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.

Impact of Tax Reform

Rate and regulatory matters are impacted by federal income tax implications. In December 2017, Tax Reform was enacted, which impacts outstanding rate and regulatory matters. For additional details on the impact of Tax Reform, see Note 12 - Income Taxes.

AEP Texas Rate Matters (Applies to AEP and AEP Texas)

AEP Texas Interim Transmission and Distribution Rates

As of December 31, 2018, AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2018, subject to review, are estimated to be $1 billion. A base rate review could result in a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition.

In April 2018, the PUCT adopted a rule requiring investor-owned utilities operating solely within ERCOT to make periodic filings for rate proceedings. The rule requires AEP Texas to file for a comprehensive rate review no later than May 1, 2019.

In 2018, the PUCT issued approvals to increase AEP Texas’ transmission rates by $22 million annually. The approvals included an increase in annual revenues to recover transmission capital additions of $46 million offset by a reduction in annual revenues of $24 million due to the reduction in the federal income tax rate due to Tax Reform. The approvals did not address the return of Excess ADIT benefits to customers.

In August 2018, the PUCT approved a Stipulation and Settlement agreement to amend AEP Texas’ Distribution Cost Recovery Factor to reduce annual distribution rates by approximately $24 million annually, beginning September 1, 2018. The settlement included an increase in annual revenues to recover 2017 distribution capital additions of $19 million offset by reductions in annual revenues of: (a) $21 million due to the reduction in the federal income tax rate due to Tax Reform, (b) $10 million due to Excess ADIT associated with certain depreciable property to be amortized using ARAM and (c) $12 million due to Excess ADIT that is not subject to rate normalization requirements to be refunded over 5 years.

Hurricane Harvey and Texas Storm Cost Securitization

In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. AEP Texas has a PUCT approved catastrophe reserve in base rates and can defer incremental storm expenses. AEP Texas currently recovers approximately $1 million of storm costs annually through base rates. As of December 31, 2018, the total balance of AEP Texas’ regulatory asset for deferred storm costs is approximately $152 million, inclusive of approximately $129 million of incremental storm expenses related to Hurricane Harvey. See the table below for additional information on the Hurricane Harvey storm restoration costs:



	December 31, 2018
Total Hurricane Harvey Storm Costs	Capital			O&M			Regulatory Asset			Total
	(in millions)
Restoration Costs Incurred	$	219.1		$	136.9		$	—		$	356.0
Incremental Operation and Maintenance Expenses (O&M)	—			(129.8		)	129.8			—
Insurance Proceeds	(12.7		)	—			(1.2		)	(13.9		)
Total Hurricane Harvey Storm Costs, Net	$	206.4		$	7.1		$	128.6		$	342.1

The securitization of storm cost recovery in Texas requires two filings with the PUCT. In August 2018, AEP Texas filed a Determination of System Restoration Costs (DSRC) with the PUCT for total estimated storm costs in the amount of $425 million, which includes estimated carrying costs. The total estimated storm costs net of insurance proceeds, tax credits received for the Disaster Tax Relief and Airport and Airway Extension Act of 2017, and Excess ADIT that is not subject to rate normalization requirements utilized to reduce the non-capital Hurricane Harvey costs is $370 million.

In November 2018, AEP Texas, the PUCT staff and intervenors filed a stipulation and settlement agreement with the PUCT that included all aspects of the DSRC filing with the following exceptions: (a) a $5 million permanent storm restoration reduction, (b) a $4 million disallowance of charges not directly related to storm restoration that will be included in a future regulatory proceeding and (c) a $5 million disallowance due to additional insurance proceeds received. See the table below for a reconciliation of the filed Determination of System Restoration Costs and settlement and stipulation agreement:



Total Estimated Storm Costs Requested in the DSRC	December 31, 2018
	(in millions)
Total Estimated Hurricane Harvey Storm Costs	$	356.0
Estimated Hurricane Harvey Carrying Costs	31.5
Estimated Litigation Costs	0.6
Non-Hurricane Harvey Storm Restoration Costs	36.5
Total Estimated Storm Costs requested in the DSRC	424.6
less:
Tax Credit	(0.8		)
Insurance Proceeds	(8.7		)
Excess ADIT (a)	(45.5		)
Total Estimated Storm Costs requested in the DSRC, after adjustments	369.6
less:
Settlement Agreement Adjustments	(10.6		)
Incremental Insurance Proceeds Received	(5.1		)
Total Estimated Storm Costs per Settlement Agreement	$	353.9


(a)	Amount represents Non-Hurricane Harvey Excess ADIT that is not subject to rate normalization requirements.

