MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Customer Demand

AEP's weather-normalized retail sales volumes for the third quarter of 2022
increased by 2.6% from the third quarter of 2021. Weather-normalized residential
sales decreased by 0.8% in the third quarter of 2022 from the third quarter of
2021. AEP's third quarter 2022 industrial sales volumes increased by 6.0%
compared to the third quarter of 2021. The increase in industrial sales was
spread across many industries. Weather-normalized commercial sales increased
3.4% in the third quarter of 2022 from the third quarter of 2021. The increase
in commercial sales was spread across many sectors.

AEP's weather-normalized retail sales volumes for the nine months ended
September 30, 2022 increased by 3.1% compared to the nine months ended
September 30, 2021. Weather-normalized residential sales increased by 0.3% for
the nine months ended September 30, 2022 compared to the nine months ended
September 30, 2021. AEP's industrial sales volumes for the nine months ended
September 30, 2022 increased by 5.5% compared to the nine months ended
September 30, 2021. The increase in industrial sales was spread across many
industries. Weather-normalized commercial sales increased 3.8% for the nine
months ended September 30, 2022 compared to the nine months ended September 30,
2021. The increase in commercial sales was spread across many sectors.

Supply Chain Disruption and Inflation

The Registrants have experienced certain supply chain disruptions driven by
several factors including staffing and travel issues caused by the COVID-19
pandemic, international tensions including the ramifications of regional
conflict, increased demand due to the economic recovery from the pandemic,
inflation, labor shortages in certain trades and shortages in the availability
of certain raw materials. These supply chain disruptions have not had a material
impact on the Registrants net income, cash flows and financial condition, but
have extended lead times for certain goods and services and have contributed to
higher prices for fuel, materials, labor, equipment and other needed
commodities. Management has implemented risk mitigation strategies in an attempt
to mitigate the impacts of these supply chain disruptions. The United States
economy has encountered a significant level of inflation that has contributed to
increased uncertainty in the outlook of near-term economic activity, including
whether inflation will continue and at what rate. A prolonged continuation or a
further increase in the severity of supply chain and inflationary disruptions
could result in additional increases in the cost of certain goods and services
and further extend lead times which could reduce future net income and cash
flows and impact financial condition.

Strategic Evaluation of AEP Energy

AEP has initiated a strategic evaluation for its ownership in AEP Energy, a
wholly-owned retail energy supplier that supplies electricity and/or natural gas
to residential, commercial and industrial customers. AEP Energy provides various
energy solutions in Illinois, Pennsylvania, Delaware, Maryland, New Jersey, Ohio
and Washington, D.C. AEP Energy had approximately 672,000 customer accounts as
of September 30, 2022. Potential alternatives may include, but are not limited
to, continued ownership or a sale of all or a part of AEP Energy. Management has
not made a decision regarding the potential alternatives, but expects to
complete the strategic evaluation in the first half of 2023.

Federal Tax Legislation

On August 16, 2022, President Biden signed H.R. 5376 into law, commonly known as the Inflation Reduction Act of 2022 or IRA. Most notably this budget reconciliation legislation creates a 15% minimum tax on adjusted

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financial statement income (Corporate Alternative Minimum Tax or CAMT), extends
and increases the value of PTCs and ITCs, adds a nuclear and clean hydrogen PTC,
an energy storage ITC and allows the sale or transfer of tax credits to third
parties for cash. With the exception of PTCs and ITCs, this legislation is
prospective and has no material impact on the current period financial
statements. As significant guidance from Treasury and the IRS is expected on the
tax provisions in the IRA, AEP will continue to monitor any issued guidance and
evaluate the impact on future net income, cash flows and financial condition.

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 August 2022, the Virginia Supreme Court issued its opinion on submitted
appeals of APCo's 2017-2019 Virginia Triennial Review concluding that the
Virginia SCC: a) erred in finding it was not reasonable for APCo to record all
remaining costs associated with early retirement of certain coal-fired
generating plants in the 2017-2019 earnings test period, b) did not err by
ordering APCo to retroactively implement depreciation rates for the years 2018
and 2019 and c) did not err in finding that APCo's affiliate costs from OVEC
were reasonable. The Virginia Supreme Court then remanded the issue regarding
the retired coal-fired plants back to the Virginia SCC for further proceedings.

In September 2022, and in response to the Virginia Supreme Court opinion and
subsequent Virginia SCC order initiating a remand proceeding, APCo submitted to
the Virginia SCC: (a) an updated 2017-2019 Virginia earnings calculation
resulting in a proposed $37 million regulatory asset related to previously
incurred costs that APCo is expecting to recover as a result of earning below
its 2017-2019 authorized ROE band, (b) an updated requested annual base rate
increase of $41 million effective October 2022 and (c) a requested rider to
recover, over the period October 2022 through January 2024, approximately $72
million related to an APCo Virginia base rate increase for the period January
2021 through September 2022. APCo's requested $41 million annual base rate
increase includes approximately $12 million related to the recovery of APCo's
regulatory asset for previously incurred costs as a result of earning below its
2017-2019 authorized ROE band. APCo implemented interim base rate and rider rate
increases effective October 2022, both of which are subject to refund and review
by the Virginia SCC. An order from the Virginia SCC in the remand proceeding is
expected in the fourth quarter of 2022.

In September 2022, APCo expensed the remaining $25 million closed coal plant
regulatory asset that was previously ordered by the Virginia SCC and recorded a
$37 million regulatory asset for previously incurred costs that APCo is
expecting to recover as a result of earning below its 2017-2019 authorized ROE
band. APCo's October 2022 through January 2024 net income, cash flows and
financial condition is expected to be positively impacted pending the Virginia
SCC's order on APCo's requested base rate and rider rate increases.

•2020-2022 Virginia Triennial Review - In March 2023, APCo will submit its
required Virginia earnings test calculation for the 2020-2022 Triennial Review
period. For Triennial Review periods in which a Virginia utility earns below its
authorized ROE band, the utility may file to recover expenses incurred, up to
the bottom of the authorized ROE band, related to major storms, the early
retirement of fossil fuel generating
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assets and certain projects necessary to comply with state and federal
environmental legislation. As of September 2022, APCo has deferred approximately
$25 million related to previously incurred costs as a result of the current
estimate that APCo will earn below the bottom of its authorized ROE band during
the 2020-2022 Triennial Review period. If it is determined that APCo has earned
above the bottom of its authorized ROE band for the 2020-2022 Triennial Review
period it could reduce future net income and cash flows and impact financial
conditions.

•2012 Texas Base Rate Case - In 2012, SWEPCo filed a request with the PUCT to
increase annual base rates primarily due to the completion of the Turk Plant. In
2013, the PUCT issued an order affirming the prudence of the Turk Plant but
determined that the Turk Plant's Texas jurisdictional capital cost cap
established in a previous Certificate of Convenience and Necessity case also
limited SWEPCo's recovery of AFUDC. Upon rehearing in 2014, the PUCT reversed
its initial ruling and determined that AFUDC was excluded from the Turk Plant's
Texas jurisdictional capital cost cap. In 2017, the Texas District Court upheld
the PUCT's 2014 order and intervenors filed appeals with the Texas Third Court
of Appeals. In July 2018, the Texas Third Court of Appeals reversed the PUCT's
judgment affirming the prudence of the Turk Plant and remanded the issue back to
the PUCT. In January 2019, SWEPCo and the PUCT filed petitions for review with
the Texas Supreme Court.

In March 2021, the Texas Supreme Court issued an opinion reversing the July 2018
judgment of the Texas Third Court of Appeals and agreeing with the PUCT's
judgment affirming the prudence of the Turk Plant. In addition, the Texas
Supreme Court remanded the AFUDC dispute back to the Texas Third Court of
Appeals. No parties filed a motion for rehearing with the Texas Supreme Court.
In August 2021, the Texas Third Court of Appeals reversed the Texas District
Court judgment affirming the PUCT's order on AFUDC, concluding that the language
of the PUCT's original 2008 order intended to include AFUDC in the Texas
jurisdictional capital cost cap, and remanded the case to the PUCT for future
proceedings. SWEPCo disagrees with the Court of Appeals decision. SWEPCo and the
PUCT submitted Petitions for Review with the Texas Supreme Court in November
2021. In October 2022, the Texas Supreme Court denied the Petitions for Review
submitted by SWEPCo and the PUCT. SWEPCo plans to file a request for rehearing.
If SWEPCo's request for rehearing is denied, the case will be remanded to the
PUCT for future proceedings.

Management does not believe a disallowance of capitalized Turk Plant costs or a
revenue refund is probable as of September 30, 2022. However, if SWEPCo is
ultimately unable to recover AFUDC in excess of the Texas jurisdictional capital
cost cap it would be expected to result in a pretax net disallowance ranging
from $80 million to $90 million. In addition, if AFUDC is ultimately determined
to be included in the Texas jurisdictional capital cost cap, SWEPCo estimates it
may be required to make customer refunds ranging from $0 to $180 million related
to revenues collected from February 2013 through September 2022 and such
determination may reduce SWEPCo's future revenues by approximately $15 million
on an annual basis.

