved OPCo’s proposed increase to the PIRR rates, in accordance with the Supreme Court of Ohio ruling. The increase to PIRR rates included $146 million in additional carrying charges and the recovery of $40 million in additional under-recovered fuel costs resulting from a decrease in customer demand. The increase is effective July 2016 through December 2018. In July 2016, intervenors filed requests for rehearing with the PUCO, which the PUCO granted in August 2016. In December 2016, OPCo filed a Global Settlement with the PUCO related to this issue. See “Ohio Global Settlement” section above.

June 2012 – May 2015 ESP Including Capacity Charge

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 July 2012, the PUCO issued an order in a separate capacity proceeding requiring OPCo to charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day.  The OPCo RPM price collected from CRES providers, which included reserve margins, was approximately $34/MW day through May 2014 and $150/MW day from June 2014 through May 2015. In April 2016, the Supreme Court of Ohio issued two opinions related to the deferral of OPCo’s capacity charges. In one of the opinions, the Supreme Court of Ohio ruled that the PUCO must reconsider an energy credit that was used to determine OPCo’s authorized capacity deferral threshold of $188.88/MW day during the August 2012 through May 2015 period. The PUCO reduced OPCo’s authorized capacity deferral threshold to $188.88/MW day largely due to an offset for an energy credit of $147.41/MW day. The Supreme Court of Ohio directed the PUCO to substantively address OPCo’s arguments that the $147.41/MW day credit was overstated by approximately $100/MW day due to various inaccuracies affecting input data and assumptions. See “Ohio Global Settlement” section above.

As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012.  The RSR was collected from customers at $3.50/MWh through May 2014 and at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. In April 2015, the PUCO issued an order that modified and approved OPCo’s July 2014 application to collect the unrecovered portion of the deferred capacity costs. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00/MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance. As of December 31, 2016, OPCo’s net deferred capacity costs balance was $202 million, including debt carrying costs, and was recorded in Regulatory Assets on the balance sheets. In April 2016, the second Supreme Court of Ohio opinion rejected a portion of OPCo’s RSR revenues collected during the period September 2012 through May 2015 and directed the PUCO to reduce OPCo’s deferred capacity costs by these previously collected RSR revenues. The Supreme Court of Ohio was not able to determine the amount of the reduction to OPCo’s deferred capacity costs and remanded the issue to the PUCO to determine the appropriate reduction. As directed by the PUCO, in May 2016, OPCo submitted revised RSR tariffs that reflect the RSR being collected subject to refund. See “Ohio Global Settlement” section above.

In April 2016, the Supreme Court of Ohio also ruled favorably on OPCo’s cross-appeal regarding a previously PUCO-imposed SEET threshold under the ESP and remanded this issue to the PUCO. See “Ohio Global Settlement” section above and “Significantly Excessive Earnings Test Filings” section below.

In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings.

In 2014, the PUCO denied all rehearing requests, 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, and 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. See “2012 and 2013 Fuel Adjustment Clause Audits” section below.

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, (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, and due to the interrelated nature of the two Supreme Court of Ohio opinions that directly relate to OPCo’s deferred capacity costs, 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. 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 December 2016, OPCo filed a Global Settlement with the PUCO related to these issues. See “Ohio Global Settlement” section above.

June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024

In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a PPA rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets.

In February 2015, the PUCO issued an order approving OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo’s and various intervenors’ requests for rehearing related to the May 2015 order. In November 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments and denied the remaining requests for rehearing. In January 2017, the PUCO granted intervenors requests for rehearing that oppose the PPA rider as well as the amended DIR caps.

In May 2015, OPCo filed an amended PPA application that (a) included OPCo’s OVEC contractual entitlement (OVEC PPA), (b) addressed the PPA requirements set forth in the PUCO’s February 2015 order and (c) included the 2,671 MWs to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units (Affiliate PPA).

In March 2016, a contested stipulation agreement related to the PPA rider application was modified and approved by the PUCO. The approved PPA rider is effective April 2016 through May 2024, subject to audit and review by the PUCO. The stipulation agreement, as approved, included (a) an Affiliate PPA between OPCo and AGR to be included in the PPA rider, (b) OPCo’s OVEC PPA to be included in the PPA rider, (c) potential additional contingent customer credits of up to $100 million to be included in the PPA rider over the final four years of the PPA rider and (d) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions.

In April 2016, the FERC issued an order granting a January 2016 complaint filed against AGR and OPCo.  The FERC order rescinded the waivers of the 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 accordance with FERC’s rules governing affiliate transactions.  As a result 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 proposed OVEC-only PPA Rider to recover the net margin after sales through PJM and 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 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. In November 2016, the PUCO issued an order on rehearing that approved recovery of the OVEC-related net margin incurred from June 2016 through the term of the PPA rider and the modification to reduce the customer credits to $15 million as requested by OPCo. The PUCO rejected OPCo’s request to eliminate both the 5% rate impact cap and the inclusion of the capacity performance penalties within the PPA rider. In January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC-only PPA and stated that the stipulation agreement approved in March 2016 does not provide customers with rate stability.

OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO makes unacceptable modifications to the stipulation, including modifications as part of the pending rehearing.

Consistent with the terms of the modified and approved stipulation agreement, and based upon a September 2016 PUCO order, in November 2016, OPCo refiled its amended ESP extension application and supporting testimony. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.

Significantly Excessive Earnings Test Filings

Background

Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric distribution utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk.

2009 SEET Filing

In 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project.

In September 2013, a proposed second phase of OPCo’s gridSMART^® (gridSMART^® Phase II) program was filed with the PUCO which included a proposed project to satisfy the PUCO 2009 SEET directive. In April 2016, a stipulation agreement related to the gridSMART^® Phase II program was filed with the PUCO. As part of the stipulation agreement, OPCo will invest at least $20 million over a six-year period for the installation of Volt VAR Optimization (VVO) technology on selected circuits throughout OPCo’s service territory. All parties to the stipulation agree that OPCo’s proposed VVO investment resolves OPCo’s outstanding obligation for renewable or similar investment associated with the PUCO’s 2009 SEET directive. As a part of the December 2016 Global Settlement, OCC agreed to no longer contest the gridSMART^® Phase II stipulation. In February 2017, the PUCO approved the gridSMART^® Phase II stipulation agreement. See “Ohio Global Settlement” section above.

2014 and 2015 SEET Filings

The PUCO established an annual SEET earnings threshold of 12% during the June 2012 - May 2015 ESP period. In May 2013, OPCo filed a cross appeal with the Supreme Court of Ohio, asserting that the SEET threshold was not based on the earnings of comparable publicly traded companies as originally required by the SEET statute.

In April 2016, the Supreme Court of Ohio agreed with OPCo’s cross-appeal assertion that a 12% SEET threshold was not based on the applicable Ohio SEET statute. The Supreme Court of Ohio reversed the 12% threshold and remanded this issue to the PUCO.

In June 2015 and May 2016, OPCo submitted its SEET filings for 2014 and 2015, respectively, with the PUCO. In August 2016, intervenors filed testimony recommending a revenue refund of approximately $20 million for 2014 and no refund for 2015 based upon a new approach to determine significantly excessive earnings that has not been previously approved by the PUCO. In September 2016, OPCo and the PUCO staff filed a stipulation agreement with the PUCO stating that no significantly excessive earnings occurred for 2014 or 2015. In September 2016, intervenors filed testimony opposing the stipulation agreement. See “Ohio Global Settlement” section above.

2016 SEET Filing

OPCo expects to submit its 2016 SEET filing in the second quarter of 2017.  OPCo’s 2016 SEET provision was determined by excluding the gain on the deferral of RSR costs related to the Global Settlement. In addition, refunds to customers included in the Global Settlement relating to the SEET remands and fuel adjustment clause proceedings were excluded from the determination of the 2016 SEET provision. Management believes its financial statements adequately address the impact of 2016 SEET requirements.  If the PUCO adopts a different 2016 SEET methodology, it could reduce future net income and cash flows and impact financial condition.

2009 Fuel Adjustment Clause Audit

In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statements of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. See “Ohio Global Settlement” section above.

2012 and 2013 Fuel Adjustment Clause Audits

In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the “June 2012 - May 2015 ESP Including Capacity Charge” and “Ohio Global Settlement” sections above.

Ormet

Ormet, a large aluminum company, had a contract to purchase power from OPCo. In OPCo’s 2009 - 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues. Through September 2009, the last month of the interim arrangement, OPCo had approximately $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s filing to approve recovery of the deferral under the interim agreement. Of the $64 million in deferred FAC costs, approximately 50% was related to Columbus Southern Power Company (CSPCo) and 50% related to OPCo, prior to the merger of CSPCo into OPCo in December 2011. CSPCo’s portion of these deferred fuel costs has been recovered as a result of the previous collections of CSPCo fuel costs from ratepayers and the PUCO’s 2013 order to apply CSPCo’s 2010 excessive earnings to offset CSPCo’s final deferred fuel balance. OPCo’s share of Ormet deferred fuel costs continues to be recovered through OPCo’s PIRR.

The Ohio Global Settlement discussed above, approved by the PUCO in February 2017, includes the resolution of the 2009, 2012 and 2013 Fuel Adjustment Clause Audits together with the finalization of the PIRR.  The resolution of those cases effectively makes the risk of non-recovery of the Ormet deferrals remote.

PSO Rate Matters (Applies to AEP and PSO)

2015 Oklahoma Base Rate Case

In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million. The request consisted 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 included a proposed return on common equity of 10.5%. The $44 million increase related to environmental investments was proposed to be effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls were 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 December 31, 2016, PSO had incurred costs of $181 million and $44 million, including AFUDC, for Northeastern Plant, Unit 3 and Comanche Plant, respectively. In January 2016, PSO implemented an interim annual base rate increase of $75 million, subject to refund.

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, 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 sheets related to the net book value of Northeastern Plant, Unit 4. These regulatory assets are pending regulatory approval.

In November 2016 and December 2016, the OCC issued orders that approved a net annual revenue increase of $19 million based upon a 9.5% return on common equity. The orders also included (a) approval to defer incurred costs related to PSO’s environmental compliance plan until those costs are included in base rates, (b) no determination related to the return of and return on the post-retirement remaining net book value of Northeastern Plant, Unit 4 since the April 2016 retirement was outside of the test year, (c) approval to include environmental consumable costs in the FAC (d) the continued depreciation of Northeastern Plant, Units 3 and 4 through 2040 (no accelerated depreciation) and (e) altered the system reliability rider by eliminating the expense portion of the rider and setting the capital portion of the rider at the December 2016 plant balance and approved recovery of deferred expenses and return on the capital balance incurred prior to the effective date of new tariffs in January 2017. Additionally, the orders stated that the cost recovery of new PPAs related to replacement power resulting from the retirement of Northeastern Plant, Unit 4 will be addressed in a future FAC proceeding. Effective December 2016, interim rates were terminated and the refund of over collections began and will be completed no later than October 2017. In accordance with the final order, updated rates and tariffs went into effect in January 2017.

If any of these costs, including a return on Northeastern Plant, Unit 4, are ultimately not recoverable, it could reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters (Applies to AEP and SWEPCo)

2012 Texas Base Rate Case

In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2.

Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million. In 2014, intervenors filed appeals of that order with the Texas District Court and SWEPCo intervened in those appeals. A hearing at the Texas District Court is scheduled for March 2017.

If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition.