AEP Texas will seek to securitize estimated distribution related assets of $247 million in the first half of 2019 while the remaining $107 million of estimated transmission related assets is expected to be recovered through interim transmission filings or an upcoming base rate case. If these costs are not recovered, it could have an adverse effect on future net income, cash flows and financial condition.

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

Virginia Legislation Affecting Earnings Reviews

In 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 were frozen until after the Virginia SCC ruled on APCo’s next biennial review. These amendments also precluded the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017.

In March 2018, new Virginia legislation impacting investor-owned utilities was enacted, effective July 1, 2018, that: (a) on a one-time basis, required APCo to exclude $10 million of incurred fuel expenses from the July 2018 over/under recovery calculation, (b) reduced APCo’s base rates by $50 million annually effective July 30, 2018, on an interim basis and subject to true-up, to reflect the reduction in the federal income tax rate due to Tax Reform, (c) will require APCo to file its next generation and distribution base rate case by March 31, 2020 using 2017, 2018 and 2019 test years (“triennial review”), (d) will require an adjustment in APCo’s base rates on April 1, 2019 to reflect actual annual reductions in corporate income taxes due to Tax Reform, (e) will require APCo to seek approval from the Virginia SCC for energy efficiency programs with projected costs in the aggregate of at least $140 million over the 10-year period ending July 1, 2028 and (f) will require APCo to construct and/or acquire solar generation facilities in Virginia, subject to approval of the Virginia SCC, of at least 200 MW of aggregate capacity by July 1, 2028.

Triennial reviews are subject to an earnings test which provides that 70% of any earnings exceeding 70 basis points over the Virginia SCC authorized return on common equity would be refunded, or may be offset by capital expenditures in Virginia SCC approved energy distribution grid transformation projects and/or new utility-owned solar and wind generation facilities. In November 2018, the Virginia SCC approved a return on common equity of 9.42% applicable to APCo base rate earnings for the 2017-2019 triennial period and rate adjustment clauses from November 2018 through November 2020. Management has reviewed APCo’s actual and forecasted earnings for the triennial period and concluded that it is not probable but is reasonably possible that APCo will over-earn in Virginia during the 2017-2019 triennial period. Due to various uncertainties, including weather, storm restoration, weather-normalized demand and potential customer shopping during 2019, management cannot estimate a range of potential APCo Virginia over-earnings during the 2017-2019 triennial period. The Virginia triennial review of APCo earnings could materially reduce future net income and cash flows and impact financial condition.

Virginia Staff Depreciation Study Request

In November 2018, Virginia staff recommended that APCo implement new Virginia jurisdictional depreciation rates effective January 1, 2018 based on APCo’s depreciation study that was prepared at Virginia staff’s request using December 31, 2017 APCo property balances. Implementation of those depreciation rates would result in a $21 million pretax increase in annual depreciation expense ($6 million related to transmission) with no corresponding increase in retail base rates. In December 2018, APCo submitted a response to the Virginia staff stating that it was inappropriate for APCo to change Virginia depreciation rates in advance of the Virginia SCC’s upcoming Triennial Review of APCo, citing the Virginia SCC’s November 2014 order to not change APCo’s Virginia depreciation rates until APCo’s next base rate case/review. If the Virginia SCC were to issue an order approving the Virginia staff’s recommended retroactive change in APCo’s Virginia depreciation rates, it would reduce future net income and cash flows and impact financial condition.

Virginia Tax Reform

In October 2018, the Virginia SCC issued an order approving APCo’s request to refund $55 million of Excess ADIT that is not subject to rate normalization requirements to customers through a rider. The rider is being paid over twelve months effective November 1, 2018 and will offset APCo’s recent increase in interim fuel rates, subject to refund, as approved by the Virginia SCC.

In October 2018, APCo also submitted a filing with the Virginia SCC to resolve outstanding issues related to Tax Reform. The filing incorporated the $50 million being refunded to customers as disclosed in “Virginia Legislation Affecting Earnings Reviews” above and, if approved, will reduce APCo’s base rates by an additional $7 million annually. The combined reduction in APCo’s base rates due to Tax Reform will refund: (a) $39 million annually of excess federal income taxes collected since January 1, 2018 until new base rates are implemented, (b) $7 million annually of Excess ADIT associated with certain depreciable property using ARAM and (c) $11 million annually of Excess ADIT that is not subject to rate normalization requirements over 10 years.