•In July 2019, 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 terminated energy efficiency programs as of
December 31, 2020, including OPCo's shared savings revenues of $26 million
annually and phased out renewable mandates after 2026. HB 6 also provided for
continued recovery of existing renewable energy contracts on a bypassable basis
through 2032 and included a provision for continued recovery of OVEC costs
through 2030 which is allocated to all electric distribution utility customers
in Ohio 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 an alleged racketeering conspiracy involving
the adoption of HB 6. Certain defendants in that case have since pleaded guilty.
In 2021, four AEP shareholders filed derivative actions purporting to
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assert claims on behalf of AEP against certain AEP officers and directors. 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,
repealed 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,
went into effect in May 2021 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 the law changes or 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 derivative actions, it could reduce future net income and cash flows
and impact financial condition.

•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 required 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 compliance filing to eliminate the incentive from its
tariff prospectively. The supplemental NOPR was subject to a 60 day comment
period followed by a 30 day period for reply comments. In July 2021, AEP
submitted reply comments. AEP is awaiting a final rule from the FERC.

In July 2021, the FERC issued an order denying Dayton Power and Light's request
for a 50 basis point RTO incentive on the basis that its RTO participation was
not voluntary, but rather is required by Ohio law. This precedent could have an
adverse impact on AEP's Ohio transmission owning subsidiaries. In its February
2022 order on rehearing, the FERC affirmed the decision in its July 2021 order.
The case is currently pending appeal at the United States Court of Appeals for
the Sixth Circuit. In May 2022, the United States Court of Appeals for the Sixth
Circuit issued an order to hold the appeal in abeyance pending resolution of
FERC proceedings on the Office of the Ohio Consumers' Counsel's February 2022
RTO Incentive Complaint.

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.

•FERC RTO Incentive Complaint - In February 2022, the Office of the Ohio
Consumers' Counsel filed a complaint against AEPSC, American Transmission
Systems, Inc. and Duke Energy Ohio, alleging the 50 basis point RTO incentive
included in Ohio Transmission Owners' respective transmission formula rates is
not just and reasonable and therefore should be eliminated on the basis that RTO
participation is not voluntary, but rather is required by Ohio law. In March
2022, AEPSC filed a motion to dismiss the Ohio Consumers' Counsel's February
2022 complaint with the FERC on the basis of certain deficiencies, including
that the complaint fails to request relief that can be granted under FERC
regulations because AEPSC is not a public utility nor does it have a
transmission rate on file with the FERC. Management believes its financial
statements adequately address the impact of the February 2022 complaint. If the
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FERC orders revenue reductions as a result of the complaint, including refunds
from the date of the complaint filing, it could reduce future net income and
cash flows and impact financial condition.

•2021 Louisiana Storm Cost Filing - In 2020, Hurricanes Laura and Delta caused
power outages and extensive damage to the SWEPCo service territories, primarily
impacting the Louisiana jurisdiction. Following both hurricanes, the LPSC issued
orders allowing Louisiana utilities, including SWEPCo, to establish regulatory
assets to track and defer expenses associated with these storms. In February
2021, severe winter weather impacted the Louisiana jurisdiction and in March
2021, the LPSC approved the deferral of incremental storm restoration expenses
related to the winter storm. In October 2021, SWEPCo filed a request with the
LPSC for recovery of $145 million in deferred storm costs associated with the
three storms. As part of the filing, SWEPCo requested recovery of the carrying
charges on the deferred regulatory asset at a weighted average cost of capital
through a rider beginning in January 2022. In May 2022, LPSC staff testimony was
submitted to the LPSC. In July 2022, SWEPCo filed rebuttal testimony which
agreed to make a request for securitization of the deferred storm costs as the
LPSC staff had recommended in their testimony. An order is expected before the
end of 2022. If any of the storm costs are not recoverable, it could reduce
future net income and cash flows and impact financial condition.

•In February 2021, severe winter weather 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. As a result of the severe winter weather, PSO and
SWEPCo incurred approximately $1.1 billion of extraordinary fuel costs and
purchases of electricity, which were deferred as regulatory assets.

In April 2021, the OCC approved the deferral of PSO's extraordinary fuel costs
and purchases of electricity as regulatory assets, including a carrying charge
at an interim rate of 0.75%, over a longer time period than what the FAC
traditionally allows. Also in April 2021, legislation was enacted in Oklahoma
permitting securitized financing of qualified costs from extreme weather events.
This legislation provides certain authority to the OCC to approve amounts to be
recovered from the issuance of ratepayer-backed securitized bonds issued by the
ODFA, an Oklahoma governmental agency. In January 2022, PSO, OCC staff and
certain intervenors filed a joint stipulation and settlement agreement with the
OCC to approve the securitization of PSO's extraordinary fuel costs and
purchases of electricity. In February 2022, the OCC approved the joint
stipulation and settlement agreement which included a determination that all of
PSO's extraordinary fuel costs and purchases of electricity were prudent and
reasonable and also provided a 0.75% carrying charge related to those costs,
subject to true-up based on actual financing costs.

In September 2022, PSO received proceeds of $687 million from the ODFA which
issued ratepayer-backed securitization bonds for the purpose of reimbursing PSO
for extraordinary fuel costs and purchases of electricity incurred during the
February 2021 severe winter weather event, which were previously recorded as
Regulatory Assets on PSO's balance sheet. The securitization bonds are the
obligation of the ODFA and there is no recourse against PSO in the event of a
bond default, and therefore are not recorded as Long-term Debt on PSO's balance
sheet. PSO will serve as the servicing agent of the bonds and is responsible for
the routine billing and collection of the securitization charges and remitting
those collections back to the ODFA. The securitization charges billed to and
collected from customers are not included as revenue on PSO's statement of
income. The collections from customers will occur over 20 years.

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. Subsequently,
SWEPCo began recovery of these fuel costs. In April 2021, SWEPCo filed testimony
supporting a five-year recovery with a carrying charge of 6.05%. In June 2022,
the APSC ordered SWEPCo to recover the Arkansas jurisdictional share of the fuel
costs over six years with a carrying charge equal to its weighted average cost
of capital, subject to a prudency review and true-up.

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In March 2021, the LPSC approved a special order granting a temporary
modification to the FAC and shortly after SWEPCo began recovery of its Louisiana
jurisdictional share of these fuel costs based on a five-year recovery period
inclusive of an interim carrying charge of 3.25%. SWEPCo will work with the LPSC
to finalize the actual recovery period and determine the appropriate carrying
charge in future proceedings.

In August 2021, SWEPCo filed an application with the PUCT to implement a net
interim fuel surcharge for the Texas jurisdictional share of these retail fuel
costs. The application requested a five-year recovery with a carrying charge of
7.18%. In March 2022, the PUCT ordered SWEPCo to recover the Texas
jurisdictional share of the fuel costs over five years with a carrying charge of
1.65% and ordered SWEPCo to file a fuel reconciliation addressing fuel costs
from January 1, 2020 through December 31, 2021.

As of September 30, 2022, SWEPCo had regulatory assets of $349 million relating
to natural gas expenses and purchases of electricity incurred during the
February 2021 severe winter weather event. SWEPCo's deferred regulatory asset
consists of $85 million, $126 million and $138 million related to the Arkansas,
Louisiana and Texas jurisdictions, respectively.

If SWEPCo is unable to recover any of the costs relating to the extraordinary
fuel and purchases of electricity, or obtain authorization of a reasonable
carrying charge on these costs, it could reduce future net income and cash flows
and impact financial condition.

•AEP transitioned to stand-alone treatment of NOLC in its PJM and SPP
transmission formula rates beginning with 2022 projected transmission revenue
requirements and 2021 true-up to actual transmission revenue requirements, and
provided notice of this change in informational filings made with the FERC.
Stand-alone treatment of the NOLCs for transmission formula rates increased the
2021 and 2022 annual revenue requirements by $78 million and $60 million,
respectively. Through the third quarter of 2022, the Registrants' financial
statements reflect a provision for refund for all NOLC revenues billed by PJM
and SPP. Also, the impact of inclusion of the NOLC in the 2021 annual formula
rate true-up not yet billed by PJM and SPP is not reflected in the Registrants'
revenues and expenses as the Registrants have not met the requirements of
alternative revenue recognition in accordance with the accounting guidance for
"Regulated Operations".

AEP is also transitioning to stand-alone treatment of NOLC in retail
jurisdiction base rate case filings. As a result of retail jurisdiction base
rate cases in Arkansas, Indiana, Oklahoma and Texas, inclusion of NOLCs in rates
in those jurisdictions is contingent upon a supportive private letter ruling
from the IRS.

