Rate Matters

3 Months Ended

Mar. 31, 2017

Rate Matters

RATE MATTERS

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

As discussed in the 2016 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2016 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2017 and updates the 2016 Annual Report.

Regulatory Assets Pending Final Regulatory Approval

	AEP
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant (a)	$	199.6	$	159.9
Storm Related Costs	24.8		25.1
Plant Retirement Costs - Materials and Supplies	9.1		9.1
Ohio Capacity Deferral	—		96.7
Other Regulatory Assets Pending Final Regulatory Approval	1.4		1.3
Regulatory Assets Currently Not Earning a Return
Cook Plant Uprate Project	36.3		36.3
Storm Related Costs	35.8		25.9
Environmental Control Projects	31.2		24.1
Plant Retirement Costs - Asset Retirement Obligation Costs	29.6		29.6
Cook Plant Turbine	13.5		12.8
Other Regulatory Assets Pending Final Regulatory Approval	29.0		29.3
Total Regulatory Assets Pending Final Regulatory Approval (b)	$	410.3	$	450.1

(a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3.

(b) As of March 31, 2017, APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction.  These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing.

	APCo
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Materials and Supplies	$	9.1	$	9.1
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs - Asset Retirement Obligation Costs	29.6		29.6
Other Regulatory Assets Pending Final Regulatory Approval	0.6		0.6
Total Regulatory Assets Pending Final Regulatory Approval (a)	$	39.3	$	39.3

(a) As of March 31, 2017, APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction.  These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing.

	I&M
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Not Earning a Return
Cook Plant Uprate Project	$	36.3	$	36.3
Cook Plant Turbine	13.5		12.8
Deferred Cook Plant Life Cycle Management Project Costs -Michigan	10.0		8.1
Rockport Dry Sorbent Injection System - Indiana	7.5		6.6
Other Regulatory Assets Pending Final Regulatory Approval	1.0		0.9
Total Regulatory Assets Pending Final Regulatory Approval	$	68.3	$	64.7

	OPCo
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Capacity Deferral	$	—	$	96.7
Regulatory Assets Currently Not Earning a Return
gridSMART® Costs	—		4.1
Total Regulatory Assets Pending Final Regulatory Approval	$	—	$	100.8

	PSO
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant (a)	$	124.2	$	84.5
Other Regulatory Assets Pending Final Regulatory Approval	0.5		0.5
Regulatory Assets Currently Not Earning a Return
Storm Related Costs	29.9		20.0
Environmental Control Projects	16.5		13.1
Total Regulatory Assets Pending Final Regulatory Approval	$	171.1	$	118.1

(a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3.

	SWEPCo
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant	$	75.4	$	75.4
Other Regulatory Assets Pending Final Regulatory Approval	0.8		0.8
Regulatory Assets Currently Not Earning a Return
Environmental Control Projects	14.7		11.0
Shipe Road Transmission Project - FERC	3.3		3.1
Asset Retirement Obligation - Arkansas, Louisiana	3.0		2.7
Rate Case Expense - Texas	1.3		1.0
Other Regulatory Assets Pending Final Regulatory Approval	2.0		1.9
Total Regulatory Assets Pending Final Regulatory Approval	$	100.5	$	95.9

If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.

AEP Texas Rate Matters (Applies to AEP)

AEP Texas Interim Transmission and Distribution Rates

As of March 31, 2017, AEP’s share of AEP Texas’ cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $581 million. A base rate review could produce a refund 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.

APCo Rate Matters (Applies to AEP and APCo)

Virginia Legislation Affecting Biennial 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 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 from 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 2016, the Virginia SCC issued an order that denied the petition of certain APCo industrial customers that requested the issuance of a declaratory order that would find the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, direct APCo to make biennial review filings beginning in 2016. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. In April 2017, oral arguments were held before 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. As of March 31, 2017, AEP’s share of ETT’s cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $636 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. 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 rates, could reduce future net income and cash flows and impact financial condition.

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

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 period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. 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 was held in March 2017.

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 Distribution Investment Rider (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, the PUCO issued orders that approved OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The orders 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 OVEC PPA and (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal. Also in 2015, OPCo subsequently filed an amended OVEC PPA application that, among other things, addressed certain PPA requirements set forth in a 2015 PUCO 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 amended DIR caps.

In 2016, the PUCO issued orders that approved a contested stipulation agreement related to the PPA rider application. Additionally, as part of these orders, the PUCO approved (a) recovery of OVEC-related net margin incurred beginning June 2016, (b) 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 (c) 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 January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC PPA and stated that the stipulation agreement approved in 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. In April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final.

In November 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 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. A hearing at the PUCO is scheduled for June 2017.

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 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.

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.

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 May 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, including those installed at the Welsh Plant, 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. As part of this filing, 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. In April 2017, various intervenors filed testimony with individual recommendations ranging from a slight net revenue reduction to a net $44 million revenue increase. The recommended return on common equity ranged from 9.2% to 9.35%. In addition, no parties recommended approval of SWEPCo’s proposed transmission cost recovery and certain parties recommended investment disallowances that could result in write-offs of up to approximately $84 million. SWEPCO continues to evaluate this intervenor testimony. Staff testimony is scheduled to be filed in May 2017. A hearing at the PUCT is scheduled for June 2017.

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.