2016 Texas Base Rate Case

In December 2016, SWEPCo filed a base rate request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. The annual increase includes approximately (a) $34 million related to additional environmental controls to comply with Federal EPA mandates, (b) $25 million for additional generation, transmission and distribution investments and increased operating costs, (c) $8 million related to transmission cost recovery within SWEPCo’s regional transmission organization and (d) $2 million in additional vegetation management.

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

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant. In February 2013, a settlement was approved by the LPSC. The settlement increased SWEPCo’s Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually.  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. The rates are subject to refund based on the prudence review of the Turk Plant. The settlement also provided that the LPSC would review base rates in 2014 and 2015 and that SWEPCo would 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 June 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.

2014 Louisiana Formula Rate Filing

In 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC.  The filing included a $5 million annual increase, which was effective August 2014.  SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million. This additional increase reflects the cost of incremental generation used to serve Louisiana customers in 2015 due to the expiration of a purchased power agreement attributable to Louisiana customers.  In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015, subject to staff review of the cost of service and prudence review of the Turk Plant. In July 2016, the LPSC approved a settlement agreement related to the staff review of the cost of service. A portion of the rates remain subject to refund based on the prudence review of the Turk Plant. See “2012 Louisiana Formula Rate Filing” above. Management believes its financial statements adequately address the impact of this settlement agreement. 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.

2015 Louisiana Formula Rate Filing

In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC.  The filing included a $14 million annual increase, which was effective August 2015.  This increase is subject to LPSC staff review and is subject to refund.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Welsh Plant - Environmental Impact

Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could cost a total of approximately $850 million, excluding AFUDC. As of December 31, 2016, SWEPCo had incurred costs of $397 million, including AFUDC, and had remaining contractual construction obligations of $11 million related to these projects.  As part of this investment, in 2016 SWEPCo completed construction of environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $370 million, excluding AFUDC.  Management continues to evaluate the impact of environmental rules and related project cost estimates. In March 2016, SWEPCo filed a request with the APSC to recover $69 million in environmental costs related to the Arkansas retail jurisdictional share of Welsh Plant, Units 1 and 3, which was approved by the APSC in August 2016. SWEPCo began recovering the Arkansas jurisdictional share of these costs in March 2016, subject to review in the next filed base rate proceeding. In September 2016, SWEPCo filed an additional request to increase the Arkansas retail jurisdictional share of the environmental investment by $10 million, for a total of $79 million. SWEPCo implemented the increase in September 2016. In December 2016, the LPSC approved deferral of certain expenses related to environmental controls installed at Welsh Plant, until these investments are put into base rates. The eligible Welsh Plant deferrals through December 31, 2016 are $8 million, excluding $5 million of unrecognized equity, subject to review by the LPSC, and include a WACC return on environmental investments and the related depreciation expense and taxes. SWEPCo will seek recovery of its project costs from customers at the state commissions and the FERC.

As of December 31, 2016, the net book value of Welsh Plant, Units 1 and 3 was $633 million, before cost of removal, including materials and supplies inventory and CWIP.  In April 2016, Welsh Plant, Unit 2 was retired. Upon retirement, $76 million was reclassified as Regulatory Assets on the balance sheets related to the net book value of Welsh Plant, Unit 2 and the related asset retirement obligation costs. In SWEPCo’s 2016 Texas Base Rate Case, SWEPCo requested recovery of the Texas jurisdictional share (approximately 33%) of the net book value of Welsh Plant, Unit 2 through 2042, the remaining life of Welsh Plant, Unit 3. Management will seek recovery of the remaining Welsh Plant, Unit 2 retirement-related regulatory assets in future rate proceedings.

If any of these costs are not recoverable, including retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.

AEP Texas Rate Matters (Applies to AEP)

TCC and TNC Merger

Effective December 31, 2016, TCC and TNC merged into AEP Utilities, Inc., as approved by the FERC and the PUCT in September 2016 and December 2016, respectively. Upon merger, AEP Utilities, Inc. changed its name to AEP Texas Inc., but maintained TCC’s and TNC’s respective customer rates. The PUCT ordered certain post-merger conditions which included a) the sharing of certain interest rate savings with customers 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.

AEP Texas Distribution Cost Recovery Factor (DCRF)

In July 2016, the PUCT approved settlement agreements between TCC, TNC and intervenors related to requests for DCRF riders to allow recovery of eligible net distribution investments. The settlement agreement included an annual revenue requirement of $56 million ($45 million for the TCC division and $11 million for the TNC division), effective September 2016. Amounts approved are subject to refund based upon a prudence review of the investments in AEP Texas’ next base rate case.

FERC Rate Matters (Applies to AEP, APCo, I&M and OPCo)

PJM Transmission Rates

In June 2016, PJM transmission owners, including the AEP East Companies, and various state commissions filed a settlement agreement with the FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. In July 2016, certain parties filed comments at the FERC contesting the settlement agreement. Upon final FERC approval, PJM would implement a transmission enhancement charge adjustment through the PJM OATT, billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms.

FERC Transmission Complaint and Proposed Modifications to Transmission Rates

In October 2016, several parties filed a joint complaint with the FERC claiming that the base return on common equity used by various AEP affiliates 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 2016, AEP affiliates filed an application with the FERC to modify the FERC formula transmission rate calculation, including adjustments for certain tax issues and a shift from historical to estimated expenses with a proposed effective date of January 1, 2017. The rates will be implemented based upon the date provided in the pending FERC order, subject to refund. Management believes its financial statements adequately address the impact of the complaint and the proposed modifications to AEP’s transmission rates in PJM. 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.

Other Rate Matters (Applies to AEP, PSO and SWEPCo)

SPP OATT Upgrade Costs

Under the SPP OATT, costs of sponsor-funded transmission upgrades may be recovered, in part, from SPP customers whose transmission service is dependent upon capacity enabled by the upgrades. Prior to 2016, SPP had not charged its customers any amounts attributable to these upgrades. In November 2016, SPP billed transmission service customers, including PSO and SWEPCo, for upgrade costs incurred since 2008. SPP then credited the qualifying transmission upgrade owners, including SWEPCo, for the use of these upgrades. In 2016, PSO and SWEPCo recognized a net unfavorable impact of approximately $3 million and $4 million, respectively, related to the OATT upgrade costs.

Ohio Power Co [Member]

Rate Matters

RATE MATTERS

The disclosures in this note apply to all Registrants unless indicated otherwise.

The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions.  Rate matters can have a material impact on net income, cash flows and possibly financial condition.  The Registrants’ recent significant rate orders and pending rate filings are addressed in this note.

APCo and WPCo Rate Matters (Applies to AEP and APCo)

2016 West Virginia Expanded Net Energy Cost Filing

In June 2016, the WVPSC approved a settlement agreement related to APCo and WPCo’s combined annual ENEC filing. The settlement agreement included $38 million ($30 million related to APCo) of additional ENEC revenues and $17 million ($14 million related to APCo) in construction surcharges annually for two years, effective July 2016. Additionally, APCo and WPCo agreed that a general rate case will not be filed before April 2018.

West Virginia Deferred Base Rate Increase

In May 2015, the WVPSC issued an order on APCo and WPCo’s combined base rate case. The order included a delayed billing of $25 million ($22 million related to APCo) of the annual base rate increase to residential customers until July 2016. In June 2016, the WVPSC issued an order that approved recovery of the total deferred billing, including carrying charges through June 2018, totaling $29 million ($27 million related to APCo). Recovery was approved over two years, effective July 2016. Additionally, at the end of the two-year amortization, any over/under-recovery of the delayed billing will be included in the annual ENEC filing. The WVPSC also approved implementation of the prospective $25 million base rate increase effective July 2016.

2015 Virginia Regulatory Asset Proceeding

In 2015, the Virginia SCC initiated a proceeding to address the treatment of APCo’s authorized regulatory assets. In September 2016, the Virginia SCC issued an order that approved the continued recovery through amortization of certain regulatory assets established prior to the period of frozen rates pursuant to the amended Virginia law (see “Virginia Legislation Affecting Biennial Reviews” below).

Virginia Legislation Affecting Biennial Reviews

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’s financial statements adequately address the impact of these amendments. The amendments 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.

In February 2016, certain APCo industrial customers filed a petition with the Virginia SCC requesting the issuance of a declaratory order that finds the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, directs APCo to make biennial review filings beginning in 2016. In July 2016, the Virginia SCC issued an order that denied the petition. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition.

ETT Rate Matters (Applies to AEP)

ETT Interim Transmission Rates

Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. During a 2015 open meeting at the PUCT, ETT committed to file a base rate case by February 2017. In January 2017, the PUCT approved ETT’s request to suspend the base rate case filing and decrease ETT’s annual revenue requirement by $46 million, effective March 2017. As of December 31, 2016, AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $591 million based upon interim rate increases received from 2009 through 2016. A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. Management is unable to determine a range of potential losses that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters (Applies to AEP and I&M)

Indiana Amended PJM Settlement Agreement

In November 2016, the IURC issued an order that approved an amended settlement agreement between I&M and certain intervenors.  This agreement amends a previously approved 2014 settlement agreement that addresses the recovery of 43.5% of certain transmission expenses through the Indiana PJM rider through 2017.

The amended agreement allows I&M to recover 100% of the Indiana jurisdictional share of these transmission expenses not recovered through base rates through the Indiana PJM rider, subject to a $109 million cap for the period January 2017 through June 2018. Beginning July 2018, I&M will be allowed to recover 100% of the Indiana jurisdictional share of these transmission expenses through the Indiana PJM rider, without a cap, until the issue is addressed by the IURC in a future proceeding, subject to the condition that I&M files a base rate case on or before January 2018. The amended agreement also provides for deferral of incremental vegetation management expenses over the period January 2017 through June 2018.  Any vegetation management expenses deferred would reduce the cap for the transmission expenses described above. As part of the amended settlement, I&M agreed that it will not file a base rate case before July 2017 and will not implement new base rates prior to July 2018.

Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR)

In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO_x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million, excluding AFUDC, to be shared equally between I&M and AEGCo.  The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year life and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. 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 limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC is scheduled for March 2017.

KGPCo Rate Matters (Applies to AEP)

Kingsport Base Rate Case

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.

OPCo Rate Matters (Applies to AEP and OPCo)

Ohio Global Settlement

In February 2017, the PUCO approved a settlement agreement (Global Settlement) filed by OPCo in December 2016. The parties to the Global Settlement include OPCo, the PUCO staff and various intervenors. The Global Settlement resolves all remaining open issues on remand from the Ohio Supreme Court in OPCo’s 2009 - 2011 and June 2012 - May 2015 ESP filings, including issues related to carrying charges on the PIRR and issues related to the RSR capacity charges. It also resolves all open issues in OPCo’s 2009, 2014 and 2015 SEET filings and 2009, 2012 and 2013 Fuel Adjustment Clause Audits.

The significant components of the Global Settlement include:

Remands Related to the PIRR

All applicable parties participating in this settlement will withdraw their pending applications for rehearing of the PUCO order that allowed for the reinstatement of the equity portion of the WACC rate on previously deferred fuel balances. As part of the Global Settlement, the PIRR rate to be collected from customers through December 2018 will be reduced by $97 million.

Remands Related to the RSR

Beginning January 2017, OPCo will be entitled to collect $388 million in RSR revenues over a total of 30 months, subject to true up at the end of the collection period in June 2019. Current RSR rates will continue until the new RSR rates are approved. The Global Settlement resolves the issues related to the non-deferral portion of RSR collections and the impact of the appropriate energy credit on capacity charges. In December 2016, OPCo recorded an increase in Regulatory Assets on the balance sheets for the deferral of $83 million in RSR capacity costs and $14 million in related debt carrying charges with a corresponding decrease in expense in Generation Deferrals and an increase in Carrying Costs Income, respectively, on the statements of income.