•SPP Capacity Planning Reserve Margin - In July 2022, SPP approved a plan to
increase its capacity planning reserve margin from 12% to 15% starting in the
summer of 2023. Compliance filings are due to SPP in February 2023 and any
deficiencies are required to be remedied by May 2023. SPP's annual
non-compliance charge as a result of not meeting capacity requirements could
range from approximately $86 thousand per MW to approximately $171 thousand per
MW. Non-compliance could also result in a failure to meet NERC criteria and
violating SPP's tariff before FERC. As of September 30, 2022, the increase in
the capacity planning reserve margin for PSO and SWEPCo to comply with this new
SPP requirement is approximately 265 MWs. Management is currently evaluating
options and expects to comply with SPP's 2023 capacity planning reserve margin
requirements. If PSO or SWEPCo incur charges or are unable to recover, or
experience delays in recovering, the costs of complying with SPP's rule, it
could reduce future net income and cash flows and impact financial condition.


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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' completed and pending base rate case proceedings in 2022. 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)
        SWEPCo           Texas         $                39.4               

9.25% March 2021

          I&M           Indiana                         61.4    (a)        

9.7% February 2022

        SWEPCo          Arkansas                        48.7               9.5%           July 2022
         KGPCo         Tennessee                         5.8               

9.5% August 2022

(a)See "2021 Indiana Base Rate Case "Section of Note 4 - Rate Matters in the 2021 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)
    SWEPCo               Louisiana               December 2020            $                94.7              10.35%                 9.1%-9.8%




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Deferred Fuel Costs

Increased fuel and purchased power prices in excess of amounts included in
fuel-related revenues has led to an increase in the under collection of fuel
costs from customers in most jurisdictions. The table below illustrates the
increase (decrease) in the deferred fuel regulatory assets by company and
jurisdiction, excluding the impacts of the February 2021 severe winter weather
event. See the "February 2021 Severe Winter Weather Impacts in SPP" sections in
Note 4 for additional information.

                                                   Traditional FAC                   As of                       As of                  Increase/
   Company              Jurisdiction               Recovery Reset             September 30, 2022           December 31, 2021            (Decrease)
APCo                 Virginia (a)                             Annually       $            359.5          $            128.6          $       230.9
APCo                 West Virginia                            Annually                    235.2                        72.7                  162.5
I&M                  Indiana                               Bi-Annually                     19.2                           -                   19.2
I&M                  Michigan                                 Annually                      6.2                         6.4                   (0.2)
PSO                  Oklahoma (b)                             Annually                    419.9                       194.6                  225.3
SWEPCo               Arkansas                                 Annually                     67.7                        23.1                   44.6
SWEPCo               Louisiana                                 Monthly                      2.4                        11.1                   (8.7)
SWEPCo               Texas                                Tri-Annually                    165.9                        47.0                  118.9
KPCo                 Kentucky                                  Monthly                     24.4                         8.2                   16.2
WPCo                 West Virginia                            Annually                    195.2                       101.6                   93.6
                                                             Total (c)       $          1,495.6          $            593.3          $       902.3



(a)Includes $191 million of noncurrent deferred fuel classified as a Regulatory
Asset on APCo's balance sheets as of September 30, 2022.
(b)Includes $241 million of noncurrent deferred fuel classified as a Regulatory
Asset on PSO's balance sheets as of September 30, 2022.
(c)Includes $24 million and $8 million as of September 30, 2022 and December 31,
2021, respectively, of deferred fuel classified as Assets Held for Sale on the
balance sheets. See "Disposition of KPCo and KTCo" section of Note 6 for
additional information.

The AEP utility subsidiaries are working with various state commissions on the
timing of recovering deferred fuel balances and have made the following recent
filings:

In April 2022, APCo and WPCo submitted their 2022 annual ENEC filing with the
WVPSC requesting a $297 million annual increase in ENEC revenues, effective
September 1, 2022. The WVPSC requested West Virginia staff perform a prudency
review of APCo and WPCo's actual and forecasted ENEC costs. Management expects
to receive a WVPSC order on the 2022 ENEC filing in the fourth quarter of 2022
and a separate WVPSC order on the prudency review of the ENEC costs in the first
quarter of 2023. See "2021 and 2022 ENEC Filings" section of Note 4 for
additional information.

In August 2022, PSO requested an interim update to its annual Fuel Cost
Adjustment (FCA) rates in accordance with the terms of the established tariff
which allows PSO or the OCC staff to request an interim FCA adjustment in the
event that the annual FCA over/under-recovered balance is $50 million or more on
a cumulative basis. In September 2022, the Director of the Public Utility
Division of the OCC approved a FCA rate designed to collect a $402 million
deferred fuel balance over a 27 month period, effective with the first billing
cycle of October 2022. PSO's fuel and purchased power expenses are subject to an
annual prudency review by the OCC.

In September 2022, APCo submitted a request to the Virginia SCC to increase its
annual fuel factor by approximately $279 million. APCo will implement interim
FAC rates effective November 2022 subject to Virginia SCC review. To help
mitigate the impact of rising fuel costs on customer bills, APCo proposed to
recover its
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deferred fuel balance as of October 31, 2022 over two years. An order from the Virginia SCC is expected in the first quarter of 2023.

In September 2022, SWEPCo filed a request with the APSC for an interim increase
to its current Energy Cost Rate (ECR) to recover $44 million of additional fuel
costs incurred from April 2022 through August 2022, subsequent to the last
annual ECR rate change. The interim rate will be effective with the first
billing cycle of October 2022 and will be in effect for six months until the ECR
is reset in April 2023.

Dolet Hills Power Station and Related Fuel Operations

In 2020, 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. In
April 2020, SWEPCo and CLECO jointly filed a notification letter to the LPSC
providing notice of the cessation of lignite mining. In December 2021, the Dolet
Hills Power Station was retired. While in operation, DHLC provided 100% of the
fuel supply to Dolet Hills Power Station.

The remaining book value of Dolet Hills Power Station non-fuel related assets
are recoverable by SWEPCo through a combination of base rates and rate riders.
As of September 30, 2022, SWEPCo's share of the net investment in the Dolet
Hills Power Station was $113 million, including materials and supplies, net of
cost of removal collected in rates.

Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo
through active fuel clauses and are subject to prudency determinations by the
various commissions. After closure of the DHLC mining operations and the Dolet
Hills Power Station, additional reclamation and other land-related costs
incurred by DHLC and Oxbow will continue to be billed to SWEPCo and included in
existing fuel clauses. As of September 30, 2022, SWEPCo had a net
under-recovered fuel balance of $236 million, inclusive of costs related to the
Dolet Hills Power Station billed by DHLC, but excluding impacts of the February
2021 severe winter weather event.

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
August 2022, the LPSC staff filed testimony recommending fuel disallowances of
$72 million, including denial of recovery of the $30 million deferral, with
refunds to customers over five years. In September 2022, SWEPCO filed rebuttal
testimony addressing the LPSC staff recommendations.

In March 2021, the APSC approved fuel rates that provide recovery of $20 million
for the Arkansas share of the 2021 Dolet Hills Power Station fuel costs over
five years through the existing fuel clause.

In August 2022, SWEPCo filed a fuel reconciliation with the PUCT covering the fuel period of January 1, 2020 through December 31, 2021.

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

Pirkey Plant and Related Fuel Operations

In 2020, management announced plans to retire the Pirkey Plant in 2023. The
Pirkey Plant non-fuel costs are recoverable by SWEPCo through base rates and
fuel costs are recovered through active fuel clauses and are subject to prudency
determinations by the various commissions. As of September 30, 2022, SWEPCo's
share of the net investment in the Pirkey Plant was $216 million, including
CWIP, before cost of removal. Sabine is a mining operator providing mining
services to the Pirkey 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
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related activities were $49 million as of September 30, 2022. As of
September 30, 2022, SWEPCo had a net under-recovered fuel balance of
$236 million, inclusive of costs related to the Pirkey Plant billed by Sabine,
but excluding impacts of the February 2021 severe winter weather event. Upon
cessation of lignite deliveries by Sabine to the Pirkey Plant, additional
operational, reclamation and other land-related costs incurred by Sabine will be
billed to SWEPCo and included in existing fuel clauses. If any of these costs
are not recoverable, it could reduce future net income and cash flows and impact
financial condition.

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

In recent years, AEP has developed its renewable portfolio within the Generation
& Marketing segment. Other activities have included, but are not limited to,
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 developed and/or acquired large scale renewable generation projects
that are backed with long-term contracts with creditworthy counterparties.

In February 2022, AEP management announced the initiation of a process to sell
all or a portion of AEP Renewables' competitive contracted renewables portfolio
within the Generation & Marketing segment. Subsequently, AEP's investment in
Flat Ridge 2 Wind LLC was removed from the competitive contracted renewables
sale portfolio. In June 2022, as a result of deteriorating financial
performance, sale negotiations and AEP's ongoing evaluation and ultimate
decision to exit the investment in the near term, AEP recorded a pretax other
than temporary impairment charge of $186 million in Equity Earnings (Losses) of
Unconsolidated Subsidiaries in AEP's Statement of Income. In the third quarter
of 2022, AEP recorded an additional $2 million pretax other than temporary
impairment charge. The carrying value of AEP's investment in Flat Ridge 2 was
not material to AEP as of September 30, 2022. In September 2022, AEP signed a
Purchase and Sale Agreement with a nonaffiliate for AEP's interest in Flat Ridge
2, subject to FERC approval. Management expects the transaction to close in the
fourth quarter of 2022 and have an immaterial impact on the financial
statements. See "Impairments" section of Note 6 for additional information.