In November 2018, the Virginia SCC staff filed testimony recommending a total annual reduction in APCo’s base rates of $69 million. The proposed reduction consisted of: (a) $41 million annually of excess federal income taxes collected since January 1, 2018 until new base rates are implemented, (b) $9 million annually of Excess ADIT associated with certain depreciable property using ARAM and (c) $19 million annually of Excess ADIT that is not subject to rate normalization requirements over 5 years. The Virginia SCC staff also recommended that APCo provide a one-time credit of $23 million for estimated excess taxes collected from customers during the 15-month period ending March 31, 2019. Intervenors filed testimony recommending that the $23 million for estimated excess taxes collected from customers during the 15-month period ending March 31, 2019 be refunded over 1 year and Excess ADIT that is not subject to rate normalization requirements be refunded over 3 years.

In December 2018, APCo filed rebuttal testimony with the Virginia SCC generally agreeing with the Virginia SCC staff testimony. A hearing at the Virginia SCC was held in January 2019 where both APCo and the Virginia SCC staff lowered their reduction for excess federal income taxes collected since January 1, 2018 by $1 million. APCo anticipates a final order from the Virginia SCC by the end of the first quarter of 2019 and expects to implement additional customer rate credits in a tax-related rider starting in April 2019. The Virginia SCC’s review of APCo’s Tax Reform filing could reduce future net income and cash flows and impact financial condition.

2018 West Virginia Base Rate Case

In May 2018, APCo and WPCo filed a joint request with the WVPSC to increase their combined West Virginia base rates by $115 million ($98 million related to APCo) annually based on a 10.22% return on common equity. The proposed annual increase included $32 million ($28 million related to APCo) due to increased annual depreciation expense and reflected the impact of the reduction in the federal income tax rate due to Tax Reform. In October 2018, APCo and WPCo filed updated schedules supporting a $95 million ($80 million related to APCo) annual increase in West Virginia base rates primarily due to the impact of West Virginia Tax Reform case discussed below.

In November 2018 APCo, WPCo, WVPSC staff and certain intervenors filed a Stipulation and Settlement agreement with the WVPSC. The agreement included a proposed annual base rate increase of $44 million ($36 million related to APCo) based upon a 9.75% return on common equity effective March 2019. The agreement provided for an annual increase of $18 million ($14 million related to APCo) due to increased annual depreciation expense. Depreciation rates were decreased from the original request primarily due to continuing with a 2040 retirement date for Clinch River Plant rather than APCo’s proposed retirement date of 2025. The agreement also included: (a) a proposal to refund, through a rider, $24 million ($19 million related to APCo) of Excess ADIT that is not subject to rate normalization requirements over two years starting March 2019, (b) a proposal to utilize $14 million ($12 million related to APCo) of Excess ADIT that is not subject to rate normalization requirements to offset regulatory asset balances relating to ENEC, (c) an agreement to work with the WVPSC to establish economic incentive programs and (d) an agreement, barring any unforeseen events, to not initiate another base rate proceeding prior to April 1, 2020. An order from the WVPSC is expected in the first quarter 2019. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

West Virginia Tax Reform

In August 2018, the WVPSC approved a settlement agreement between APCo, WPCo and various intervenors that addresses the reduction in the federal income tax rate due to Tax Reform and provides refunds to customers, through a rider, effective September 1, 2018 of approximately $63 million ($51 million related to APCo) through June 2020. In addition, per the agreement, APCo and WPCo utilized $139 million ($125 million related to APCo) of current tax savings and Excess ADIT that is not subject to rate normalization requirements to offset regulatory asset balances related to carbon capture, storm damage, ENEC and vegetation management. The WVPSC order indicated that the remaining balance of Excess ADIT that is not subject to rate normalization requirements would be addressed at a later date.

ETT Rate Matters (Applies to AEP)

ETT Interim Transmission Rates

AEP 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. Through December 31, 2018, AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $884 million. A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring.

In April 2018, the PUCT adopted a rule requiring investor-owned utilities operating solely inside ERCOT to make periodic filings for rate proceedings. The rule requires ETT to file for a comprehensive rate review no later than February 1, 2021.

In June 2018, the PUCT approved ETT’s application to reduce its transmission rates by $28 million annually, beginning June 21, 2018, to reflect the reduction in the federal income tax rate due to Tax Reform. The filing did not address the return of Excess ADIT benefits to customers.

In December 2018, the PUCT approved ETT’s request to refund $11 million of excess federal income taxes collected in 2018 prior to the reduction in transmission rates that were implemented on June 21, 2018. The refunds were completed in December 2018.

