American Electric Power : MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Impacts of Severe Winter Weather

In February 2021, severe winter weather impacted the service territories of APCo, KPCo, PSO and SWEPCo resulting in power outages, extensive damage to infrastructure and disruptions to SPP market conditions. Impacts of the severe winter weather are included below. See Note 4 - Rate Matters for additional information.

Storm Restoration Costs

The impact of the severe winter weather resulted in power outages and extensive
damage to transmission and distribution infrastructures across the service
territories of APCo, KPCo and SWEPCo. As of March 31, 2021, an estimated $57
million of capital expenditures and $137 million of restoration expenses have
been incurred related to the severe winter weather. Approximately $131 million
of the expenses represent incremental restoration expenses and have been
deferred as regulatory assets. The KPSC and LPSC issued orders authorizing the
deferral of incremental restoration expenses as regulatory assets. APCo and KPCo
intend to seek recovery of these restoration costs in their next respective base
rate cases while SWEPCo is expected to seek recovery in a separate filing. If
any of the restoration costs are not recoverable, it could reduce future net
income and cash flows and impact financial condition.

Impacts in SPP

The severe winter weather also had a significant impact in SPP resulting in the
declaration of Energy Emergency Alert Levels 2 and 3 for the first time in SPP's
history. The winter storm increased the demand for natural gas and restricted
the available natural gas supply resulting in significantly increased market
prices for natural gas power plants to meet reliability needs for the SPP
electric system.

Retail Customers

As of March 31, 2021, PSO and SWEPCo have deferred regulatory assets of
$689 million and $496 million, respectively, relating to estimated natural gas
expenses and purchases of electricity incurred from February 9, 2021, to
February 20, 2021, as a result of severe winter weather. These amounts represent
estimates as of March 31, 2021, and are subject to final settlement as
additional information becomes available. PSO and SWEPCo have active fuel
clauses that allow for the recovery of prudently incurred fuel and purchased
power expenses. Given the significance of these costs, PSO and SWEPCo expect the
costs to be subject to prudency reviews. Management believes these costs are
probable of future recovery, but expects the recovery period to be extended to
mitigate the impact on customer bills.

In March 2021, the APSC issued an order authorizing recovery of the Arkansas
jurisdictional share of the retail customer fuel costs over five years, with the
appropriate carrying charge to be determined at a later date. Accordingly, in
April 2021, SWEPCo began recovery of its Arkansas jurisdictional share of these
fuel costs, which are subject to true-up by the APSC. Also in April 2021, SWEPCo
filed testimony supporting a five-year recovery with a pretax rate of return of
6.05%. A hearing is expected in the third quarter of 2021. A separate proceeding
will address the prudency of the fuel costs.

Also in March 2021, the LPSC approved a special order granting a temporary
modification to the FAC that allows SWEPCo to recover the Louisiana
jurisdictional share of the retail fuel costs over a longer period. In April
2021, SWEPCo began recovery of its Louisiana jurisdictional share of these fuel
costs based on a five year recovery
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period. SWEPCo will work with the LPSC to finalize the actual recovery period and determine the appropriate carrying charge in future proceedings.

In April 2021, the OCC approved a waiver for PSO allowing the deferral of the
extraordinary fuel and purchase of electricity costs, including carrying costs,
over a longer time period than what the FAC traditionally allows. A time frame
for recovery and the appropriate carrying charge will be decided at a later
date. Also in April 2021, legislation was introduced in Oklahoma proposing to
securitize the extraordinary fuel and purchase of electricity costs impacting
the utilities within the state. Under the proposal, the State of Oklahoma would
issue securitization bonds and provide the proceeds to utilities to recover
their share of the costs. PSO will continue to evaluate and monitor the
advancement of the proposed legislation.

SWEPCo expects to make a filing with the PUCT in the second quarter of 2021 to seek a recovery mechanism and an appropriate carrying charge for the Texas jurisdictional share of the retail fuel costs.

Wholesale Customers

SWEPCo is also working with certain wholesale customers to establish payment
terms for $88 million of accounts receivable resulting from the severe winter
weather events. Management believes these receivables are probable of future
collection.

PSO and SWEPCo Cash Flow Implications

PSO and SWEPCo evaluated financing alternatives to address the timing difference
between the payment of the estimated natural gas expenses and purchases of
electricity to suppliers and subsequent recovery from customers. In March 2021,
PSO drew $100 million on its revolving credit facility and SWEPCo issued
$500 million of Senior Unsecured Notes. In March 2021, Parent entered into a
$500 million 364-day Term Loan and borrowed the full amount. The proceeds from
this loan were used to help fund capital contributions to PSO and SWEPCo
totaling $425 million and $100 million, respectively. In April 2021, PSO
received an additional capital contribution from Parent of $125 million to
further address these costs.

Although the February 2021 severe winter weather did not materially impact AEP's
results of operations for the three months ended March 31, 2021, if either PSO
or SWEPCo is unable to recover these fuel and purchased power costs, or obtain
authorization of a reasonable carrying charge on these costs, it could reduce
future net income and cash flows and impact financial condition.

ERCOT

In response to the extreme winter weather event, the Governor of Texas issued a
Declaration of a State of Disaster for all counties in Texas. To assist with a
return to normalcy, the PUCT issued an order that placed a temporary moratorium
on customer disconnections due to non-payment for transmission and distribution
utilities. This moratorium will be in effect until otherwise ordered by the
PUCT. If related costs are not recoverable, it could reduce future net income
and cash flows and impact financial condition.

COVID-19

In 2020, COVID-19 was declared a pandemic by the World Health Organization and
the Centers for Disease Control and Prevention. Its rapid spread around the
world and throughout the United States prompted many countries, including the
United States, to institute restrictions on travel, public gatherings and
certain business operations. These restrictions significantly disrupted economic
activity in AEP's service territory and resulted in reduced demand for energy,
particularly from commercial and industrial customers. Management expects
weather-normalized customer demand to continue to improve during 2021 as
additional vaccinations occur and economic activity improves. However, if the
severity of the economic disruption increases, AEP's future results of
operations, financial condition, and cash flows could be further adversely
impacted.

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During 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. As of March 31, 2021, AEP's
electric operating companies have resumed customary disconnection practices in
all regulated jurisdictions with the exception of Arkansas and Virginia. In
March 2021, the APSC issued an order allowing electric utilities in Arkansas to
begin disconnections for non-payment beginning on May 3, 2021. AEP continues to
work with regulators and stakeholders in Virginia and management currently
anticipates resuming customary disconnection practices in the third quarter of
2021. 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 continue to review current accounts receivable collection
experience with historical trends, specifically reviewing metrics such as cash
collections, days sales outstanding, daily customer deposits, and aging
summaries. In addition, the Registrants reviewed historical loss information
generally comprised of a rolling 12-month average, in conjunction with a
qualitative assessment of elements that impact the collectability of
receivables, such as changes in economic factors, regulatory matters, industry
trends, customer credit factors, payment plan options and other programs
available to customers. AEP has been and continues to be proactive in engaging
with customers to collect payments or establish payment arrangements for
outstanding balances. As of March 31, 2021, AEP currently does not expect
accounts receivable aging to have a material adverse impact on the Registrants'
allowance for uncollectible accounts based on considerations of the COVID-19
impacts and past trends during times of economic instability. Management
continues to monitor developments that could have an impact on customer
collections.

Market volatility and delayed customer accounts receivable collections due to
the expansion of customer payment arrangements could reduce cash from operations
and cause an adverse impact to liquidity. As of March 31, 2021, AEP's available
liquidity was $3.4 billion. Management believes the Registrants have adequate
liquidity under existing credit facilities. To the extent that future access to
the capital markets or the cost of funding is adversely affected by COVID-19,
future results of operations, financial condition, and cash flows may be
adversely impacted.

The Registrants continue to take steps to mitigate the potential risks to
customers, suppliers and employees posed by the spread of COVID-19. The
Registrants have updated and implemented a company-wide pandemic plan to address
specific aspects of COVID-19. This plan guides emergency response, business
continuity, and the precautionary measures AEP is taking on behalf of its
employees and the public. The Registrants continue to take extra precautions for
employees who work in the field and for employees who work in their facilities,
and have work from home policies where appropriate. The Registrants will
continue to monitor developments affecting both their workforce and customers,
and will take additional precautions that management determines are necessary in
order to mitigate the impacts. AEP continues to focus on providing safe,
uninterrupted service to its customers, which includes the implementation of
strong physical and cyber-security measures to ensure that its systems remain
functional with a partially remote workforce. As of March 31, 2021, there has
been no material adverse impact to the Registrants' business operations and
customer service due to remote work. Management will continue to review and
modify plans as conditions change. Despite efforts to manage these impacts to
the Registrants, the ultimate impact of COVID-19 also depends on factors beyond
management's knowledge or control, including the duration and severity of this
outbreak as well as third-party actions taken to contain its spread and mitigate
its public health effects. Therefore, management cannot estimate the potential
future impact to financial position, results of operations and cash flows, but
the impacts could be material.


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Customer Demand

AEP's weather-normalized retail sales volumes for the first quarter of 2021
decreased by 1.9% from the first quarter of 2020. Weather-normalized residential
sales increased by 1.5% in the first quarter of 2021 from the first quarter of
2020. AEP's first quarter 2021 industrial sales volumes decreased by 6.1%
compared to the first quarter of 2020. The decline in industrial sales was
spread across many industries. Industrial sales were also negatively impacted by
the severe winter event in AEP's western operating territories in February 2021.
Weather-normalized commercial sales decreased 1.6% in the first quarter of 2021
from the first quarter of 2020.

Regulatory Matters

AEP's public utility subsidiaries are involved in rate and regulatory
proceedings at the FERC and their state commissions. Depending on the outcomes,
these rate and regulatory proceedings can have a material impact on results of
operations, cash flows and possibly financial condition. AEP is currently
involved in the following key proceedings. See Note 4 - Rate Matters for
additional information.

•2017-2019 Virginia Triennial Review - In November 2020, the Virginia SCC issued
an order on APCo's 2017-2019 Triennial Review filing 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).

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 clarify 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.

In March 2021, the Virginia SCC issued an order confirming certain of its
decisions from the November 2020 order and rejecting the various requests for
reconsideration from APCo and an intervenor. In confirming its decision to
reject an intervenor's recommendation that APCo's AMI costs incurred during the
triennial period be disallowed, the Virginia SCC clarified that APCo established
the need to replace its existing AMR meters, and that based on the uncertainty
surrounding the continued manufacturing and support of AMR technology, APCo
reasonably chose to replace them with AMI meters. In March 2021, APCo filed a
notice of appeal of the reconsideration order with the Virginia Supreme Court.
APCo expects to submit its brief before the Virginia Supreme Court in the second
or third quarter of 2021.

In April 2021, and in conjunction with APCo's November 2020 and March 2021
appeals with the Virginia Supreme Court, APCo filed a petition for interim rates
with the Virginia Supreme Court (subject to refund with interest and supported
by a bond issuance) requesting a $40 million increase in annual APCo Virginia
base rates. APCo submitted this filing based on Virginia law that allows the
Virginia Supreme Court to authorize interim rates until the final disposition on
APCo's appeals. APCo also requested an expedited schedule from the Virginia
Supreme Court on APCo's appeals.

