Rate Matters	12 Months Ended
Dec. 31, 2020
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrants’ recent significant rate orders and pending rate filings are addressed in this note. COVID-19 Pandemic During the first quarter of 2020, AEP’s electric operating companies informed both retail customers and state regulators that disconnections for non-payment were temporarily suspended. Shortly thereafter, AEP’s state regulators also imposed temporary moratoria on customary disconnection practices. During the third and the fourth quarters of 2020, most state regulators began to lift restrictions on disconnects. As of December 31, 2020, AEP had resumed disconnections in its regulated jurisdictions with the exception of Virginia, Kentucky and Arkansas. Disconnections resumed in Kentucky during January 2021. AEP continues to work with regulators and stakeholders in Virginia and Arkansas and management currently anticipates resuming customary disconnection practices in the first half of 2021. However, this timing could change if there is new legislation or other regulatory directives issued in the future. Continuing adverse economic conditions may result in the inability of customers to pay for electric service, which could affect revenue recognition and the collectability of accounts receivable. The Registrants have worked with their state commissions to achieve deferral authority for incremental expenses incurred due to COVID-19. All of AEP’s regulated jurisdictions have issued COVID-19 orders, granting deferral authority for incremental COVID-19 expenses, with the exception of Kentucky and Tennessee. If any costs related to COVID-19 are not recoverable, it could reduce future net income and cash flows and impact financial condition. AEP Texas Rate Matters (Applies to AEP and AEP Texas) 2019 Texas Base Rate Case In May 2019, AEP Texas filed a request with the PUCT for a $56 million annual increase in rates based upon a proposed 10.5% ROE. The filing included a proposed Income Tax Refund Rider that will refund $21 million annually of Excess ADIT that is primarily not subject to normalization requirements. The rate case also sought a prudence determination on all transmission and distribution capital additions through 2018 included in interim rates from 2008 to December 2019. In April 2020, the PUCT issued an order approving a stipulation and settlement agreement. The order includes an annual base rate reduction of $40 million based upon a 9.4% ROE with a capital structure of 57.5% debt and 42.5% common equity effective with the first billing cycle in June 2020. The order provides recovery of $26 million in capitalized vegetation management expenses that were incurred through 2018. The order includes disallowances of $23 million related to capital investments recorded through 2018 and $4 million related to rate case expenses. In addition, AEP Texas will refund: (a) $77 million of Excess ADIT and excess federal income taxes collected as a result of Tax Reform to distribution customers over a one year period, (b) $31 million of Excess ADIT and excess federal income taxes collected as a result of Tax Reform to transmission customers as a one-time credit and (c) $30 million of previously collected rates that were subject to reconciliation in this proceeding over a one year period with no carrying costs. The order requires AEP Texas to file its next base rate case within four years of the date that the final order was issued. The order also states future financially based capital incentives will not be included in interim transmission and distribution rates and contains various ring-fencing provisions. As a result of the final order, AEP Texas will refund $275 million of Excess ADIT associated with certain depreciable property using ARAM to transmission customers. AEP Texas will determine how to refund the remaining Excess ADIT that is not subject to normalization requirements in future proceedings. In December 2019, as a result of the initial stipulation and settlement agreement, AEP Texas (a) recorded an impairment of $33 million related to capital investments, which included $10 million of 2019 investments, in Asset Impairments and Other Related Charges on the statements of income, (b) recorded a $30 million provision for refund on the statements of income for revenues previously collected through rates and (c) wrote-off $4 million of rate case expenses to Other Operation on the statements of income. AEP Texas Interim Transmission and Distribution Rates Through December 31, 2020, AEP Texas’ cumulative revenues from interim base rate increases that are subject to review is estimated to be $79 million. A base rate review could result in a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. AEP Texas is required to file for a comprehensive rate review no later than April 3, 2024. APCo and WPCo Rate Matters (Applies to AEP and APCo) 2017-2019 Virginia Triennial Review Amendments to Virginia law impacting investor-owned utilities were enacted, effective July 1, 2018, that required APCo to file a generation and distribution base rate case by March 31, 2020 using 2017, 2018 and 2019 earnings test years (triennial review). Triennial reviews are subject to an earnings test, which provides that 70% of any earnings in excess of 70 basis points above APCo’s Virginia SCC authorized ROE would be refunded to customers. In such case, the Virginia SCC could also lower APCo’s Virginia retail base rates on a prospective basis. In November 2018, the Virginia SCC authorized a ROE of 9.42% applicable to APCo base rate earnings for the 2017-2019 triennial period. Virginia law provides that costs associated with asset impairments of retired coal generation assets, or automated meters, or both, which a utility records as an expense, shall be attributed to the test periods under review in a triennial review proceeding, and be deemed recovered. In 2015, APCo retired the Sporn Plant, the Kanawha River Plant, the Glen Lyn Plant, Clinch River Unit 3 and the coal portions of Clinch River Units 1 and 2 (collectively, the retired coal-fired generation assets). The net book value of the Virginia jurisdictional share of these plants was $93 million before cost of removal, including materials and supplies inventory and ARO balances. Based on management’s interpretation of Virginia law and more certainty regarding APCo’s triennial revenues, expenses and resulting earnings upon reaching the end of the three-year review period, APCo recorded a pretax expense of $93 million related to its previously retired coal-fired generation assets in December 2019. As a result, management deemed these costs to be substantially recovered by APCo during the triennial review period. In March 2020, APCo submitted its 2017-2019 Virginia triennial earnings review filing and base rate case with the Virginia SCC as required by state law. APCo requested a $65 million annual increase in base rates based upon a proposed 9.9% ROE. The requested annual increase included $19 million related to depreciation for updated test year end depreciable balances and a proposed increase in APCo’s Virginia depreciation rates and $8 million related to APCo’s calculated shortfall in 2017-2019 Virginia earnings. Inclusive of the Virginia jurisdictional share of the $93 million expense associated with APCo’s retired coal-fired generation assets, APCo calculated its 2017-2019 Virginia earnings for the triennial period to be below the authorized ROE range. APCo is currently in the process of retiring and replacing its Virginia jurisdictional Automated Meter Reading (AMR) meters with AMI meters. As of December 31, 2020 and 2019, APCo had approximately $35 million and $51 