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

2017 Indiana Base Rate Case

In 2017, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity. In February 2018, I&M filed a Stipulation and Settlement Agreement for a $97 million annual increase, based on a 9.95% return on equity, in Indiana rates effective July 1, 2018 subject to a temporary offsetting reduction to customer bills through December 2018 for a credit rider related to the timing of estimated in-service dates of certain capital expenditures. In May 2018, the IURC issued an order approving the Stipulation and Settlement Agreement.

2017 Michigan Base Rate Case

In 2017, I&M filed a request with the MPSC for a $52 million annual increase in Michigan base rates based upon a proposed 10.6% return on common equity. In February 2018, an MPSC ALJ issued a Proposal for Decision and recommended an annual revenue increase of $49 million, including an intervenor’s proposal for up to 10% of I&M’s Michigan retail customers to choose an alternate supplier for generation and a proposed capacity rate based on PJM’s net cost of new entry value of $289/MW-day, as well as the MPSC staff’s recommended calculation of depreciation expense for both units of Rockport Plant through 2028 and a return on common equity of 9.8%. In April 2018, the MPSC issued an order that generally approved the ALJ proposal resulting in an annual revenue increase of $50 million, effective April 2018 based on a 9.9% return on common equity. The MPSC also approved the ALJ’s recommendation related to the capacity rate.

If the maximum 10% of customers choose an alternate supplier starting in February 2019, the estimated annual pretax loss due to the reduced capacity rate would be approximately $9 million. In October 2018, I&M filed a request with the MPSC seeking authority to defer costs related to customers choosing an alternate supplier starting in February 2019. In December 2018, the MPSC rejected I&M’s request.

Michigan Tax Reform

In August 2018, the MPSC approved I&M’s application to refund, through a rider, approximately $9 million annually for the impact of Tax Reform on I&M’s Michigan jurisdictional earnings effective September 1, 2018. In October 2018, I&M also made two filings with the MPSC recommending to: (a) refund $3 million over eight months for the impact of Tax Reform on Michigan jurisdictional earnings for the period April 26, 2018 through August 31, 2018, (b) refund approximately $68 million of Excess ADIT associated with certain depreciable property using ARAM and (c) refund approximately $37 million of Excess ADIT that is not subject to rate normalization requirements over 10 years. In January 2019, I&M received an order from the MPSC requiring I&M to refund $5 million over six months, effective February 2019, for the Michigan jurisdictional impacts of Tax Reform related to the period January 1, 2018 through August 31, 2018. An order from the MPSC regarding Excess ADIT is expected in the first half of 2019.

Rockport Plant, Unit 2 SCR

In 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. 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 and is expected to be placed in service in May 2020. 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 and recover, through a rider, its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year period as provided by statute and other related expenses.

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

Management intends to request recovery of the Michigan jurisdictional share of the SCR project in a future base rate case. If the Michigan jurisdictional share of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. The AEGCo ownership share of the SCR project will be billable under the Rockport UPA to I&M and KPCo and will be subject to future regulatory approval for recovery.

KPCo Rate Matters (Applies to AEP)

2017 Kentucky Base Rate Case

In January 2018, the KPSC issued an order approving a non-unanimous settlement agreement with certain modifications resulting in an annual revenue increase of $12 million, effective January 2018, based on a 9.7% return on equity. The KPSC’s primary revenue requirement modification to the settlement agreement was a $14 million annual revenue reduction for the decrease in the corporate federal income tax rate due to Tax Reform. The KPSC approved: (a) the deferral of a total of $50 million of Rockport Plant UPA expenses for the years 2018 through 2022, with the manner and timing of recovery of the deferral to be addressed in KPCo’s next base rate case, (b) the recovery/return of 80% of certain annual PJM OATT expenses above/below the corresponding level recovered in base rates, (c) KPCo’s commitment to not file a base rate case for three years with rates effective no earlier than 2021 and (d) increased depreciation expense based upon updated Big Sandy Plant, Unit 1 depreciation rates using a 20-year depreciable life.

In February 2018, KPCo filed with the KPSC for rehearing of the January 2018 base case order. In June 2018, the KPSC issued an order approving an additional revenue increase of $765 thousand related to the calculation of federal income tax expense. This rate increase was effective June, 2018.

Kentucky Tax Reform

In June 2018, the KPSC issued an order approving a settlement agreement between KPCo and an intervenor that stipulates that KPCo will refund an estimated $82 million of Excess ADIT associated with certain depreciable property using ARAM and an estimated $93 million of Excess ADIT that is not subject to rate normalization requirements over 18 years. The refund was effective July 1, 2018.

OPCo Rate Matters (Applies to AEP and OPCo)

Ohio Electric Security Plan Filings

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 DIR, effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA.