Louisiana Turk Plant Prudence Review

Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 29%) of the Turk Plant, have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed into service in December 2012.

A hearing at the LPSC related to the Turk Plant prudence review is scheduled for September 2017. If the LPSC orders refunds based upon the pending prudence review of 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.

2017 Louisiana Formula Rate Filing

In April 2017, SWEPCo filed its formula rate plan for test year 2015 with the LPSC.  The filing included a $36 million annual increase, which will be effective May 2017 and includes Louisiana’s jurisdictional share of Welsh and Flint Creek environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review.  The $36 million 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 March 31, 2017, SWEPCo had incurred costs of $398 million, including AFUDC, and had remaining contractual construction obligations of $10 million related to these projects.  Management continues to evaluate the impact of environmental rules and related project cost estimates. As of March 31, 2017, the total net book value of Welsh Plant, Units 1 and 3 was $630 million, before cost of removal, including materials and supplies inventory and CWIP. 

In 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 base rate proceeding. In December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant, until these investments are included in base rates. The Louisiana jurisdictional share of Welsh Plant deferrals through March 31, 2017 were $11 million, excluding $6 million of unrecognized equity, subject to review by the LPSC, and include a weighted average cost of capital (WACC) return on environmental investments and the related depreciation expense and taxes. SWEPCo has sought recovery of its project costs from retail customers at the state commissions and is recovering these costs from wholesale customers through their FERC-approved agreements.

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

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

In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by various AEP affiliates in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.

Modifications to AEP East Transmission Companies Rates

In November 2016, certain AEP affiliates filed an application with 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 estimated expenses, with a proposed effective date of January 1, 2017. The filing proposed that the rates would be implemented based upon the date provided in the resulting FERC order. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017, the AEP East Transmission Companies implemented the modified PJM OATT formula rates subject to refund which are based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Appalachian Power Co [Member]

Rate Matters

RATE MATTERS

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

As discussed in the 2016 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2016 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2017 and updates the 2016 Annual Report.

Regulatory Assets Pending Final Regulatory Approval

	AEP
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant (a)	$	199.6	$	159.9
Storm Related Costs	24.8		25.1
Plant Retirement Costs - Materials and Supplies	9.1		9.1
Ohio Capacity Deferral	—		96.7
Other Regulatory Assets Pending Final Regulatory Approval	1.4		1.3
Regulatory Assets Currently Not Earning a Return
Cook Plant Uprate Project	36.3		36.3
Storm Related Costs	35.8		25.9
Environmental Control Projects	31.2		24.1
Plant Retirement Costs - Asset Retirement Obligation Costs	29.6		29.6
Cook Plant Turbine	13.5		12.8
Other Regulatory Assets Pending Final Regulatory Approval	29.0		29.3
Total Regulatory Assets Pending Final Regulatory Approval (b)	$	410.3	$	450.1

(a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3.

(b) As of March 31, 2017, APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction.  These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing.

	APCo
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Materials and Supplies	$	9.1	$	9.1
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs - Asset Retirement Obligation Costs	29.6		29.6
Other Regulatory Assets Pending Final Regulatory Approval	0.6		0.6
Total Regulatory Assets Pending Final Regulatory Approval (a)	$	39.3	$	39.3

(a) As of March 31, 2017, APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction.  These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing.

	I&M
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Not Earning a Return
Cook Plant Uprate Project	$	36.3	$	36.3
Cook Plant Turbine	13.5		12.8
Deferred Cook Plant Life Cycle Management Project Costs -Michigan	10.0		8.1
Rockport Dry Sorbent Injection System - Indiana	7.5		6.6
Other Regulatory Assets Pending Final Regulatory Approval	1.0		0.9
Total Regulatory Assets Pending Final Regulatory Approval	$	68.3	$	64.7

	OPCo
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Capacity Deferral	$	—	$	96.7
Regulatory Assets Currently Not Earning a Return
gridSMART® Costs	—		4.1
Total Regulatory Assets Pending Final Regulatory Approval	$	—	$	100.8

	PSO
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant (a)	$	124.2	$	84.5
Other Regulatory Assets Pending Final Regulatory Approval	0.5		0.5
Regulatory Assets Currently Not Earning a Return
Storm Related Costs	29.9		20.0
Environmental Control Projects	16.5		13.1
Total Regulatory Assets Pending Final Regulatory Approval	$	171.1	$	118.1

(a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3.

	SWEPCo
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant	$	75.4	$	75.4
Other Regulatory Assets Pending Final Regulatory Approval	0.8		0.8
Regulatory Assets Currently Not Earning a Return
Environmental Control Projects	14.7		11.0
Shipe Road Transmission Project - FERC	3.3		3.1
Asset Retirement Obligation - Arkansas, Louisiana	3.0		2.7
Rate Case Expense - Texas	1.3		1.0
Other Regulatory Assets Pending Final Regulatory Approval	2.0		1.9
Total Regulatory Assets Pending Final Regulatory Approval	$	100.5	$	95.9

If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.

AEP Texas Rate Matters (Applies to AEP)

AEP Texas Interim Transmission and Distribution Rates

As of March 31, 2017, AEP’s share of AEP Texas’ cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $581 million. A base rate review could produce a refund 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.