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APCo ultimately seeks an increase in base rates through its appeal to the
Virginia Supreme Court. Among other issues, this appeal includes APCo's request
for proper treatment of the closed coal-fired plant assets in APCo's 2017-2019
triennial period, reducing APCo's earnings below the bottom of its authorized
ROE band. If APCo's appeals regarding treatment of the closed coal plants are
granted by the Virginia Supreme Court, it could initially reduce future net
income and impact financial condition.

•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. In March 2021, OPCo, the PUCO staff and various intervenors
filed a joint stipulation and settlement agreement with the PUCO based upon an
annual revenue decrease of $68 million and an ROE of 9.7%. The difference
between OPCo's requested annual base rate increase and the agreed upon decrease
is primarily due to a reduction in the requested ROE, the removal of proposed
future energy efficiency costs and a decrease in vegetation management expenses
moved to recovery in riders. In addition, the joint stipulation and settlement
agreement includes an increased fixed monthly residential customer charge, the
discontinuation of rate decoupling and the continuation of the DIR with annual
revenue caps of $57 million in 2021, $91 million in 2022, $116 million in 2023
and $51 million for the first five months of 2024. Annual revenue caps for the
DIR can be increased if OPCo achieves certain reliability standards. A hearing
is scheduled with the PUCO in May 2021.

•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 March 31, 2021, management estimates that SWEPCo has
incurred incremental other operation and maintenance expenses of $82 million
($79 million of which has been deferred as a regulatory asset related to the
Louisiana jurisdiction) and incremental capital expenditures of $31 million, all
of which is related to the Louisiana jurisdiction. Management expects to request
recovery of these storm costs in a filing inclusive of SWEPCo's various other
storm costs.

•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. 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 March 2021, the Texas Supreme Court issued an opinion
reversing the July 2018 judgment of the Texas Third Court of Appeals. The Texas
Supreme Court's opinion agrees with the PUCT's judgment affirming the prudence
of the Turk Plant. Motions for rehearing were due April 12, 2021 and no party
filed a timely motion. As of March 31, 2021, the net book value of Turk Plant
was $1.4 billion, before cost of removal, including materials and supplies
inventory and CWIP. SWEPCo's Texas jurisdictional share of the Turk Plant
investment is approximately 33%.

•In July 2019, clean energy legislation from Ohio House Bill 6 (HB 6) which
offered incentives for power-generating facilities with zero or reduced carbon
emissions was signed into law by the Ohio Governor.  HB 6 phased out current
energy efficiency programs as of December 31, 2020, including shared savings
revenues of $26 million annually and renewable mandates after 2026. HB 6 also
provided for the recovery of existing renewable energy contracts on a bypassable
basis through 2032 and included a provision for recovery of OVEC costs through
2030 which will be allocated to all electric distribution utilities on a
non-bypassable basis.  OPCo's Inter-Company Power Agreement for OVEC terminates
in June 2040. In July 2020, an investigation led by the U.S. Attorney's Office
resulted in a federal grand jury indictment of the Speaker of the Ohio House of
Representatives, Larry Householder, four other individuals, and Generation Now,
an entity registered as a 501(c)(4) social welfare organization, in connection
with a racketeering
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conspiracy involving the adoption of HB 6. Certain defendants in that case have
since pleaded guilty. In August 2020, an AEP shareholder filed a putative class
action lawsuit against AEP and certain of its officers for alleged violations of
securities laws in connection with HB 6. In January and February 2021, two AEP
shareholders filed two derivative actions purporting to assert claims on behalf
of AEP against certain AEP officers and directors based on allegations similar
to those in the putative securities class action. In April 2021, another similar
derivative action asserting claims on behalf of AEP against certain AEP officers
and directors was filed. See Litigation Related to Ohio House Bill 6 section of
Litigation below for additional information.

In March 2021, the Governor of Ohio signed legislation that, among other things,
rescinded the payments to the nonaffiliated owner of Ohio's nuclear power plants
that were previously authorized under HB 6. The new legislation, House Bill 128,
goes into effect after 90 days and leaves unchanged other provisions of HB 6
regarding energy efficiency programs, recovery of renewable energy costs and
recovery of OVEC costs. To the extent that OPCo is unable to recover the costs
of renewable energy contracts on a bypassable basis by the end of 2032, recover
costs of OVEC after 2030 or incurs significant costs associated with the
securities class action or the derivative actions, it could reduce future net
income and cash flows and impact financial condition.

•In April 2020, the Virginia Clean Economy Act was signed into law by the
Virginia Governor and became effective in July 2020. The law includes the
following requirements: (a) Virginia electric utilities to retire no later than
2045 all electric generating units located in Virginia that emit carbon as a
by-product, (b) APCo to produce 100% of the company's power to serve Virginia
customers from renewable sources by 2050 with increasing percentages of
mandatory renewable energy sources each year and (c) Virginia electric utilities
to achieve increasing annual energy efficiency savings from 2022-2025 using 2019
as the base year. This law also provides that if the Virginia SCC finds in any
triennial review that revenue reductions related to energy efficiency programs
approved and deployed since the utility's previous triennial review have caused
the utility to earn more than 70 basis points below its authorized rate of
return, the Virginia SCC shall order increases to the utility's rates necessary
to recover such revenue reductions. If any of these costs are not recoverable,
it could reduce future net income and cash flows and impact financial condition.

•In December 2020, APCo and WPCo filed a proposal with the WVPSC to implement an
investment tracker surcharge mechanism for recovering costs associated with
capital investment made between base rate cases. The initial filing requests a
total annual increase of $50 million ($41 million related to APCo), which
represents recovery of costs associated with infrastructure investments made
over an approximate three-year period since the companies' last base rate case
filing in 2018. The filing also proposes that APCo and WPCo could submit annual
filings with requested increases capped to a percentage of total retail revenues
(3.5% in the first year and 3% in subsequent filings with an overall cap of
9.5%). If a future base rate case is filed, the surcharge would reset to zero on
implementation of the new rates. In January 2021, WVPSC staff filed a motion
recommending that the WVPSC reject the proposal. The WVPSC deferred ruling on
the staff motion and established a procedural schedule, which includes testimony
from all parties to be received in May 2021 and a hearing is scheduled for June
2021. If APCo and WPCo do not receive approval to recover these incremental
investments through the proposed tracker surcharge mechanism between base rate
cases, it could cause a temporary reduction in future net income and cash flows
and impact financial condition until APCo and WPCo can seek approval in their
next base rate case.

•In April 2021, the FERC issued a supplemental Notice of Proposed Rulemaking
(NOPR) proposing to modify its incentive for transmission owners that join RTOs
(RTO Incentive). Under the supplemental NOPR, the RTO Incentive would be
modified such that a utility would only be eligible for the RTO Incentive for
the first three years after the utility joins a FERC-approved Transmission
Organization. This is a significant departure from a previous NOPR issued in
2020 seeking to increase the RTO Incentive from 50 basis points to 100 basis
points. The supplemental NOPR also requires utilities that have received the RTO
Incentive for three or more years to submit, within 30 days of the effective
date of a final rule, a
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compliance filing to eliminate the incentive from its tariff prospectively. The
supplemental NOPR is subject to a 30 day comment period followed by a 15 day
period for reply comments. A final rule is expected in the fourth quarter of
2021.

In 2019, the FERC approved settlement agreements establishing base ROEs of 9.85%
(10.35% inclusive of RTO Incentive adder of 0.5%) and 10% (10.5% inclusive of
RTO Incentive adder of 0.5%) for AEP's PJM and SPP transmission-owning
subsidiaries, respectively. In 2020, the FERC determined the base ROE for MISO's
transmission owning subsidiaries, should be 10.02% (10.52% inclusive of RTO
Incentive adder of 0.5%).

If the FERC modifies its RTO Incentive policy, it would be applied, as
applicable, to AEP's PJM, SPP and MISO transmission owning subsidiaries on a
prospective basis, and could affect future net income and cash flows and impact
financial condition. Based on management's preliminary estimates, if a final
rule is adopted consistent with the April 2021 supplemental NOPR, it could
reduce AEP's pretax income by approximately $55 million to $70 million on an
annual basis.

Utility Rates and Rate Proceedings

The Registrants file rate cases with their regulatory commissions in order to
establish fair and appropriate electric service rates to recover their costs and
earn a fair return on their investments. The outcomes of these regulatory
proceedings impact the Registrants' current and future results of operations,
cash flows and financial position.

The following tables show the Registrants' pending base rate case proceedings in 2021. See Note 4 - Rate Matters for additional information.

Completed Base Rate Case Proceedings

                                           Approved Revenue               

Approved New Rates

         Company       Jurisdiction      Requirement Increase                ROE          Effective
                                             (in millions)
          KPCo           Kentucky       $                52.7    (a)        9.3%         January 2021

(a)See "2020 Kentucky Base Rate Case" section of Note 4 Rate Matters in the 2020 Annual Report for additional information.

Pending Base Rate Case Proceedings

                                                                                                                                          Commission Staff/
                                                   Filing                 Requested Revenue                    Requested                 Intervenor Range of
   Company             Jurisdiction                 Date                 Requirement Increase                     ROE                      Recommended ROE
                                                                            (in millions)
     OPCo                  Ohio                   June 2020            $                42.3                     10.15%                8.76%-9.78%           (a)
    SWEPCo                 Texas                October 2020                           105.0    (b)              10.35%                  9%-9.22%            (c)
    SWEPCo               Louisiana              December 2020                          134.0                     10.35%                    (d)



(a)In March, 2021 a joint stipulation and settlement agreement was filed with
the PUCO which included a $68 million decrease in base rates based upon an ROE
of 9.7%.
(b)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.
(c)Staff and intervenor recommended base rate increases ranged from $20 million
to $70 million.
(d)Awaiting procedural schedule.
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Renewable Generation

The growth of AEP's renewable generation portfolio reflects the company's strategy to diversify generation resources to provide clean energy options to customers that meet both their energy and capacity needs.

Contracted Renewable Generation Facilities

AEP continues to develop its renewable portfolio within the Generation &
Marketing segment.  Activities include working directly with wholesale and large
retail customers to provide tailored solutions based upon market knowledge,
technology innovations and deal structuring which may include distributed solar,
wind, combined heat and power, energy storage, waste heat recovery, energy
efficiency, peaking generation and other forms of cost reducing energy
technologies. The Generation & Marketing segment also develops and/or acquires
large scale renewable generation projects that are backed with long-term
contracts with creditworthy counterparties.

In November 2020, AEP signed a Purchase and Sale Agreement with a nonaffiliate
to acquire a 75% interest in the 100 MW Dry Lake Solar Project located in
southern Nevada for approximately $114 million. The transaction closed in the
first quarter of 2021 and the solar project is expected to be in-service in the
second quarter of 2021. See Note 6 - Acquisitions for additional information.