In 2015 and 2016, the PUCO issued orders in this proceeding. As part of the issued orders, the PUCO approved: (a) the DIR with modified revenue caps, (b) recovery of OVEC-related net margin incurred beginning June 2016, (c) potential additional contingent customer credits of up to $15 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 2017, the PUCO rejected all pending rehearing requests related to the OVEC PPA. In June 2017, intervenors filed appeals to the Supreme Court of Ohio stating that the PUCO’s approval of the OVEC PPA was unlawful and does not provide customers with rate stability. In June 2018, oral arguments were held before the Supreme Court of Ohio. In November 2018, the Ohio Supreme Court unanimously affirmed the PUCO’s order in the June 2015 - May 2018 ESP and PPA Rider cases.

In 2016, OPCo refiled its amended ESP extension application and supporting testimony, consistent with the terms of the modified and approved stipulation agreement and based upon a 2016 PUCO order. The amended filing proposed to extend the ESP through May 2024.

In 2017, OPCo and various intervenors filed a stipulation agreement with the PUCO. The stipulation extends the term of the ESP through May 2024 and includes: (a) an extension of the OVEC PPA rider, (b) a proposed 10% 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) rate caps related to OPCo’s DIR ranging from $215 million to $290 million for the periods 2018 through 2021 and (e) the addition of various new riders, including a Smart City Rider and a Renewable Generation Rider. DIR rate caps will be reset in OPCo’s next distribution base rate case which must be filed by June 2020.

In April 2018, the PUCO issued an order approving the ESP extension stipulation agreement, with no significant changes. In May 2018, OPCo and various intervenors filed requests for rehearing with the PUCO. In June 2018, these requests for rehearing were approved to allow further consideration of the requests. In August 2018, the PUCO denied all requests for rehearing. In October 2018, an appeal was filed with the Ohio Supreme Court challenging various approved riders. If the Ohio Supreme Court reverses the PUCO’s decision, it could reduce future net income and cash flows and impact financial condition.

2016 SEET Filing

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 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.

In 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement that was filed at the PUCO in December 2016 and subsequently approved in February 2017: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings.

In 2017, OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group.

In January 2018, PUCO staff filed testimony that OPCo did not have significantly excessive earnings in 2016. Also in January 2018, an intervenor filed testimony recommending a $53 million refund to customers related to OPCo 2016 SEET earnings. In February 2018, OPCo and PUCO staff filed a stipulation agreement in which both parties agreed that OPCo did not have significantly excessive earnings in 2016.

A 2016 SEET hearing was held in April 2018 and management expects to receive an order in the first half of 2019. While management believes that OPCo’s adjusted 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s proposed SEET adjustments, including treatment of the Global Settlement issues described above, adjust the comparable risk group or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could negatively affect future SEET filings, reduce future net income and cash flows and impact financial condition.

Ohio Tax Reform

In October 2018, the PUCO issued an order approving a September 2018 settlement agreement between OPCo and various intervenors that addresses the reduction in the federal income tax rate due to Tax Reform. The settlement will: (a) refund excess federal income tax of $20 million annually, through a rider, effective January 1, 2018 until new base rates are implemented, (b) refund an estimated $278 million of Excess ADIT associated with depreciable property through OPCo’s DIR using ARAM, (c) utilize $48 million of Excess ADIT that is not subject to rate normalization to offset regulatory asset balances related to OPCo’s distribution decoupling program and (d) refund the remaining estimated $129 million of Excess ADIT that is not subject to rate normalization by December 31, 2024 through a rider beginning in the fourth quarter of 2018.

PSO Rate Matters (Applies to AEP and PSO)

2018 Oklahoma Base Rate Case

In October 2018, PSO filed a request with the OCC for an $88 million annual increase in Oklahoma retail rates based upon a 10.3% return on common equity. PSO also proposed to implement a performance-based rate plan that combines a formula rate with a set of customer-focused performance incentive measures related to reliability, public safety, customer satisfaction and economic development. The proposed annual increase includes $13 million related to increased annual depreciation rates and $7 million related to increased storm expense amortization. The requested increase in annual depreciation rates includes the recovery of Oklaunion Power Station through 2028 (currently being recovered in rates through 2046). Management has announced plans to retire Oklaunion Power Station by October 2020.