As of September 30, 2022, excluding Flat Ridge 2, the competitive contracted
renewable portfolio assets totaled 1.4 gigawatts of generation resources
representing consolidated solar and wind assets, with a net book value of $1.2
billion, and a 50% interest in five joint venture wind farms, totaling $246
million, accounted for as equity method investments. The anticipated disposition
of all or a portion of the AEP Renewables' portfolio has not met the accounting
requirements to be presented as Held for Sale as of September 30, 2022. If AEP
is unable to recover the book value or carrying value of these assets through a
sales process, it could reduce future net income and impact financial condition.


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Regulated Renewable Generation Facilities

North Central Wind Facilities

In 2020, PSO and SWEPCo received regulatory approvals to acquire the NCWF,
comprised of three Oklahoma wind facilities totaling 1,484 MWs, on a fixed cost
turn-key basis at completion. PSO and SWEPCo own undivided interests of 45.5%
and 54.5% of the NCWF, respectively. Output from the NCWF serves retail load in
PSO's Oklahoma service territory and both retail and FERC wholesale load in
SWEPCo's service territories in Arkansas and Louisiana. The Oklahoma and
Louisiana portions of the NCWF revenue requirement, net of PTC benefit, are
recoverable through authorized riders beginning at commercial operation and
until such time as amounts are reflected in base rates. The Arkansas portion of
the NCWF revenue requirement was approved for recovery through base rates in the
2021 Arkansas Base Rate Case. The table below provides a summary of the
facilities as of September 30, 2022:
    Project                 In-Service Date              Net Book Value         Federal PTC Qualification % (a)            Generating Capacity
                                                          (in millions)                                                          (in MWs)
Sundance               April 2021                       $        282.3                                    100  %                      199
Maverick               September 2021                            398.3                                     80  %                      287
Traverse               March 2022                              1,255.0                                    100  %    (b)               998



(a)PTC benefits are available for a ten year period following the in-service
date.
(b)The PTC for Traverse was increased to 100% in the third quarter of 2022 as a
result of the IRA legislation.

See "North Central Wind Energy Facilities" section of Note 6 for additional information.

Recent Renewable Generation Filings

In December 2021 and January 2022, APCo filed petitions with the Virginia SCC
and WVPSC, respectively, for prudency and cost recovery of: (a) an APCo-owned
204 MW wind generation facility, (b) three APCo-owned solar generation
facilities totaling 205 MWs and (c) three solar purchased power agreements
(PPAs) totaling 89 MWs. In June 2022, the WVPSC approved APCo's January 2022
petition for cost recovery of an APCo-owned 50 MW solar generation facility
which was included within the 205 MWs requested. In July 2022, the Virginia SCC
approved APCo's December 2021 petition for prudency and cost recovery as
submitted. An order from the WVPSC is anticipated in the fourth quarter of 2022
related to the remaining items in APCo's January 2022 petition. In September
2022, APCo received a notice of termination for a 19 MW Solar PPA due to the
developer being unsuccessful in obtaining local permits. The 19 MW Solar PPA was
included in the December 2021 and January 2022 petitions filed with the Virginia
SCC and WVPSC, respectively. If the WVPSC does not approve one or more of the
projects included in APCo's January 2022 petition, the associated allocation of
cost and production of the facilities will be assigned to Virginia retail
customers. Under separate, existing APCo Virginia and West Virginia tariffs,
APCo is also authorized for cost recovery of an additional 40 MWs of recently
completed solar PPAs.

In May 2022, SWEPCo submitted filings before the APSC, LPSC and PUCT requesting
approval to acquire three renewable energy projects totaling 999 MWs. In October
2022, SWEPCo also submitted the necessary filings with the FERC. The projects
are comprised of two wind facilities, totaling 799 MWs, and one solar facility,
totaling 200 MWs. One of the wind facilities, totaling approximately 201 MWs, is
expected to reach commercial operation in December 2024 with the remaining
facilities expected to reach commercial operation in December 2025.






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Significant Renewable Generation Requests for Proposal (RFP)

As part of AEP's transition to diversify the company's generation resources and
build its renewable generation portfolio, the Registrants file RFPs in an effort
to identify potential wind and solar projects. The table below includes the
significant RFPs recently issued. These projects would be subject to regulatory
approval.

                                                                                                            Owned/
            Company                          Issuance Date                   Generation Type                 PPA                 Generating Capacity
                                                                                                                                       (in MWs)
APCo                                   January 2022                     Wind                            Owned                              1,000
APCo                                   January 2022                     Solar (a)                       Owned                                100
APCo                                   February 2022                    Solar                           Owned                                150
APCo                                   June 2022                        Solar/Wind                      PPA                                  100
I&M                                    March 2022                       Wind                            Owned                                800
I&M                                    March 2022                       Solar (a)                       Owned                                500
PSO                                    November 2021                    Wind                            Owned                              2,800
PSO                                    November 2021                    Solar (a)                       Owned                              1,350
SWEPCo                                 September 2022                   Wind                            Owned                              1,900
SWEPCo                                 September 2022                   Solar (a)                       Owned                                500
Total Significant RFP's                                                                                                                    9,200

(a)Includes an option for battery storage.

Disposition of KPCo and KTCo

In October 2021, AEP entered into a Stock Purchase Agreement (SPA) to sell KPCo
and KTCo to Liberty Utilities Co., a subsidiary of Algonquin Power & Utilities
Corp. (Liberty), for approximately a $2.85 billion enterprise value. In May
2022, the KPSC approved the transfer of KPCo to Liberty subject to certain
conditions contingent upon the closing of the sale. AEP has received clearance
under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and the Committee
on Foreign Investment in the United States. The sale remains subject to FERC
approval under Section 203 of the Federal Power Act.

In September 2022, AEP, AEPTCo and Liberty entered into an amendment (Amendment)
to the SPA which reduced the purchase price to approximately $2.646 billion and
Liberty agreed to waive, upon FERC approval of the sale, the SPA condition
precedent to closing requiring the issuance of regulatory orders approving a new
proposed Mitchell Plant Operations and Maintenance Agreement and Mitchell Plant
Ownership Agreement between KPCo and WPCo. The Amendment also provided that the
closing shall not occur prior to January 4, 2023, unless mutually agreed to by
AEP and Liberty.

Mitchell Plant Operations and Maintenance Agreement and Ownership Agreement

KPCo and WPCo each own a 50% undivided interest in the 1,560 MW coal-fired
Mitchell Plant. As of September 30, 2022, the net book value of KPCo's share of
the Mitchell Plant, before cost of removal including CWIP and inventory, was
$576 million.

In November 2021, AEP made filings with the KPSC, WVPSC and FERC seeking
approval of a new proposed Mitchell Plant Operations and Maintenance Agreement
and Mitchell Plant Ownership Agreement. In February 2022, AEP filed a motion to
withdraw its filing with the FERC. The KPSC and WVPSC issued orders addressing
AEP's filings in May 2022 and July 2022. Those orders proposed materially
different modifications to the Mitchell Plant agreements filed by AEP such that
the new agreements could not be executed by the parties. In lieu of new
agreements, in July 2022, KPCo and WPCo confirmed with the KPSC and WVPSC,
respectively, that they will continue operating under the existing Mitchell
Agreement, utilizing the Mitchell Agreement Operating Committee's authority
under that agreement to issue appropriate resolutions so the parties can operate
in accordance with each
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state commission's directives related to CCR and ELG investment. In September
2022, pursuant to resolutions under the existing Mitchell Plant agreement, WPCo
replaced KPCo as the Operator of Mitchell Plant.

Transfer of Ownership

FERC Proceedings

In December 2021, Liberty, KPCo and KTCo requested FERC approval of the sale
under Section 203 of the Federal Power Act. In February 2022, several
intervenors in the case filed protests related to whether the sale will
negatively impact the wholesale transmission rates of applicants. In April 2022,
the FERC issued a deficiency letter stating that the Section 203 application is
deficient and that additional information is required to process it. In May
2022, Liberty, KPCo and KTCo supplemented the application and in June 2022, the
FERC issued an order formally notifying AEP that it was exercising its ability
to take up to an additional 180 days to act on the application. An order from
the FERC is expected in the fourth quarter of 2022.