As of March 31, 2021, subsidiaries within AEP's Generation & Marketing segment
had approximately 1,549 MWs of contracted renewable generation projects
in-service.  In addition, as of March 31, 2021, these subsidiaries had
approximately 239 MWs of renewable generation projects under construction with
total estimated capital costs of $349 million related to these projects.

Regulated Renewable Generation Facilities

In 2020, PSO received approval from the OCC and SWEPCo received approval from
the APSC and LPSC to acquire the North Central Wind Energy Facilities, comprised
of three Oklahoma wind facilities totaling 1,485 MWs, on a fixed cost turn-key
basis at completion. Both the APSC and LPSC approved the flex-up option,
agreeing to acquire the Texas portion, which the PUCT denied. PSO will own 45.5%
and SWEPCo will own 54.5% of the project, which will cost approximately $2
billion.

In May 2020, the IRS issued a notice extending the "Continuity Safe Harbor"
deadlines for qualifying renewable energy projects that began construction in
2016 and 2017 by one year as many projects are facing supply chain and other
project development delays caused by COVID-19. Under the May 2020 IRS notice,
qualifying renewable energy projects that began construction in 2016 and 2017
and which are placed in-service by the end of 2021 and 2022, respectively, will
satisfy the Continuity Safe Harbor. Provided that each facility does satisfy the
Continuity Safe Harbor, under the current IRS guidance, the 199 MW wind facility
will qualify for 100% of the federal PTC, and the remaining two wind facilities,
totaling 1,286 MWs, will qualify for 80% of the federal PTC.

In April 2021, the 199 MW wind facility was acquired and placed in-service with
an estimated investment of $307 million. The 287 MW wind facility is targeted to
be acquired and placed in-service in December 2021 and the 999 MW wind facility
is targeted to be acquired and placed in-service between December 2021 and April
2022. See Note 6 - Acquisitions for additional information.

Strategic Evaluation of KPCo

AEP has initiated a strategic evaluation for its ownership in KPCo, a
wholly-owned regulated generation, transmission and distribution utility with
approximately 166,000 retail customers in eastern Kentucky. Potential
alternatives may include continued ownership or a sale of KPCo. Management has
not made a decision regarding the potential alternatives, but expects a decision
will be made during 2021. As of March 31, 2021, KPCo has total assets of
approximately $2.7 billion and total equity of approximately $837 million.

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Racine

In February 2021, AEP signed an agreement to sell Racine to a nonaffiliated
party. As of March 31, 2021, the net book value of Racine was $45 million. The
sale of Racine requires approval from the FERC and the U.S. Army Corps of
Engineers. The sale is expected to close in the second quarter of 2021 and
result in an immaterial gain. Racine was not presented as Held for Sale on AEP's
balance sheets due to immateriality.

Dolet Hills Power Station and Related Fuel Operations

During the second quarter of 2019, the Dolet Hills Power Station initiated a
seasonal operating schedule. In January 2020, in accordance with the terms of
SWEPCo's settlement of its base rate review filed with the APSC, management
announced that SWEPCo will seek regulatory approval to retire the Dolet Hills
Power Station by the end of 2026. DHLC provides 100% of the fuel supply to Dolet
Hills Power Station. After careful consideration of current economic conditions,
and particularly for the benefit of their customers, management of SWEPCo and
CLECO determined DHLC would not proceed developing additional Oxbow Lignite
Company (Oxbow) mining areas for future lignite extraction and ceased extraction
of lignite at the mine in May 2020. Based on these actions, management revised
the estimated useful life of DHLC's and Oxbow's assets to coincide with the date
at which extraction was discontinued in the second quarter of 2020 and the date
at which delivery of lignite is expected to cease in September 2021. Management
also revised the useful life of the Dolet Hills Power Station to 2021 based on
the remaining estimated fuel supply available for continued seasonal operation.
In March 2020, primarily due to the revision in the useful life of DHLC, SWEPCo
recorded a revision to increase estimated ARO liabilities by $21 million. In
April 2020, SWEPCo and CLECO jointly filed a notification letter to the LPSC
providing notice of the cessation of lignite mining.

The Dolet Hills Power Station costs are recoverable by SWEPCo through base rates. SWEPCo's share of the net investment in the Dolet Hills Power Station is $150 million, including CWIP and materials and supplies, before cost of removal.

Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo
through active fuel clauses. Under the fuel agreements, SWEPCo's fuel inventory
and unbilled fuel costs from mining related activities were $126 million as of
March 31, 2021. Also, as of March 31, 2021, SWEPCo had a net over-recovered fuel
balance of $20 million, excluding impacts of the February 2021 severe winter
weather event, which includes fuel consumed at the Dolet Hills Power Station.
Additional operational and land-related costs are expected to be incurred by
DHLC and Oxbow and billed to SWEPCo prior to the closure of the Dolet Hills
Power Station and recovered through fuel clauses.

In June 2020, SWEPCo filed a fuel reconciliation with the PUCT for its retail
operations in Texas, including Dolet Hills, for the reconciliation period of
March 1, 2017 to December 31, 2019. See "2020 Texas Fuel Reconciliation" section
of Note 4 for additional information.

In October 2020, SWEPCo filed a request with the LPSC seeking approval to close
the mines and to recover the Louisiana jurisdictional share of the additional
fuel costs. In March 2021, the LPSC issued an order allowing SWEPCo to recover
up to $20 million of fuel costs in 2021 and defer approximately $30 million of
additional costs with a recovery period to be determined at a later date.

In March 2021, the APSC approved fuel rates that provide recovery of the Arkansas share of the 2021 Dolet Hills Power Station fuel costs over five years through the existing fuel clause.

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

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Pirkey Power Plant and Related Fuel Operations

In November 2020, management announced plans to retire the Pirkey Power Plant in
2023. The Pirkey Power Plant costs are recoverable by SWEPCo through base rates.
SWEPCo's share of the net investment in the Pirkey Power Plant is $209 million,
including CWIP, before cost of removal. Sabine is a mining operator providing
mining services to the Pirkey Power Plant. Under the provisions of the mining
agreement, SWEPCo is required to pay, as part of the cost of lignite delivered,
an amount equal to mining costs plus a management fee. SWEPCo expects fuel
deliveries, including billings of all fixed and operating costs, from Sabine to
cease during the first quarter of 2023. Under the fuel agreements, SWEPCo's fuel
inventory and unbilled fuel costs from mining related activities were $163
million as of March 31, 2021. Also, as of March 31, 2021, SWEPCo had a net
over-recovered fuel balance of $20 million, excluding impacts of the February
2021 severe winter weather event, which includes fuel consumed at the Pirkey
Power Plant. Additional operational costs are expected to be incurred by Sabine
and billed to SWEPCo, as well as land-related costs incurred by SWEPCo, prior to
the closure of the Pirkey Power Plant and recovered through fuel clauses. If any
of these costs are not recoverable, it could reduce future net income and cash
flows and impact financial condition.

LITIGATION

In the ordinary course of business, AEP is involved in employment, commercial,
environmental and regulatory litigation. Since it is difficult to predict the
outcome of these proceedings, management cannot predict the eventual resolution,
timing or amount of any loss, fine or penalty. Management assesses the
probability of loss for each contingency and accrues a liability for cases that
have a probable likelihood of loss if the loss can be estimated. Adverse results
in these proceedings have the potential to reduce future net income and cash
flows and impact financial condition. See Note 4 - Rate Matters and Note 5 -
Commitments, Guarantees and Contingencies for additional information.

Rockport Plant Litigation

In 2013, the Wilmington Trust Company filed a complaint in the U.S. District
Court for the Southern District of New York against AEGCo and I&M alleging that
it would be unlawfully burdened by the terms of the modified NSR consent decree
after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of
the consent decree allow the installation of environmental emission control
equipment, repowering, refueling or retirement of the unit.  The plaintiffs seek
a judgment declaring that the defendants breached the lease, must satisfy
obligations related to installation of emission control equipment and indemnify
the plaintiffs. The New York court granted a motion to transfer this case to the
U.S. District Court for the Southern District of Ohio.

AEGCo and I&M sought and were granted dismissal by the U.S. District Court for
the Southern District of Ohio of certain of the plaintiffs' claims, including
claims for compensatory damages, breach of contract, breach of the implied
covenant of good faith and fair dealing and indemnification of costs. Plaintiffs
voluntarily dismissed the surviving claims that AEGCo and I&M failed to exercise
prudent utility practices with prejudice, and the court issued a final judgment.
The plaintiffs subsequently filed an appeal in the U.S. Court of Appeals for the
Sixth Circuit.

In 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion and
judgment affirming the district court's dismissal of the owners' breach of good
faith and fair dealing claim as duplicative of the breach of contract claims,
reversing the district court's dismissal of the breach of contract claims and
remanding the case for further proceedings.

Thereafter, AEP filed a motion with the U.S. District Court for the Southern
District of Ohio in the original NSR litigation, seeking to modify the consent
decree. The district court granted the owners' unopposed motion to stay the
lease litigation to afford time for resolution of AEP's motion to modify the
consent decree. The consent decree was modified based on an agreement among the
parties in July 2019. The district court's stay of the lease litigation expired
in August 2020. Upon expiration of the stay, plaintiffs filed a motion for
partial summary judgment,
                                       10
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arguing that the consent decree violates the facility lease and the
participation agreement and requesting that the district court enter a judgment
for the plaintiffs on their breach of contract claim. AEP's memorandum in
opposition to plaintiffs' motion for partial summary judgment was filed in
October 2020. At the parties' request, the district court stayed the case until
April 19, 2021 to provide the parties an opportunity to resolve the case. See
"Obligations under the New Source Review Litigation Consent Decree" section
below for additional information.

On April 20, 2021, I&M and AEGCo reached an agreement to acquire 100% of the
interests in Rockport Plant, Unit 2 for $115.5 million from certain financial
institutions that own the unit through trusts established by Wilmington Trust,
the nonaffiliated owner trustee of the ownership interests in the unit, with
closing to occur as of the end of the Rockport Plant, Unit 2 lease in December
2022. As a result, the parties have submitted a stipulation and order of
dismissal requesting that the district court dismiss the case without prejudice
to plaintiffs asserting their claims in a re-filed action or in a new action.
The agreement is subject to customary closing conditions, including regulatory
approvals, and as of the closing will result in a final settlement of, and
release of claims in, the lease litigation. Management believes its financial
statements appropriately reflect the expected resolution of the pending
litigation.