In January 2019, OCC staff and various intervenors filed testimony. OCC staff recommended a $57 million annual rate increase based on a 9% return on common equity while intervenor recommendations ranged from a decrease in rates of $6 million to an increase in rates of $34 million based on a return on common equity ranging from 9.3% to 9.36%, respectively. The difference between PSO’s requested annual base rate increase and the OCC staff and intervenors recommendations are primarily due to: (a) a reduction in the requested return on common equity, (b) a rejection to PSO’s request to increase depreciation rates, including the proposed accelerated recovery of the Oklaunion Power Station through 2028, (c) a disallowance of certain incentives and operation and maintenance expenses and (d) a proposal to refund Excess ADIT that is not subject to rate normalization requirements over 5 years instead of 10 years. In addition, certain parties recommended a debt only return on, or no recovery of, PSO’s estimated remaining net book value in the Oklaunion Power Station after its retirement, which is estimated to be $49 million. Also, a party recommended a potential refund of $9 million related to an SPP rider claiming that PSO did not adequately support the related costs. No parties supported PSO’s performance-based rate plan as filed.

In February 2019, PSO filed testimony rebutting the various parties’ recommendations included above. PSO also proposed that the performance-based rate plan be implemented on a one-year trial basis where it could be reevaluated at the conclusion of the trial period. In addition, PSO agreed that the prudence of capital investment would be deferred until PSO’s next base rate case. A hearing at the OCC is scheduled to begin in March 2019. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Oklahoma Tax Reform

In August 2018, the OCC issued an order that approved PSO’s compliance filing that addresses the reduction in the federal income tax rate due to Tax Reform. As a result of the order PSO implemented a rider in September 2018 to: (a) refund $3 million of excess federal income taxes collected from January 9, 2018 through February 28, 2018 by the end of 2018, (b) refund an estimated $353 million of Excess ADIT associated with certain depreciable property using ARAM and (c) refund an estimated $72 million of Excess ADIT that is not subject to rate normalization requirements over 10 years.

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.

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, SWEPCo reversed $114 million of a previously recorded regulatory disallowance in 2013. The resulting annual base rate increase was approximately $52 million. In 2017, the Texas District Court upheld the PUCT’s 2014 order and intervenors filed appeals with the Texas Third Court of Appeals.

In July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In August 2018, SWEPCo filed a Motion for Reconsideration at the Court of Appeals, which was denied. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court.

As of December 31, 2018, the net book value of Turk Plant was $1.5 billion, before cost of removal, including materials and supplies inventory and CWIP. If certain parts of the PUCT order are overturned and if SWEPCo cannot ultimately fully recover its approximate 33% 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 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a return on common equity of 9.6%, effective May 2017. The final order also included: (a) approval to recover the Texas jurisdictional share of environmental investments placed in service, as of June 30, 2016, at various plants, including Welsh Plant, Units 1 and 3, (b) approval of recovery of, but no return on, the Texas jurisdictional share of the net book value of Welsh Plant, Unit 2, (c) approval of $2 million in additional vegetation management expenses and (d) the rejection of SWEPCo’s proposed transmission cost recovery mechanism.

As a result of the final order, in 2017 SWEPCo: (a) recorded an impairment charge of $19 million, which included $7 million associated with the lack of return on Welsh Plant, Unit 2 and $12 million related to other disallowed plant investments, (b) recognized $32 million of additional revenues, for the period of May 2017 through December 2017, that was surcharged to customers in 2018 and (c) recognized an additional $7 million of expenses consisting primarily of depreciation expense and vegetation management expense, offset by the deferral of rate case expense. SWEPCo implemented new rates in February 2018 billings. The $32 million of additional 2017 revenues was collected during 2018. In March 2018, the PUCT clarified and corrected portions of the final order, without changing the overall decision or amounts of the rate change. The order has been appealed by various intervenors.

In April 2018, SWEPCo made an income tax rate refund tariff filing which includes an annual revenue reduction of approximately $18 million to reflect the difference between rates collected under the final order and the rates that would be collected under Tax Reform. The filing did not address the return of Excess ADIT benefits to customers. In June 2018, the ALJ issued an order approving interim rates that provided for a reduction of residential rates of $8 million that began in June 2018. In September 2018, the ALJ issued an order approving interim rates for the remaining customers that began in November 2018. In December 2018, the PUCT issued an order approving the new rates.

Texas Tax Reform

In October 2018, SWEPCo filed a Stipulation and Settlement Agreement with the PUCT to refund $10 million of excess federal income taxes collected, as a result of Tax Reform, from January 1, 2018 through June 14, 2018 for residential customers and January 1, 2018 through September 19, 2018 for all other customer classes. An interim order was issued by an ALJ and the refunds were made to customers through a rider in the fourth quarter of 2018. In December 2018, the PUCT issued an order approving the settlement agreement.

2015 Louisiana Formula Rate Filing

In 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. In December 2018, the LPSC issued an order approving the increase as filed.