APCo Rate Matters (Applies to AEP and APCo)

Virginia Legislation Affecting Biennial 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 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 from 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 2016, the Virginia SCC issued an order that denied the petition of certain APCo industrial customers that requested the issuance of a declaratory order that would find the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, direct APCo to make biennial review filings beginning in 2016. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. In April 2017, oral arguments were held before 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. As of March 31, 2017, AEP’s share of ETT’s cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $636 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. 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 rates, could reduce future net income and cash flows and impact financial condition.

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

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 period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. 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 was held in March 2017.

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 Distribution Investment Rider (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, the PUCO issued orders that approved OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The orders 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 OVEC PPA and (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal. Also in 2015, OPCo subsequently filed an amended OVEC PPA application that, among other things, addressed certain PPA requirements set forth in a 2015 PUCO 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 amended DIR caps.

In 2016, the PUCO issued orders that approved a contested stipulation agreement related to the PPA rider application. Additionally, as part of these orders, the PUCO approved (a) recovery of OVEC-related net margin incurred beginning June 2016, (b) 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 (c) 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 January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC PPA and stated that the stipulation agreement approved in 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. In April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final.

In November 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 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. A hearing at the PUCO is scheduled for June 2017.

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 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.

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.

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 May 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, including those installed at the Welsh Plant, 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. As part of this filing, 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. In April 2017, various intervenors filed testimony with individual recommendations ranging from a slight net revenue reduction to a net $44 million revenue increase. The recommended return on common equity ranged from 9.2% to 9.35%. In addition, no parties recommended approval of SWEPCo’s proposed transmission cost recovery and certain parties recommended investment disallowances that could result in write-offs of up to approximately $84 million. SWEPCO continues to evaluate this intervenor testimony. Staff testimony is scheduled to be filed in May 2017. A hearing at the PUCT is scheduled for June 2017.

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.

Louisiana Turk Plant Prudence Review

Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 29%) of the Turk Plant, have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed into service in December 2012.

A hearing at the LPSC related to the Turk Plant prudence review is scheduled for September 2017. If the LPSC orders refunds based upon the pending prudence review of 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.

2017 Louisiana Formula Rate Filing

In April 2017, SWEPCo filed its formula rate plan for test year 2015 with the LPSC.  The filing included a $36 million annual increase, which will be effective May 2017 and includes Louisiana’s jurisdictional share of Welsh and Flint Creek environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review.  The $36 million 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 March 31, 2017, SWEPCo had incurred costs of $398 million, including AFUDC, and had remaining contractual construction obligations of $10 million related to these projects.  Management continues to evaluate the impact of environmental rules and related project cost estimates. As of March 31, 2017, the total net book value of Welsh Plant, Units 1 and 3 was $630 million, before cost of removal, including materials and supplies inventory and CWIP. 

In 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 base rate proceeding. In December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant, until these investments are included in base rates. The Louisiana jurisdictional share of Welsh Plant deferrals through March 31, 2017 were $11 million, excluding $6 million of unrecognized equity, subject to review by the LPSC, and include a weighted average cost of capital (WACC) return on environmental investments and the related depreciation expense and taxes. SWEPCo has sought recovery of its project costs from retail customers at the state commissions and is recovering these costs from wholesale customers through their FERC-approved agreements.

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

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

In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by various AEP affiliates in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.

Modifications to AEP East Transmission Companies Rates

In November 2016, certain AEP affiliates filed an application with 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 estimated expenses, with a proposed effective date of January 1, 2017. The filing proposed that the rates would be implemented based upon the date provided in the resulting FERC order. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017, the AEP East Transmission Companies implemented the modified PJM OATT formula rates subject to refund which are based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Indiana Michigan Power Co [Member]

Rate Matters

RATE MATTERS

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

As discussed in the 2016 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2016 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2017 and updates the 2016 Annual Report.

Regulatory Assets Pending Final Regulatory Approval

	AEP
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant (a)	$	199.6	$	159.9
Storm Related Costs	24.8		25.1
Plant Retirement Costs - Materials and Supplies	9.1		9.1
Ohio Capacity Deferral	—		96.7
Other Regulatory Assets Pending Final Regulatory Approval	1.4		1.3
Regulatory Assets Currently Not Earning a Return
Cook Plant Uprate Project	36.3		36.3
Storm Related Costs	35.8		25.9
Environmental Control Projects	31.2		24.1
Plant Retirement Costs - Asset Retirement Obligation Costs	29.6		29.6
Cook Plant Turbine	13.5		12.8
Other Regulatory Assets Pending Final Regulatory Approval	29.0		29.3
Total Regulatory Assets Pending Final Regulatory Approval (b)	$	410.3	$	450.1

(a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3.

(b) As of March 31, 2017, APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction.  These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing.

	APCo
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Materials and Supplies	$	9.1	$	9.1
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs - Asset Retirement Obligation Costs	29.6		29.6
Other Regulatory Assets Pending Final Regulatory Approval	0.6		0.6
Total Regulatory Assets Pending Final Regulatory Approval (a)	$	39.3	$	39.3

(a) As of March 31, 2017, APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction.  These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing.