Claims Challenging Transition of American Electric Power System Retirement Plan to Cash Balance Formula

The American Electric Power System Retirement Plan (the Plan) has received a
letter written on behalf of four participants (the Claimants) making a claim for
additional plan benefits and purporting to advance such claims on behalf of a
class. When the Plan's benefit formula was changed in the year 2000, AEP
provided a special provision for employees hired before January 1, 2001,
allowing them to continue benefit accruals under the then benefit formula for a
full 10 years alongside of the new cash balance benefit formula then being
implemented.  Employees who were hired on or after January 1, 2001 accrued
benefits only under the new cash balance benefit formula.  The Claimants have
asserted claims that: (a) the Plan violates the requirements under the Employee
Retirement Income Security Act (ERISA) intended to preclude back-loading the
accrual of benefits to the end of a participant's career, (b) the Plan violates
the age discrimination prohibitions of ERISA and the Age Discrimination in
Employment Act and (c) the company failed to provide required notice regarding
the changes to the Plan.  AEP has responded to the Claimants providing a
reasoned explanation for why each of their claims have been denied. The denial
of those claims was appealed to the AEP System Retirement Plan Appeal Committee
and the Committee upheld the denial of claims. Management will continue to
defend against the claims.  Management is unable to determine a range of
potential losses that is reasonably possible of occurring.

Litigation Related to Ohio House Bill 6 (HB 6)

In August 2020, an AEP shareholder filed a putative class action lawsuit in the
United States District Court for the Southern District of Ohio against AEP and
certain of its officers for alleged violations of securities laws. The amended
complaint alleges misrepresentations or omissions by AEP regarding: (a) its
alleged participation in or connection to public corruption with respect to the
passage of HB 6 and (b) its regulatory, legislative, political contribution, 501
(c)(4) organization contribution and lobbying activities in Ohio. The complaint
seeks monetary damages, among other forms of relief. The company will continue
to defend against the claims. Management is unable to determine a range of
potential losses that is reasonably possible of occurring.

In January 2021, an AEP shareholder filed a derivative action in the United
States District Court for the Southern District of Ohio purporting to assert
claims on behalf of AEP against certain AEP officers and directors. In February
2021, a second AEP shareholder filed a similar derivative action in the Court of
Common Pleas of Franklin County, Ohio. In April 2021, a third AEP shareholder
filed a similar derivative action in the U.S. District Court for the Southern
District of Ohio. These derivative complaints allege the officers and directors
made misrepresentations and omissions similar to those alleged in the putative
securities class action lawsuit filed against AEP. The derivative complaints
together assert claims for: (a) breach of fiduciary duty, (b) waste of corporate
assets, (c) unjust enrichment, (d) breach of duty for insider trading and (e)
contribution for violations of sections 10(b) and 21D of the Securities Exchange
Act of 1934; and seek monetary damages and changes to AEP's corporate governance
and internal policies among other forms of relief. The company will continue to
defend against the claims. Management is unable to determine a range of
potential losses that is reasonably possible of occurring.

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On March 1, 2021, AEP received a litigation demand letter from counsel
representing a purported AEP shareholder. The litigation demand letter is
directed to the Board of Directors of AEP and contains factual allegations
involving HB 6 that are generally consistent with those in the derivative
litigation filed in state and federal court. The letter demands, among other
things, that the AEP Board undertake an independent investigation into alleged
legal violations by directors and officers, and that, following such
investigation, the Company commence a civil action for breaches of fiduciary
duty and related claims and take appropriate disciplinary action against those
individuals who allegedly harmed the company. The AEP Board will act in response
to the letter as appropriate. Management is unable to determine a range of
potential losses that is reasonably possible of occurring.


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ENVIRONMENTAL ISSUES

AEP has a substantial capital investment program and incurs additional
operational costs to comply with environmental control requirements. Additional
investments and operational changes will be made in response to existing and
anticipated requirements to reduce emissions from fossil generation and in
response to rules governing the beneficial use and disposal of coal combustion
by-products, clean water and renewal permits for certain water discharges.

AEP is engaged in litigation about environmental issues, was notified of
potential responsibility for the clean-up of contaminated sites and incurred
costs for disposal of SNF and future decommissioning of the nuclear units. AEP,
along with other parties, challenged a portion of the Federal EPA
requirements. Management is engaged in the development of possible future
requirements including the items discussed below. Management believes that
further analysis and better coordination of these environmental requirements
would facilitate planning and lower overall compliance costs while achieving the
same environmental goals.

AEP will seek recovery of expenditures for pollution control technologies and
associated costs from customers through rates in regulated
jurisdictions. Environmental rules could result in accelerated depreciation,
impairment of assets or regulatory disallowances. If AEP cannot recover the
costs of environmental compliance, it would reduce future net income and cash
flows and impact financial condition.

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed below will have a
material impact on AEP System generating units. Management continues to evaluate
the impact of these rules, project scope and technology available to achieve
compliance. As of March 31, 2021, the AEP System owned generating capacity of
approximately 24,600 MWs, of which approximately 12,100 MWs were
coal-fired. Management continues to refine the cost estimates of complying with
these rules and other impacts of the environmental proposals on fossil
generation. Based upon management estimates, AEP's future investment to meet
these existing and proposed requirements ranges from approximately $350 million
to $700 million through 2027.

The cost estimates will change depending on the timing of implementation and
whether the Federal EPA provides flexibility in finalizing proposed rules or
revising certain existing requirements. The cost estimates will also change
based on: (a) potential state rules that impose more stringent standards, (b)
additional rulemaking activities in response to court decisions, (c) actual
performance of the pollution control technologies installed, (d) changes in
costs for new pollution controls, (e) new generating technology developments,
(f) total MWs of capacity retired and replaced, including the type and amount of
such replacement capacity and (g) other factors. In addition, management
continues to evaluate the economic feasibility of environmental investments on
regulated and competitive plants.

Obligations under the New Source Review Litigation Consent Decree

In 2007, the U.S. District Court for the Southern District of Ohio approved a
consent decree between AEP subsidiaries in the eastern area of the AEP System
and the Department of Justice, the Federal EPA, eight northeastern states and
other interested parties to settle claims that the AEP subsidiaries violated the
NSR provisions of the CAA when they undertook various equipment repair and
replacement projects over a period of nearly 20 years. The consent decree's
terms include installation of environmental control equipment on certain
generating units, a declining cap on SO2 and NOX emissions from the AEP System
and various mitigation projects. The consent decree has been modified six times,
for various reasons, most recently in 2020. All of the environmental control
equipment required by the consent decree has been installed.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation's
air quality and control sources of air emissions. The states implement and
administer many of these programs and could impose additional or more stringent
requirements. The primary regulatory programs that continue to drive investments
in AEP's existing generating units include: (a) periodic revisions to NAAQS and
the development of SIPs to achieve any more
                                       13
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stringent standards, (b) implementation of the regional haze program by the
states and the Federal EPA, (c) regulation of hazardous air pollutant emissions
under MATS, (d) implementation and review of CSAPR and (e) the Federal EPA's
regulation of greenhouse gas emissions from fossil generation under Section 111
of the CAA. Notable developments in significant CAA regulatory requirements
affecting AEP's operations are discussed in the following sections.

National Ambient Air Quality Standards

The Federal EPA periodically reviews and revises the NAAQS for criteria
pollutants under the CAA. Revisions tend to increase the stringency of the
standards, which in turn may require AEP to make investments in pollution
control equipment at existing generating units, or, since most units are already
well controlled, to make changes in how units are dispatched and operated. Most
recently, the Biden administration has indicated that it is likely to revisit
the NAAQS for ozone and PM, which were left unchanged by the prior
administration following its review. Management cannot currently predict if any
changes to either standard are likely or what such changes may be, but will
continue to monitor this issue and any future rulemakings.

Regional Haze

The Federal EPA issued a Clean Air Visibility Rule (CAVR) in 2005, which could
require power plants and other facilities to install best available retrofit
technology to address regional haze in federal parks and other protected areas.
CAVR is implemented by the states, through SIPs, or by the Federal EPA, through
FIPs. In 2017, the Federal EPA revised the rules governing submission of SIPs to
implement the visibility programs, including a provision that postpones the due
date for the next comprehensive SIP revisions until 2021. Petitions for review
of the final rule revisions have been filed in the U.S. Court of Appeals for the
District of Columbia Circuit.

Arkansas has an approved regional haze SIP and all of SWEPCo's affected units are in compliance with the relevant requirements.

In Texas, the Federal EPA disapproved portions of the Texas regional haze SIP
and finalized a FIP that allows participation in the CSAPR ozone season program
to satisfy the NOX regional haze obligations for electric generating units in
Texas. Additionally, the Federal EPA finalized an intrastate SO2 emissions
trading program based on CSAPR allowance allocations. Legal challenges to these
various rulemakings are pending in both the U.S. Court of Appeals for the Fifth
Circuit and the U.S. Court of Appeals for the District of Columbia Circuit.
Management cannot predict the outcome of that litigation, although management
supports the intrastate trading program as a compliance alternative to
source-specific controls and has intervened in the litigation in support of the
Federal EPA.

Cross-State Air Pollution Rule

CSAPR is a regional trading program designed to address interstate transport of
emissions that contributed significantly to downwind non-attainment with the
1997 ozone and PM NAAQS. CSAPR relies on SO2 and NOX allowances and individual
state budgets to compel further emission reductions from electric utility
generating units. Interstate trading of allowances is allowed on a restricted
sub-regional basis.

In January 2021, the Federal EPA finalized a revised CSAPR rule, which substantially reduces the ozone season NOX budgets in 2021-2024. Management believes it can meet the requirements of the rule in the near term, and is evaluating its compliance options for later years, when the budgets are further reduced.

Climate Change, CO2 Regulation and Energy Policy

In 2019, the Affordable Clean Energy (ACE) rule established a framework for
states to adopt standards of performance for utility boilers based on heat rate
improvements for such boilers. However, in January 2021, the U.S. Court of
Appeals for the D.C. Circuit vacated the ACE rule and remanded it to the Federal
EPA. Management is unable to predict how the Federal EPA will respond to the
court's remand.

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In 2018, the Federal EPA filed a proposed rule revising the standards for new
sources and determined that partial carbon capture and storage is not the best
system of emission reduction because it is not available throughout the U.S. and
is not cost-effective. That rule has not been finalized. Management continues to
actively monitor these rulemaking activities.

While no federal regulatory requirements to reduce CO2 emissions are in place,
AEP has taken action to reduce and offset CO2 emissions from its generating
fleet. AEP expects CO2 emissions from its operations to continue to decline due
to the retirement of some of its coal-fired generation units, and actions taken
to diversify the generation fleet and increase energy efficiency where there is
regulatory support for such activities. The majority of the states where AEP has
generating facilities passed legislation establishing renewable energy,
alternative energy and/or energy efficiency requirements that can assist in
reducing carbon emissions. In April 2020, Virginia enacted clean energy
legislation to allow the state to participate in the Regional Greenhouse Gas
Initiative, require the retirement of all fossil-fueled generation by 2045 and
require 100% renewable energy to be provided to Virginia customers by 2050.
Management is taking steps to comply with these requirements, including
increasing wind and solar installations, purchasing renewable power and
broadening AEP System's portfolio of energy efficiency programs.