million of Virginia jurisdictional AMR meters as well as $73 million and $75 million of Virginia jurisdictional AMI meters recorded on its balance sheets. APCo pursued full recovery of these assets through its Virginia depreciation rates as discussed above. In November 2020, the Virginia SCC issued an order concluding that APCo earned above its authorized ROE but within its ROE band for the 2017-2019 period, resulting in no refund to customers and no change to APCo base rates on a prospective basis. The Virginia SCC approved a prospective 9.2% ROE for APCo's 2020-2022 triennial review period with the continuation of a 140 basis point band (8.5% bottom, 9.2% midpoint, 9.9% top). This 9.2% authorized ROE will also be applied to certain APCo rate adjustment clauses. APCo’s earnings for the 2020-2022 triennial review will continue to be subject to an earnings test, which provides that 70% of any earnings in excess of 70 basis points above APCo’s Virginia SCC authorized ROE would be refunded to customers. Conversely, as defined by Virginia law, APCo is also eligible to defer for future recovery certain environmental and major storm operation and maintenance expenses up to the bottom of APCo’s authorized Virginia 2020-2022 earnings ROE band. The Virginia SCC also disagreed with APCo’s treatment of the retired coal-fired generation assets for regulatory purposes, and instead adopted the Virginia SCC Staff’s recommendation to treat the remaining unrecovered costs of the retired coal-fired generation assets as a regulatory asset to be amortized over 10 years as of the June 2015 retirement date. The Virginia SCC’s adoption of the Staff’s recommended regulatory treatment of the coal-fired generation assets resulted in a net $40 million increase to APCo’s 2020 pretax income. In addition, the Virginia SCC’s order also included: (a) implementation of the Staff-modified APCo 2017 depreciation study effective January 1, 2018 and (b) implementation of the Staff-modified APCo 2019 depreciation study effective January 1, 2020. The adoption of these depreciation studies resulted in an approximate $47 million reduction to APCo’s 2020 pretax income comprised of a $44 million reduction to revenues for amounts recognized in advance of the recording of depreciation expense for the periods January 2018 through October 2020 and a $3 million increase in depreciation expense for the periods November and December 2020. A corresponding regulatory liability was recorded for the $44 million reduction to revenues. The Virginia SCC’s approval of APCo’s 2019 depreciation study included the ongoing depreciation and recovery of APCo’s Virginia AMI/AMR meter balances. In November 2020, APCo filed a notice of appeal with the Virginia Supreme Court. In December 2020, an intervenor filed a petition at the Virginia SCC requesting reconsideration of: (a) the failure of the Virginia SCC to apply a threshold earnings test to the approved regulatory asset for APCo’s closed coal-fired generation assets, (b) the Virginia SCC’s use of a 2011 benchmark study to measure the replacement value of capacity for purposes of APCo’s 2017 – 2019 earnings test and (c) the reasonableness and prudency of APCo’s investments in AMI meters. In December 2020, APCo filed a petition at the Virginia SCC requesting reconsideration of: (a) certain issues related to APCo’s going-forward rates and (b) the Virginia SCC’s decision to deny APCo tariff changes that align rates with underlying costs. For APCo’s going-forward rates, APCo requested that the Virginia SCC clarify its final order and whether APCo’s current rates will allow it to earn a fair return. If the Virginia SCC’s order did conclude on APCo’s ability to earn a fair return through existing base rates, APCo further requested that the Virginia SCC clarify whether it has the authority to also permit an increase in base rates. If the Virginia SCC did not conclude on APCo’s ability to earn a fair return, APCo requested the Virginia SCC provide such a conclusion. In January 2021, as requested by the Virginia SCC, APCo filed briefs related to the petition for reconsideration. If the Virginia SCC issues an unfavorable ruling related to the intervenor petition, it could reduce future net income and cash flows and impact financial condition. West Virginia ENEC and Vegetation Management Riders In June 2020, the WVPSC issued an order directing APCo and WPCo to increase rider rates relating to ENEC and vegetation management by a combined $101 million ($81 million related to APCo) over twelve months beginning September 2020. This increase will be partially offset by a refund of $38 million ($31 million related to APCo) of Excess ADIT that is not subject to normalization requirements over ten months beginning September 2020. These transactions will result in no overall impact to net income. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates AEP has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next base rate proceeding. Through December 31, 2020, AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $1.2 billion. A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. In 2018, the PUCT adopted a rule requiring investor-owned utilities operating solely inside ERCOT to make periodic filings for base rate proceedings. The rule required ETT to file for a comprehensive base rate review no later than February 1, 2021. In December 2020, ETT and various intervenors filed a stipulation and settlement agreement with the PUCT. The agreement maintained ETT’s previously allowed ROE and capital structure and includes: (a) an $8 million decrease to the current annual revenue requirement effective February 1, 2021, (b) ETT must make an interim transmission cost of service filing by April 1, 2021, (c) a $2 million line item decrease to the revenue requirement determined in each interim transmission cost of service filing until the filing of the next comprehensive base rate review and (d) no determination of prudence on any transmission investment added since ETT’s last comprehensive base rate review, which would leave the $1.2 billion of cumulative revenues above subject to review in the next comprehensive base rate review. In January 2021, the PUCT approved the stipulation and settlement agreement. As part of the approved agreement, new rates were implemented in February 2021 and ETT is required to file for a comprehensive base rate review no later than February 1, 2023. I&M Rate Matters (Applies to AEP and I&M) 2019 Indiana Base Rate Case In May 2019, I&M filed a request with the IURC for a $172 million annual increase. The requested increase in Indiana rates would be phased-in through January 2021 and was based upon a proposed 10.5% ROE. The proposed annual increase included $78 million related to a proposed annual increase in depreciation expense. The requested annual increase in depreciation expense included $52 million related to proposed investments and $26 million related to increased depreciation rates. The request included the continuation of all existing riders and a new AMI rider for proposed meter projects. In March 2020, the IURC issued an order approving a phased-in increase in base rates of up to $77 million based upon an ROE of 9.7%. This approved phase-in increase includes: (a) an annual increase in base rates of $44 million effective March 2020 and (b) an annual increase in base rates of up to $77 million, effective January 2021, based on the IURC-approved forecast of December 31, 2020 Indiana jurisdictional electric plant in service. In January 2021, I&M updated its Indiana retail rates with the IURC based on actual December 31, 2020 I&M Indiana jurisdictional electric plant in service, resulting