For the year ended December 31, 2016, AEP recorded approximately $97 million in RSR capacity deferrals and related carrying charges to the following line items on the statements of income:

	AEP
	(in millions)
Fuel and Other Consumables Used for Electric Generation	$	(19.0	)
Purchased Electricity for Resale	(19.9		)
Other Operation	(15.7		)
Depreciation and Amortization	(42.1		)
Total Decrease in RSR Expenses	$	(96.7	)

As of December 31, 2016, OPCo’s total RSR under-recovery balance, including carrying charges, was $299 million.

Remands Related to the SEET

As part of the Global Settlement,$20 million will be returned to customers over a 12-month period commencing within 45 days of the final PUCO order adopting the Global Settlement. The Global Settlement states that this obligation has no precedential effect on OPCo’s SEET methodology. In addition, the parties agreed that earnings were not significantly excessive in 2015. In December 2016, OPCo accrued $20 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the issues related to the 2014 and 2015 SEET proceedings.

Fuel Adjustment Clause Proceedings

OPCo will refund $100 million paid by SSO customers from August 2012 - May 2015 related to OVEC and Lawrenceburg purchases. In December 2016, OPCo accrued $100 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the claimed recovery of fixed fuel costs through both the FAC and the approved capacity charges. This refund will be a one-time credit that will be applied the earlier of either 45 days after the final non-appealable order from the PUCO adopting the Global Settlement, or the December 2017 billing cycle.

Ohio Electric Security Plan Filings

2009 – 2011 ESP

The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018.

In 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a WACC rate. In 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and remanded the matter back to the PUCO for reinstatement of the WACC rate. In June 2016, the PUCO approved OPCo’s proposed increase to the PIRR rates, in accordance with the Supreme Court of Ohio ruling. The increase to PIRR rates included $146 million in additional carrying charges and the recovery of $40 million in additional under-recovered fuel costs resulting from a decrease in customer demand. The increase is effective July 2016 through December 2018. In July 2016, intervenors filed requests for rehearing with the PUCO, which the PUCO granted in August 2016. In December 2016, OPCo filed a Global Settlement with the PUCO related to this issue. See “Ohio Global Settlement” section above.

June 2012 – May 2015 ESP Including Capacity Charge

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 July 2012, the PUCO issued an order in a separate capacity proceeding requiring OPCo to charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day.  The OPCo RPM price collected from CRES providers, which included reserve margins, was approximately $34/MW day through May 2014 and $150/MW day from June 2014 through May 2015. In April 2016, the Supreme Court of Ohio issued two opinions related to the deferral of OPCo’s capacity charges. In one of the opinions, the Supreme Court of Ohio ruled that the PUCO must reconsider an energy credit that was used to determine OPCo’s authorized capacity deferral threshold of $188.88/MW day during the August 2012 through May 2015 period. The PUCO reduced OPCo’s authorized capacity deferral threshold to $188.88/MW day largely due to an offset for an energy credit of $147.41/MW day. The Supreme Court of Ohio directed the PUCO to substantively address OPCo’s arguments that the $147.41/MW day credit was overstated by approximately $100/MW day due to various inaccuracies affecting input data and assumptions. See “Ohio Global Settlement” section above.

As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012.  The RSR was collected from customers at $3.50/MWh through May 2014 and at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. In April 2015, the PUCO issued an order that modified and approved OPCo’s July 2014 application to collect the unrecovered portion of the deferred capacity costs. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00/MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance. As of December 31, 2016, OPCo’s net deferred capacity costs balance was $202 million, including debt carrying costs, and was recorded in Regulatory Assets on the balance sheets. In April 2016, the second Supreme Court of Ohio opinion rejected a portion of OPCo’s RSR revenues collected during the period September 2012 through May 2015 and directed the PUCO to reduce OPCo’s deferred capacity costs by these previously collected RSR revenues. The Supreme Court of Ohio was not able to determine the amount of the reduction to OPCo’s deferred capacity costs and remanded the issue to the PUCO to determine the appropriate reduction. As directed by the PUCO, in May 2016, OPCo submitted revised RSR tariffs that reflect the RSR being collected subject to refund. See “Ohio Global Settlement” section above.

In April 2016, the Supreme Court of Ohio also ruled favorably on OPCo’s cross-appeal regarding a previously PUCO-imposed SEET threshold under the ESP and remanded this issue to the PUCO. See “Ohio Global Settlement” section above and “Significantly Excessive Earnings Test Filings” section below.

In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings.

In 2014, the PUCO denied all rehearing requests, 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, and 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. See “2012 and 2013 Fuel Adjustment Clause Audits” section below.

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, (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, and due to the interrelated nature of the two Supreme Court of Ohio opinions that directly relate to OPCo’s deferred capacity costs, 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. 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 December 2016, OPCo filed a Global Settlement with the PUCO related to these issues. See “Ohio Global Settlement” section above.

June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024

In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a PPA rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets.

In February 2015, the PUCO issued an order approving OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo’s and various intervenors’ requests for rehearing related to the May 2015 order. In November 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments and denied the remaining requests for rehearing. In January 2017, the PUCO granted intervenors requests for rehearing that oppose the PPA rider as well as the amended DIR caps.

In May 2015, OPCo filed an amended PPA application that (a) included OPCo’s OVEC contractual entitlement (OVEC PPA), (b) addressed the PPA requirements set forth in the PUCO’s February 2015 order and (c) included the 2,671 MWs to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units (Affiliate PPA).

In March 2016, a contested stipulation agreement related to the PPA rider application was modified and approved by the PUCO. The approved PPA rider is effective April 2016 through May 2024, subject to audit and review by the PUCO. The stipulation agreement, as approved, included (a) an Affiliate PPA between OPCo and AGR to be included in the PPA rider, (b) OPCo’s OVEC PPA to be included in the PPA rider, (c) potential additional contingent customer credits of up to $100 million to be included in the PPA rider over the final four years of the PPA rider and (d) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions.

In April 2016, the FERC issued an order granting a January 2016 complaint filed against AGR and OPCo.  The FERC order rescinded the waivers of the 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 accordance with FERC’s rules governing affiliate transactions.  As a result 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 proposed OVEC-only PPA Rider to recover the net margin after sales through PJM and 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 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. In November 2016, the PUCO issued an order on rehearing that approved recovery of the OVEC-related net margin incurred from June 2016 through the term of the PPA rider and the modification to reduce the customer credits to $15 million as requested by OPCo. The PUCO rejected OPCo’s request to eliminate both the 5% rate impact cap and the inclusion of the capacity performance penalties within the PPA rider. In January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC-only PPA and stated that the stipulation agreement approved in March 2016 does not provide customers with rate stability.

OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO makes unacceptable modifications to the stipulation, including modifications as part of the pending rehearing.

Consistent with the terms of the modified and approved stipulation agreement, and based upon a September 2016 PUCO order, in November 2016, OPCo refiled its amended ESP extension application and supporting testimony. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.

Significantly Excessive Earnings Test Filings

Background

Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric distribution utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk.

2009 SEET Filing

In 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project.

In September 2013, a proposed second phase of OPCo’s gridSMART^® (gridSMART^® Phase II) program was filed with the PUCO which included a proposed project to satisfy the PUCO 2009 SEET directive. In April 2016, a stipulation agreement related to the gridSMART^® Phase II program was filed with the PUCO. As part of the stipulation agreement, OPCo will invest at least $20 million over a six-year period for the installation of Volt VAR Optimization (VVO) technology on selected circuits throughout OPCo’s service territory. All parties to the stipulation agree that OPCo’s proposed VVO investment resolves OPCo’s outstanding obligation for renewable or similar investment associated with the PUCO’s 2009 SEET directive. As a part of the December 2016 Global Settlement, OCC agreed to no longer contest the gridSMART^® Phase II stipulation. In February 2017, the PUCO approved the gridSMART^® Phase II stipulation agreement. See “Ohio Global Settlement” section above.

2014 and 2015 SEET Filings

The PUCO established an annual SEET earnings threshold of 12% during the June 2012 - May 2015 ESP period. In May 2013, OPCo filed a cross appeal with the Supreme Court of Ohio, asserting that the SEET threshold was not based on the earnings of comparable publicly traded companies as originally required by the SEET statute.

In April 2016, the Supreme Court of Ohio agreed with OPCo’s cross-appeal assertion that a 12% SEET threshold was not based on the applicable Ohio SEET statute. The Supreme Court of Ohio reversed the 12% threshold and remanded this issue to the PUCO.

In June 2015 and May 2016, OPCo submitted its SEET filings for 2014 and 2015, respectively, with the PUCO. In August 2016, intervenors filed testimony recommending a revenue refund of approximately $20 million for 2014 and no refund for 2015 based upon a new approach to determine significantly excessive earnings that has not been previously approved by the PUCO. In September 2016, OPCo and the PUCO staff filed a stipulation agreement with the PUCO stating that no significantly excessive earnings occurred for 2014 or 2015. In September 2016, intervenors filed testimony opposing the stipulation agreement. See “Ohio Global Settlement” section above.

2016 SEET Filing

OPCo expects to submit its 2016 SEET filing in the second quarter of 2017.  OPCo’s 2016 SEET provision was determined by excluding the gain on the deferral of RSR costs related to the Global Settlement. In addition, refunds to customers included in the Global Settlement relating to the SEET remands and fuel adjustment clause proceedings were excluded from the determination of the 2016 SEET provision. Management believes its financial statements adequately address the impact of 2016 SEET requirements.  If the PUCO adopts a different 2016 SEET methodology, it could reduce future net income and cash flows and impact financial condition.

2009 Fuel Adjustment Clause Audit

In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statements of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. See “Ohio Global Settlement” section above.

2012 and 2013 Fuel Adjustment Clause Audits

In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the “June 2012 - May 2015 ESP Including Capacity Charge” and “Ohio Global Settlement” sections above.

Ormet

Ormet, a large aluminum company, had a contract to purchase power from OPCo. In OPCo’s 2009 - 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues. Through September 2009, the last month of the interim arrangement, OPCo had approximately $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s filing to approve recovery of the deferral under the interim agreement. Of the $64 million in deferred FAC costs, approximately 50% was related to Columbus Southern Power Company (CSPCo) and 50% related to OPCo, prior to the merger of CSPCo into OPCo in December 2011. CSPCo’s portion of these deferred fuel costs has been recovered as a result of the previous collections of CSPCo fuel costs from ratepayers and the PUCO’s 2013 order to apply CSPCo’s 2010 excessive earnings to offset CSPCo’s final deferred fuel balance. OPCo’s share of Ormet deferred fuel costs continues to be recovered through OPCo’s PIRR.

The Ohio Global Settlement discussed above, approved by the PUCO in February 2017, includes the resolution of the 2009, 2012 and 2013 Fuel Adjustment Clause Audits together with the finalization of the PIRR.  The resolution of those cases effectively makes the risk of non-recovery of the Ormet deferrals remote.

PSO Rate Matters (Applies to AEP and PSO)

2015 Oklahoma Base Rate Case

In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million. The request consisted 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 included a proposed return on common equity of 10.5%. The $44 million increase related to environmental investments was proposed to be effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls were 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 December 31, 2016, PSO had incurred costs of $181 million and $44 million, including AFUDC, for Northeastern Plant, Unit 3 and Comanche Plant, respectively. In January 2016, PSO implemented an interim annual base rate increase of $75 million, subject to refund.