In February 2021, AEP announced new intermediate and long-term CO2 emission
reduction goals, based on the output of the company's integrated resource plans,
which take into account economics, customer demand, grid reliability and
resiliency, regulations and the company's current business strategy. The
intermediate goal is an 80% reduction from 2000 CO2 emission levels from AEP
generating facilities by 2030; the long-term goal is net-zero CO2 emissions from
AEP generating facilities by 2050. AEP's total estimated CO2 emissions in 2020
were approximately 44 million metric tons, a 73% reduction from AEP's 2000 CO2
emissions. AEP has made significant progress in reducing CO2 emissions from its
power generation fleet and expects its emissions to continue to decline.
Technological advances, including energy storage, will determine how quickly AEP
can achieve zero emissions while continuing to provide reliable, affordable
power for customers.

Excessive costs to comply with future legislation or regulations has led to the
announcement of early plant closures and could force AEP to close additional
coal-fired generation facilities earlier than their estimate useful life. If AEP
is unable to recover the costs of its investments, it would reduce future net
income and cash flows and impact financial condition.

Coal Combustion Residual Rule

The Federal EPA's CCR rule regulates the disposal and beneficial re-use of CCR,
including fly ash and bottom ash created from coal-fired generating units and
FGD gypsum generated at some coal-fired plants.  The rule applies to active CCR
landfills and surface impoundments at operating electric utility or independent
generation facilities.

In August 2020, the Federal EPA revised the CCR rule to include a requirement
that unlined CCR storage ponds cease operations and initiate closure by April
11, 2021. The revised rule provides two options that allow facilities to extend
the date by which they must cease receipt of coal ash and close the ponds.
                                       15
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The first option provides an extension to cease receipt of CCR no later than
October 15, 2023 for most units, and October 15, 2024 for a narrow subset of
units; however, the Federal EPA's grant of such an extension will be based upon
a satisfactory demonstration of the need for additional time to develop
alternative ash disposal capacity and will be limited to the soonest timeframe
technically feasible to cease receipt of CCR. Additionally, each request must
undergo formal review, including public comments, and be approved by the Federal
EPA. AEP filed applications for additional time to develop alternative disposal
capacity at the following plants:

                                                                                  Generating                                                        Projected
      Company                                Plant Name and Unit                   Capacity                     Net Book Value (a)               Retirement Date
                                                                                   (in MWs)                        (in millions)
APCo                                   Amos                                                  2,930             $          2,149.4                     2040
APCo                                   Mountaineer                                           1,320                          971.2                     2040
SWEPCo                                 Flint Creek Plant                                       258                          275.7                     2038
KPCo                                   Mitchell Plant                                          780                          599.9                     2040
WPCo                                   Mitchell Plant                                          780                          597.9                     2040
AEGCo                                  Rockport Plant, Unit 1                                  655                          242.2                     2028
I&M                                    Rockport Plant, Unit 1                                  655                          558.2     (b)             2028



(a)Net book value before cost of removal including CWIP and inventory.
(b)Amount includes a $186 million regulatory asset related to the retired
Tanners Creek Plant. The IURC and MPSC authorized recovery of the Tanners Creek
Plant regulatory asset over the useful life of Rockport Plant, Unit 1 in 2015
and 2014, respectively.

In December 2020, APCo filed requests with the Virginia SCC and WVPSC to obtain
the regulatory approvals necessary to implement the compliance plans and seek
recovery of the estimated $240 million investment for the Amos and Mountaineer
plants. In December 2020 and February 2021, WPCo and KPCo filed requests with
the WVPSC and KPSC, respectively, to obtain the regulatory approvals necessary
to implement the compliance plans and seek recovery of the estimated $132
million investment for the Mitchell Plant. Within those requests, WPCo and KPCo
also filed a $25 million alternative with the WVPSC and KPSC, respectively,
which would allow the Mitchell Plant to continue operating only through 2028.

The second option is a retirement option, which provides a generating facility
an extended operating time without developing alternative CCR disposal. Under
the retirement option, a generating facility would have until October 17, 2023
to cease operation and to close CCR storage ponds 40 acres or less in size, or
through October 17, 2028 for facilities with CCR storage ponds greater than 40
acres in size. Pursuant to this option, AEP informed the Federal EPA of its
intent to retire the Pirkey Power Plant and cease using coal at the Welsh Plant:
                                                                                                                         Accelerated
                                                                    Generating                 Net Investment            Depreciation                 Projected
     Company                         Plant Name and Unit             Capacity                        (a)               Regulatory Asset             Retirement Date
                                                                     (in MWs)                                (in millions)
SWEPCo                               Pirkey Power Plant                        580             $      178.3          $            30.8                 2023 (b)
                                     Welsh Plants, Units
SWEPCo                               1 and 3                                 1,053                    528.8                       14.2               2028 (c)(d)



(a)Net book value including CWIP excluding cost of removal and materials and
supplies.
(b)Pirkey Power Plant is currently being recovered through 2025 in the Louisiana
jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.
(c)In November 2020, management announced it will cease using coal at the Welsh
Plant in 2028.
(d)Unit 1 is currently being recovered through 2027 in the Louisiana
jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Unit 3 is
currently being recovered through 2032 in the Louisiana jurisdiction and through
2042 in the Arkansas and Texas jurisdictions.

AEP may incur significant costs to upgrade or close and replace surface
impoundments and landfills used to manage CCR and to conduct any required
remedial actions. Under the retirement option above, AEP may need to recover
remaining depreciation and estimated closure costs associated with retiring
plants over a shorter period. If AEP cannot ultimately recover the costs of
environmental compliance and/or the remaining depreciation and estimated closure
costs associated with retiring plants in a timely manner, it would reduce future
net income and cash flows and impact financial condition.

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Closure and post-closure costs have been included in ARO in accordance with the
requirements in the final rule. Additional ARO revisions will occur on a
site-by-site basis if groundwater monitoring activities conclude that corrective
actions are required to mitigate groundwater impacts, which could include costs
to remove ash from some unlined units.

If removal of ash is required without providing similar assurances of cost
recovery in regulated jurisdictions, it would impose significant additional
operating costs on AEP, which could lead to increased financing costs and
liquidity needs. Other units in Virginia, Ohio, West Virginia and Kentucky have
already been closed in place in accordance with state law programs. Management
will continue to participate in rulemaking activities and make adjustments based
on new federal and state requirements affecting its ash disposal units.

Clean Water Act Regulations

The Federal EPA's ELG rule for generating facilities establishes limits on FGD
wastewater, fly ash and bottom ash transport water and flue gas mercury control
wastewater, which are to be implemented through each facility's wastewater
discharge permit. A recent revision to the ELG rule, published in October 2020,
establishes additional options for reusing and discharging small volumes of
bottom ash transport water, provides an exception for retiring units and extends
the compliance deadline to a date as soon as possible beginning one year after
the rule was published but no later than December 2025. Management has assessed
technology additions and retrofits to comply with the rule and the impacts of
the Federal EPA's recent actions on facilities' wastewater discharge permitting
for FGD wastewater and bottom ash transport water. Permit modifications for
affected facilities were filed in January 2021 that reflect the outcome of that
assessment.

Impact of Environmental Regulation on Coal-Fired Generation

Compliance with extensive environmental regulations requires significant capital
investment in environmental monitoring, installation of pollution control
equipment, emission fees, disposal costs and permits. Management continuously
evaluates cost estimates of complying with these regulations which may result in
a decision to retire coal-fired generating facilities earlier than their
currently estimated useful lives.

In addition to the November 2020 announcement related to the Federal EPA's CCR
rules, management also decided not to renew the Rockport Plant, Unit 2 lease
when it expires in 2022. Previously, management retired or announced early
closure plans for Welsh Unit 2, Oklaunion Power Station, Dolet Hills Power
Station and Northeastern Plant Unit 3.


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The table below summarizes the net book value, as of March 31, 2021, of generating facilities retired or planned for early retirement:

                                                                                                     Accelerated                           Actual/Projected                        Current Authorized
                                                                               Net                   Depreciation                             Retirement                                Recovery                    Annual
      Company                        Plant                                Investment (a)           Regulatory Asset                              Date                                    Period                Depreciation (b)
                                                                                           (in millions)                                                          (in millions)
SWEPCo                    Dolet Hills Power Station                     $          51.3          $            92.6                               2021                                      (c)                $           7.7
PSO                       Northeastern Plant, Unit 3                              190.5                      114.8                               2026                                      (d)                           14.9
PSO                       Oklaunion Power Station                                     -                       34.0                               2020                                      (e)                            0.4
SWEPCo                    Pirkey Power Plant                                      178.3                       30.8                               2023                                      (f)                           13.7
SWEPCo                    Welsh Plant, Units 1 and 3                              528.8                       14.2                             2028 (g)                                    (h)                           33.3
SWEPCo                    Welsh Plant, Unit 2                                         -                       35.2                               2016                                      (i)                              -



(a)Net book value including CWIP excluding cost of removal and materials and
supplies.
(b)These amounts represent the amount of annual depreciation that has been
collected from customers over the prior 12-month period.
(c)Dolet Hills Power Station is currently being recovered through 2026 in the
Louisiana jurisdiction and through 2046 in the Arkansas and Texas jurisdictions.
(d)Northeastern Plant, Unit 3 is currently being recovered through 2040.
(e)Oklaunion Power Station is currently being recovered through 2046.
(f)Pirkey Power Plant is currently being recovered through 2025 in the Louisiana
jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.
(g)In November 2020, management announced it will cease using coal at the Welsh
Plant in 2028.
(h)Welsh Plant, Unit 1 is being recovered through 2027 in the Louisiana
jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Welsh
Plant, Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and
through 2042 in the Arkansas and Texas jurisdictions.
(i)Welsh Plant, Unit 2 is being recovered over the blended useful life of Welsh
Plant, Units 1 and 3.

Management is seeking or will seek regulatory recovery, as necessary, for any
net book value remaining when the plants are retired. To the extent the net book
value of these generation assets are not deemed recoverable, it could materially
reduce future net income, cash flows and impact financial condition.
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RESULTS OF OPERATIONS

SEGMENTS

AEP's primary business is the generation, transmission and distribution of
electricity. Within its Vertically Integrated Utilities segment, AEP centrally
dispatches generation assets and manages its overall utility operations on an
integrated basis because of the substantial impact of cost-based rates and
regulatory oversight. Intersegment sales and transfers are generally based on
underlying contractual arrangements and agreements.

AEP's reportable segments and their related business activities are outlined below:

Vertically Integrated Utilities

•Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.

Transmission and Distribution Utilities

•Transmission and distribution of electricity for sale to retail and wholesale
customers through assets owned and operated by AEP Texas and OPCo.
•OPCo purchases energy and capacity at auction to serve standard service offer
customers and provides transmission and distribution services for all connected
load.

AEP Transmission Holdco

•Development, construction and operation of transmission facilities through
investments in AEPTCo. These investments have FERC-approved ROE.
•Development, construction and operation of transmission facilities through
investments in AEP's transmission-only joint ventures. These investments have
PUCT-approved or FERC-approved ROE.

Generation & Marketing

•Contracted renewable energy investments and management services. •Marketing, risk management and retail activities in ERCOT, MISO, PJM and SPP. •Competitive generation in PJM.