in a $60 million net annual base rate increase when compared to I&M Indiana base rate levels prior to March 2020. The order also approved the majority of I&M’s proposed changes in depreciation as well as the test year level of AMI deployment, but did not approve a cost recovery rider for AMI investments made in subsequent years. The order rejected I&M’s proposed re-allocation of capacity costs related to the loss of a significant FERC wholesale contract, which negatively impacts I&M’s annual pretax earnings by approximately $20 million starting June 2020. KPCo Rate Matters (Applies to AEP) 2020 Kentucky Base Rate Case In June 2020, KPCo filed a request with the KPSC for a $65 million net annual increase in base rates based upon a proposed 10% ROE with the increase to be implemented no earlier than January 2021. The filing proposes that KPCo would offset the first year of rate increases by refunding Excess ADIT that is not subject to normalization requirements to customers. Additionally, KPCo requested recovery of the previously authorized deferral of $50 million of Rockport Plant UPA expenses and related carrying charges over a 5-year period beginning in December 2022, through an existing purchased power rider. In January 2021, the KPSC issued an order approving an annual increase in base rates of $52 million based upon an ROE of 9.3% effective with billing cycles mid-January 2021. The order shortened the previously authorized refund period for Excess ADIT that is not subject to normalization requirements being refunded through a rider from 18 years to 3 years. In addition, the order approved recovery of certain annual PJM OATT expenses above/below the corresponding level recovered in base rates through a rider until KPCo’s next base case; however, recovery of these transmission costs will be re-examined by the KPSC in KPCo’s next base case. The KPSC deferred KPCo’s request to authorize a specific recovery period and mechanism for the previously authorized deferral of $50 million of Rockport Plant UPA expenses and related carrying charges to a future proceeding. The order requires KPCo to submit its next base case in June 2023 for rates effective in January 2024. In February 2021, KPCo filed for rehearing with the KPSC challenging various adjustments that were made in the order and requesting certain clarifications. Also in February 2021, the KPSC issued an order on rehearing that modified the approved annual increase in base rates from $52 million to $53 million and clarified several items, including the timing of the future proceeding to address a specific recovery period and mechanism for the previously authorized deferral of $50 million of Rockport Plant Unit Power Agreement expenses and related carrying charges. The KPSC will initiate a future proceeding to address a specific recovery period and mechanism for the deferral after KPCo makes a written filing identifying the capacity replacement for the Rockport Unit Power Agreement, including the name of the capacity resource and related reasonably anticipated costs. OPCo Rate Matters (Applies to AEP and OPCo) 2020 Ohio Base Rate Case In June 2020, OPCo filed a request with the PUCO for a $42 million annual increase in base rates based upon a proposed 10.15% ROE net of existing riders. Additionally, OPCo filed a request with the PUCO for a 60-day temporary delay of the normal rate case proceeding due to the COVID-19 pandemic with rates expected to be effective approximately mid-2021. In November 2020, PUCO staff filed testimony supporting an annual revenue decrease ranging from $102 million to $123 million based upon an ROE of 8.76% to 9.78%. The difference between OPCo’s request and the staff testimony are primarily due to reductions in: (a) demand-side management programs of $40 million, (b) ROE ranging from $9 million to $30 million, (c) employee-related expenses of $23 million, (d) rate base of $19 million, (e) property taxes of $17 million, (f) other various expenses of $15 million, (g) depreciation expense of $11 million and (h) vegetation management programs of $10 million which is subject to over/under-recovery through a rider. The staff’s proposed disallowance of plant in service could also result in a write-off of up to $27 million. In addition, the staff recommended that capitalized incentives be excluded from base rates prospectively and also recommended annual revenue caps for the DIR of $57 million in 2021, $78 million in 2022, $96 million in 2023 and $46 million for the first five months of 2024. In December 2020, OPCo and intervenors filed objections. A procedural schedule for the case is pending due to ongoing settlement discussions. If any of the requested costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2019 Ohio DIR Audit OPCo conducts business under an ESP as approved by the PUCO which subjects the DIR to annual audits. In August 2020, a third-party consulting company filed an audit report with the PUCO indicating that OPCo exceeded its 2019 authorized revenue limit by $17 million. Management disagrees with the audit results and believes that OPCo was below its authorized revenue limit in 2019. The PUCO has not yet issued a procedural schedule to address the audit results. If the results of the audit are upheld by the PUCO and any refunds to customers or revenue reductions are ordered, 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. Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, SWEPCo reversed $114 million of a previously recorded regulatory disallowance in 2013. The resulting annual base rate increase was approximately $52 million. In 2017, the Texas District Court upheld the PUCT’s 2014 order and intervenors filed appeals with the Texas Third Court of Appeals. In July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court. In the fourth quarter of 2019 and first quarter of 2020, SWEPCo and various intervenors filed briefs with the Texas Supreme Court. In August 2020, the Texas Supreme Court granted SWEPCo’s petition for review and oral arguments were held in December 2020. SWEPCo expects a decision from the Texas Supreme Court in 2021. As of December 31, 2020, the net book value of Turk Plant was $1.4 billion, before cost of removal, including materials and supplies inventory and CWIP. If certain parts of the PUCT order are overturned and if SWEPCo cannot ultimately fully recover its approximate 33% Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition. 2016 Texas Base Rate Case In 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% ROE. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a ROE of 9.6%, effective May 2017. The final order also included: (a) approval to recover the Texas jurisdictional share of environmental investments placed in- service, as of June 30, 2016, at various plants, including Welsh Plant, Units 1 and 3, (b) approval of recovery of, but no return on, the Texas jurisdictional share of the net book value of Welsh Plant, Unit 2, (c) approval of $2 million in additional vegetation management expenses and (d) the rejection of SWEPCo’s proposed transmission cost recovery mechanism. As a result of the final order, in 2017 SWEPCo: (a) recorded an impairment charge of $19 million, which included $7 million associated with the lack of return on Welsh Plant, Unit 2 and $12 million related to other disallowed plant investments, (b) recognized $32 million of additional revenues, for the period of May 2017 through December 2017, that was surcharged to customers in 2018 and (c) recognized an additional $7 million of expenses consisting primarily of depreciation expense and vegetation management expense, offset by the deferral of rate case expense. SWEPCo implemented new rates in February 2018 billings. The $32 million of additional 2017 revenues was collected during 2018. In March 2018, the PUCT clarified and corrected portions of the final order, without changing the overall decision or amounts of the rate change. The order has been appealed by various intervenors. If certain parts of the PUCT order are overturned, it could reduce future net income and cash flows and impact financial condition. 