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, 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 sheets related to the net book value of Northeastern Plant, Unit 4. These regulatory assets are pending regulatory approval.

In November 2016 and December 2016, the OCC issued orders that approved a net annual revenue increase of $19 million based upon a 9.5% return on common equity. The orders also included (a) approval to defer incurred costs related to PSO’s environmental compliance plan until those costs are included in base rates, (b) no determination related to the return of and return on the post-retirement remaining net book value of Northeastern Plant, Unit 4 since the April 2016 retirement was outside of the test year, (c) approval to include environmental consumable costs in the FAC (d) the continued depreciation of Northeastern Plant, Units 3 and 4 through 2040 (no accelerated depreciation) and (e) altered the system reliability rider by eliminating the expense portion of the rider and setting the capital portion of the rider at the December 2016 plant balance and approved recovery of deferred expenses and return on the capital balance incurred prior to the effective date of new tariffs in January 2017. Additionally, the orders stated that the cost recovery of new PPAs related to replacement power resulting from the retirement of Northeastern Plant, Unit 4 will be addressed in a future FAC proceeding. Effective December 2016, interim rates were terminated and the refund of over collections began and will be completed no later than October 2017. In accordance with the final order, updated rates and tariffs went into effect in January 2017.

If any of these costs, including a return on Northeastern Plant, Unit 4, are ultimately not recoverable, it could reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters (Applies to AEP and SWEPCo)

2012 Texas Base Rate Case

In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2.

Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million. In 2014, intervenors filed appeals of that order with the Texas District Court and SWEPCo intervened in those appeals. A hearing at the Texas District Court is scheduled for March 2017.

If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition.

2016 Texas Base Rate Case

In December 2016, SWEPCo filed a base rate request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. The annual increase includes approximately (a) $34 million related to additional environmental controls to comply with Federal EPA mandates, (b) $25 million for additional generation, transmission and distribution investments and increased operating costs, (c) $8 million related to transmission cost recovery within SWEPCo’s regional transmission organization and (d) $2 million in additional vegetation management.

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

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant. In February 2013, a settlement was approved by the LPSC. The settlement increased SWEPCo’s Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually.  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. The rates are subject to refund based on the prudence review of the Turk Plant. The settlement also provided that the LPSC would review base rates in 2014 and 2015 and that SWEPCo would 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 June 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.

2014 Louisiana Formula Rate Filing

In 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC.  The filing included a $5 million annual increase, which was effective August 2014.  SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million. This additional increase reflects the cost of incremental generation used to serve Louisiana customers in 2015 due to the expiration of a purchased power agreement attributable to Louisiana customers.  In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015, subject to staff review of the cost of service and prudence review of the Turk Plant. In July 2016, the LPSC approved a settlement agreement related to the staff review of the cost of service. A portion of the rates remain subject to refund based on the prudence review of the Turk Plant. See “2012 Louisiana Formula Rate Filing” above. Management believes its financial statements adequately address the impact of this settlement agreement. 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.

2015 Louisiana Formula Rate Filing

In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC.  The filing included a $14 million annual increase, which was effective August 2015.  This increase is subject to LPSC staff review and is subject to refund.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Welsh Plant - Environmental Impact

Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could cost a total of approximately $850 million, excluding AFUDC. As of December 31, 2016, SWEPCo had incurred costs of $397 million, including AFUDC, and had remaining contractual construction obligations of $11 million related to these projects.  As part of this investment, in 2016 SWEPCo completed construction of environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $370 million, excluding AFUDC.  Management continues to evaluate the impact of environmental rules and related project cost estimates. In March 2016, SWEPCo filed a request with the APSC to recover $69 million in environmental costs related to the Arkansas retail jurisdictional share of Welsh Plant, Units 1 and 3, which was approved by the APSC in August 2016. SWEPCo began recovering the Arkansas jurisdictional share of these costs in March 2016, subject to review in the next filed base rate proceeding. In September 2016, SWEPCo filed an additional request to increase the Arkansas retail jurisdictional share of the environmental investment by $10 million, for a total of $79 million. SWEPCo implemented the increase in September 2016. In December 2016, the LPSC approved deferral of certain expenses related to environmental controls installed at Welsh Plant, until these investments are put into base rates. The eligible Welsh Plant deferrals through December 31, 2016 are $8 million, excluding $5 million of unrecognized equity, subject to review by the LPSC, and include a WACC return on environmental investments and the related depreciation expense and taxes. SWEPCo will seek recovery of its project costs from customers at the state commissions and the FERC.

As of December 31, 2016, the net book value of Welsh Plant, Units 1 and 3 was $633 million, before cost of removal, including materials and supplies inventory and CWIP.  In April 2016, Welsh Plant, Unit 2 was retired. Upon retirement, $76 million was reclassified as Regulatory Assets on the balance sheets related to the net book value of Welsh Plant, Unit 2 and the related asset retirement obligation costs. In SWEPCo’s 2016 Texas Base Rate Case, SWEPCo requested recovery of the Texas jurisdictional share (approximately 33%) of the net book value of Welsh Plant, Unit 2 through 2042, the remaining life of Welsh Plant, Unit 3. Management will seek recovery of the remaining Welsh Plant, Unit 2 retirement-related regulatory assets in future rate proceedings.

If any of these costs are not recoverable, including retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.

AEP Texas Rate Matters (Applies to AEP)

TCC and TNC Merger

Effective December 31, 2016, TCC and TNC merged into AEP Utilities, Inc., as approved by the FERC and the PUCT in September 2016 and December 2016, respectively. Upon merger, AEP Utilities, Inc. changed its name to AEP Texas Inc., but maintained TCC’s and TNC’s respective customer rates. The PUCT ordered certain post-merger conditions which included a) the sharing of certain interest rate savings with customers 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.

AEP Texas Distribution Cost Recovery Factor (DCRF)

In July 2016, the PUCT approved settlement agreements between TCC, TNC and intervenors related to requests for DCRF riders to allow recovery of eligible net distribution investments. The settlement agreement included an annual revenue requirement of $56 million ($45 million for the TCC division and $11 million for the TNC division), effective September 2016. Amounts approved are subject to refund based upon a prudence review of the investments in AEP Texas’ next base rate case.

FERC Rate Matters (Applies to AEP, APCo, I&M and OPCo)

PJM Transmission Rates

In June 2016, PJM transmission owners, including the AEP East Companies, and various state commissions filed a settlement agreement with the FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. In July 2016, certain parties filed comments at the FERC contesting the settlement agreement. Upon final FERC approval, PJM would implement a transmission enhancement charge adjustment through the PJM OATT, billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms.

FERC Transmission Complaint and Proposed Modifications to Transmission Rates

In October 2016, several parties filed a joint complaint with the FERC claiming that the base return on common equity used by various AEP affiliates 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 2016, AEP affiliates filed an application with the FERC to modify the FERC formula transmission rate calculation, including adjustments for certain tax issues and a shift from historical to estimated expenses with a proposed effective date of January 1, 2017. The rates will be implemented based upon the date provided in the pending FERC order, subject to refund. Management believes its financial statements adequately address the impact of the complaint and the proposed modifications to AEP’s transmission rates in PJM. 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.

Other Rate Matters (Applies to AEP, PSO and SWEPCo)

SPP OATT Upgrade Costs

Under the SPP OATT, costs of sponsor-funded transmission upgrades may be recovered, in part, from SPP customers whose transmission service is dependent upon capacity enabled by the upgrades. Prior to 2016, SPP had not charged its customers any amounts attributable to these upgrades. In November 2016, SPP billed transmission service customers, including PSO and SWEPCo, for upgrade costs incurred since 2008. SPP then credited the qualifying transmission upgrade owners, including SWEPCo, for the use of these upgrades. In 2016, PSO and SWEPCo recognized a net unfavorable impact of approximately $3 million and $4 million, respectively, related to the OATT upgrade costs.

Public Service Co Of Oklahoma [Member]

Rate Matters

RATE MATTERS

The disclosures in this note apply to all Registrants unless indicated otherwise.

The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions.  Rate matters can have a material impact on net income, cash flows and possibly financial condition.  The Registrants’ recent significant rate orders and pending rate filings are addressed in this note.

APCo and WPCo Rate Matters (Applies to AEP and APCo)

2016 West Virginia Expanded Net Energy Cost Filing

In June 2016, the WVPSC approved a settlement agreement related to APCo and WPCo’s combined annual ENEC filing. The settlement agreement included $38 million ($30 million related to APCo) of additional ENEC revenues and $17 million ($14 million related to APCo) in construction surcharges annually for two years, effective July 2016. Additionally, APCo and WPCo agreed that a general rate case will not be filed before April 2018.

West Virginia Deferred Base Rate Increase

In May 2015, the WVPSC issued an order on APCo and WPCo’s combined base rate case. The order included a delayed billing of $25 million ($22 million related to APCo) of the annual base rate increase to residential customers until July 2016. In June 2016, the WVPSC issued an order that approved recovery of the total deferred billing, including carrying charges through June 2018, totaling $29 million ($27 million related to APCo). Recovery was approved over two years, effective July 2016. Additionally, at the end of the two-year amortization, any over/under-recovery of the delayed billing will be included in the annual ENEC filing. The WVPSC also approved implementation of the prospective $25 million base rate increase effective July 2016.

2015 Virginia Regulatory Asset Proceeding

In 2015, the Virginia SCC initiated a proceeding to address the treatment of APCo’s authorized regulatory assets. In September 2016, the Virginia SCC issued an order that approved the continued recovery through amortization of certain regulatory assets established prior to the period of frozen rates pursuant to the amended Virginia law (see “Virginia Legislation Affecting Biennial Reviews” below).

Virginia Legislation Affecting Biennial Reviews

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’s financial statements adequately address the impact of these amendments. The amendments 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.

In February 2016, certain APCo industrial customers filed a petition with the Virginia SCC requesting the issuance of a declaratory order that finds the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, directs APCo to make biennial review filings beginning in 2016. In July 2016, the Virginia SCC issued an order that denied the petition. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition.

ETT Rate Matters (Applies to AEP)

ETT Interim Transmission Rates

Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. During a 2015 open meeting at the PUCT, ETT committed to file a base rate case by February 2017. In January 2017, the PUCT approved ETT’s request to suspend the base rate case filing and decrease ETT’s annual revenue requirement by $46 million, effective March 2017. As of December 31, 2016, AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $591 million based upon interim rate increases received from 2009 through 2016. A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. Management is unable to determine a range of potential losses that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters (Applies to AEP and I&M)

Indiana Amended PJM Settlement Agreement

In November 2016, the IURC issued an order that approved an amended settlement agreement between I&M and certain intervenors.  This agreement amends a previously approved 2014 settlement agreement that addresses the recovery of 43.5% of certain transmission expenses through the Indiana PJM rider through 2017.

The amended agreement allows I&M to recover 100% of the Indiana jurisdictional share of these transmission expenses not recovered through base rates through the Indiana PJM rider, subject to a $109 million cap for the period January 2017 through June 2018. Beginning July 2018, I&M will be allowed to recover 100% of the Indiana jurisdictional share of these transmission expenses through the Indiana PJM rider, without a cap, until the issue is addressed by the IURC in a future proceeding, subject to the condition that I&M files a base rate case on or before January 2018. The amended agreement also provides for deferral of incremental vegetation management expenses over the period January 2017 through June 2018.  Any vegetation management expenses deferred would reduce the cap for the transmission expenses described above. As part of the amended settlement, I&M agreed that it will not file a base rate case before July 2017 and will not implement new base rates prior to July 2018.

Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR)

In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO_x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million, excluding AFUDC, to be shared equally between I&M and AEGCo.  The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year life and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. 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 limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC is scheduled for March 2017.

KGPCo Rate Matters (Applies to AEP)

Kingsport Base Rate Case

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.

OPCo Rate Matters (Applies to AEP and OPCo)

Ohio Global Settlement

In February 2017, the PUCO approved a settlement agreement (Global Settlement) filed by OPCo in December 2016. The parties to the Global Settlement include OPCo, the PUCO staff and various intervenors. The Global Settlement resolves all remaining open issues on remand from the Ohio Supreme Court in OPCo’s 2009 - 2011 and June 2012 - May 2015 ESP filings, including issues related to carrying charges on the PIRR and issues related to the RSR capacity charges. It also resolves all open issues in OPCo’s 2009, 2014 and 2015 SEET filings and 2009, 2012 and 2013 Fuel Adjustment Clause Audits.

The significant components of the Global Settlement include:

Remands Related to the PIRR

All applicable parties participating in this settlement will withdraw their pending applications for rehearing of the PUCO order that allowed for the reinstatement of the equity portion of the WACC rate on previously deferred fuel balances. As part of the Global Settlement, the PIRR rate to be collected from customers through December 2018 will be reduced by $97 million.

Remands Related to the RSR

Beginning January 2017, OPCo will be entitled to collect $388 million in RSR revenues over a total of 30 months, subject to true up at the end of the collection period in June 2019. Current RSR rates will continue until the new RSR rates are approved. The Global Settlement resolves the issues related to the non-deferral portion of RSR collections and the impact of the appropriate energy credit on capacity charges. In December 2016, OPCo recorded an increase in Regulatory Assets on the balance sheets for the deferral of $83 million in RSR capacity costs and $14 million in related debt carrying charges with a corresponding decrease in expense in Generation Deferrals and an increase in Carrying Costs Income, respectively, on the statements of income.

For the year ended December 31, 2016, AEP recorded approximately $97 million in RSR capacity deferrals and related carrying charges to the following line items on the statements of income:

	AEP
	(in millions)
Fuel and Other Consumables Used for Electric Generation	$	(19.0	)
Purchased Electricity for Resale	(19.9		)
Other Operation	(15.7		)
Depreciation and Amortization	(42.1		)
Total Decrease in RSR Expenses	$	(96.7	)

As of December 31, 2016, OPCo’s total RSR under-recovery balance, including carrying charges, was $299 million.

Remands Related to the SEET

As part of the Global Settlement,$20 million will be returned to customers over a 12-month period commencing within 45 days of the final PUCO order adopting the Global Settlement. The Global Settlement states that this obligation has no precedential effect on OPCo’s SEET methodology. In addition, the parties agreed that earnings were not significantly excessive in 2015. In December 2016, OPCo accrued $20 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the issues related to the 2014 and 2015 SEET proceedings.

Fuel Adjustment Clause Proceedings

OPCo will refund $100 million paid by SSO customers from August 2012 - May 2015 related to OVEC and Lawrenceburg purchases. In December 2016, OPCo accrued $100 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the claimed recovery of fixed fuel costs through both the FAC and the approved capacity charges. This refund will be a one-time credit that will be applied the earlier of either 45 days after the final non-appealable order from the PUCO adopting the Global Settlement, or the December 2017 billing cycle.

Ohio Electric Security Plan Filings

2009 – 2011 ESP

The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018.

In 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a WACC rate. In 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and remanded the matter back to the PUCO for reinstatement of the WACC rate. In June 2016, the PUCO approved OPCo’s proposed increase to the PIRR rates, in accordance with the Supreme Court of Ohio ruling. The increase to PIRR rates included $146 million in additional carrying charges and the recovery of $40 million in additional under-recovered fuel costs resulting from a decrease in customer demand. The increase is effective July 2016 through December 2018. In July 2016, intervenors filed requests for rehearing with the PUCO, which the PUCO granted in August 2016. In December 2016, OPCo filed a Global Settlement with the PUCO related to this issue. See “Ohio Global Settlement” section above.

June 2012 – May 2015 ESP Including Capacity Charge

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 July 2012, the PUCO issued an order in a separate capacity proceeding requiring OPCo to charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day.  The OPCo RPM price collected from CRES providers, which included reserve margins, was approximately $34/MW day through May 2014 and $150/MW day from June 2014 through May 2015. In April 2016, the Supreme Court of Ohio issued two opinions related to the deferral of OPCo’s capacity charges. In one of the opinions, the Supreme Court of Ohio ruled that the PUCO must reconsider an energy credit that was used to determine OPCo’s authorized capacity deferral threshold of $188.88/MW day during the August 2012 through May 2015 period. The PUCO reduced OPCo’s authorized capacity deferral threshold to $188.88/MW day largely due to an offset for an energy credit of $147.41/MW day. The Supreme Court of Ohio directed the PUCO to substantively address OPCo’s arguments that the $147.41/MW day credit was overstated by approximately $100/MW day due to various inaccuracies affecting input data and assumptions. See “Ohio Global Settlement” section above.

As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012.  The RSR was collected from customers at $3.50/MWh through May 2014 and at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. In April 2015, the PUCO issued an order that modified and approved OPCo’s July 2014 application to collect the unrecovered portion of the deferred capacity costs. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00/MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance. As of December 31, 2016, OPCo’s net deferred capacity costs balance was $202 million, including debt carrying costs, and was recorded in Regulatory Assets on the balance sheets. In April 2016, the second Supreme Court of Ohio opinion rejected a portion of OPCo’s RSR revenues collected during the period September 2012 through May 2015 and directed the PUCO to reduce OPCo’s deferred capacity costs by these previously collected RSR revenues. The Supreme Court of Ohio was not able to determine the amount of the reduction to OPCo’s deferred capacity costs and remanded the issue to the PUCO to determine the appropriate reduction. As directed by the PUCO, in May 2016, OPCo submitted revised RSR tariffs that reflect the RSR being collected subject to refund. See “Ohio Global Settlement” section above.

In April 2016, the Supreme Court of Ohio also ruled favorably on OPCo’s cross-appeal regarding a previously PUCO-imposed SEET threshold under the ESP and remanded this issue to the PUCO. See “Ohio Global Settlement” section above and “Significantly Excessive Earnings Test Filings” section below.

In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings.

In 2014, the PUCO denied all rehearing requests, 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, and 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. See “2012 and 2013 Fuel Adjustment Clause Audits” section below.

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, (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, and due to the interrelated nature of the two Supreme Court of Ohio opinions that directly relate to OPCo’s deferred capacity costs, 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. 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 December 2016, OPCo filed a Global Settlement with the PUCO related to these issues. See “Ohio Global Settlement” section above.

June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024

In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a PPA rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets.

In February 2015, the PUCO issued an order approving OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo’s and various intervenors’ requests for rehearing related to the May 2015 order. In November 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments and denied the remaining requests for rehearing. In January 2017, the PUCO granted intervenors requests for rehearing that oppose the PPA rider as well as the amended DIR caps.

In May 2015, OPCo filed an amended PPA application that (a) included OPCo’s OVEC contractual entitlement (OVEC PPA), (b) addressed the PPA requirements set forth in the PUCO’s February 2015 order and (c) included the 2,671 MWs to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units (Affiliate PPA).

In March 2016, a contested stipulation agreement related to the PPA rider application was modified and approved by the PUCO. The approved PPA rider is effective April 2016 through May 2024, subject to audit and review by the PUCO. The stipulation agreement, as approved, included (a) an Affiliate PPA between OPCo and AGR to be included in the PPA rider, (b) OPCo’s OVEC PPA to be included in the PPA rider, (c) potential additional contingent customer credits of up to $100 million to be included in the PPA rider over the final four years of the PPA rider and (d) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions.

In April 2016, the FERC issued an order granting a January 2016 complaint filed against AGR and OPCo.  The FERC order rescinded the waivers of the 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 accordance with FERC’s rules governing affiliate transactions.  As a result 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 proposed OVEC-only PPA Rider to recover the net margin after sales through PJM and 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 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. In November 2016, the PUCO issued an order on rehearing that approved recovery of the OVEC-related net margin incurred from June 2016 through the term of the PPA rider and the modification to reduce the customer credits to $15 million as requested by OPCo. The PUCO rejected OPCo’s request to eliminate both the 5% rate impact cap and the inclusion of the capacity performance penalties within the PPA rider. In January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC-only PPA and stated that the stipulation agreement approved in March 2016 does not provide customers with rate stability.

OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO makes unacceptable modifications to the stipulation, including modifications as part of the pending rehearing.

Consistent with the terms of the modified and approved stipulation agreement, and based upon a September 2016 PUCO order, in November 2016, OPCo refiled its amended ESP extension application and supporting testimony. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.

Significantly Excessive Earnings Test Filings

Background

Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric distribution utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk.

2009 SEET Filing

In 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project.

In September 2013, a proposed second phase of OPCo’s gridSMART^® (gridSMART^® Phase II) program was filed with the PUCO which included a proposed project to satisfy the PUCO 2009 SEET directive. In April 2016, a stipulation agreement related to the gridSMART^® Phase II program was filed with the PUCO. As part of the stipulation agreement, OPCo will invest at least $20 million over a six-year period for the installation of Volt VAR Optimization (VVO) technology on selected circuits throughout OPCo’s service territory. All parties to the stipulation agree that OPCo’s proposed VVO investment resolves OPCo’s outstanding obligation for renewable or similar investment associated with the PUCO’s 2009 SEET directive. As a part of the December 2016 Global Settlement, OCC agreed to no longer contest the gridSMART^® Phase II stipulation. In February 2017, the PUCO approved the gridSMART^® Phase II stipulation agreement. See “Ohio Global Settlement” section above.

2014 and 2015 SEET Filings

The PUCO established an annual SEET earnings threshold of 12% during the June 2012 - May 2015 ESP period. In May 2013, OPCo filed a cross appeal with the Supreme Court of Ohio, asserting that the SEET threshold was not based on the earnings of comparable publicly traded companies as originally required by the SEET statute.

In April 2016, the Supreme Court of Ohio agreed with OPCo’s cross-appeal assertion that a 12% SEET threshold was not based on the applicable Ohio SEET statute. The Supreme Court of Ohio reversed the 12% threshold and remanded this issue to the PUCO.

In June 2015 and May 2016, OPCo submitted its SEET filings for 2014 and 2015, respectively, with the PUCO. In August 2016, intervenors filed testimony recommending a revenue refund of approximately $20 million for 2014 and no refund for 2015 based upon a new approach to determine significantly excessive earnings that has not been previously approved by the PUCO. In September 2016, OPCo and the PUCO staff filed a stipulation agreement with the PUCO stating that no significantly excessive earnings occurred for 2014 or 2015. In September 2016, intervenors filed testimony opposing the stipulation agreement. See “Ohio Global Settlement” section above.

2016 SEET Filing

OPCo expects to submit its 2016 SEET filing in the second quarter of 2017.  OPCo’s 2016 SEET provision was determined by excluding the gain on the deferral of RSR costs related to the Global Settlement. In addition, refunds to customers included in the Global Settlement relating to the SEET remands and fuel adjustment clause proceedings were excluded from the determination of the 2016 SEET provision. Management believes its financial statements adequately address the impact of 2016 SEET requirements.  If the PUCO adopts a different 2016 SEET methodology, it could reduce future net income and cash flows and impact financial condition.