2017 Louisiana Formula Rate Filing

In 2017, the LPSC approved an uncontested stipulation agreement that SWEPCo filed for its formula rate plan for test year 2015. The filing included a net annual increase not to exceed $31 million, which was effective May 2017 and includes SWEPCo’s Louisiana jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls which were placed in service in 2016. Also in 2017, SWEPCo filed testimony in Louisiana supporting the prudence of its environmental control investment for Welsh Plant, Units 1 and 3 and Flint Creek power plants. These environmental costs were subject to prudence review by the LPSC. In August 2018, the LPSC issued an order affirming prudence and approved the settlement agreement for the environmental control investment. In December 2018, the LPSC issued an order approving the $31 million increase as filed.

2018 Louisiana Formula Rate Filing

In April 2018, SWEPCo filed its formula rate plan for test year 2017 with the LPSC. The filing included a net $28 million annual increase, which was effective August 2018 and included SWEPCo’s Louisiana jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls. The filing also included a reduction in the federal income tax rate due to Tax Reform but did not address the return of Excess ADIT benefits to customers.

In July 2018, SWEPCo made a supplemental filing to its formula rate plan with the LPSC to reduce the requested annual increase to $18 million. The difference between SWEPCo’s requested $28 million annual increase and the $18 million annual increase in the supplemental filing is primarily the result of the return of Excess ADIT benefits to customers.

In October 2018, the LPSC staff issued a recommendation that SWEPCo refund $11 million of excess federal income taxes collected, as a result of Tax Reform, from January 1, 2018 through July 31, 2018. A decision by the LPSC is expected in 2019.

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 total approximately $550 million, excluding AFUDC. As of December 31, 2018, SWEPCo had incurred costs of $399 million, including AFUDC, related to these projects. Management continues to evaluate the impact of environmental rules and related project cost estimates. As of December 31, 2018, the total net book value of Welsh Plant, Units 1 and 3 was $629 million, before cost of removal, including materials and supplies inventory and CWIP.

In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas filed base rate proceeding. In 2017, the LPSC approved recovery of $131 million in investments related to its Louisiana jurisdictional share of environmental controls installed at Welsh Plant. SWEPCo’s approved Louisiana jurisdictional share of Welsh Plant deferrals: (a) are $10 million, excluding $5 million of unrecognized equity as of December 31, 2018, (b) is subject to review by the LPSC and (c) includes a WACC return on environmental investments and the related depreciation expense and taxes. See “2017 Louisiana Formula Rate Filing” and “2018 Louisiana Formula Rate Filing” disclosures above.

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

Arkansas Tax Reform

In September 2018, the APSC issued an order that approved SWEPCo’s application to implement a rider for SWEPCo’s Arkansas jurisdiction to address the reduction in the federal income tax rate due to Tax Reform. The rider was implemented in the first billing cycle of October 2018 to: (a) refund $7 million over 15 months of excess federal income taxes collected from January 1, 2018 through September 30, 2018, (b) refund an ongoing estimated $655 thousand monthly from October 1, 2018 until new base rates go into effect as a result of a subsequent APSC order, (c) refund an estimated $66 million of Excess ADIT associated with certain depreciable property using ARAM and (d) refund an estimated $11 million of Excess ADIT that is not subject to rate normalization requirements over 15 months.

FERC Rate Matters

PJM Transmission Rates (Applies to AEP, APCo, I&M and OPCo)

In 2016, PJM transmission owners, including AEP’s transmission owning subsidiaries within PJM, and various state commissions filed a settlement agreement at 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 May 2018, the FERC approved the settlement agreement. PJM implemented a transmission enhancement charge adjustment through the PJM OATT, which will be billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms and has recorded $98 million to Customer Accounts Receivable and $68 million to Deferred Charges and Other Noncurrent Assets, with offsets to Regulatory Liabilities and Deferred Investment Tax Credits as of December 31, 2018.