2018 Louisiana Formula Rate Filing In April 2018, SWEPCo filed its formula rate plan for test year 2017 with the LPSC. The filing included a net $28 million annual increase, which was effective August 2018 and included SWEPCo’s Louisiana jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls. The filing also included a reduction in the federal income tax rate due to Tax Reform but did not address the return of Excess ADIT benefits to customers. In July 2018, SWEPCo made a supplemental filing to its formula rate plan with the LPSC to reduce the requested annual increase to $18 million. The difference between SWEPCo’s requested $28 million annual increase and the $18 million annual increase in the supplemental filing is primarily the result of the return of Excess ADIT benefits to customers. In October 2018, the LPSC staff issued a recommendation that SWEPCo refund $11 million of excess federal income taxes collected, as a result of Tax Reform, from January 1, 2018 through July 31, 2018. In June 2019, the LPSC staff issued its report which reaffirmed its $11 million refund recommendation. The report also contends that SWEPCo’s requested annual rate increase of $18 million, which was implemented in August 2018, is overstated by $4 million and proposes an annual rate increase of $14 million. Additionally, the report recommends SWEPCo refund the excess over-collections associated with the $4 million difference for the period of August 2018 through the implementation of new rates. In July 2019, the LPSC approved the $11 million refund. In July 2020, the LPSC issued an order approving an unopposed stipulation and settlement agreement for a one-time refund of $6 million over three months beginning in August 2020. Hurricane Laura In August 2020, Hurricane Laura hit the coasts of Louisiana and Texas, causing power outages to more than 130,000 customers across SWEPCo’s service territories. Prior to Hurricane Laura, SWEPCo did not have a catastrophe reserve or automatic deferral authority within any of its jurisdictions. In October 2020, the LPSC issued an order allowing Louisiana utilities, including SWEPCo, to establish a regulatory asset to track and defer expenses associated with Hurricane Laura. In October 2020, as part of the 2020 Texas Base Rate Case, SWEPCo requested deferral authority of incremental other operation and maintenance expenses. As of December 31, 2020, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $84 million ($82 million of which has been deferred as a regulatory asset related to the Louisiana jurisdiction) and incremental capital expenditures of $23 million, all of which is related to the Louisiana jurisdiction. If any costs related to Hurricane Laura are not recoverable, it could reduce future net income and cash flows and impact financial condition. Hurricane Delta In October 2020, Hurricane Delta hit the coast of Louisiana, causing power outages to more than 23,000 customers in SWEPCo’s Louisiana jurisdiction. In November 2020, the LPSC issued an order allowing Louisiana utilities, including SWEPCo, to establish a regulatory asset to track and defer expenses associated with Hurricane Delta. As of December 31, 2020, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $17 million, which has been deferred as a regulatory asset. Also, management estimates that SWEPCo has incurred incremental capital expenditures of $2 million. If any costs related to Hurricane Delta are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2020 Texas Base Rate Case In October 2020, SWEPCo filed a request with the PUCT for a $105 million annual increase in Texas base rates based upon a proposed 10.35% ROE. The request would move transmission and distribution interim revenues recovered through riders into base rates. Eliminating these riders would result in a net annual requested base rate increase of $90 million primarily due to increased investments. The proposed net annual increase: (a) includes $5 million related to vegetation management to maintain and improve the reliability of its Texas jurisdictional distribution system, (b) requests a $10 million annual depreciation increase and (c) seeks $2 million annually to establish a storm catastrophe reserve. In addition, SWEPCo also requested recovery of the Texas jurisdictional share of the Dolet Hills Power Station of $45 million which is expected to be retired by the end of 2021. Intervenor and staff testimony is scheduled to be filed in March and April 2021, respectively. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2020 Louisiana Base Rate Case In December 2020, SWEPCo filed a request with the LPSC for a $134 million annual increase in Louisiana base rates based upon a proposed 10.35% ROE. The request would extend the formula rate plan for five years and includes modifications to the formula rate plan to allow for forward-looking transmission costs, reflects the impact of net operating losses associated with the acceleration of certain tax benefits and incorporates future federal corporate income tax changes. The proposed net annual increase: (a) requests a $32 million annual depreciation increase to recover Louisiana’s share of the Dolet Hills Power Station, Pirkey Power Plant and Welsh Plant, all of which are expected to be retired early, and (b) includes $10 million annually to recover deferred other operation and maintenance expenses related to Hurricanes Laura and Delta. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. FERC Rate Matters AFUDC Waiver (Applies to all Registrants except AEP Texas) In June 2020, FERC granted a temporary waiver providing utilities the option to elect to modify the existing AFUDC rate calculations in response to the COVID-19 pandemic. As a result of the waiver, the AFUDC formula for the 12-month period starting with March 2020 may be calculated using the simple average of the actual historical short-term debt balances for 2019, instead of current period short-term balances. All other aspects of the AFUDC formula remained unchanged. AEP subsidiaries including certain Registrant Subsidiaries elected to apply the waiver in July 2020. The impact upon election was immaterial on the Registrants’ financial statements. In February 2021, FERC issued an order extending the waiver through September 2021. OKTCo Radial Asset Transfer (Applies to AEP, AEPTCo and PSO) In August 2020, AEPSC filed a request with FERC, on behalf of PSO and OKTCo, to transfer OKTCo’s interests in its radial assets to PSO. OKTCo had previously constructed radial assets in the PSO service territory and after the radial assets were placed into service, management determined the radial assets were not eligible to be included as part of OKTCo’s SPP OATT formula rates. In October 2020, FERC approved the request and in December 2020, OKTCo completed the transfer of its interest in the radial assets to PSO, through Parent, at net book value. At the transfer date, the net book value of the radial assets were $60 million, before associated tax liabilities. PSO will seek recovery of the radial assets in its next base rate case, which must be filed by October 2021. If PSO does not receive approval to recover the radial assets, it could reduce future net income and cash flows and impact financial condition.