KPSC Proceedings

In May 2022, the KPSC approved the transfer of KPCo to Liberty subject to
conditions contingent upon the closing of the sale, including establishment of
regulatory liabilities to subsidize retail customer transmission and
distribution expenses, a fuel adjustment clause bill credit, and a three-year
Big Sandy decommissioning rider rate holiday during which KPCo's carrying charge
is reduced by 50%. As a result of the conditions imposed by KPSC, in the second
quarter of 2022, AEP recorded a $69 million loss on the expected sale of the
Kentucky Operations in accordance with accounting guidance for Fair Value
Measurement.

Further, as a result of the Amendment and the change to the anticipated timing
of the completion of the transaction, AEP recorded an additional $194 million
pretax loss ($149 million net of tax) on the expected sale of the Kentucky
Operations in the third quarter of 2022 in accordance with the accounting
guidance for Fair Value Measurement. AEP recorded a $263 million pretax loss
($218 million net of tax) on the expected sale of the Kentucky Operations for
the nine months ended September 30, 2022. AEP expects cash proceeds, net of
taxes and transaction fees, from the sale of approximately $1.2 billion.

Subject to receipt of FERC authorization under Section 203 of the Federal Power
Act, the sale is expected to close in January 2023 with Liberty acquiring the
assets and assuming the liabilities of KPCo and KTCo, excluding pension and
other post-retirement benefit plan assets and liabilities. AEP expects to
provide customary transition services to Liberty for a period of time after
closing of the transaction. AEP plans to use the proceeds from the sale to fund
its continued investment in regulated businesses, including transmission and
regulated renewables projects. If additional reductions in the fair value of the
Kentucky Operations occur, it would reduce future net income and cash flows.
                                       13
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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 suit 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
sought a judgment declaring that the defendants breached the lease, must satisfy
obligations related to installation of emission control equipment and indemnify
the plaintiffs. See "Obligations under the New Source Review Litigation Consent
Decree" section below for additional information.

After the litigation proceeded at the district court and appellate court, in
April 2021, I&M and AEGCo reached an agreement to acquire 100% of the interests
in Rockport Plant, Unit 2 for $116 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. The
agreement is subject to customary closing conditions and as of the closing will
result in a final settlement of, and release of claims in, the lease litigation.
As a result, in May 2021, at the parties' request, the district court entered a
stipulation and order dismissing the case without prejudice to plaintiffs
asserting their claims in a re-filed action or a new action. The required
regulatory approvals at the IURC and FERC have been obtained that would allow
the closing to occur as of the end of the lease in December 2022. Management
believes its financial statements appropriately reflect the resolution of the
litigation.

Upon the end of the Rockport Unit 2 lease in December 2022, AEGCo's 50%
ownership share of Rockport Unit 2 will be billed 100% to I&M under a
FERC-approved unit power agreement. In addition, upon the end of the Rockport
Unit 2 lease, I&M's 50% ownership share of Rockport Unit 2 and I&M's purchased
power from AEGCo related to Rockport Unit 2 will be a merchant resource for I&M
until Rockport Unit 2 is retired. A 2021 IURC order approved a settlement
agreement addressing the future use of Rockport Unit 2 as a short-term capacity
resource through the June 2023 - May 2024 PJM planning year. I&M has a similar
proposal pending before the MPSC in I&M's 2022 Michigan Integrated Resource Plan
(IRP) filing. If I&M cannot recover its future investment and expenses related
to the merchant share of Rockport Unit 2, it could reduce future net income and
cash flows and impact financial condition.

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

Four participants in The American Electric Power System Retirement Plan (the
Plan) filed a class action complaint in December 2021 in the U.S. District Court
for the Southern District of Ohio against AEPSC and the Plan. 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 plaintiffs assert a number of claims on behalf of
themselves and the purported class, including 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) AEP failed to provide required
notice regarding the changes to the Plan. Among other relief, the Complaint
seeks reformation of the Plan to provide additional benefits and the recovery of
plan benefits for former employees under such reformed plan. The plaintiffs
previously had submitted claims for
                                       14
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additional plan benefits to AEP, which were denied. On February 15, 2022, AEPSC
and the Plan filed a motion to dismiss the complaint for failure to state a
claim. On August 16, 2022, the district court granted the motion to dismiss the
complaint without prejudice. The plaintiffs have filed a motion for leave to
file an amended complaint. AEP 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 2019, Ohio adopted and implemented HB 6 which benefits OPCo by authorizing
rate recovery for certain costs including renewable energy contracts and OVEC's
coal-fired generating units. OPCo engaged in lobbying efforts and provided
testimony during the legislative process in connection with HB 6. In July 2020,
an investigation led by the U.S. Attorney's Office resulted in a federal grand
jury indictment of an Ohio legislator and associates in connection with an
alleged racketeering conspiracy involving the adoption of HB 6. After AEP
learned of the criminal allegations against the Ohio legislator and others
relating to HB 6, AEP, with assistance from outside advisors, conducted a review
of the circumstances surrounding the passage of the bill. Management does not
believe that AEP was involved in any wrongful conduct in connection with the
passage of 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 alleged 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 sought monetary damages, among other forms of relief. In December
2021, the district court issued an opinion and order dismissing the securities
litigation complaint with prejudice, determining that the complaint failed to
plead any actionable misrepresentations or omissions. The plaintiffs did not
appeal the ruling.

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 and a fourth AEP shareholder filed a similar derivative action
in the Supreme Court for the State of New York, Nassau County. 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 court entered a scheduling order in
the New York state court derivative action staying the case other than with
respect to briefing the motion to dismiss. AEP filed its motion to dismiss on
April 29, 2022. On September 13, 2022, the New York state court granted the
motion to dismiss with prejudice and plaintiffs have filed a notice of appeal
with the New York appellate court. The two derivative actions pending in federal
district court in Ohio have been consolidated and the plaintiffs in the
consolidated action filed an amended complaint. AEP filed a motion to dismiss on
May 3, 2022 and briefing on the motion to dismiss has been completed. Discovery
remains stayed pending the district court's ruling on the motion to dismiss. The
plaintiff in the Ohio state court case advised that they no longer agreed to
stay the proceedings, therefore, AEP filed a motion to continue the stays of
proceedings on May 20, 2022 and the plaintiff filed an amended complaint on June
2, 2022. On June 15, 2022, the Ohio state court entered an order continuing the
stays of that case until the resolution of the consolidated derivative actions
pending in Ohio federal district court. The defendants will continue to defend
against the claims. Management is unable to determine a range of potential
losses that is reasonably possible of occurring.

In March 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, AEP commence a
civil action for breaches of fiduciary duty and related claims and take
appropriate disciplinary action against those individuals who
                                       15
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allegedly harmed the company. The shareholder that sent the letter has since withdrawn the litigation demand, which is now terminated and of no further effect.

In May 2021, AEP received a subpoena from the SEC's Division of Enforcement
seeking various documents, including documents relating to the passage of HB 6
and documents relating to AEP's policies and financial processes and controls.
In August 2022, AEP received a second subpoena from the SEC seeking various
additional documents relating to its ongoing inquiry. AEP is cooperating fully
with the SEC's investigation. Although the outcome of the SEC's investigation
cannot be predicted, management does not believe the results of this inquiry
will have a material impact on financial condition, results of operations or
cash flows.

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. 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 September 30, 2022, the AEP System owned generating capacity
of approximately 25,300 MWs, of which approximately 11,300 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 $300 million
to $500 million through 2026.

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, (g) compliance with the Federal EPA's revised coal
combustion residual rules and (h) 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
                                       16
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consent decree has been modified seven times, for various reasons, most recently in 2022. 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 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 postponed 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.


                                       17

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In January 2021, the Federal EPA finalized a revised CSAPR rule, which
substantially reduces the ozone season NOX budgets in 2021-2024. Several
utilities and other entities potentially subject to the Federal EPA's NOX
regulations have challenged that final rule in the U.S. Court of Appeals for the
District of Columbia Circuit and briefing is underway. Management cannot predict
the outcome of that litigation, but 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. In addition, in February 2022, the EPA
Administrator signed a proposed FIP for 2015 Ozone NAAQS that would further
revise the ozone season NOX budgets under the existing CSAPR program. AEP is
evaluating the proposed changes.

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. In October 2021 the United States Supreme Court granted certiorari and
combined four separate petitions seeking review of the D.C. Circuit Court
decisions. Oral arguments were held in February 2022 and on June 30, 2022, the
United States Supreme Court reversed the D.C. Circuit Court's decision and
remanded for further proceedings. The Federal EPA must take some action before
anything is required of the utilities as a result of this decision. At a
minimum, if the Federal EPA intends to implement the ACE rule, it must conduct
additional rulemaking to update its applicable deadlines, which have all passed.
Alternatively, the Federal EPA may abandon the ACE rule and proceed to regulate
greenhouse gases through a new rule, the scope of which is unknown. The Federal
EPA has previously announced it expects to propose a new rule by spring of 2023.
Management is unable to predict how the Federal EPA will respond to the court's
remand.