2009 Fuel Adjustment Clause Audit

In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statements of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. See “Ohio Global Settlement” section above.

2012 and 2013 Fuel Adjustment Clause Audits

In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the “June 2012 - May 2015 ESP Including Capacity Charge” and “Ohio Global Settlement” sections above.

Ormet

Ormet, a large aluminum company, had a contract to purchase power from OPCo. In OPCo’s 2009 - 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues. Through September 2009, the last month of the interim arrangement, OPCo had approximately $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s filing to approve recovery of the deferral under the interim agreement. Of the $64 million in deferred FAC costs, approximately 50% was related to Columbus Southern Power Company (CSPCo) and 50% related to OPCo, prior to the merger of CSPCo into OPCo in December 2011. CSPCo’s portion of these deferred fuel costs has been recovered as a result of the previous collections of CSPCo fuel costs from ratepayers and the PUCO’s 2013 order to apply CSPCo’s 2010 excessive earnings to offset CSPCo’s final deferred fuel balance. OPCo’s share of Ormet deferred fuel costs continues to be recovered through OPCo’s PIRR.

The Ohio Global Settlement discussed above, approved by the PUCO in February 2017, includes the resolution of the 2009, 2012 and 2013 Fuel Adjustment Clause Audits together with the finalization of the PIRR.  The resolution of those cases effectively makes the risk of non-recovery of the Ormet deferrals remote.

PSO Rate Matters (Applies to AEP and PSO)

2015 Oklahoma Base Rate Case

In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million. The request consisted 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 included a proposed return on common equity of 10.5%. The $44 million increase related to environmental investments was proposed to be effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls were 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 December 31, 2016, PSO had incurred costs of $181 million and $44 million, including AFUDC, for Northeastern Plant, Unit 3 and Comanche Plant, respectively. In January 2016, PSO implemented an interim annual base rate increase of $75 million, subject to refund.

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, 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 sheets related to the net book value of Northeastern Plant, Unit 4. These regulatory assets are pending regulatory approval.

In November 2016 and December 2016, the OCC issued orders that approved a net annual revenue increase of $19 million based upon a 9.5% return on common equity. The orders also included (a) approval to defer incurred costs related to PSO’s environmental compliance plan until those costs are included in base rates, (b) no determination related to the return of and return on the post-retirement remaining net book value of Northeastern Plant, Unit 4 since the April 2016 retirement was outside of the test year, (c) approval to include environmental consumable costs in the FAC (d) the continued depreciation of Northeastern Plant, Units 3 and 4 through 2040 (no accelerated depreciation) and (e) altered the system reliability rider by eliminating the expense portion of the rider and setting the capital portion of the rider at the December 2016 plant balance and approved recovery of deferred expenses and return on the capital balance incurred prior to the effective date of new tariffs in January 2017. Additionally, the orders stated that the cost recovery of new PPAs related to replacement power resulting from the retirement of Northeastern Plant, Unit 4 will be addressed in a future FAC proceeding. Effective December 2016, interim rates were terminated and the refund of over collections began and will be completed no later than October 2017. In accordance with the final order, updated rates and tariffs went into effect in January 2017.

If any of these costs, including a return on Northeastern Plant, Unit 4, are ultimately not recoverable, it could reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters (Applies to AEP and SWEPCo)

2012 Texas Base Rate Case

In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2.

Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million. In 2014, intervenors filed appeals of that order with the Texas District Court and SWEPCo intervened in those appeals. A hearing at the Texas District Court is scheduled for March 2017.

If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition.

2016 Texas Base Rate Case

In December 2016, SWEPCo filed a base rate request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. The annual increase includes approximately (a) $34 million related to additional environmental controls to comply with Federal EPA mandates, (b) $25 million for additional generation, transmission and distribution investments and increased operating costs, (c) $8 million related to transmission cost recovery within SWEPCo’s regional transmission organization and (d) $2 million in additional vegetation management.

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

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant. In February 2013, a settlement was approved by the LPSC. The settlement increased SWEPCo’s Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually.  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. The rates are subject to refund based on the prudence review of the Turk Plant. The settlement also provided that the LPSC would review base rates in 2014 and 2015 and that SWEPCo would 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 June 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.

2014 Louisiana Formula Rate Filing

In 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC.  The filing included a $5 million annual increase, which was effective August 2014.  SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million. This additional increase reflects the cost of incremental generation used to serve Louisiana customers in 2015 due to the expiration of a purchased power agreement attributable to Louisiana customers.  In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015, subject to staff review of the cost of service and prudence review of the Turk Plant. In July 2016, the LPSC approved a settlement agreement related to the staff review of the cost of service. A portion of the rates remain subject to refund based on the prudence review of the Turk Plant. See “2012 Louisiana Formula Rate Filing” above. Management believes its financial statements adequately address the impact of this settlement agreement. 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.

2015 Louisiana Formula Rate Filing

In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC.  The filing included a $14 million annual increase, which was effective August 2015.  This increase is subject to LPSC staff review and is subject to refund.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Welsh Plant - Environmental Impact

Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could cost a total of approximately $850 million, excluding AFUDC. As of December 31, 2016, SWEPCo had incurred costs of $397 million, including AFUDC, and had remaining contractual construction obligations of $11 million related to these projects.  As part of this investment, in 2016 SWEPCo completed construction of environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $370 million, excluding AFUDC.  Management continues to evaluate the impact of environmental rules and related project cost estimates. In March 2016, SWEPCo filed a request with the APSC to recover $69 million in environmental costs related to the Arkansas retail jurisdictional share of Welsh Plant, Units 1 and 3, which was approved by the APSC in August 2016. SWEPCo began recovering the Arkansas jurisdictional share of these costs in March 2016, subject to review in the next filed base rate proceeding. In September 2016, SWEPCo filed an additional request to increase the Arkansas retail jurisdictional share of the environmental investment by $10 million, for a total of $79 million. SWEPCo implemented the increase in September 2016. In December 2016, the LPSC approved deferral of certain expenses related to environmental controls installed at Welsh Plant, until these investments are put into base rates. The eligible Welsh Plant deferrals through December 31, 2016 are $8 million, excluding $5 million of unrecognized equity, subject to review by the LPSC, and include a WACC return on environmental investments and the related depreciation expense and taxes. SWEPCo will seek recovery of its project costs from customers at the state commissions and the FERC.

As of December 31, 2016, the net book value of Welsh Plant, Units 1 and 3 was $633 million, before cost of removal, including materials and supplies inventory and CWIP.  In April 2016, Welsh Plant, Unit 2 was retired. Upon retirement, $76 million was reclassified as Regulatory Assets on the balance sheets related to the net book value of Welsh Plant, Unit 2 and the related asset retirement obligation costs. In SWEPCo’s 2016 Texas Base Rate Case, SWEPCo requested recovery of the Texas jurisdictional share (approximately 33%) of the net book value of Welsh Plant, Unit 2 through 2042, the remaining life of Welsh Plant, Unit 3. Management will seek recovery of the remaining Welsh Plant, Unit 2 retirement-related regulatory assets in future rate proceedings.

If any of these costs are not recoverable, including retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.

AEP Texas Rate Matters (Applies to AEP)

TCC and TNC Merger

Effective December 31, 2016, TCC and TNC merged into AEP Utilities, Inc., as approved by the FERC and the PUCT in September 2016 and December 2016, respectively. Upon merger, AEP Utilities, Inc. changed its name to AEP Texas Inc., but maintained TCC’s and TNC’s respective customer rates. The PUCT ordered certain post-merger conditions which included a) the sharing of certain interest rate savings with customers 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.

AEP Texas Distribution Cost Recovery Factor (DCRF)

In July 2016, the PUCT approved settlement agreements between TCC, TNC and intervenors related to requests for DCRF riders to allow recovery of eligible net distribution investments. The settlement agreement included an annual revenue requirement of $56 million ($45 million for the TCC division and $11 million for the TNC division), effective September 2016. Amounts approved are subject to refund based upon a prudence review of the investments in AEP Texas’ next base rate case.

FERC Rate Matters (Applies to AEP, APCo, I&M and OPCo)

PJM Transmission Rates

In June 2016, PJM transmission owners, including the AEP East Companies, and various state commissions filed a settlement agreement with the FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. In July 2016, certain parties filed comments at the FERC contesting the settlement agreement. Upon final FERC approval, PJM would implement a transmission enhancement charge adjustment through the PJM OATT, billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms.

FERC Transmission Complaint and Proposed Modifications to Transmission Rates

In October 2016, several parties filed a joint complaint with the FERC claiming that the base return on common equity used by various AEP affiliates 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 2016, AEP affiliates filed an application with the FERC to modify the FERC formula transmission rate calculation, including adjustments for certain tax issues and a shift from historical to estimated expenses with a proposed effective date of January 1, 2017. The rates will be implemented based upon the date provided in the pending FERC order, subject to refund. Management believes its financial statements adequately address the impact of the complaint and the proposed modifications to AEP’s transmission rates in PJM. 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.

Other Rate Matters (Applies to AEP, PSO and SWEPCo)

SPP OATT Upgrade Costs

Under the SPP OATT, costs of sponsor-funded transmission upgrades may be recovered, in part, from SPP customers whose transmission service is dependent upon capacity enabled by the upgrades. Prior to 2016, SPP had not charged its customers any amounts attributable to these upgrades. In November 2016, SPP billed transmission service customers, including PSO and SWEPCo, for upgrade costs incurred since 2008. SPP then credited the qualifying transmission upgrade owners, including SWEPCo, for the use of these upgrades. In 2016, PSO and SWEPCo recognized a net unfavorable impact of approximately $3 million and $4 million, respectively, related to the OATT upgrade costs.

Southwestern Electric Power Co [Member]

Rate Matters

RATE MATTERS

The disclosures in this note apply to all Registrants unless indicated otherwise.

The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions.  Rate matters can have a material impact on net income, cash flows and possibly financial condition.  The Registrants’ recent significant rate orders and pending rate filings are addressed in this note.

APCo and WPCo Rate Matters (Applies to AEP and APCo)

2016 West Virginia Expanded Net Energy Cost Filing

In June 2016, the WVPSC approved a settlement agreement related to APCo and WPCo’s combined annual ENEC filing. The settlement agreement included $38 million ($30 million related to APCo) of additional ENEC revenues and $17 million ($14 million related to APCo) in construction surcharges annually for two years, effective July 2016. Additionally, APCo and WPCo agreed that a general rate case will not be filed before April 2018.

West Virginia Deferred Base Rate Increase

In May 2015, the WVPSC issued an order on APCo and WPCo’s combined base rate case. The order included a delayed billing of $25 million ($22 million related to APCo) of the annual base rate increase to residential customers until July 2016. In June 2016, the WVPSC issued an order that approved recovery of the total deferred billing, including carrying charges through June 2018, totaling $29 million ($27 million related to APCo). Recovery was approved over two years, effective July 2016. Additionally, at the end of the two-year amortization, any over/under-recovery of the delayed billing will be included in the annual ENEC filing. The WVPSC also approved implementation of the prospective $25 million base rate increase effective July 2016.

2015 Virginia Regulatory Asset Proceeding

In 2015, the Virginia SCC initiated a proceeding to address the treatment of APCo’s authorized regulatory assets. In September 2016, the Virginia SCC issued an order that approved the continued recovery through amortization of certain regulatory assets established prior to the period of frozen rates pursuant to the amended Virginia law (see “Virginia Legislation Affecting Biennial Reviews” below).