During the first quarter of 2020, AEP’s electric operating companies informed both retail customers and state regulators that disconnections for non-payment were temporarily suspended. Shortly thereafter, AEP’s state regulators also imposed temporary moratoria on customary disconnection practices. During the third and the fourth quarters of 2020, most state regulators began to lift restrictions on disconnects. As of December 31, 2020, AEP had resumed disconnections in its regulated jurisdictions with the exception of Virginia, Kentucky and Arkansas. Disconnections resumed in Kentucky during January 2021. AEP continues to work with regulators and stakeholders in Virginia and Arkansas and management currently anticipates resuming customary disconnection practices in the first half of 2021. However, this timing could change if there is new legislation or other regulatory directives issued in the future. Continuing adverse economic conditions may result in the inability of customers to pay for electric service, which could affect revenue recognition and the collectability of accounts receivable. The Registrants have worked with their state commissions to achieve deferral authority for incremental expenses incurred due to COVID-19. All of AEP’s regulated jurisdictions have issued COVID-19 orders, granting deferral authority for incremental COVID-19 expenses, with the exception of Kentucky and Tennessee. If any costs related to COVID-19 are not recoverable, it could reduce future net income and cash flows and impact financial condition.

In April 2020, the PUCT issued an order approving a stipulation and settlement agreement. The order includes an annual base rate reduction of $40 million based upon a 9.4% ROE with a capital structure of 57.5% debt and 42.5% common equity effective with the first billing cycle in June 2020. The order provides recovery of $26 million in capitalized vegetation management expenses that were incurred through 2018. The order includes disallowances of $23 million related to capital investments recorded through 2018 and $4 million related to rate case expenses. In addition, AEP Texas will refund: (a) $77 million of Excess ADIT and excess federal income taxes collected as a result of Tax Reform to distribution customers over a one year period, (b) $31 million of Excess ADIT and excess federal income taxes collected as a result of Tax Reform to transmission customers as a one-time credit and (c) $30 million of previously collected rates that were subject to reconciliation in this proceeding over a one year period with no carrying costs. The order requires AEP Texas to file its next base rate case within four years of the date that the final order was issued. The order also states future financially based capital incentives will not be included in interim transmission and distribution rates and contains various ring-fencing provisions. As a result of the final order, AEP Texas will refund $275 million of Excess ADIT associated with certain depreciable property using ARAM to transmission customers. AEP Texas will determine how to refund the remaining Excess ADIT that is not subject to normalization requirements in future proceedings.