	I&M
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Not Earning a Return
Cook Plant Uprate Project	$	36.3	$	36.3
Cook Plant Turbine	13.5		12.8
Deferred Cook Plant Life Cycle Management Project Costs -Michigan	10.0		8.1
Rockport Dry Sorbent Injection System - Indiana	7.5		6.6
Other Regulatory Assets Pending Final Regulatory Approval	1.0		0.9
Total Regulatory Assets Pending Final Regulatory Approval	$	68.3	$	64.7

	OPCo
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Capacity Deferral	$	—	$	96.7
Regulatory Assets Currently Not Earning a Return
gridSMART® Costs	—		4.1
Total Regulatory Assets Pending Final Regulatory Approval	$	—	$	100.8

	PSO
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant (a)	$	124.2	$	84.5
Other Regulatory Assets Pending Final Regulatory Approval	0.5		0.5
Regulatory Assets Currently Not Earning a Return
Storm Related Costs	29.9		20.0
Environmental Control Projects	16.5		13.1
Total Regulatory Assets Pending Final Regulatory Approval	$	171.1	$	118.1

(a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3.

	SWEPCo
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant	$	75.4	$	75.4
Other Regulatory Assets Pending Final Regulatory Approval	0.8		0.8
Regulatory Assets Currently Not Earning a Return
Environmental Control Projects	14.7		11.0
Shipe Road Transmission Project - FERC	3.3		3.1
Asset Retirement Obligation - Arkansas, Louisiana	3.0		2.7
Rate Case Expense - Texas	1.3		1.0
Other Regulatory Assets Pending Final Regulatory Approval	2.0		1.9
Total Regulatory Assets Pending Final Regulatory Approval	$	100.5	$	95.9

If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.

AEP Texas Rate Matters (Applies to AEP)

AEP Texas Interim Transmission and Distribution Rates

As of March 31, 2017, AEP’s share of AEP Texas’ cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $581 million. A base rate review could produce a refund 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.

APCo Rate Matters (Applies to AEP and APCo)

Virginia Legislation Affecting Biennial 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 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 from 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 2016, the Virginia SCC issued an order that denied the petition of certain APCo industrial customers that requested the issuance of a declaratory order that would find the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, direct APCo to make biennial review filings beginning in 2016. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. In April 2017, oral arguments were held before 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. As of March 31, 2017, AEP’s share of ETT’s cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $636 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. 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 rates, could reduce future net income and cash flows and impact financial condition.

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

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 period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. 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 was held in March 2017.

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 Distribution Investment Rider (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, the PUCO issued orders that approved OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The orders 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 OVEC PPA and (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal. Also in 2015, OPCo subsequently filed an amended OVEC PPA application that, among other things, addressed certain PPA requirements set forth in a 2015 PUCO 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 amended DIR caps.

In 2016, the PUCO issued orders that approved a contested stipulation agreement related to the PPA rider application. Additionally, as part of these orders, the PUCO approved (a) recovery of OVEC-related net margin incurred beginning June 2016, (b) 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 (c) 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 January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC PPA and stated that the stipulation agreement approved in 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. In April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final.

In November 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 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. A hearing at the PUCO is scheduled for June 2017.

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 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.

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.

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 May 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, including those installed at the Welsh Plant, 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. As part of this filing, 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. In April 2017, various intervenors filed testimony with individual recommendations ranging from a slight net revenue reduction to a net $44 million revenue increase. The recommended return on common equity ranged from 9.2% to 9.35%. In addition, no parties recommended approval of SWEPCo’s proposed transmission cost recovery and certain parties recommended investment disallowances that could result in write-offs of up to approximately $84 million. SWEPCO continues to evaluate this intervenor testimony. Staff testimony is scheduled to be filed in May 2017. A hearing at the PUCT is scheduled for June 2017.

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.

Louisiana Turk Plant Prudence Review

Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 29%) of the Turk Plant, have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed into service in December 2012.

A hearing at the LPSC related to the Turk Plant prudence review is scheduled for September 2017. If the LPSC orders refunds based upon the pending prudence review of 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.

2017 Louisiana Formula Rate Filing

In April 2017, SWEPCo filed its formula rate plan for test year 2015 with the LPSC.  The filing included a $36 million annual increase, which will be effective May 2017 and includes Louisiana’s jurisdictional share of Welsh and Flint Creek environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review.  The $36 million 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 March 31, 2017, SWEPCo had incurred costs of $398 million, including AFUDC, and had remaining contractual construction obligations of $10 million related to these projects.  Management continues to evaluate the impact of environmental rules and related project cost estimates. As of March 31, 2017, the total net book value of Welsh Plant, Units 1 and 3 was $630 million, before cost of removal, including materials and supplies inventory and CWIP. 

In 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 base rate proceeding. In December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant, until these investments are included in base rates. The Louisiana jurisdictional share of Welsh Plant deferrals through March 31, 2017 were $11 million, excluding $6 million of unrecognized equity, subject to review by the LPSC, and include a weighted average cost of capital (WACC) return on environmental investments and the related depreciation expense and taxes. SWEPCo has sought recovery of its project costs from retail customers at the state commissions and is recovering these costs from wholesale customers through their FERC-approved agreements.

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

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

In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by various AEP affiliates in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.

Modifications to AEP East Transmission Companies Rates

In November 2016, certain AEP affiliates filed an application with 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 estimated expenses, with a proposed effective date of January 1, 2017. The filing proposed that the rates would be implemented based upon the date provided in the resulting FERC order. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017, the AEP East Transmission Companies implemented the modified PJM OATT formula rates subject to refund which are based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Ohio Power Co [Member]

Rate Matters

RATE MATTERS

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

As discussed in the 2016 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2016 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2017 and updates the 2016 Annual Report.