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 October 2022, 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. AEP
adjusted its near-term carbon dioxide emission reduction target from a 2000
baseline to a 2005 baseline, upgraded its 80% reduction by 2030 target to
include full Scope 1 emissions and accelerated its net-zero goal by five years
to 2045. AEP's total Scope 1 GHG emissions in 2021 were approximately 56 million
metric tons CO2e, approximately a 63% reduction from AEP's 2005 Scope 1 GHG
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 have led to the
announcement of early plant closures and could force AEP to close additional
coal-fired generation facilities earlier than their estimated 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.
                                       18
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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 and
inactive CCR landfills and surface impoundments at facilities of active electric
utility or independent power producers.

In 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.

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)
AEGCo                                  Rockport Plant, Unit 1                                  655             $             222.2                     2028
APCo                                   Amos Plant                                            2,930                         2,123.6                     2040
APCo                                   Mountaineer Plant                                     1,320                           979.0                     2040
I&M                                    Rockport Plant, Unit 1                                  655                           462.9     (b)             2028
KPCo                                   Mitchell Plant                                          780                           575.6                     2040
SWEPCo                                 Flint Creek Plant                                       258                           263.6                     2038
WPCo                                   Mitchell Plant                                          780                           603.6                     2040



(a)Net book value before cost of removal including CWIP and inventory.
(b)Amount includes a $153 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 January 2022, the Federal EPA began responding to applications for extension
requests and has proposed to deny several extension requests based on
allegations that the utilities that received such responses are not in
compliance with the CCR Rule. The Federal EPA's allegations of noncompliance
rely on new interpretations of the CCR Rule requirements. The actions of the
Federal EPA have been challenged in the U.S. Court of Appeals for the District
of Columbia Circuit as unlawful rulemaking that revises the existing CCR Rule
requirements without proper notice and without opportunity for comment.
Management is unable to predict the outcome of that litigation. On July 12,
2022, the Federal EPA proposed conditional approval of the pending extension
request for the Mountaineer Plant. The Federal EPA has not yet proposed any
action on the other pending extension requests submitted by AEP; however,
statements made by the Federal EPA in proposed denials of extension requests
submitted by other utilities indicate that there is a risk that the Federal EPA
may similarly conclude that AEP is not eligible for an extension of time to
cease use of those CCR impoundments and/or that one or more of AEP's facilities
is not in compliance with the CCR Rule. If that occurs, AEP may incur material
additional costs to change its plans for complying with the CCR Rule, including
the potential to have to temporarily cease operation of one or more facilities
until an acceptable compliance alternative can be implemented. Such temporary
cessation of operation could materially impact the cost of serving customers of
the affected utility. Further, actions by the Federal EPA could require AEP to
remove coal ash from CCR units that have already been closed in accordance with
state law programs or could require AEP to incur costs related to CCR units at
various active and legacy facilities.

Closure and post-closure costs have been included in ARO in accordance with the
requirements in the Federal EPA's final CCR 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. AEP may incur
significant additional costs complying with the Federal EPA's CCR Rule including
costs to upgrade or close and replace surface impoundments and landfills used to
manage CCR and to conduct any required remedial actions including removal of
coal ash. If additional costs are incurred and AEP is unable to obtain cost
recovery, it would reduce
                                       19
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future net income and cash flows and impact financial condition. Management will
continue to participate in rulemaking activities and make adjustments based on
new federal and state requirements affecting its ash disposal units.

The second option to obtain an extension of the April 11, 2021 deadline to cease
operation of unlined impoundments allows a generating facility to continue
operating its existing impoundments without developing alternative CCR disposal,
provided the facility commits to cease combustion of coal by a date certain.
Under this option, a generating facility would have until October 17, 2023 to
cease coal-fired operations 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 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 Plant                             580             $       65.0          $           150.7                 2023 (b)
                                      Welsh Plant, Units
SWEPCo                                1 and 3                                1,053                    432.3                       75.7                 2028 (c)(d)



(a)Net book value including CWIP excluding cost of removal and materials and
supplies.
(b)Pirkey 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.

To date, the Federal EPA has not taken any action on these pending extension
requests. Under the second option above, AEP may need to recover remaining
depreciation and estimated closure costs associated with these 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 these plants in a timely manner, it would reduce future net
income and cash flows and impact financial condition.

Clean Water Act Regulations

The Federal EPA's ELG rule for generating facilities establishes limits for 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 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. For affected facilities that
must install additional technologies to meet the ELG rule limits, permit
modifications were filed in January 2021 that reflect the outcome of that
assessment. AEP continues to work with state agencies to finalize permit terms
and conditions. Other facilities opted to file Notices of Planned Participation
(NOPP), pursuant to which the facilities are not required to install additional
controls to meet ELG limits provided they make commitments to cease coal
combustion by a date certain. The Federal EPA has announced its intention to
reconsider the 2020 rule and to further revise limits applicable to discharges
of landfill and impoundment leachate. A proposed rule is expected in late 2022
or early 2023. Management cannot predict whether the Federal EPA will actually
finalize further revisions or what such revisions might be, but will continue to
monitor this issue and will participate in further rulemaking activities as they
arise.

In August 2021, the Federal EPA and the Army Corps of Engineers announced their
plan to reconsider and revise the Navigable Waters Protection Rule, which
defines "waters of the United States" under the Clean Water Act. Shortly
thereafter, the United States District Court for the District of Arizona vacated
and remanded the Navigable Waters Protection Rule, which had the effect of
reinstating the prior, much broader, version of the rule. Because the scope of
waters subject to the Federal EPA and Army Corps of Engineers jurisdictions is
broader under the prior rule, permitting decisions made in recent years are
subject to reevaluation; permits may now be necessary where
                                       20
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none were previously required, and issued permits may need to be reopened to
impose additional obligations. In December 2021, the Federal EPA proposed a rule
that would roll back the definition of "waters of the United States" to the
pre-2015 definition. The Federal EPA also announced that it would be considering
further changes through a future rulemaking, which would build upon the
foundation of the proposed rule. Management will continue to monitor rulemaking
on this issue.

In October 2022, the U.S. Supreme Court heard an appeal related to the scope of
"waters of the United States," specifically which wetlands can be regulated as
waters of the United States. Management cannot predict the outcome of that
litigation.

CCR and ELG Compliance Plan Filings

Mitchell Plant (Applies to AEP)

KPCo and WPCo each own a 50% interest in the Mitchell Plant. As of September 30,
2022, the net book value of KPCo's share of the Mitchell Plant, before cost of
removal including CWIP and inventory, was $576 million. 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 CCR and
ELG compliance plans and seek recovery of the estimated $132 million investment
for the Mitchell Plant that would allow the plant to continue operating beyond
2028. Within those requests, WPCo and KPCo also filed a $25 million alternative
to implement only the CCR-related investments with the WVPSC and KPSC,
respectively, which would allow the Mitchell Plant to continue operating only
through 2028.

In July 2021, the KPSC issued an order approving the CCR only alternative and
rejecting the full CCR and ELG compliance plan. In May 2022, the KPSC approved
recovery of the Kentucky jurisdictional share of ELG costs incurred at the
Mitchell Plant prior to July 15, 2021.

In August 2021, the WVPSC approved the full CCR and ELG compliance plan for the
WPCo share of the Mitchell Plant. In September 2021, WPCo submitted a filing
with the WVPSC to reopen the CCR/ELG case that was approved by the WVPSC in
August 2021. Due to the rejection by the KPSC of the KPCo share of the ELG
investments, WPCo requested the WVPSC consider approving the construction and
recovery of all ELG costs at the plant. In October 2021, the WVPSC affirmed its
August 2021 order approving the construction of CCR/ELG investments and directed
WPCo to proceed with CCR/ELG compliance plans that would allow the plant to
continue operating beyond 2028. The WVPSC also ordered that WPCo will be given
the opportunity to recover, from its customers, the ELG and new capital and
operating costs arising solely from the WVPSC's directive to operate the plant
beyond 2028 if the WVPSC finds that the costs are reasonably and prudently
incurred. The WVPSC's order further states that unless KPCo pays for its share
of costs for ELG improvements and costs necessary to continue operations beyond
2028, the benefit of the capacity and energy made possible by those improvements
and operating Mitchell Plant beyond 2028 should benefit only West Virginia
jurisdictional customers who have shared in paying for those costs.

Amos and Mountaineer Plants (Applies to AEP and APCo)

In December 2020, APCo submitted filings with the Virginia SCC and WVPSC
requesting regulatory approvals necessary to recover the estimated $240 million
investment needed to implement CCR and ELG compliance for the Amos and
Mountaineer plants. In August 2021, the Virginia SCC issued an order approving
recovery of CCR-related operation and maintenance expenses and investments at
the Amos and Mountaineer Plants through an active rider. The order also denied
APCo's request to recover the cost of ELG investments and denied recovery of
previously incurred ELG costs, but did not preclude APCo from refiling for
approval. In March 2022, APCo refiled for approval to recover the cost of the
ELG investments and previously incurred ELG costs. Intervenor testimony was
submitted in August 2022 recommending the denial of ELG cost recovery. In
October 2022, a Virginia Hearing Examiner recommended that the Virginia SCC
approve recovery of APCo's requested ELG investment
                                       21
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costs at Amos and Mountaineer Plants. Management expects to receive an order from the Virginia SCC in the fourth quarter of 2022.