In December 2019, as a result of the initial stipulation and settlement agreement, AEP Texas (a) recorded an impairment of $33 million related to capital investments, which included $10 million of 2019 investments, in Asset Impairments and Other Related Charges on the statements of income, (b) recorded a $30 million provision for refund on the statements of income for revenues previously collected through rates and (c) wrote-off $4 million of rate case expenses to Other Operation on the statements of income.

Through December 31, 2020, AEP Texas’ cumulative revenues from interim base rate increases that are subject to review is estimated to be $79 million. A base rate review could result in a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. AEP Texas is required to file for a comprehensive rate review no later than April 3, 2024.

Amendments to Virginia law impacting investor-owned utilities were enacted, effective July 1, 2018, that required APCo to file a generation and distribution base rate case by March 31, 2020 using 2017, 2018 and 2019 earnings test years (triennial review). Triennial reviews are subject to an earnings test, which provides that 70% of any earnings in excess of 70 basis points above APCo’s Virginia SCC authorized ROE would be refunded to customers. In such case, the Virginia SCC could also lower APCo’s Virginia retail base rates on a prospective basis. In November 2018, the Virginia SCC authorized a ROE of 9.42% applicable to APCo base rate earnings for the 2017-2019 triennial period.

Virginia law provides that costs associated with asset impairments of retired coal generation assets, or automated meters, or both, which a utility records as an expense, shall be attributed to the test periods under review in a triennial review proceeding, and be deemed recovered. In 2015, APCo retired the Sporn Plant, the Kanawha River Plant, the Glen Lyn Plant, Clinch River Unit 3 and the coal portions of Clinch River Units 1 and 2 (collectively, the retired coal-fired generation assets). The net book value of the Virginia jurisdictional share of these plants was $93 million before cost of removal, including materials and supplies inventory and ARO balances. Based on management’s interpretation of Virginia law and more certainty regarding APCo’s triennial revenues, expenses and resulting earnings upon reaching the end of the three-year review period, APCo recorded a pretax expense of $93 million related to its previously retired coal-fired generation assets in December 2019. As a result, management deemed these costs to be substantially recovered by APCo during the triennial review period.

In March 2020, APCo submitted its 2017-2019 Virginia triennial earnings review filing and base rate case with the Virginia SCC as required by state law. APCo requested a $65 million annual increase in base rates based upon a proposed 9.9% ROE. The requested annual increase included $19 million related to depreciation for updated test year end depreciable balances and a proposed increase in APCo’s Virginia depreciation rates and $8 million related to APCo’s calculated shortfall in 2017-2019 Virginia earnings. Inclusive of the Virginia jurisdictional share of the $93 million expense associated with APCo’s retired coal-fired generation assets, APCo calculated its 2017-2019 Virginia earnings for the triennial period to be below the authorized ROE range.

In November 2020, the Virginia SCC issued an order concluding that APCo earned above its authorized ROE but within its ROE band for the 2017-2019 period, resulting in no refund to customers and no change to APCo base rates on a prospective basis. The Virginia SCC approved a prospective 9.2% ROE for APCo's 2020-2022 triennial review period with the continuation of a 140 basis point band (8.5% bottom, 9.2% midpoint, 9.9% top). This 9.2% authorized ROE will also be applied to certain APCo rate adjustment clauses. APCo’s earnings for the 2020-2022 triennial review will continue to be subject to an earnings test, which provides that 70% of any earnings in excess of 70 basis points above APCo’s Virginia SCC authorized ROE would be refunded to customers. Conversely, as defined by Virginia law, APCo is also eligible to defer for future recovery certain environmental and major storm operation and maintenance expenses up to the bottom of APCo’s authorized Virginia 2020-2022 earnings ROE band. The Virginia SCC also disagreed with APCo’s treatment of the retired coal-fired generation assets for regulatory purposes, and instead adopted the Virginia SCC Staff’s recommendation to treat the remaining unrecovered costs of the retired coal-fired generation assets as a regulatory asset to be amortized over 10 years as of the June 2015 retirement date. The Virginia SCC’s adoption of the Staff’s recommended regulatory treatment of the coal-fired generation assets resulted in a net $40 million increase to APCo’s 2020 pretax income. In addition, the Virginia SCC’s order also included: (a) implementation of the Staff-modified APCo 2017 depreciation study effective January 1, 2018 and (b) implementation of the Staff-modified APCo 2019 depreciation study effective January 1, 2020. The adoption of these depreciation studies resulted in an approximate $47 million reduction to APCo’s 2020 pretax income comprised of a $44 million reduction to revenues for amounts recognized in advance of the recording of depreciation expense for the periods January 2018 through October 2020 and a $3 million increase in depreciation expense for the periods November and December 2020. A corresponding regulatory liability was recorded for the $44 million reduction to revenues. The Virginia SCC’s approval of APCo’s 2019 depreciation study included the ongoing depreciation and recovery of APCo’s Virginia AMI/AMR meter balances. In November 2020, APCo filed a notice of appeal with the Virginia Supreme Court.

In December 2020, APCo filed a petition at the Virginia SCC requesting reconsideration of: (a) certain issues related to APCo’s going-forward rates and (b) the Virginia SCC’s decision to deny APCo tariff changes that align rates with underlying costs. For APCo’s going-forward rates, APCo requested that the Virginia SCC clarify its final order and whether APCo’s current rates will allow it to earn a fair return. If the Virginia SCC’s order did conclude on APCo’s ability to earn a fair return through existing base rates, APCo further requested that the Virginia SCC clarify whether it has the authority to also permit an increase in base rates. If the Virginia SCC did not conclude on APCo’s ability to earn a fair return, APCo requested the Virginia SCC provide such a conclusion. In January 2021, as requested by the Virginia SCC, APCo filed briefs related to the petition for reconsideration.

AEP has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next base rate proceeding. Through December 31, 2020, AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $1.2 billion. A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring.