Regulatory Assets Pending Final Regulatory Approval

	AEP
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant (a)	$	199.6	$	159.9
Storm Related Costs	24.8		25.1
Plant Retirement Costs - Materials and Supplies	9.1		9.1
Ohio Capacity Deferral	—		96.7
Other Regulatory Assets Pending Final Regulatory Approval	1.4		1.3
Regulatory Assets Currently Not Earning a Return
Cook Plant Uprate Project	36.3		36.3
Storm Related Costs	35.8		25.9
Environmental Control Projects	31.2		24.1
Plant Retirement Costs - Asset Retirement Obligation Costs	29.6		29.6
Cook Plant Turbine	13.5		12.8
Other Regulatory Assets Pending Final Regulatory Approval	29.0		29.3
Total Regulatory Assets Pending Final Regulatory Approval (b)	$	410.3	$	450.1

(a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3.

(b) As of March 31, 2017, APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction.  These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing.

	APCo
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Materials and Supplies	$	9.1	$	9.1
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs - Asset Retirement Obligation Costs	29.6		29.6
Other Regulatory Assets Pending Final Regulatory Approval	0.6		0.6
Total Regulatory Assets Pending Final Regulatory Approval (a)	$	39.3	$	39.3

(a) As of March 31, 2017, APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction.  These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing.

	I&M
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Not Earning a Return
Cook Plant Uprate Project	$	36.3	$	36.3
Cook Plant Turbine	13.5		12.8
Deferred Cook Plant Life Cycle Management Project Costs -Michigan	10.0		8.1
Rockport Dry Sorbent Injection System - Indiana	7.5		6.6
Other Regulatory Assets Pending Final Regulatory Approval	1.0		0.9
Total Regulatory Assets Pending Final Regulatory Approval	$	68.3	$	64.7

	OPCo
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Capacity Deferral	$	—	$	96.7
Regulatory Assets Currently Not Earning a Return
gridSMART® Costs	—		4.1
Total Regulatory Assets Pending Final Regulatory Approval	$	—	$	100.8

	PSO
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant (a)	$	124.2	$	84.5
Other Regulatory Assets Pending Final Regulatory Approval	0.5		0.5
Regulatory Assets Currently Not Earning a Return
Storm Related Costs	29.9		20.0
Environmental Control Projects	16.5		13.1
Total Regulatory Assets Pending Final Regulatory Approval	$	171.1	$	118.1

(a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3.

	SWEPCo
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant	$	75.4	$	75.4
Other Regulatory Assets Pending Final Regulatory Approval	0.8		0.8
Regulatory Assets Currently Not Earning a Return
Environmental Control Projects	14.7		11.0
Shipe Road Transmission Project - FERC	3.3		3.1
Asset Retirement Obligation - Arkansas, Louisiana	3.0		2.7
Rate Case Expense - Texas	1.3		1.0
Other Regulatory Assets Pending Final Regulatory Approval	2.0		1.9
Total Regulatory Assets Pending Final Regulatory Approval	$	100.5	$	95.9

If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.

AEP Texas Rate Matters (Applies to AEP)

AEP Texas Interim Transmission and Distribution Rates

As of March 31, 2017, AEP’s share of AEP Texas’ cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $581 million. A base rate review could produce a refund 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.

APCo Rate Matters (Applies to AEP and APCo)

Virginia Legislation Affecting Biennial 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 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 from 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 2016, the Virginia SCC issued an order that denied the petition of certain APCo industrial customers that requested the issuance of a declaratory order that would find the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, direct APCo to make biennial review filings beginning in 2016. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. In April 2017, oral arguments were held before 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. As of March 31, 2017, AEP’s share of ETT’s cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $636 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. 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 rates, could reduce future net income and cash flows and impact financial condition.

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

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 period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. 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 was held in March 2017.

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 Distribution Investment Rider (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, the PUCO issued orders that approved OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The orders 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 OVEC PPA and (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal. Also in 2015, OPCo subsequently filed an amended OVEC PPA application that, among other things, addressed certain PPA requirements set forth in a 2015 PUCO 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 amended DIR caps.

In 2016, the PUCO issued orders that approved a contested stipulation agreement related to the PPA rider application. Additionally, as part of these orders, the PUCO approved (a) recovery of OVEC-related net margin incurred beginning June 2016, (b) 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 (c) 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 January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC PPA and stated that the stipulation agreement approved in 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. In April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final.

In November 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 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. A hearing at the PUCO is scheduled for June 2017.

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 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.

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.

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 May 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, including those installed at the Welsh Plant, 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. As part of this filing, 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. In April 2017, various intervenors filed testimony with individual recommendations ranging from a slight net revenue reduction to a net $44 million revenue increase. The recommended return on common equity ranged from 9.2% to 9.35%. In addition, no parties recommended approval of SWEPCo’s proposed transmission cost recovery and certain parties recommended investment disallowances that could result in write-offs of up to approximately $84 million. SWEPCO continues to evaluate this intervenor testimony. Staff testimony is scheduled to be filed in May 2017. A hearing at the PUCT is scheduled for June 2017.

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.

Louisiana Turk Plant Prudence Review

Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 29%) of the Turk Plant, have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed into service in December 2012.