Also in August 2021, the WVPSC approved the request to construct CCR/ELG
investments at the Amos and Mountaineer Plants and approved recovery of the West
Virginia jurisdictional share of these costs through an active rider. In October
2021, due to the Virginia SCC previously rejecting those ELG investments, the
WVPSC issued an order directing APCo to proceed with CCR/ELG compliance plans
that would allow the plants to continue operating beyond 2028. The WVPSC also
ordered that APCo will be given the opportunity to recover, from West Virginia
customers, the ELG and new capital and operating costs arising solely from the
WVPSC's directive to operate the plants beyond 2028 if the WVPSC finds that the
costs are reasonably and prudently incurred. The October 2021 order further
states that unless the Virginia jurisdictional customers of APCo pay for their
share of costs for ELG improvements and costs necessary to continue operations
beyond 2028, the benefit of the capacity and energy made possible by those
improvements and operating the Amos and Mountaineer Plants beyond 2028 should
benefit only West Virginia and FERC jurisdictional customers who have shared in
paying for those costs.

APCo expects the total Amos and Mountaineer Plant ELG investment, excluding AFUDC, to be approximately $162 million. As of September 30, 2022, APCo's Virginia jurisdictional share of the net book value, before cost of removal including CWIP and inventory, of the Amos and Mountaineer Plants was approximately $1.5 billion and APCo's Virginia jurisdictional share of its ELG investment balance in CWIP for these plants was $62 million.

If any of the ELG costs are not approved for recovery and/or the retirement dates of the Amos and Mountaineer Plants are accelerated to 2028 without commensurate cost recovery, it would reduce future net income and cash flows and impact financial condition.

                                       22
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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, remediation 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.

Previously, management retired or announced early closure plans for Welsh Unit 2, Dolet Hills Power Station and Northeastern Plant Unit 3.

The table below summarizes the net book value, as of September 30, 2022, of generating facilities retired or planned for early retirement in advance of the retirement date currently authorized for ratemaking purposes:

                                                                                                         Accelerated                             Actual/Projected                          Current Authorized
                                                                                    Net                  Depreciation                               Retirement                                  Recovery                   Annual
     Company                          Plant                                   Investment (a)           Regulatory Asset                                Date                                      Period               Depreciation (b)
                                                                                               (in millions)                                                              (in millions)
PSO                     Northeastern Plant, Unit 3                           $        143.7          $           141.4                                 2026                                        (c)                $         14.9

SWEPCo                  Dolet Hills Power Station                                         -                       54.7                                 2021                                        (d)                             -
SWEPCo                  Pirkey Plant                                                   65.0                      150.7                                 2023                                        (e)                          12.5
SWEPCo                  Welsh Plant, Units 1 and 3                                    432.3                       75.7                                 2028     (f)                                (g)                          39.8
SWEPCo                  Welsh Plant, Unit 2                                               -                       35.2                                 2016                                        (h)                             -



(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)Northeastern Plant, Unit 3 is currently being recovered through 2040.
(d)Dolet Hills Power Station is currently being recovered through 2026 in the
Louisiana jurisdiction and through 2046 in the Texas jurisdiction. In December
2021, the PUCT authorized the recovery of SWEPCo's Texas jurisdictional share of
the Dolet Hills Power Station through 2046 without providing a return on the
investment which resulted in a disallowance of $12 million. In May 2022, the
APSC authorized the recovery of SWEPCo's Arkansas jurisdictional share of the
Dolet Hills Power Station through 2027 without providing a return on investment,
which resulted in an immaterial disallowance in the second quarter of 2022. See
Note 4 - Rate Matters for additional information.
(e)Pirkey Plant is currently being recovered through 2025 in the Louisiana
jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.
(f)In November 2020, management announced it will cease using coal at the Welsh
Plant in 2028.
(g)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.
(h)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 is not deemed recoverable, it could materially
reduce future net income, cash flows and impact financial condition.
                                       23
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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, 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.

                                       24
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The following table presents Earnings (Loss) Attributable to AEP Common Shareholders by segment:

                                                       Three Months Ended                       Nine Months Ended
                                                          September 30,                           September 30,
                                                     2022                 2021               2022               2021
                                                                             (in millions)
Vertically Integrated Utilities                $    476.9             $   437.7          $ 1,076.3          $   936.3
Transmission and Distribution Utilities             165.5                 155.9              483.1              424.0
AEP Transmission Holdco                             170.5                 166.8              485.4              507.5
Generation & Marketing                               97.5                 100.7              284.3              189.7
Corporate and Other                                (226.7)                (65.1)            (406.2)            (108.3)
Earnings Attributable to AEP Common
Shareholders                                   $    683.7             $   796.0          $ 1,922.9          $ 1,949.2



AEP CONSOLIDATED

Third Quarter of 2022 Compared to Third Quarter of 2021

Earnings Attributable to AEP Common Shareholders decreased from $796 million in 2021 to $684 million in 2022 primarily due to:

•A loss on the expected sale of the Kentucky Operations. •An increase in depreciation expense due to continued investment.

This decrease was partially offset by:

•Favorable rate proceedings in AEP's various jurisdictions.

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021

Earnings Attributable to AEP Common Shareholders decreased from $1,949 million in 2021 to $1,923 million in 2022 primarily due to:

•A loss on the expected sale of the Kentucky Operations. •An impairment of AEP's equity investment in Flat Ridge 2. •An increase in depreciation expense due to continued investment.

These decreases were partially offset by:

•A gain on the sale of mineral rights.
•Favorable rate proceedings in AEP's various jurisdictions.
•Increased sales volumes.
•Favorable mark-to-market economic hedge activity driven by higher commodity
prices.

AEP's results of operations by operating segment are discussed below.

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VERTICALLY INTEGRATED UTILITIES

                                                              Three Months Ended                     Nine Months Ended
                                                                 September 30,                         September 30,
         Vertically Integrated Utilities                    2022           

   2021               2022               2021
                                                                                    (in millions)
Revenues                                                $ 3,226.3          $ 2,759.3          $ 8,562.2          $ 7,557.2
Fuel and Purchased Electricity                            1,191.9              855.3            2,895.8            2,364.7

Gross Margin                                              2,034.4            1,904.0            5,666.4            5,192.5
Other Operation and Maintenance                             834.0              796.9            2,383.1            2,240.6
Asset Impairments and Other Related Charges                  24.9                  -               24.9                  -
Establishment of 2017-2019 Virginia Triennial
Review Regulatory Asset                                     (37.0)                 -              (37.0)                 -

Depreciation and Amortization                               520.6              436.3            1,525.0            1,302.2
Taxes Other Than Income Taxes                               130.1              124.1              383.9              375.6
Operating Income                                            561.8              546.7            1,386.5            1,274.1

Other Income                                                  9.0                4.1               24.9                9.9
Allowance for Equity Funds Used During
Construction                                                  6.0                9.6               20.4               30.3
Non-Service Cost Components of Net Periodic
Benefit Cost                                                 27.4               17.0               82.4               51.0
Interest Expense                                           (168.8)            (144.3)            (477.1)            (425.5)
Income Before Income Tax Expense (Benefit) and
Equity Earnings                                             435.4              433.1            1,037.1              939.8
Income Tax Expense (Benefit)                                (41.2)              (4.6)             (41.3)               3.4
Equity Earnings of Unconsolidated Subsidiary                  0.3                1.0                1.0                2.5
Net Income                                                  476.9              438.7            1,079.4              938.9
Net Income Attributable to Noncontrolling
Interests                                                       -                1.0                3.1                2.6
Earnings Attributable to AEP Common Shareholders        $   476.9          $   437.7          $ 1,076.3          $   936.3



        Summary of KWh Energy Sales for Vertically Integrated Utilities

                                  Three Months Ended                   Nine Months Ended
                                    September 30,                        September 30,
                              2022                 2021            2022                  2021
                                                   (in millions of KWhs)
        Retail:
        Residential          9,115                9,119          25,379                25,125
        Commercial           6,640                6,468          18,069                17,396
        Industrial           8,862                8,485          25,930                24,798
        Miscellaneous          623                  604           1,745                 1,672
        Total Retail        25,240               24,676          71,123                68,991

        Wholesale (a)        4,254                5,713          12,388                14,842

        Total KWhs          29,494               30,389          83,511                83,833

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

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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                Nine Months Ended
                                          September 30,                     September 30,
                                     2022                2021          2022                2021
                                                          (in degree days)
        Eastern Region
        Actual - Heating (a)           8                   1         1,750               1,710
        Normal - Heating (b)           4                   4         1,748               1,742

        Actual - Cooling (c)         783                 847         1,178               1,209
        Normal - Cooling (b)         745                 744         1,082               1,087

        Western Region
        Actual - Heating (a)           -                   -           930                 993
        Normal - Heating (b)           -                   1           906                 901

        Actual - Cooling (c)       1,653               1,485         2,558               2,163
        Normal - Cooling (b)       1,413               1,410         2,134               2,137

(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.