Virginia Legislation Affecting Biennial Reviews

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’s financial statements adequately address the impact of these amendments. The amendments 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.

In February 2016, certain APCo industrial customers filed a petition with the Virginia SCC requesting the issuance of a declaratory order that finds the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, directs APCo to make biennial review filings beginning in 2016. In July 2016, the Virginia SCC issued an order that denied the petition. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition.

ETT Rate Matters (Applies to AEP)

ETT Interim Transmission Rates

Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. During a 2015 open meeting at the PUCT, ETT committed to file a base rate case by February 2017. In January 2017, the PUCT approved ETT’s request to suspend the base rate case filing and decrease ETT’s annual revenue requirement by $46 million, effective March 2017. As of December 31, 2016, AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $591 million based upon interim rate increases received from 2009 through 2016. A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. Management is unable to determine a range of potential losses that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters (Applies to AEP and I&M)

Indiana Amended PJM Settlement Agreement

In November 2016, the IURC issued an order that approved an amended settlement agreement between I&M and certain intervenors.  This agreement amends a previously approved 2014 settlement agreement that addresses the recovery of 43.5% of certain transmission expenses through the Indiana PJM rider through 2017.

The amended agreement allows I&M to recover 100% of the Indiana jurisdictional share of these transmission expenses not recovered through base rates through the Indiana PJM rider, subject to a $109 million cap for the period January 2017 through June 2018. Beginning July 2018, I&M will be allowed to recover 100% of the Indiana jurisdictional share of these transmission expenses through the Indiana PJM rider, without a cap, until the issue is addressed by the IURC in a future proceeding, subject to the condition that I&M files a base rate case on or before January 2018. The amended agreement also provides for deferral of incremental vegetation management expenses over the period January 2017 through June 2018.  Any vegetation management expenses deferred would reduce the cap for the transmission expenses described above. As part of the amended settlement, I&M agreed that it will not file a base rate case before July 2017 and will not implement new base rates prior to July 2018.

Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR)

In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO_x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million, excluding AFUDC, to be shared equally between I&M and AEGCo.  The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year life and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. 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 limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC is scheduled for March 2017.

KGPCo Rate Matters (Applies to AEP)

Kingsport Base Rate Case

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.

OPCo Rate Matters (Applies to AEP and OPCo)

Ohio Global Settlement

In February 2017, the PUCO approved a settlement agreement (Global Settlement) filed by OPCo in December 2016. The parties to the Global Settlement include OPCo, the PUCO staff and various intervenors. The Global Settlement resolves all remaining open issues on remand from the Ohio Supreme Court in OPCo’s 2009 - 2011 and June 2012 - May 2015 ESP filings, including issues related to carrying charges on the PIRR and issues related to the RSR capacity charges. It also resolves all open issues in OPCo’s 2009, 2014 and 2015 SEET filings and 2009, 2012 and 2013 Fuel Adjustment Clause Audits.

The significant components of the Global Settlement include:

Remands Related to the PIRR

All applicable parties participating in this settlement will withdraw their pending applications for rehearing of the PUCO order that allowed for the reinstatement of the equity portion of the WACC rate on previously deferred fuel balances. As part of the Global Settlement, the PIRR rate to be collected from customers through December 2018 will be reduced by $97 million.

Remands Related to the RSR

Beginning January 2017, OPCo will be entitled to collect $388 million in RSR revenues over a total of 30 months, subject to true up at the end of the collection period in June 2019. Current RSR rates will continue until the new RSR rates are approved. The Global Settlement resolves the issues related to the non-deferral portion of RSR collections and the impact of the appropriate energy credit on capacity charges. In December 2016, OPCo recorded an increase in Regulatory Assets on the balance sheets for the deferral of $83 million in RSR capacity costs and $14 million in related debt carrying charges with a corresponding decrease in expense in Generation Deferrals and an increase in Carrying Costs Income, respectively, on the statements of income.

For the year ended December 31, 2016, AEP recorded approximately $97 million in RSR capacity deferrals and related carrying charges to the following line items on the statements of income:

	AEP
	(in millions)
Fuel and Other Consumables Used for Electric Generation	$	(19.0	)
Purchased Electricity for Resale	(19.9		)
Other Operation	(15.7		)
Depreciation and Amortization	(42.1		)
Total Decrease in RSR Expenses	$	(96.7	)

As of December 31, 2016, OPCo’s total RSR under-recovery balance, including carrying charges, was $299 million.

Remands Related to the SEET

As part of the Global Settlement,$20 million will be returned to customers over a 12-month period commencing within 45 days of the final PUCO order adopting the Global Settlement. The Global Settlement states that this obligation has no precedential effect on OPCo’s SEET methodology. In addition, the parties agreed that earnings were not significantly excessive in 2015. In December 2016, OPCo accrued $20 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the issues related to the 2014 and 2015 SEET proceedings.

Fuel Adjustment Clause Proceedings

OPCo will refund $100 million paid by SSO customers from August 2012 - May 2015 related to OVEC and Lawrenceburg purchases. In December 2016, OPCo accrued $100 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the claimed recovery of fixed fuel costs through both the FAC and the approved capacity charges. This refund will be a one-time credit that will be applied the earlier of either 45 days after the final non-appealable order from the PUCO adopting the Global Settlement, or the December 2017 billing cycle.

Ohio Electric Security Plan Filings

2009 – 2011 ESP

The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018.

In 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a WACC rate. In 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and remanded the matter back to the PUCO for reinstatement of the WACC rate. In June 2016, the PUCO approved OPCo’s proposed increase to the PIRR rates, in accordance with the Supreme Court of Ohio ruling. The increase to PIRR rates included $146 million in additional carrying charges and the recovery of $40 million in additional under-recovered fuel costs resulting from a decrease in customer demand. The increase is effective July 2016 through December 2018. In July 2016, intervenors filed requests for rehearing with the PUCO, which the PUCO granted in August 2016. In December 2016, OPCo filed a Global Settlement with the PUCO related to this issue. See “Ohio Global Settlement” section above.

June 2012 – May 2015 ESP Including Capacity Charge

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 July 2012, the PUCO issued an order in a separate capacity proceeding requiring OPCo to charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day.  The OPCo RPM price collected from CRES providers, which included reserve margins, was approximately $34/MW day through May 2014 and $150/MW day from June 2014 through May 2015. In April 2016, the Supreme Court of Ohio issued two opinions related to the deferral of OPCo’s capacity charges. In one of the opinions, the Supreme Court of Ohio ruled that the PUCO must reconsider an energy credit that was used to determine OPCo’s authorized capacity deferral threshold of $188.88/MW day during the August 2012 through May 2015 period. The PUCO reduced OPCo’s authorized capacity deferral threshold to $188.88/MW day largely due to an offset for an energy credit of $147.41/MW day. The Supreme Court of Ohio directed the PUCO to substantively address OPCo’s arguments that the $147.41/MW day credit was overstated by approximately $100/MW day due to various inaccuracies affecting input data and assumptions. See “Ohio Global Settlement” section above.

As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012.  The RSR was collected from customers at $3.50/MWh through May 2014 and at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. In April 2015, the PUCO issued an order that modified and approved OPCo’s July 2014 application to collect the unrecovered portion of the deferred capacity costs. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00/MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance. As of December 31, 2016, OPCo’s net deferred capacity costs balance was $202 million, including debt carrying costs, and was recorded in Regulatory Assets on the balance sheets. In April 2016, the second Supreme Court of Ohio opinion rejected a portion of OPCo’s RSR revenues collected during the period September 2012 through May 2015 and directed the PUCO to reduce OPCo’s deferred capacity costs by these previously collected RSR revenues. The Supreme Court of Ohio was not able to determine the amount of the reduction to OPCo’s deferred capacity costs and remanded the issue to the PUCO to determine the appropriate reduction. As directed by the PUCO, in May 2016, OPCo submitted revised RSR tariffs that reflect the RSR being collected subject to refund. See “Ohio Global Settlement” section above.

In April 2016, the Supreme Court of Ohio also ruled favorably on OPCo’s cross-appeal regarding a previously PUCO-imposed SEET threshold under the ESP and remanded this issue to the PUCO. See “Ohio Global Settlement” section above and “Significantly Excessive Earnings Test Filings” section below.

In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings.

In 2014, the PUCO denied all rehearing requests, 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, and 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. See “2012 and 2013 Fuel Adjustment Clause Audits” section below.

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, (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, and due to the interrelated nature of the two Supreme Court of Ohio opinions that directly relate to OPCo’s deferred capacity costs, 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. 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 December 2016, OPCo filed a Global Settlement with the PUCO related to these issues. See “Ohio Global Settlement” section above.

June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024

In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a PPA rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets.

In February 2015, the PUCO issued an order approving OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo’s and various intervenors’ requests for rehearing related to the May 2015 order. In November 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments and denied the remaining requests for rehearing. In January 2017, the PUCO granted intervenors requests for rehearing that oppose the PPA rider as well as the amended DIR caps.

In May 2015, OPCo filed an amended PPA application that (a) included OPCo’s OVEC contractual entitlement (OVEC PPA), (b) addressed the PPA requirements set forth in the PUCO’s February 2015 order and (c) included the 2,671 MWs to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units (Affiliate PPA).

In March 2016, a contested stipulation agreement related to the PPA rider application was modified and approved by the PUCO. The approved PPA rider is effective April 2016 through May 2024, subject to audit and review by the PUCO. The stipulation agreement, as approved, included (a) an Affiliate PPA between OPCo and AGR to be included in the PPA rider, (b) OPCo’s OVEC PPA to be included in the PPA rider, (c) potential additional contingent customer credits of up to $100 million to be included in the PPA rider over the final four years of the PPA rider and (d) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions.

In April 2016, the FERC issued an order granting a January 2016 complaint filed against AGR and OPCo.  The FERC order rescinded the waivers of the 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 accordance with FERC’s rules governing affiliate transactions.  As a result 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 proposed OVEC-only PPA Rider to recover the net margin after sales through PJM and 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 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. In November 2016, the PUCO issued an order on rehearing that approved recovery of the OVEC-related net margin incurred from June 2016 through the term of the PPA rider and the modification to reduce the customer credits to $15 million as requested by OPCo. The PUCO rejected OPCo’s request to eliminate both the 5% rate impact cap and the inclusion of the capacity performance penalties within the PPA rider. In January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC-only PPA and stated that the stipulation agreement approved in March 2016 does not provide customers with rate stability.

OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO makes unacceptable modifications to the stipulation, including modifications as part of the pending rehearing.

Consistent with the terms of the modified and approved stipulation agreement, and based upon a September 2016 PUCO order, in November 2016, OPCo refiled its amended ESP extension application and supporting testimony. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.

Significantly Excessive Earnings Test Filings

Background

Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric distribution utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk.

2009 SEET Filing

In 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project.

In September 2013, a proposed second phase of OPCo’s gridSMART^® (gridSMART^® Phase II) program was filed with the PUCO which included a proposed project to satisfy the PUCO 2009 SEET directive. In April 2016, a stipulation agreement related to the gridSMART^® Phase II program was filed with the PUCO. As part of the stipulation agreement, OPCo will invest at least $20 million over a six-year period for the installation of Volt VAR Optimization (VVO) technology on selected circuits throughout OPCo’s service territory. All parties to the stipulation agree that OPCo’s proposed VVO investment resolves OPCo’s outstanding obligation for renewable or similar investment associated with the PUCO’s 2009 SEET directive. As a part of the December 2016 Global Settlement, OCC agreed to no longer contest the gridSMART^® Phase II stipulation. In February 2017, the PUCO approved the gridSMART^® Phase II stipulation agreement. See “Ohio Global Settlement” section above.