The remainder of AEP's activities are presented as Corporate and Other. While
not considered a reportable segment, Corporate and Other primarily includes the
purchasing of receivables from certain AEP utility subsidiaries, Parent's
guarantee revenue received from affiliates, investment income, interest income
and interest expense and other nonallocated costs.

The following discussion of AEP's results of operations by operating segment
includes an analysis of Gross Margin, which is a non-GAAP financial measure.
Gross Margin includes Total Revenues less the costs of Fuel and Other
Consumables Used for Electric Generation as well as Purchased Electricity for
Resale and Amortization of Generation Deferrals as presented in the Registrants'
statements of income as applicable. Under the various state utility rate making
processes, these expenses are generally reimbursable directly from and billed to
customers. As a result, they do not typically impact Operating Income or
Earnings Attributable to AEP Common Shareholders. Management believes that Gross
Margin provides a useful measure for investors and other financial statement
users to analyze AEP's financial performance in that it excludes the effect on
Total Revenues caused by volatility in these expenses. Operating Income, which
is presented in accordance with GAAP in AEP's statements of income, is the most
directly comparable GAAP financial measure to the presentation of Gross Margin.
AEP's definition of Gross Margin may not be directly comparable to similarly
titled financial measures used by other companies.

                                       19
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The following table presents Earnings (Loss) Attributable to AEP Common
Shareholders by segment:
                                                                 Three Months Ended March
                                                                           31,
                                                                              2021                     2020
                                                                                      (in millions)
Vertically Integrated Utilities                                        $         270.4          $         245.3
Transmission and Distribution Utilities                                          114.4                    116.2
AEP Transmission Holdco                                                          172.0                    140.6
Generation & Marketing                                                            36.6                     28.4
Corporate and Other                                                              (18.4)                   (35.3)
Earnings Attributable to AEP Common Shareholders                       $         575.0          $         495.2



AEP CONSOLIDATED

First Quarter of 2021 Compared to First Quarter of 2020

Earnings Attributable to AEP Common Shareholders increased from $495 million in 2020 to $575 million in 2021 primarily due to:

•An increase in weather-related usage in the residential customer class. •Favorable rate proceedings in AEP's various jurisdictions.

These increases were partially offset by:

•A decrease in usage in the commercial and industrial customer classes.

                                       20
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VERTICALLY INTEGRATED UTILITIES

Three Months Ended

                                                                           March 31,
             Vertically Integrated Utilities                                     2021                   2020
                                                                                        (in millions)
Revenues                                                                   $     2,537.3          $     2,226.7
Fuel and Purchased Electricity                                                     859.0                  671.2

Gross Margin                                                                     1,678.3                1,555.5
Other Operation and Maintenance                                                    740.2                  691.3

Depreciation and Amortization                                                      432.1                  381.7
Taxes Other Than Income Taxes                                                      123.5                  117.1
Operating Income                                                                   382.5                  365.4

Other Income                                                                         0.7                    1.6
Allowance for Equity Funds Used During Construction                                  9.9                    8.2
Non-Service Cost Components of Net Periodic Benefit Cost                            17.0                   16.9
Interest Expense                                                                  (139.6)                (144.5)

Income Before Income Tax Expense (Benefit) and Equity Earnings

                                                                           270.5                  247.6
Income Tax Expense (Benefit)                                                        (0.2)                   2.1
Equity Earnings of Unconsolidated Subsidiary                                         0.7                    0.8
Net Income                                                                         271.4                  246.3
Net Income Attributable to Noncontrolling Interests                                  1.0                    1.0
Earnings Attributable to AEP Common Shareholders                           $       270.4          $       245.3



        Summary of KWh Energy Sales for Vertically Integrated Utilities
                                          Three Months Ended March 31,
                                          2021                       2020
                                              (in millions of KWhs)
                  Retail:
                  Residential           9,481                        8,262
                  Commercial            5,258                        5,366
                  Industrial            7,702                        8,475
                  Miscellaneous           519                          530
                  Total Retail         22,960                       22,633

                  Wholesale (a)         4,642                        3,618

                  Total KWhs           27,602                       26,251

(a)Includes Off-system Sales, municipalities and cooperatives, unit power and other wholesale customers.

                                       21
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Heating degree days and cooling degree days are metrics commonly used in the
utility industry as a measure of the impact of weather on revenues. In general,
degree day changes in the eastern region have a larger effect on revenues than
changes in the western region due to the relative size of the two regions and
the number of customers within each region.

 Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities
                                              Three Months Ended March 31,
                                              2021                       2020
                                                    (in degree days)
               Eastern Region
               Actual - Heating (a)         1,539                       1,241
               Normal - Heating (b)         1,600                       1,611

               Actual - Cooling (c)             3                          13
               Normal - Cooling (b)             4                           5

               Western Region
               Actual - Heating (a)           958                         649
               Normal - Heating (b)           866                         867

               Actual - Cooling (c)            26                          51
               Normal - Cooling (b)            28                          28

(a)Heating degree days are calculated on a 55 degree temperature base. (b)Normal Heating/Cooling represents the thirty-year average of degree days. (c)Cooling degree days are calculated on a 65 degree temperature base.

                                       22
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First Quarter of 2021 Compared to First Quarter of 2020

                   Reconciliation of First Quarter of 2020 to First Quarter 

of 2021

        Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
                                            (in millions)

First Quarter of 2020                                                                  $      245.3

Changes in Gross Margin:
Retail Margins                                                                                 95.5
Margins from Off-system Sales                                                                  20.8
Transmission Revenues                                                                          10.3
Other Revenues                                                                                 (3.8)
Total Change in Gross Margin                                                                  122.8

Changes in Expenses and Other:
Other Operation and Maintenance                                                               (48.9)

Depreciation and Amortization                                                                 (50.4)
Taxes Other Than Income Taxes                                                                  (6.4)

Other Income                                                                                   (0.9)
Allowance for Equity Funds Used During Construction                                             1.7
Non-Service Cost Components of Net Periodic Pension Cost                                        0.1
Interest Expense                                                                                4.9
Total Change in Expenses and Other                                                            (99.9)

Income Tax Expense                                                                              2.3
Equity Earnings of Unconsolidated Subsidiary                                                   (0.1)

First Quarter of 2021                                                                  $      270.4

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

•Retail Margins increased $96 million primarily due to the following:
•A $61 million increase in weather-related usage primarily in the eastern region
and primarily in the residential class.
•A $17 million increase in municipal and cooperative revenues at SWEPCo
primarily due to the February 2021 severe winter weather event.
•A $15 million increase at KPCo due to rider revenues. This increase was
partially offset in other expense items below.
•A $14 million increase at APCo and WPCo due to revenue from rate riders
primarily in West Virginia. This increase was partially offset in other expense
items below.
•A $2 million increase in revenue from rate riders at PSO. This increase was
partially offset in other expense items below.
•The effect of rate proceedings in AEP's service territories which included:
•A $12 million increase at I&M due to the Indiana and Michigan base rate cases
and rider revenues. This increase was partially offset in other expense items
below.
•A $6 million increase at KPCo due to base rate case revenues implemented in
January 2021.
These increases were partially offset by:
•A $23 million decrease in weather-normalized retail margins driven by a $41
million decrease in the commercial and industrial customer classes partially
offset by an $18 million increase in the residential customer class.
•A $16 million decrease in weather-normalized wholesale margins, including the
loss of a significant wholesale contract at I&M.
                                       23
--------------------------------------------------------------------------------

•A $5 million decrease related to Tax Reform primarily due to an increase in
customer refunds at KPCo. This decrease was partially offset in Income Tax
Expense below.
•Margins from Off-system Sales increased $21 million primarily due to Turk Plant
merchant sales as a result of the February 2021 severe winter weather event at
SWEPCo.
•Transmission Revenues increased $10 million due to an increase in transmission
investment.
•Other Revenues decreased $4 million primarily due to decreased pole attachment
revenue at APCo and a decrease in rental revenue at WPCo and KPCo.

Expenses and Other changed between years as follows:

•Other Operation and Maintenance expenses increased $49 million primarily due to
the following:
•A $37 million increase in transmission services.
•A $16 million increase due to distribution reliability primarily related to
vegetation management. This increase was offset in Gross Margin above.
•A $5 million increase due to storms primarily at KPCo, SWEPCo and I&M.
•A $4 million increase due to a decreased Nuclear Electric Insurance Limited
distribution in 2021.
These increases were partially offset by:
•An $11 million decrease in employee-related expenses.
•Depreciation and Amortization expenses increased $50 million primarily due to a
higher depreciable base and an increase in depreciation rates at I&M. This
increase was partially offset in Gross Margin above.
•Taxes Other Than Income Taxes increased $6 million primarily due to increased
property taxes at SWEPCo resulting from the expiration of the Louisiana
Industrial Tax Exemption related to the Stall Plant.
•Interest Expense decreased $5 million primarily due to a decrease in interest
rates on variable rate notes at I&M.

                                       24
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TRANSMISSION AND DISTRIBUTION UTILITIES

Three Months Ended

March 31,

        Transmission and Distribution Utilities                                  2021                   2020
                                                                                        (in millions)
Revenues                                                                   $     1,088.1          $     1,106.9
Purchased Electricity                                                              205.5                  191.4

Gross Margin                                                                       882.6                  915.5
Other Operation and Maintenance                                                    365.2                  367.2

Depreciation and Amortization                                                      172.7                  214.5
Taxes Other Than Income Taxes                                                      157.6                  146.2
Operating Income                                                                   187.1                  187.6
Interest and Investment Income                                                       0.4                    0.7
Carrying Costs Income                                                                0.5                    0.4

Allowance for Equity Funds Used During Construction                                  6.8                    7.0
Non-Service Cost Components of Net Periodic Benefit Cost                             7.3                    7.3
Interest Expense                                                                   (74.5)                 (71.4)
Income Before Income Tax Expense                                                   127.6                  131.6
Income Tax Expense                                                                  13.2                   15.4
Net Income                                                                         114.4                  116.2
Net Income Attributable to Noncontrolling Interests                                    -                      -
Earnings Attributable to AEP Common Shareholders                           $       114.4          $       116.2



    Summary of KWh Energy Sales for Transmission and Distribution Utilities
                                           Three Months Ended March 31,
                                           2021                       2020
                                               (in millions of KWhs)
                Retail:
                Residential              6,924                        6,300
                Commercial               5,576                        5,873
                Industrial               5,281                        5,908
                Miscellaneous              166                          182
                Total Retail (a)        17,947                       18,263

                Wholesale (b)              603                          390

                Total KWhs              18,550                       18,653

(a) Represents energy delivered to distribution customers. (b) Primarily Ohio's contractually obligated purchases of OVEC power sold to PJM.

                                       25
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Heating degree days and cooling degree days are metrics commonly used in the
utility industry as a measure of the impact of weather on revenues. In general,
degree day changes in the eastern region have a larger effect on revenues than
changes in the western region due to the relative size of the two regions and
the number of customers within each region.