FERC Transmission Complaint - AEP’s PJM Participants (Applies to AEP, AEPTCo, APCo, I&M and OPCo)

In 2016, seven parties filed a complaint at the FERC that alleged the base return on common equity used by AEP’s transmission owning subsidiaries within PJM in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint. In 2017, a FERC order set the matter for hearing and settlement procedures. In March 2018, AEP’s transmission owning subsidiaries within PJM and six of the complainants filed a settlement agreement with the FERC (the seventh complainant abstained). If approved by the FERC, the settlement agreement: (a) establishes a base ROE for AEP’s transmission owning subsidiaries within PJM of 9.85% (10.35% inclusive of the RTO incentive adder of 0.5%), effective January 1, 2018, (b) requires AEP’s transmission owning subsidiaries within PJM to provide a one-time refund of $50 million, attributable from the date of the complaint through December 31, 2017, which was credited to customer bills in the second quarter of 2018 and (c) increases the cap on the equity portion of the capital structure to 55% from 50%. As part of the settlement agreement, AEP’s transmission owning subsidiaries within PJM also filed updated transmission formula rates incorporating the reduction in the corporate federal income tax rate due to Tax Reform, effective January 1, 2018 and providing for the amortization of the portion of the Excess ADIT that is not subject to the normalization method of accounting, ratably over a ten-year period through credits to the federal income tax expense component of the revenue requirement. In April 2018, an ALJ accepted the interim settlement rates, which included the $50 million one-time refund that occurred in the second quarter of 2018. These interim rates are subject to refund or surcharge, with interest.

In April 2018, certain intervenors filed comments at the FERC recommending a base ROE of 8.48% and a one-time refund of $184 million. The FERC trial staff filed comments recommending a base ROE of 8.41% and a one-time refund of $175 million. Another intervenor recommended the refund be calculated in accordance with the base ROE that will ultimately be approved by the FERC. In May 2018, management filed reply comments providing further support for the 9.85% base ROE agreed to in the settlement agreement. In February 2019, the FERC issued an order that requested additional information in order to evaluate the settlement. That order did not rule on the merits of the settlement.

If the FERC orders revenue reductions in excess of the terms of the settlement agreement, it could reduce future net income and cash flows and impact financial condition.

Modifications to AEP’s PJM Transmission Rates (Applies to AEP, AEPTCo, APCo, I&M and OPCo)

In 2016, AEP’s transmission owning subsidiaries within PJM filed an application at the FERC to modify the PJM OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to projected expenses. The modified PJM OATT formula rates are based on projected calendar year financial activity and projected plant balances. In 2017, AEP’s transmission owning subsidiaries within PJM filed an uncontested settlement agreement with the FERC resolving all outstanding issues. In April 2018, the FERC approved the uncontested settlement agreement and rates were implemented effective January 1, 2018.

FERC Transmission Complaint - AEP’s SPP Participants (Applies to AEP, AEPTCo, PSO and SWEPCo)

In 2017, several parties filed a complaint at the FERC that states the base return on common equity used by AEP’s transmission owning subsidiaries within SPP in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36%, effective upon the date of the complaint through September 5, 2018. A FERC order set the matter for hearing and settlement procedures. The parties were unable to settle and the proceeding is currently in the hearing phase.

In September 2018, the same parties filed another complaint at the FERC that states the base return on common equity used by AEP’s transmission owning subsidiaries within SPP in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.71%, effective upon the date of the second complaint. A hearing at the FERC is scheduled for August 2019.

Management believes its financial statements adequately address the impact of these complaints. If the FERC orders revenue reductions as a result of these complaints, including refunds from the date of the complaint filings, it could reduce future net income and cash flows and impact financial condition.

Modifications to AEP’s SPP Transmission Rates (Applies to AEP, AEPTCo, PSO and SWEPCo)

In 2017, AEP’s transmission owning subsidiaries within SPP filed an application at the FERC to modify the SPP OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to projected expenses. The modified SPP OATT formula rates are based on projected calendar year financial activity and projected plant balances. The FERC accepted the proposed modifications effective January 1, 2018, subject to refund. In February 2019, AEP’s transmission owning subsidiaries within SPP filed an uncontested settlement agreement with the FERC, subject to FERC approval, resolving all outstanding issues. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

FERC SWEPCo Power Supply Agreements Complaint - East Texas Electric Cooperative, Inc. (ETEC) and Northeast Texas Electric Cooperative, Inc. (NTEC) (Applies to AEP and SWEPCo)

In 2017, ETEC and NTEC filed a complaint at the FERC that states the base return on common equity used by SWEPCo in calculating its power supply formula rates is excessive and should be reduced from 11.1% to 8.41%, effective upon the date of the complaint. A FERC order set the matter for hearing and settlement procedures.

In July 2018, the FERC issued an order approving a settlement agreement between SWEPCo, ETEC and NTEC that resolves the issues of the complaint. The order: (a) reduced the base return on common equity from 11.1% to 10.1% effective September 1, 2017, (b) required SWEPCo to provide a one-time billing credit of $287 thousand to reflect the decrease in return on common equity from September 1, 2017 through December 31, 2017 and (c) implemented the lower return on common equity on contracts starting January 1, 2018.