A hearing at the LPSC related to the Turk Plant prudence review is scheduled for September 2017. If the LPSC orders refunds based upon the pending prudence review of 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.

2017 Louisiana Formula Rate Filing

In April 2017, SWEPCo filed its formula rate plan for test year 2015 with the LPSC.  The filing included a $36 million annual increase, which will be effective May 2017 and includes Louisiana’s jurisdictional share of Welsh and Flint Creek environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review.  The $36 million 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 March 31, 2017, SWEPCo had incurred costs of $398 million, including AFUDC, and had remaining contractual construction obligations of $10 million related to these projects.  Management continues to evaluate the impact of environmental rules and related project cost estimates. As of March 31, 2017, the total net book value of Welsh Plant, Units 1 and 3 was $630 million, before cost of removal, including materials and supplies inventory and CWIP. 

In 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 base rate proceeding. In December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant, until these investments are included in base rates. The Louisiana jurisdictional share of Welsh Plant deferrals through March 31, 2017 were $11 million, excluding $6 million of unrecognized equity, subject to review by the LPSC, and include a weighted average cost of capital (WACC) return on environmental investments and the related depreciation expense and taxes. SWEPCo has sought recovery of its project costs from retail customers at the state commissions and is recovering these costs from wholesale customers through their FERC-approved agreements.

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

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

In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by various AEP affiliates in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.

Modifications to AEP East Transmission Companies Rates

In November 2016, certain AEP affiliates filed an application with 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 estimated expenses, with a proposed effective date of January 1, 2017. The filing proposed that the rates would be implemented based upon the date provided in the resulting FERC order. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017, the AEP East Transmission Companies implemented the modified PJM OATT formula rates subject to refund which are based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Public Service Co Of Oklahoma [Member]

Rate Matters

RATE MATTERS

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

As discussed in the 2016 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2016 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2017 and updates the 2016 Annual Report.

Regulatory Assets Pending Final Regulatory Approval

	AEP
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant (a)	$	199.6	$	159.9
Storm Related Costs	24.8		25.1
Plant Retirement Costs - Materials and Supplies	9.1		9.1
Ohio Capacity Deferral	—		96.7
Other Regulatory Assets Pending Final Regulatory Approval	1.4		1.3
Regulatory Assets Currently Not Earning a Return
Cook Plant Uprate Project	36.3		36.3
Storm Related Costs	35.8		25.9
Environmental Control Projects	31.2		24.1
Plant Retirement Costs - Asset Retirement Obligation Costs	29.6		29.6
Cook Plant Turbine	13.5		12.8
Other Regulatory Assets Pending Final Regulatory Approval	29.0		29.3
Total Regulatory Assets Pending Final Regulatory Approval (b)	$	410.3	$	450.1

(a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3.

(b) As of March 31, 2017, APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction.  These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing.

	APCo
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Materials and Supplies	$	9.1	$	9.1
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs - Asset Retirement Obligation Costs	29.6		29.6
Other Regulatory Assets Pending Final Regulatory Approval	0.6		0.6
Total Regulatory Assets Pending Final Regulatory Approval (a)	$	39.3	$	39.3

(a) As of March 31, 2017, APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction.  These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing.

	I&M
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Not Earning a Return
Cook Plant Uprate Project	$	36.3	$	36.3
Cook Plant Turbine	13.5		12.8
Deferred Cook Plant Life Cycle Management Project Costs -Michigan	10.0		8.1
Rockport Dry Sorbent Injection System - Indiana	7.5		6.6
Other Regulatory Assets Pending Final Regulatory Approval	1.0		0.9
Total Regulatory Assets Pending Final Regulatory Approval	$	68.3	$	64.7

	OPCo
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Capacity Deferral	$	—	$	96.7
Regulatory Assets Currently Not Earning a Return
gridSMART® Costs	—		4.1
Total Regulatory Assets Pending Final Regulatory Approval	$	—	$	100.8

	PSO
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant (a)	$	124.2	$	84.5
Other Regulatory Assets Pending Final Regulatory Approval	0.5		0.5
Regulatory Assets Currently Not Earning a Return
Storm Related Costs	29.9		20.0
Environmental Control Projects	16.5		13.1
Total Regulatory Assets Pending Final Regulatory Approval	$	171.1	$	118.1

(a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3.

	SWEPCo
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant	$	75.4	$	75.4
Other Regulatory Assets Pending Final Regulatory Approval	0.8		0.8
Regulatory Assets Currently Not Earning a Return
Environmental Control Projects	14.7		11.0
Shipe Road Transmission Project - FERC	3.3		3.1
Asset Retirement Obligation - Arkansas, Louisiana	3.0		2.7
Rate Case Expense - Texas	1.3		1.0
Other Regulatory Assets Pending Final Regulatory Approval	2.0		1.9
Total Regulatory Assets Pending Final Regulatory Approval	$	100.5	$	95.9

If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.

AEP Texas Rate Matters (Applies to AEP)

AEP Texas Interim Transmission and Distribution Rates

As of March 31, 2017, AEP’s share of AEP Texas’ cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $581 million. A base rate review could produce a refund 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.