  Summary of Heating and Cooling Degree Days for Transmission and Distribution
                                   Utilities
                                              Three Months Ended March 31,
                                              2021                       2020
                                                    (in degree days)
               Eastern Region
               Actual - Heating (a)         1,777                       1,473
               Normal - Heating (b)         1,883                       1,898

               Actual - Cooling (c)             -                           3
               Normal - Cooling (b)             3                           3

               Western Region
               Actual - Heating (a)           315                          91
               Normal - Heating (b)           185                         185

               Actual - Cooling (d)           137                         231
               Normal - Cooling (b)           126                         125



(a)Heating degree days are calculated on a 55 degree temperature base.
(b)Normal Heating/Cooling represents the thirty-year average of degree days.
(c)Eastern Region cooling degree days are calculated on a 65 degree temperature
base.
(d)Western Region cooling degree days are calculated on a 70 degree temperature
base.

                                       26
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First Quarter of 2021 Compared to First Quarter of 2020

                  Reconciliation of First Quarter of 2020 to First Quarter 

of 2021

   Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
                                           (in millions)

First Quarter of 2020                                                                $      116.2

Changes in Gross Margin:
Retail Margins                                                                               24.8
Margins from Off-system Sales                                                               (37.4)
Transmission Revenues                                                                        12.4
Other Revenues                                                                              (32.7)
Total Change in Gross Margin                                                                (32.9)

Changes in Expenses and Other:
Other Operation and Maintenance                                                               2.0
Depreciation and Amortization                                                                41.8
Taxes Other Than Income Taxes                                                               (11.4)
Interest and Investment Income                                                               (0.3)
Carrying Costs Income                                                                         0.1
Allowance for Equity Funds Used During Construction                                          (0.2)

Interest Expense                                                                             (3.1)
Total Change in Expenses and Other                                                           28.9

Income Tax Expense                                                                            2.2

First Quarter of 2021                                                                $      114.4

The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of purchased electricity were as follows:

•Retail Margins increased $25 million primarily due to the following:
•A $58 million net increase in Ohio Basic Transmission Cost Rider revenues and
recoverable PJM expenses. This increase was partially offset in Other Operation
and Maintenance expenses below.
•A $19 million increase in weather-related usage in Texas primarily due to a
246% increase in heating degree days, partially offset by a 41% decrease in
cooling degree days.
•A $10 million increase from interim rate increases driven by increased
distribution investment in Texas.
•A $6 million increase in the Legacy Generation Resource Rider (LGRR) in Ohio.
This increase was offset in Margins from Off-system Sales and Other Revenues
below.
•A $6 million increase from interim rate increases driven by increased
transmission investment in Texas.
•A $5 million increase in rider revenues in Ohio associated with the DIR. This
increase was partially offset in other expense items below.
•A $5 million increase in revenues associated with a vegetation management rider
in Ohio. This increase was partially offset in Other Operation and Maintenance
expenses below.
These increases were partially offset by:
•A $27 million decrease due to the ending of the Energy Efficiency and Peak
Demand Rider in Ohio in December 2020. This decrease was partially offset in
Other Operation and Maintenance expenses below.
•A $25 million decrease in weather-normalized margins in Texas primarily in the
residential and commercial classes.
•A $16 million decrease in revenues in Ohio associated with the Universal
Service Fund (USF). This decrease was offset in Other Operation and Maintenance
expenses below.
•A $15 million decrease due to refunds in Texas of Excess ADIT and excess
federal income taxes collected as a result of Tax Reform.

                                       27
--------------------------------------------------------------------------------

•Margins from Off-system Sales decreased $37 million primarily due to the
following:
•A $30 million decrease in Texas due to lower Oklaunion Power Station PPA
revenues. Oklaunion Power Station was retired in September 2020 and sold to a
nonaffiliated third-party in October 2020. This decrease was partially offset in
Depreciation and Amortization expenses below.
•A $14 million decrease in Ohio primarily due to unfavorable deferrals of OVEC
costs. This decrease was offset in Retail Margins above and Other Revenues
below.
•Transmission Revenues increased $12 million primarily due to the following:
•A $19 million increase from interim rate increases driven by increased
transmission investment in Texas.
This increase was partially offset by:
•A $4 million decrease due to refunds to customers associated with the most
recent base rate case in Texas. This decrease was offset in Other Revenues
below.
•Other Revenues decreased $33 million primarily due to the following:
•A $46 million decrease in securitization revenues primarily due to the AEP
Texas Central Transition Funding II LLC bonds that matured in July 2020. This
decrease was offset in Depreciation and Amortization expenses and Interest
Expense below.
This decrease was partially offset by:
•An $8 million increase in revenues due to the amortization of a provision for
refund recorded as part of the most recent base rate case in Texas. This
increase was partially offset in Retail Margins and Transmission Revenues above.
•A $6 million increase primarily due to third-party LGRR revenue related to the
recovery of OVEC costs in Ohio. This increase was offset in Retail Margins and
Margins from Off-system Sales above.

Expenses and Other changed between years as follows:

•Other Operation and Maintenance expenses decreased $2 million primarily due to
the following:
•A $22 million decrease in energy efficiency/demand side management expenses in
Ohio. This decrease was partially offset in Retail Margins above.
•A $20 million decrease in Texas due to lower Oklaunion Power Station PPA
expenses. Oklaunion Power Station was retired in September 2020 and sold to a
nonaffiliated third-party in October 2020. This decrease was offset in Gross
Margin above.
•A $16 million decrease in remitted USF surcharge payments to the Ohio
Department of Development to fund an energy assistance program for qualified
Ohio customers. This decrease was offset in Retail Margins above.
•A $7 million decrease in factored Customers Accounts Receivable expenses in
Ohio primarily due to a current year adjustment to allowance for doubtful
accounts.
These decreases were partially offset by:
•A $61 million increase in transmission expenses primarily due to an increase in
PJM recoverable expenses. This increase was offset in Gross Margin above.
•A $5 million increase in recoverable distribution expenses in Ohio primarily
related to vegetation management. This increase was offset in Retail Margins
above.
•Depreciation and Amortization expenses decreased $42 million primarily due to
the following:
•A $44 million decrease in securitization amortizations in Texas related
primarily to the AEP Texas Central Transition Funding II LLC bonds that matured
in July 2020. The securitization decrease was offset in Other Revenues above.
•A $16 million decrease in depreciation expense due to the retirement of the
Oklaunion Power Station in September 2020. This decrease was partially offset
above in Margins from Off-system Sales and Other Operation and Maintenance
expenses.
These decreases were partially offset by:
•A $16 million increase in depreciation expense due to an increase in the
depreciable base of transmission and distribution assets.


                                       28
--------------------------------------------------------------------------------

•Taxes Other Than Income Taxes increased $11 million primarily due to increased
property taxes driven by additional investments in transmission and distribution
assets and higher tax rates.
•Interest Expense increased $3 million primarily due to higher long-term debt
balances.

                                       29
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AEP TRANSMISSION HOLDCO
                                                                       Three Months Ended
                                                                           March 31,
                AEP Transmission Holdco                                          2021                   2020
                                                                                        (in millions)
Transmission Revenues                                                      $       377.0          $       310.2
Other Operation and Maintenance                                                     27.2                   29.9
Depreciation and Amortization                                                       72.7                   58.1
Taxes Other Than Income Taxes                                                       59.2                   51.9
Operating Income                                                                   217.9                  170.3
Interest and Investment Income                                                       0.2                    0.9

Allowance for Equity Funds Used During Construction                                 16.7                   16.2
Non-Service Cost Components of Net Periodic Benefit Cost                             0.5                    0.5
Interest Expense                                                                   (35.3)                 (30.8)
Income Before Income Tax Expense and Equity Earnings                               200.0                  157.1
Income Tax Expense                                                                  45.8                   38.4
Equity Earnings of Unconsolidated Subsidiary                                        19.0                   22.9
Net Income                                                                         173.2                  141.6
Net Income Attributable to Noncontrolling Interests                                  1.2                    1.0
Earnings Attributable to AEP Common Shareholders                           $       172.0          $       140.6



    Summary of Investment in Transmission Assets for AEP Transmission Holdco
                                                                  March 31,
                                                             2021            2020
                                                                (in millions)
         Plant in Service                                $ 10,549.3      $  

9,086.6

         Construction Work in Progress                      1,635.9         

1,576.3

         Accumulated Depreciation and Amortization            648.1         

464.0

         Total Transmission Property, Net                $ 11,537.1      $ 

10,198.9

                                       30
--------------------------------------------------------------------------------

First Quarter of 2021 Compared to First Quarter of 2020

Reconciliation of First Quarter of 2020 to First Quarter of 2021

 Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
                                 (in millions)
          First Quarter of 2020                                     $ 140.6

          Changes in Transmission Revenues:
          Transmission Revenues                                        66.8
          Total Change in Transmission Revenues                        66.8

          Changes in Expenses and Other:
          Other Operation and Maintenance                               2.7
          Depreciation and Amortization                               (14.6)
          Taxes Other Than Income Taxes                                (7.3)
          Interest and Investment Income                               (0.7)

          Allowance for Equity Funds Used During Construction           0.5

          Interest Expense                                             (4.5)
          Total Change in Expenses and Other                          (23.9)

          Income Tax Expense                                           (7.4)
          Equity Earnings of Unconsolidated Subsidiary                 (3.9)
          Net Income Attributable to Noncontrolling Interests          (0.2)

          First Quarter of 2021                                     $ 172.0

The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and nonaffiliates, were as follows:

•Transmission Revenues increased $67 million primarily due to continued investment in transmission assets.