In 2018, the PUCT adopted a rule requiring investor-owned utilities operating solely inside ERCOT to make periodic filings for base rate proceedings. The rule required ETT to file for a comprehensive base rate review no later than February 1, 2021. In December 2020, ETT and various intervenors filed a stipulation and settlement agreement with the PUCT. The agreement maintained ETT’s previously allowed ROE and capital structure and includes: (a) an $8 million decrease to the current annual revenue requirement effective February 1, 2021, (b) ETT must make an interim transmission cost of service filing by April 1, 2021, (c) a $2 million line item decrease to the revenue requirement determined in each interim transmission cost of service filing until the filing of the next comprehensive base rate review and (d) no determination of prudence on any transmission investment added since ETT’s last comprehensive base rate review, which would leave the $1.2 billion of cumulative revenues above subject to review in the next comprehensive base rate review. In January 2021, the PUCT approved the stipulation and settlement agreement. As part of the approved agreement, new rates were implemented in February 2021 and ETT is required to file for a comprehensive base rate review no later than February 1, 2023.

In May 2019, I&M filed a request with the IURC for a $172 million annual increase. The requested increase in Indiana rates would be phased-in through January 2021 and was based upon a proposed 10.5% ROE. The proposed annual increase included $78 million related to a proposed annual increase in depreciation expense. The requested annual increase in depreciation expense included $52 million related to proposed investments and $26 million related to increased depreciation rates. The request included the continuation of all existing riders and a new AMI rider for proposed meter projects.

In March 2020, the IURC issued an order approving a phased-in increase in base rates of up to $77 million based upon an ROE of 9.7%. This approved phase-in increase includes: (a) an annual increase in base rates of $44 million effective March 2020 and (b) an annual increase in base rates of up to $77 million, effective January 2021, based on the IURC-approved forecast of December 31, 2020 Indiana jurisdictional electric plant in service. In January 2021, I&M updated its Indiana retail rates with the IURC based on actual December 31, 2020 I&M Indiana jurisdictional electric plant in service, resulting in a $60 million net annual base rate increase when compared to I&M Indiana base rate levels prior to March 2020. The order also approved the majority of I&M’s proposed changes in depreciation as well as the test year level of AMI deployment, but did not approve a cost recovery rider for AMI investments made in subsequent years. The order rejected I&M’s proposed re-allocation of capacity costs related to the loss of a significant FERC wholesale contract, which negatively impacts I&M’s annual pretax earnings by approximately $20 million starting June 2020.

In June 2020, KPCo filed a request with the KPSC for a $65 million net annual increase in base rates based upon a proposed 10% ROE with the increase to be implemented no earlier than January 2021. The filing proposes that KPCo would offset the first year of rate increases by refunding Excess ADIT that is not subject to normalization requirements to customers. Additionally, KPCo requested recovery of the previously authorized deferral of $50 million of Rockport Plant UPA expenses and related carrying charges over a 5-year period beginning in December 2022, through an existing purchased power rider.

In January 2021, the KPSC issued an order approving an annual increase in base rates of $52 million based upon an ROE of 9.3% effective with billing cycles mid-January 2021. The order shortened the previously authorized refund period for Excess ADIT that is not subject to normalization requirements being refunded through a rider from 18 years to 3 years. In addition, the order approved recovery of certain annual PJM OATT expenses above/below the corresponding level recovered in base rates through a rider until KPCo’s next base case; however, recovery of these transmission costs will be re-examined by the KPSC in KPCo’s next base case. The KPSC deferred KPCo’s request to authorize a specific recovery period and mechanism for the previously authorized deferral of $50 million of Rockport Plant UPA expenses and related carrying charges to a future proceeding. The order requires KPCo to submit its next base case in June 2023 for rates effective in January 2024.

In February 2021, KPCo filed for rehearing with the KPSC challenging various adjustments that were made in the order and requesting certain clarifications. Also in February 2021, the KPSC issued an order on rehearing that modified the approved annual increase in base rates from $52 million to $53 million and clarified several items, including the timing of the future proceeding to address a specific recovery period and mechanism for the previously authorized deferral of $50 million of Rockport Plant Unit Power Agreement expenses and related carrying charges. The KPSC will initiate a future proceeding to address a specific recovery period and mechanism for the deferral after KPCo makes a written filing identifying the capacity replacement for the Rockport Unit Power Agreement, including the name of the capacity resource and related reasonably anticipated costs.

In November 2020, PUCO staff filed testimony supporting an annual revenue decrease ranging from $102 million to $123 million based upon an ROE of 8.76% to 9.78%. The difference between OPCo’s request and the staff testimony are primarily due to reductions in: (a) demand-side management programs of $40 million, (b) ROE ranging from $9 million to $30 million, (c) employee-related expenses of $23 million, (d) rate base of $19 million, (e) property taxes of $17 million, (f) other various expenses of $15 million, (g) depreciation expense of $11 million and (h) vegetation management programs of $10 million which is subject to over/under-recovery through a rider. The staff’s proposed disallowance of plant in service could also result in a write-off of up to $27 million. In addition, the staff recommended that capitalized incentives be excluded from base rates prospectively and also recommended annual revenue caps for the DIR of $57 million in 2021, $78 million in 2022, $96 million in 2023 and $46 million for the first five months of 2024. In December 2020, OPCo and intervenors filed objections. A procedural schedule for the case is pending due to ongoing settlement discussions. If any of the requested costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

OPCo conducts business under an ESP as approved by the PUCO which subjects the DIR to annual audits. In August 2020, a third-party consulting company filed an audit report with the PUCO indicating that OPCo exceeded its 2019 authorized revenue limit by $17 million. Management disagrees with the audit results and believes that OPCo was below its authorized revenue limit in 2019. The PUCO has not yet issued a procedural schedule to address the audit results. If the results of the audit are upheld by the PUCO and any refunds to customers or revenue reductions are ordered, it could reduce future net income and cash flows and impact financial condition.

In July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court. In the fourth quarter of 2019 and first quarter of 2020, SWEPCo and various intervenors filed briefs with the Texas Supreme Court. In August 2020, the Texas Supreme Court granted SWEPCo’s petition for review and oral arguments were held in December 2020. SWEPCo expects a decision from the Texas Supreme Court in 2021.