APCo Rate Matters (Applies to AEP and APCo)

Virginia Legislation Affecting Biennial 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 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 from 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 2016, the Virginia SCC issued an order that denied the petition of certain APCo industrial customers that requested the issuance of a declaratory order that would find the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, direct APCo to make biennial review filings beginning in 2016. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. In April 2017, oral arguments were held before 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. As of March 31, 2017, AEP’s share of ETT’s cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $636 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. 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 rates, could reduce future net income and cash flows and impact financial condition.

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

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 period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. 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 was held in March 2017.

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 Distribution Investment Rider (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, the PUCO issued orders that approved OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The orders 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 OVEC PPA and (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal. Also in 2015, OPCo subsequently filed an amended OVEC PPA application that, among other things, addressed certain PPA requirements set forth in a 2015 PUCO 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 amended DIR caps.

In 2016, the PUCO issued orders that approved a contested stipulation agreement related to the PPA rider application. Additionally, as part of these orders, the PUCO approved (a) recovery of OVEC-related net margin incurred beginning June 2016, (b) 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 (c) 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 January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC PPA and stated that the stipulation agreement approved in 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. In April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final.

In November 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 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. A hearing at the PUCO is scheduled for June 2017.

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 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.

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.

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 May 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, including those installed at the Welsh Plant, 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. As part of this filing, 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. In April 2017, various intervenors filed testimony with individual recommendations ranging from a slight net revenue reduction to a net $44 million revenue increase. The recommended return on common equity ranged from 9.2% to 9.35%. In addition, no parties recommended approval of SWEPCo’s proposed transmission cost recovery and certain parties recommended investment disallowances that could result in write-offs of up to approximately $84 million. SWEPCO continues to evaluate this intervenor testimony. Staff testimony is scheduled to be filed in May 2017. A hearing at the PUCT is scheduled for June 2017.

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.

Louisiana Turk Plant Prudence Review

Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 29%) of the Turk Plant, have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed into service in December 2012.

A hearing at the LPSC related to the Turk Plant prudence review is scheduled for September 2017. If the LPSC orders refunds based upon the pending prudence review of 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.

2017 Louisiana Formula Rate Filing

In April 2017, SWEPCo filed its formula rate plan for test year 2015 with the LPSC.  The filing included a $36 million annual increase, which will be effective May 2017 and includes Louisiana’s jurisdictional share of Welsh and Flint Creek environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review.  The $36 million 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 March 31, 2017, SWEPCo had incurred costs of $398 million, including AFUDC, and had remaining contractual construction obligations of $10 million related to these projects.  Management continues to evaluate the impact of environmental rules and related project cost estimates. As of March 31, 2017, the total net book value of Welsh Plant, Units 1 and 3 was $630 million, before cost of removal, including materials and supplies inventory and CWIP. 

In 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 base rate proceeding. In December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant, until these investments are included in base rates. The Louisiana jurisdictional share of Welsh Plant deferrals through March 31, 2017 were $11 million, excluding $6 million of unrecognized equity, subject to review by the LPSC, and include a weighted average cost of capital (WACC) return on environmental investments and the related depreciation expense and taxes. SWEPCo has sought recovery of its project costs from retail customers at the state commissions and is recovering these costs from wholesale customers through their FERC-approved agreements.

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

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

In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by various AEP affiliates in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.

Modifications to AEP East Transmission Companies Rates

In November 2016, certain AEP affiliates filed an application with 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 estimated expenses, with a proposed effective date of January 1, 2017. The filing proposed that the rates would be implemented based upon the date provided in the resulting FERC order. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017, the AEP East Transmission Companies implemented the modified PJM OATT formula rates subject to refund which are based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Southwestern Electric Power Co [Member]

Rate Matters

RATE MATTERS

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

As discussed in the 2016 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2016 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2017 and updates the 2016 Annual Report.

Regulatory Assets Pending Final Regulatory Approval

	AEP
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant (a)	$	199.6	$	159.9
Storm Related Costs	24.8		25.1
Plant Retirement Costs - Materials and Supplies	9.1		9.1
Ohio Capacity Deferral	—		96.7
Other Regulatory Assets Pending Final Regulatory Approval	1.4		1.3
Regulatory Assets Currently Not Earning a Return
Cook Plant Uprate Project	36.3		36.3
Storm Related Costs	35.8		25.9
Environmental Control Projects	31.2		24.1
Plant Retirement Costs - Asset Retirement Obligation Costs	29.6		29.6
Cook Plant Turbine	13.5		12.8
Other Regulatory Assets Pending Final Regulatory Approval	29.0		29.3
Total Regulatory Assets Pending Final Regulatory Approval (b)	$	410.3	$	450.1

(a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3.

(b) As of March 31, 2017, APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction.  These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing.

	APCo
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Materials and Supplies	$	9.1	$	9.1
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs - Asset Retirement Obligation Costs	29.6		29.6
Other Regulatory Assets Pending Final Regulatory Approval	0.6		0.6
Total Regulatory Assets Pending Final Regulatory Approval (a)	$	39.3	$	39.3

(a) As of March 31, 2017, APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction.  These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing.