Expenses and Other, Income Tax Expense and Equity Earnings of Unconsolidated Subsidiary changed between years as follows:

•Depreciation and Amortization expenses increased $15 million primarily due to a
higher depreciable base.
•Taxes Other Than Income Taxes increased $7 million primarily due to higher
property taxes as a result of increased transmission investment.
•Interest Expense increased $5 million primarily due to higher long-term debt
balances.
•Income Tax Expense increased $7 million primarily due to an increase in pretax
book income.
•Equity Earnings of Unconsolidated Subsidiary decreased $4 million primarily due
to lower pretax equity earnings for PATH-WV.
                                       31
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GENERATION & MARKETING
                                                                       Three Months Ended
                                                                           March 31,
                 Generation & Marketing                                          2021                   2020
                                                                                        (in millions)
Revenues                                                                   $       634.2          $       438.6
Fuel, Purchased Electricity and Other                                              565.9                  360.3

Gross Margin                                                                        68.3                   78.3
Other Operation and Maintenance                                                     28.2                   41.4

Depreciation and Amortization                                                       18.6                   17.7
Taxes Other Than Income Taxes                                                        2.6                    3.4
Operating Income                                                                    18.9                   15.8
Interest and Investment Income                                                       0.5                    1.0

Non-Service Cost Components of Net Periodic Benefit Cost                             3.8                    3.9
Interest Expense                                                                    (3.3)                  (8.5)
Income Before Income Tax Benefit and Equity Earnings                                19.9                   12.2
Income Tax Benefit                                                                 (15.1)                 (12.4)
Equity Earnings of Unconsolidated Subsidiaries                                       3.2                    5.9
Net Income                                                                          38.2                   30.5
Net Earnings Attributable to Noncontrolling Interests                                1.6                    2.1
Earnings Attributable to AEP Common Shareholders                           $        36.6          $        28.4



              Summary of MWhs Generated for Generation & Marketing
                                             Three Months Ended
                                                  March 31,
                                           2021                  2020
                                            (in millions of MWhs)
                        Fuel Type:
                        Coal                 1                     1
                        Renewables           1                     1

                        Total MWhs           2                     2


                                       32

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First Quarter of 2021 Compared to First Quarter of 2020

                   Reconciliation of First Quarter of 2020 to First Quarter 

of 2021

             Earnings Attributable to AEP Common Shareholders from

Generation & Marketing
                                            (in millions)

First Quarter of 2020                                                                  $       28.4

Changes in Gross Margin:
Merchant Generation                                                                             4.0
Renewable Generation                                                                            5.3
Retail, Trading and Marketing                                                                 (19.3)
Total Change in Gross Margin                                                                  (10.0)

Changes in Expenses and Other:
Other Operation and Maintenance                                                                13.2

Depreciation and Amortization                                                                  (0.9)
Taxes Other Than Income Taxes                                                                   0.8
Interest and Investment Income                                                                 (0.5)

Non-Service Cost Components of Net Periodic Benefit Cost                                       (0.1)
Interest Expense                                                                                5.2
Total Change in Expenses and Other                                                             17.7

Income Tax Expense                                                                              2.7
Equity Earnings of Unconsolidated Subsidiaries                                                 (2.7)
Net Earnings Attributable to Noncontrolling Interests                                           0.5

First Quarter of 2021                                                                  $       36.6

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

•Merchant Generation increased $4 million primarily due to lower PPA expenses
resulting from the retirement of the Oklaunion Power Station.
•Renewable Generation increased $5 million primarily due to higher market
revenues from wind assets in the ERCOT region.
•Retail, Trading and Marketing decreased $19 million due to lower trading and
retail margins due to unprecedented cold temperatures and record market prices
in February 2021.

Expenses and Other changed between years as follows:

•Other Operation and Maintenance expenses decreased $13 million primarily due to
the following:
•An $8 million decrease due the retirement of Conesville Plant Unit 4 in 2020.
•A $6 million decrease due to gains recorded on the sale of land.
•Interest Expense decreased $5 million due to lower borrowing costs in 2021.

                                       33
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CORPORATE AND OTHER

First Quarter of 2021 Compared to First Quarter of 2020

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $35 million in 2020 to a loss of $18 million in 2021 primarily due to:

•A $17 million unrealized gain from an investment in ChargePoint. •A $12 million decrease in interest expense. •A $6 million increase in equity earnings.

These items were partially offset by:

•A $9 million increase in general corporate expenses. •An $8 million increase in Income Tax Expense due to an increase in pretax income and the recognition of a $4 million prior period adjustment in 2021.

AEP SYSTEM INCOME TAXES

First Quarter of 2021 Compared to First Quarter of 2020

Income Tax Expense increased $8 million primarily due to an increase in pretax book income partially offset with an increase in production tax credits.

                                       34
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FINANCIAL CONDITION

AEP measures financial condition by the strength of its balance sheets and the liquidity provided by its cash flows.

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization

                                                                March 31, 2021                              December 31, 2020
                                                                                    (dollars in millions)
Long-term Debt, including amounts due within one
year                                                 $     32,345.0                57.1  %       $       31,072.5                57.2  %
Short-term Debt                                             3,048.4                 5.4                   2,479.3                 4.6
Total Debt                                                 35,393.4                62.5                  33,551.8                61.8
AEP Common Equity                                          20,972.8                37.1                  20,550.9                37.8
Noncontrolling Interests                                      247.2                 0.4                     223.6                 0.4
Total Debt and Equity Capitalization                 $     56,613.4               100.0  %       $       54,326.3               100.0  %



AEP's ratio of debt-to-total capital increased from 61.8% as of December 31,
2020 to 62.5% as of March 31, 2021 primarily due to an increase in debt to help
address the cash flow implications resulting from the February 2021 severe
winter weather event in addition to supporting distribution, transmission and
renewable investment growth.

Liquidity

Liquidity, or access to cash, is an important factor in determining AEP's
financial stability. Management believes AEP has adequate liquidity under its
existing credit facilities. As of March 31, 2021, AEP had $5 billion of
revolving credit facilities to support its commercial paper program. Additional
liquidity is available from cash from operations and a receivables
securitization agreement. Management is committed to maintaining adequate
liquidity. AEP generally uses short-term borrowings to fund working capital
needs, property acquisitions and construction until long-term funding is
arranged. Sources of long-term funding include issuance of long-term debt,
leasing agreements, hybrid securities or common stock. In February 2021, severe
winter weather impacted certain AEP service territories resulting in disruptions
to SPP market conditions. In March 2021, AEP entered into a $500 million 364-day
Term Loan and borrowed the full amount to help address the cash flow
implications resulting from the February 2021 severe winter weather event. See
Note 4 - Rate Matters for additional information.

Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments. As of March 31, 2021, available liquidity was approximately $3.4 billion as illustrated in the table below:

                                                             Amount         

Maturity

     Commercial Paper Backup:                            (in millions)
                    Revolving Credit Facility           $      4,000.0       March 2026
                    Revolving Credit Facility                  1,000.0       March 2023
                    364-Day Term Loan                            500.0       March 2022

     Cash and Cash Equivalents                                   273.2
     Total Liquidity Sources                                   5,773.2
     Less:          AEP Commercial Paper Outstanding           1,874.4
                    364-Day Term Loan                            500.0

     Net Available Liquidity                            $      3,398.8



AEP uses its commercial paper program to meet the short-term borrowing needs of
its subsidiaries. The program funds a Utility Money Pool, which funds AEP's
utility subsidiaries; a Nonutility Money Pool, which funds certain AEP
nonutility subsidiaries; and the short-term debt requirements of subsidiaries
that are not participating in either money pool for regulatory or operational
reasons, as direct borrowers. The maximum amount of commercial paper outstanding
during the first three months of 2021 was $2 billion. The weighted-average
interest rate for AEP's commercial paper during 2021 was 0.24%.
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Other Credit Facilities

An uncommitted facility gives the issuer of the facility the right to accept or
decline each request made under the facility. AEP issues letters of credit on
behalf of subsidiaries under six uncommitted facilities totaling $425 million.
The Registrants' maximum future payments for letters of credit issued under the
uncommitted facilities as of March 31, 2021 was $183 million with maturities
ranging from April 2021 to March 2022.

Securitized Accounts Receivables

AEP's receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and expires in September 2022.

In March 2021, AEP Credit amended its receivables securitization agreement to
extend trigger levels established in October 2020 and to also provide a step
down approach to these levels as management continues to monitor the accounts
receivable balances across the affiliated utility subsidiaries in response to
the COVID-19 pandemic. As of March 31, 2021, the affiliated utility subsidiaries
are in compliance with all requirements under the agreement. To the extent that
an affiliated utility subsidiary is deemed ineligible under the agreement, the
affiliated utility subsidiary would no longer participate in the receivables
securitization agreement and the Registrants would need to rely on additional
sources of funding for operation and working capital, which may adversely impact
liquidity.

Debt Covenants and Borrowing Limitations

AEP's credit agreements contain certain covenants and require it to maintain a
percentage of debt-to-total capitalization at a level that does not exceed
67.5%. The method for calculating outstanding debt and capitalization is
contractually-defined in AEP's credit agreements. Debt as defined in the
revolving credit agreement excludes securitization bonds and debt of AEP Credit.
As of March 31, 2021, this contractually-defined percentage was 59.5%.
Non-performance under these covenants could result in an event of default under
these credit agreements. In addition, the acceleration of AEP's payment
obligations, or the obligations of certain of AEP's major subsidiaries, prior to
maturity under any other agreement or instrument relating to debt outstanding in
excess of $50 million, would cause an event of default under these credit
agreements.  This condition also applies in a majority of AEP's
non-exchange-traded commodity contracts and would similarly allow lenders and
counterparties to declare the outstanding amounts payable. However, a default
under AEP's non-exchange-traded commodity contracts would not cause an event of
default under its credit agreements.

The revolving credit facilities do not permit the lenders to refuse a draw on any facility if a material adverse change occurs.

Utility Money Pool borrowings and external borrowings may not exceed amounts
authorized by regulatory orders and AEP manages its borrowings to stay within
those authorized limits.

At-the-Market (ATM) Program

AEP participates in an ATM offering program that allows AEP to issue, from time
to time, up to an aggregate of $1 billion of its common stock, including shares
of common stock that may be sold pursuant to an equity forward sales agreement.
As of March 31, 2021, approximately $840 million of equity is available for
issuance under the ATM offering program. See Note 12 - Financing Activities for
additional information.

Equity Units

In August 2020, AEP issued 17 million Equity Units initially in the form of
corporate units, at a stated amount of $50 per unit, for a total stated amount
of $850 million. Net proceeds from the issuance were approximately $833 million.
Each corporate unit represents a 1/20 undivided beneficial ownership interest in
$1,000 principal amount of AEP's 1.30% Junior Subordinated Notes due in 2025 and
a forward equity purchase contract which settles after three years in 2023. The
proceeds were used to support AEP's overall capital expenditure plans.
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In March 2019, AEP issued 16.1 million Equity Units initially in the form of
corporate units, at a stated amount of $50 per unit, for a total stated amount
of $805 million. Net proceeds from the issuance were approximately $785 million.
Each corporate unit represents a 1/20 undivided beneficial ownership interest in
$1,000 principal amount of AEP's 3.40% Junior Subordinated Notes due in 2024 and
a forward equity purchase contract which settles after three years in 2022. The
proceeds from this issuance were used to support AEP's overall capital
expenditure plans including the acquisition of Sempra Renewables LLC.

See Note 12 - Financing Activities for additional information.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.74 per share in April
2021. Future dividends may vary depending upon AEP's profit levels, operating
cash flow levels and capital requirements, as well as financial and other
business conditions existing at the time. Parent's income primarily derives from
common stock equity in the earnings of its utility subsidiaries. Various
financing arrangements and regulatory requirements may impose certain
restrictions on the ability of the subsidiaries to transfer funds to Parent in
the form of dividends. Management does not believe these restrictions will have
any significant impact on its ability to access cash to meet the payment of
dividends on its common stock. See "Dividend Restrictions" section of Note 12
for additional information.

Credit Ratings

AEP and its utility subsidiaries do not have any credit arrangements that would
require material changes in payment schedules or terminations as a result of a
credit downgrade, but its access to the commercial paper market may depend on
its credit ratings. In addition, downgrades in AEP's credit ratings by one of
the rating agencies could increase its borrowing costs. Counterparty concerns
about the credit quality of AEP or its utility subsidiaries could subject AEP to
additional collateral demands under adequate assurance clauses under its
derivative and non-derivative energy contracts.

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