In 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% ROE. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a ROE of 9.6%, effective May 2017. The final order also included: (a) approval to recover the Texas jurisdictional share of environmental investments placed in- service, as of June 30, 2016, at various plants, including Welsh Plant, Units 1 and 3, (b) approval of recovery of, but no return on, the Texas jurisdictional share of the net book value of Welsh Plant, Unit 2, (c) approval of $2 million in additional vegetation management expenses and (d) the rejection of SWEPCo’s proposed transmission cost recovery mechanism.

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

In October 2018, the LPSC staff issued a recommendation that SWEPCo refund $11 million of excess federal income taxes collected, as a result of Tax Reform, from January 1, 2018 through July 31, 2018. In June 2019, the LPSC staff issued its report which reaffirmed its $11 million refund recommendation. The report also contends that SWEPCo’s requested annual rate increase of $18 million, which was implemented in August 2018, is overstated by $4 million and proposes an annual rate increase of $14 million. Additionally, the report recommends SWEPCo refund the excess over-collections associated with the $4 million difference for the period of August 2018 through the implementation of new rates. In July 2019, the LPSC approved the $11 million refund. In July 2020, the LPSC issued an order approving an unopposed stipulation and settlement agreement for a one-time refund of $6 million over three months beginning in August 2020.

In August 2020, Hurricane Laura hit the coasts of Louisiana and Texas, causing power outages to more than 130,000 customers across SWEPCo’s service territories. Prior to Hurricane Laura, SWEPCo did not have a catastrophe reserve or automatic deferral authority within any of its jurisdictions. In October 2020, the LPSC issued an order allowing Louisiana utilities, including SWEPCo, to establish a regulatory asset to track and defer expenses associated with Hurricane Laura. In October 2020, as part of the 2020 Texas Base Rate Case, SWEPCo requested deferral authority of incremental other operation and maintenance expenses. As of December 31, 2020, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $84 million ($82 million of which has been deferred as a regulatory asset related to the Louisiana jurisdiction) and incremental capital expenditures of $23 million, all of which is related to the Louisiana jurisdiction. If any costs related to Hurricane Laura are not recoverable, it could reduce future net income and cash flows and impact financial condition.

In October 2020, Hurricane Delta hit the coast of Louisiana, causing power outages to more than 23,000 customers in SWEPCo’s Louisiana jurisdiction. In November 2020, the LPSC issued an order allowing Louisiana utilities, including SWEPCo, to establish a regulatory asset to track and defer expenses associated with Hurricane Delta. As of December 31, 2020, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $17 million, which has been deferred as a regulatory asset. Also, management estimates that SWEPCo has incurred incremental capital expenditures of $2 million. If any costs related to Hurricane Delta are not recoverable, it could reduce future net income and cash flows and impact financial condition.

In October 2020, SWEPCo filed a request with the PUCT for a $105 million annual increase in Texas base rates based upon a proposed 10.35% ROE. The request would move transmission and distribution interim revenues recovered through riders into base rates. Eliminating these riders would result in a net annual requested base rate increase of $90 million primarily due to increased investments. The proposed net annual increase: (a) includes $5 million related to vegetation management to maintain and improve the reliability of its Texas jurisdictional distribution system, (b) requests a $10 million annual depreciation increase and (c) seeks $2 million annually to establish a storm catastrophe reserve. In addition, SWEPCo also requested recovery of the Texas jurisdictional share of the Dolet Hills Power Station of $45 million which is expected to be retired by the end of 2021. Intervenor and staff testimony is scheduled to be filed in March and April 2021, respectively. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

In December 2020, SWEPCo filed a request with the LPSC for a $134 million annual increase in Louisiana base rates based upon a proposed 10.35% ROE. The request would extend the formula rate plan for five years and includes modifications to the formula rate plan to allow for forward-looking transmission costs, reflects the impact of net operating losses associated with the acceleration of certain tax benefits and incorporates future federal corporate income tax changes. The proposed net annual increase: (a) requests a $32 million annual depreciation increase to recover Louisiana’s share of the Dolet Hills Power Station, Pirkey Power Plant and Welsh Plant, all of which are expected to be retired early, and (b) includes $10 million annually to recover deferred other operation and maintenance expenses related to Hurricanes Laura and Delta. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

In June 2020, FERC granted a temporary waiver providing utilities the option to elect to modify the existing AFUDC rate calculations in response to the COVID-19 pandemic. As a result of the waiver, the AFUDC formula for the 12-month period starting with March 2020 may be calculated using the simple average of the actual historical short-term debt balances for 2019, instead of current period short-term balances. All other aspects of the AFUDC formula remained unchanged. AEP subsidiaries including certain Registrant Subsidiaries elected to apply the waiver in July 2020. The impact upon election was immaterial on the Registrants’ financial statements. In February 2021, FERC issued an order extending the waiver through September 2021.

In August 2020, AEPSC filed a request with FERC, on behalf of PSO and OKTCo, to transfer OKTCo’s interests in its radial assets to PSO. OKTCo had previously constructed radial assets in the PSO service territory and after the radial assets were placed into service, management determined the radial assets were not eligible to be included as part of OKTCo’s SPP OATT formula rates. In October 2020, FERC approved the request and in December 2020, OKTCo completed the transfer of its interest in the radial assets to PSO, through Parent, at net book value. At the transfer date, the net book value of the radial assets were $60 million, before associated tax liabilities. PSO will seek recovery of the radial assets in its next base rate case, which must be filed by October 2021. If PSO does not receive approval to recover the radial assets, it could reduce future net income and cash flows and impact financial condition.