2014 and 2015 SEET Filings

The PUCO established an annual SEET earnings threshold of 12% during the June 2012 - May 2015 ESP period. In May 2013, OPCo filed a cross appeal with the Supreme Court of Ohio, asserting that the SEET threshold was not based on the earnings of comparable publicly traded companies as originally required by the SEET statute.

In April 2016, the Supreme Court of Ohio agreed with OPCo’s cross-appeal assertion that a 12% SEET threshold was not based on the applicable Ohio SEET statute. The Supreme Court of Ohio reversed the 12% threshold and remanded this issue to the PUCO.

In June 2015 and May 2016, OPCo submitted its SEET filings for 2014 and 2015, respectively, with the PUCO. In August 2016, intervenors filed testimony recommending a revenue refund of approximately $20 million for 2014 and no refund for 2015 based upon a new approach to determine significantly excessive earnings that has not been previously approved by the PUCO. In September 2016, OPCo and the PUCO staff filed a stipulation agreement with the PUCO stating that no significantly excessive earnings occurred for 2014 or 2015. In September 2016, intervenors filed testimony opposing the stipulation agreement. See “Ohio Global Settlement” section above.

2016 SEET Filing

OPCo expects to submit its 2016 SEET filing in the second quarter of 2017.  OPCo’s 2016 SEET provision was determined by excluding the gain on the deferral of RSR costs related to the Global Settlement. In addition, refunds to customers included in the Global Settlement relating to the SEET remands and fuel adjustment clause proceedings were excluded from the determination of the 2016 SEET provision. Management believes its financial statements adequately address the impact of 2016 SEET requirements.  If the PUCO adopts a different 2016 SEET methodology, it could reduce future net income and cash flows and impact financial condition.

2009 Fuel Adjustment Clause Audit

In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statements of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. See “Ohio Global Settlement” section above.

2012 and 2013 Fuel Adjustment Clause Audits

In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the “June 2012 - May 2015 ESP Including Capacity Charge” and “Ohio Global Settlement” sections above.

Ormet

Ormet, a large aluminum company, had a contract to purchase power from OPCo. In OPCo’s 2009 - 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues. Through September 2009, the last month of the interim arrangement, OPCo had approximately $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s filing to approve recovery of the deferral under the interim agreement. Of the $64 million in deferred FAC costs, approximately 50% was related to Columbus Southern Power Company (CSPCo) and 50% related to OPCo, prior to the merger of CSPCo into OPCo in December 2011. CSPCo’s portion of these deferred fuel costs has been recovered as a result of the previous collections of CSPCo fuel costs from ratepayers and the PUCO’s 2013 order to apply CSPCo’s 2010 excessive earnings to offset CSPCo’s final deferred fuel balance. OPCo’s share of Ormet deferred fuel costs continues to be recovered through OPCo’s PIRR.

The Ohio Global Settlement discussed above, approved by the PUCO in February 2017, includes the resolution of the 2009, 2012 and 2013 Fuel Adjustment Clause Audits together with the finalization of the PIRR.  The resolution of those cases effectively makes the risk of non-recovery of the Ormet deferrals remote.

PSO Rate Matters (Applies to AEP and PSO)

2015 Oklahoma Base Rate Case

In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million. The request consisted 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 included a proposed return on common equity of 10.5%. The $44 million increase related to environmental investments was proposed to be effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls were 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 December 31, 2016, PSO had incurred costs of $181 million and $44 million, including AFUDC, for Northeastern Plant, Unit 3 and Comanche Plant, respectively. In January 2016, PSO implemented an interim annual base rate increase of $75 million, subject to refund.

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, 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 sheets related to the net book value of Northeastern Plant, Unit 4. These regulatory assets are pending regulatory approval.

In November 2016 and December 2016, the OCC issued orders that approved a net annual revenue increase of $19 million based upon a 9.5% return on common equity. The orders also included (a) approval to defer incurred costs related to PSO’s environmental compliance plan until those costs are included in base rates, (b) no determination related to the return of and return on the post-retirement remaining net book value of Northeastern Plant, Unit 4 since the April 2016 retirement was outside of the test year, (c) approval to include environmental consumable costs in the FAC (d) the continued depreciation of Northeastern Plant, Units 3 and 4 through 2040 (no accelerated depreciation) and (e) altered the system reliability rider by eliminating the expense portion of the rider and setting the capital portion of the rider at the December 2016 plant balance and approved recovery of deferred expenses and return on the capital balance incurred prior to the effective date of new tariffs in January 2017. Additionally, the orders stated that the cost recovery of new PPAs related to replacement power resulting from the retirement of Northeastern Plant, Unit 4 will be addressed in a future FAC proceeding. Effective December 2016, interim rates were terminated and the refund of over collections began and will be completed no later than October 2017. In accordance with the final order, updated rates and tariffs went into effect in January 2017.

If any of these costs, including a return on Northeastern Plant, Unit 4, are ultimately not recoverable, it could reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters (Applies to AEP and SWEPCo)

2012 Texas Base Rate Case

In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2.

Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million. In 2014, intervenors filed appeals of that order with the Texas District Court and SWEPCo intervened in those appeals. A hearing at the Texas District Court is scheduled for March 2017.

If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition.

2016 Texas Base Rate Case

In December 2016, SWEPCo filed a base rate request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. The annual increase includes approximately (a) $34 million related to additional environmental controls to comply with Federal EPA mandates, (b) $25 million for additional generation, transmission and distribution investments and increased operating costs, (c) $8 million related to transmission cost recovery within SWEPCo’s regional transmission organization and (d) $2 million in additional vegetation management.

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

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant. In February 2013, a settlement was approved by the LPSC. The settlement increased SWEPCo’s Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually.  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. The rates are subject to refund based on the prudence review of the Turk Plant. The settlement also provided that the LPSC would review base rates in 2014 and 2015 and that SWEPCo would 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 June 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.

2014 Louisiana Formula Rate Filing

In 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC.  The filing included a $5 million annual increase, which was effective August 2014.  SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million. This additional increase reflects the cost of incremental generation used to serve Louisiana customers in 2015 due to the expiration of a purchased power agreement attributable to Louisiana customers.  In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015, subject to staff review of the cost of service and prudence review of the Turk Plant. In July 2016, the LPSC approved a settlement agreement related to the staff review of the cost of service. A portion of the rates remain subject to refund based on the prudence review of the Turk Plant. See “2012 Louisiana Formula Rate Filing” above. Management believes its financial statements adequately address the impact of this settlement agreement. 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.

2015 Louisiana Formula Rate Filing

In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC.  The filing included a $14 million annual increase, which was effective August 2015.  This increase is subject to LPSC staff review and is subject to refund.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Welsh Plant - Environmental Impact

Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could cost a total of approximately $850 million, excluding AFUDC. As of December 31, 2016, SWEPCo had incurred costs of $397 million, including AFUDC, and had remaining contractual construction obligations of $11 million related to these projects.  As part of this investment, in 2016 SWEPCo completed construction of environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $370 million, excluding AFUDC.  Management continues to evaluate the impact of environmental rules and related project cost estimates. In March 2016, SWEPCo filed a request with the APSC to recover $69 million in environmental costs related to the Arkansas retail jurisdictional share of Welsh Plant, Units 1 and 3, which was approved by the APSC in August 2016. SWEPCo began recovering the Arkansas jurisdictional share of these costs in March 2016, subject to review in the next filed base rate proceeding. In September 2016, SWEPCo filed an additional request to increase the Arkansas retail jurisdictional share of the environmental investment by $10 million, for a total of $79 million. SWEPCo implemented the increase in September 2016. In December 2016, the LPSC approved deferral of certain expenses related to environmental controls installed at Welsh Plant, until these investments are put into base rates. The eligible Welsh Plant deferrals through December 31, 2016 are $8 million, excluding $5 million of unrecognized equity, subject to review by the LPSC, and include a WACC return on environmental investments and the related depreciation expense and taxes. SWEPCo will seek recovery of its project costs from customers at the state commissions and the FERC.

As of December 31, 2016, the net book value of Welsh Plant, Units 1 and 3 was $633 million, before cost of removal, including materials and supplies inventory and CWIP.  In April 2016, Welsh Plant, Unit 2 was retired. Upon retirement, $76 million was reclassified as Regulatory Assets on the balance sheets related to the net book value of Welsh Plant, Unit 2 and the related asset retirement obligation costs. In SWEPCo’s 2016 Texas Base Rate Case, SWEPCo requested recovery of the Texas jurisdictional share (approximately 33%) of the net book value of Welsh Plant, Unit 2 through 2042, the remaining life of Welsh Plant, Unit 3. Management will seek recovery of the remaining Welsh Plant, Unit 2 retirement-related regulatory assets in future rate proceedings.

If any of these costs are not recoverable, including retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.

AEP Texas Rate Matters (Applies to AEP)

TCC and TNC Merger

Effective December 31, 2016, TCC and TNC merged into AEP Utilities, Inc., as approved by the FERC and the PUCT in September 2016 and December 2016, respectively. Upon merger, AEP Utilities, Inc. changed its name to AEP Texas Inc., but maintained TCC’s and TNC’s respective customer rates. The PUCT ordered certain post-merger conditions which included a) the sharing of certain interest rate savings with customers 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.

AEP Texas Distribution Cost Recovery Factor (DCRF)

In July 2016, the PUCT approved settlement agreements between TCC, TNC and intervenors related to requests for DCRF riders to allow recovery of eligible net distribution investments. The settlement agreement included an annual revenue requirement of $56 million ($45 million for the TCC division and $11 million for the TNC division), effective September 2016. Amounts approved are subject to refund based upon a prudence review of the investments in AEP Texas’ next base rate case.

FERC Rate Matters (Applies to AEP, APCo, I&M and OPCo)

PJM Transmission Rates

In June 2016, PJM transmission owners, including the AEP East Companies, and various state commissions filed a settlement agreement with the FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. In July 2016, certain parties filed comments at the FERC contesting the settlement agreement. Upon final FERC approval, PJM would implement a transmission enhancement charge adjustment through the PJM OATT, billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms.

FERC Transmission Complaint and Proposed Modifications to Transmission Rates

In October 2016, several parties filed a joint complaint with the FERC claiming that the base return on common equity used by various AEP affiliates 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 2016, AEP affiliates filed an application with the FERC to modify the FERC formula transmission rate calculation, including adjustments for certain tax issues and a shift from historical to estimated expenses with a proposed effective date of January 1, 2017. The rates will be implemented based upon the date provided in the pending FERC order, subject to refund. Management believes its financial statements adequately address the impact of the complaint and the proposed modifications to AEP’s transmission rates in PJM. 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.

Other Rate Matters (Applies to AEP, PSO and SWEPCo)

SPP OATT Upgrade Costs

Under the SPP OATT, costs of sponsor-funded transmission upgrades may be recovered, in part, from SPP customers whose transmission service is dependent upon capacity enabled by the upgrades. Prior to 2016, SPP had not charged its customers any amounts attributable to these upgrades. In November 2016, SPP billed transmission service customers, including PSO and SWEPCo, for upgrade costs incurred since 2008. SPP then credited the qualifying transmission upgrade owners, including SWEPCo, for the use of these upgrades. In 2016, PSO and SWEPCo recognized a net unfavorable impact of approximately $3 million and $4 million, respectively, related to the OATT upgrade costs.