	I&M
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Not Earning a Return
Cook Plant Uprate Project	$	36.3	$	36.3
Cook Plant Turbine	13.5		12.8
Deferred Cook Plant Life Cycle Management Project Costs -Michigan	10.0		8.1
Rockport Dry Sorbent Injection System - Indiana	7.5		6.6
Other Regulatory Assets Pending Final Regulatory Approval	1.0		0.9
Total Regulatory Assets Pending Final Regulatory Approval	$	68.3	$	64.7

	OPCo
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Capacity Deferral	$	—	$	96.7
Regulatory Assets Currently Not Earning a Return
gridSMART® Costs	—		4.1
Total Regulatory Assets Pending Final Regulatory Approval	$	—	$	100.8

	PSO
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant (a)	$	124.2	$	84.5
Other Regulatory Assets Pending Final Regulatory Approval	0.5		0.5
Regulatory Assets Currently Not Earning a Return
Storm Related Costs	29.9		20.0
Environmental Control Projects	16.5		13.1
Total Regulatory Assets Pending Final Regulatory Approval	$	171.1	$	118.1

(a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3.

	SWEPCo
	March 31,		December 31,
	2017		2016
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant	$	75.4	$	75.4
Other Regulatory Assets Pending Final Regulatory Approval	0.8		0.8
Regulatory Assets Currently Not Earning a Return
Environmental Control Projects	14.7		11.0
Shipe Road Transmission Project - FERC	3.3		3.1
Asset Retirement Obligation - Arkansas, Louisiana	3.0		2.7
Rate Case Expense - Texas	1.3		1.0
Other Regulatory Assets Pending Final Regulatory Approval	2.0		1.9
Total Regulatory Assets Pending Final Regulatory Approval	$	100.5	$	95.9

If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.

AEP Texas Rate Matters (Applies to AEP)

AEP Texas Interim Transmission and Distribution Rates

As of March 31, 2017, AEP’s share of AEP Texas’ cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $581 million. A base rate review could produce a refund 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.

APCo Rate Matters (Applies to AEP and APCo)

Virginia Legislation Affecting Biennial 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 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 from 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 2016, the Virginia SCC issued an order that denied the petition of certain APCo industrial customers that requested the issuance of a declaratory order that would find the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, direct APCo to make biennial review filings beginning in 2016. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. In April 2017, oral arguments were held before 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. As of March 31, 2017, AEP’s share of ETT’s cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $636 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. 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 rates, could reduce future net income and cash flows and impact financial condition.

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

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 period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. 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 was held in March 2017.

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 Distribution Investment Rider (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, the PUCO issued orders that approved OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The orders 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 OVEC PPA and (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal. Also in 2015, OPCo subsequently filed an amended OVEC PPA application that, among other things, addressed certain PPA requirements set forth in a 2015 PUCO 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 amended DIR caps.

In 2016, the PUCO issued orders that approved a contested stipulation agreement related to the PPA rider application. Additionally, as part of these orders, the PUCO approved (a) recovery of OVEC-related net margin incurred beginning June 2016, (b) 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 (c) 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 January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC PPA and stated that the stipulation agreement approved in 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. In April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final.

In November 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 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. A hearing at the PUCO is scheduled for June 2017.

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 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.

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.

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 May 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, including those installed at the Welsh Plant, 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. As part of this filing, 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. In April 2017, various intervenors filed testimony with individual recommendations ranging from a slight net revenue reduction to a net $44 million revenue increase. The recommended return on common equity ranged from 9.2% to 9.35%. In addition, no parties recommended approval of SWEPCo’s proposed transmission cost recovery and certain parties recommended investment disallowances that could result in write-offs of up to approximately $84 million. SWEPCO continues to evaluate this intervenor testimony. Staff testimony is scheduled to be filed in May 2017. A hearing at the PUCT is scheduled for June 2017.

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.

Louisiana Turk Plant Prudence Review

Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 29%) of the Turk Plant, have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed into service in December 2012.

A hearing at the LPSC related to the Turk Plant prudence review is scheduled for September 2017. If the LPSC orders refunds based upon the pending prudence review of 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.

2017 Louisiana Formula Rate Filing

In April 2017, SWEPCo filed its formula rate plan for test year 2015 with the LPSC.  The filing included a $36 million annual increase, which will be effective May 2017 and includes Louisiana’s jurisdictional share of Welsh and Flint Creek environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review.  The $36 million 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 March 31, 2017, SWEPCo had incurred costs of $398 million, including AFUDC, and had remaining contractual construction obligations of $10 million related to these projects.  Management continues to evaluate the impact of environmental rules and related project cost estimates. As of March 31, 2017, the total net book value of Welsh Plant, Units 1 and 3 was $630 million, before cost of removal, including materials and supplies inventory and CWIP. 

In 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 base rate proceeding. In December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant, until these investments are included in base rates. The Louisiana jurisdictional share of Welsh Plant deferrals through March 31, 2017 were $11 million, excluding $6 million of unrecognized equity, subject to review by the LPSC, and include a weighted average cost of capital (WACC) return on environmental investments and the related depreciation expense and taxes. SWEPCo has sought recovery of its project costs from retail customers at the state commissions and is recovering these costs from wholesale customers through their FERC-approved agreements.

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

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

In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by various AEP affiliates in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.

Modifications to AEP East Transmission Companies Rates

In November 2016, certain AEP affiliates filed an application with 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 estimated expenses, with a proposed effective date of January 1, 2017. The filing proposed that the rates would be implemented based upon the date provided in the resulting FERC order. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017, the AEP East Transmission Companies implemented the modified PJM OATT formula rates subject to refund which are based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.