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

Third Quarter of 2022 Compared to Third Quarter of 2021

                   Reconciliation of Third Quarter of 2021 to Third Quarter 

of 2022

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

Third Quarter of 2021                                                                  $      437.7

Changes in Gross Margin:
Retail Margins                                                                                 92.7
Margins from Off-system Sales                                                                   8.3
Transmission Revenues                                                                          21.9
Other Revenues                                                                                  7.5
Total Change in Gross Margin                                                                  130.4

Changes in Expenses and Other:
Other Operation and Maintenance                                                               (37.1)
Asset Impairments and Other Related Charges                                                   (24.9)

Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset

                   37.0
Depreciation and Amortization                                                                 (84.3)
Taxes Other Than Income Taxes                                                                  (6.0)

Other Income                                                                                    4.9
Allowance for Equity Funds Used During Construction                                            (3.6)
Non-Service Cost Components of Net Periodic Pension Cost                                       10.4
Interest Expense                                                                              (24.5)
Total Change in Expenses and Other                                                           (128.1)

Income Tax Benefit                                                                             36.6
Equity Earnings of Unconsolidated Subsidiary                                                   (0.7)
Net Income Attributable to Noncontrolling Interests                                             1.0

Third Quarter of 2022                                                                  $      476.9

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 $93 million primarily due to the following:
•A $47 million increase at PSO due to a $26 million increase in base rate
revenues and a $21 million increase in rider revenues. These increases were
partially offset in other expense items below.
•A $40 million increase at SWEPCo primarily due to base rate revenue increases
in Texas and Arkansas and an increase in rider revenues in all jurisdictions.
These increases were partially offset in other expense items below.
•A $22 million increase at APCo and WPCo due to an increase in rider revenues in
Virginia and West Virginia. This increase was partially offset in other expense
items below.
•A $15 million increase at I&M primarily due to an increase in rider revenues.
This increase was partially offset in other expense items below.
•An $11 million increase in weather-related usage primarily in the residential
class.
These increases were partially offset by:
•A $47 million decrease at PSO and SWEPCo resulting from the NCWF PTC benefits
provided to customers through fuel clause mechanisms. This decrease was
partially offset in Income Tax Benefit below.
                                       28
--------------------------------------------------------------------------------


•A $10 million decrease in weather-normalized retail margins primarily in the
residential class.
•Margins from Off-system Sales increased $8 million primarily due to the
following:
•A $7 million increase due to an increase in Turk Plant merchant sales at
SWEPCo.
•A $3 million increase at APCo primarily due to increased generation and strong
market pricing.
•Transmission Revenues increased $22 million primarily due to continued
investment in transmission assets and increased load.
•Other Revenues increased $8 million primarily due to an increase in pole
attachment rental revenue.

Expenses and Other and Income Tax Expense changed between years as follows:

•Other Operation and Maintenance expenses increased $37 million primarily due to
the following:
•A $15 million increase in PJM transmission services. This increase was
partially offset in Retail Margins above.
•A $13 million increase in SPP transmission services. This increase was
partially offset in Retail Margins above.
•An $11 million increase due to the expensing of cancelled capital projects.
•An $11 million increase in generation expenses primarily due to plant outages
and maintenance at APCo and I&M.
•A $6 million increase in storm restoration expenses.
•A $5 million increase in distribution system improvements across multiple
operating companies.
•A $5 million increase in Energy Efficiency/Demand Response expenses. This
increase was partially offset in Retail Margins above.
These increases were partially offset by:
•A $36 million decrease due to the modification of the Rockport Plant, Unit 2
lease which resulted in a change in lease classification from an operating lease
to a finance lease in December 2021 at AEGCo and I&M. This decrease is offset in
Depreciation and Amortization expense below.
•Asset Impairments and Other Related Charges increased $25 million at APCo due
to the write-off of a regulatory asset in accordance with the August 2022
Virginia Supreme Court opinion related to the 2017-2019 Virginia Triennial
review.
•Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset increased
$37 million at APCo due to the establishment of a regulatory asset based on an
August 2022 Virginia Supreme Court opinion and resulting under-earning during
the 2017-2019 Triennial Review.
•Depreciation and Amortization expenses increased $84 million primarily due to
the following:
•A $45 million increase due to a higher depreciable base primarily at APCo, I&M,
PSO and SWEPCo and the implementation of new rates and the timing of refunds to
customers under rate rider mechanisms at PSO and in Arkansas and Texas for
SWEPCo. The increase due to implementation of new rates and the timing of
refunds to customers under rate rider mechanisms at PSO was partially offset in
Retail Margins above.
•A $39 million increase due to the modification of the Rockport Plant, Unit 2
lease which resulted in a change in lease classification from an operating lease
to a finance lease in December 2021 at AEGCo and I&M. This increase was
partially offset in Other Operation and Maintenance expenses above.
•Taxes Other Than Income Taxes increased $6 million due to the following:
•A $9 million increase at PSO and SWEPCo primarily due to increased property
taxes and a new infrastructure fee at PSO implemented by the City of Tulsa in
March 2022. This increase was partially offset in Retail Margins above.
This increase was partially offset by:
•A $5 million decrease at I&M primarily due to the repeal of the Indiana Utility
Receipts Tax in July 2022. This decrease was partially offset in Retail Margins
above.
•Other Income increased $5 million at PSO primarily due to carrying charges on
regulatory assets resulting from the February 2021 severe winter weather event.
•Allowance for Equity Funds Used During Construction decreased $4 million
primarily due to a decrease in AFUDC equity rates at APCo.
                                       29
--------------------------------------------------------------------------------


•Non-Service Cost Components of Net Periodic Benefit Cost decreased $10 million
primarily due to an increase in discount rates, an increase in the expected
return on plan assets and favorable plan returns in 2021.
•Interest Expense increased $25 million primarily due to higher long-term debt
balances at APCo, PSO and SWEPCo, increased Advances from Affiliates at SWEPCo
and higher interest rates at APCo.
•Income Tax Benefit increased $37 million primarily due to an increase in PTCs
partially offset by a decrease in amortization of Excess ADIT. These items were
partially offset in Retail Margins above.

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

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021

Reconciliation of Nine Months Ended September 30, 2021 to Nine Months Ended September 30, 2022

Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities

                                            (in millions)

Nine Months Ended September 30, 2021                                                   $      936.3

Changes in Gross Margin:
Retail Margins                                                                                404.6
Margins from Off-system Sales                                                                 (18.9)
Transmission Revenues                                                                          66.8
Other Revenues                                                                                 21.4
Total Change in Gross Margin                                                                  473.9

Changes in Expenses and Other:
Other Operation and Maintenance                                                              (142.5)
Asset Impairments and Other Related Charges                                                   (24.9)

Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset

                   37.0
Depreciation and Amortization                                                                (222.8)
Taxes Other Than Income Taxes                                                                  (8.3)

Other Income                                                                                   15.0
Allowance for Equity Funds Used During Construction                                            (9.9)
Non-Service Cost Components of Net Periodic Pension Cost                                       31.4
Interest Expense                                                                              (51.6)
Total Change in Expenses and Other                                                           (376.6)

Income Tax Expense                                                                             44.7
Equity Earnings of Unconsolidated Subsidiary                                                   (1.5)
Net Income Attributable to Noncontrolling Interests                                            (0.5)

Nine Months Ended September 30, 2022                                                   $    1,076.3

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 $405 million primarily due to the following:
•A $111 million increase at APCo and WPCo due to an increase in rider revenues
in Virginia and West Virginia. This increase was partially offset in other
expense items below.
•A $95 million increase at PSO due to a $51 million increase in base rate
revenues and a $44 million increase in rider revenues. These increases were
partially offset in other expense items below.
•An $80 million increase at SWEPCo primarily due to base rate revenue increases
in Texas and Arkansas and an increase in rider revenues in all retail
jurisdictions. These increases were partially offset in other expense items
below.
•A $43 million increase at I&M due to an increase in rider revenues offset by
lower wholesale true-ups. This increase was partially offset in other expense
items below.
•A $41 million increase in weather-related usage primarily in the residential
class.
•A $35 million increase in weather-normalized retail margins primarily in the
commercial class.
                                       31
--------------------------------------------------------------------------------


These increases were partially offset by:
•A $62 million decrease at PSO and SWEPCo resulting from the NCWF PTC benefits
provided to customers through fuel clause mechanisms. This decrease was
partially offset in Income Tax Expense below.
•Margins from Off-system Sales decreased $19 million primarily due to the
following:
•A $10 million decrease due to Turk Plant merchant sales as a result of the
February 2021 severe winter weather event at SWEPCo.
•A $7 million decrease at KPCo due to a change in the OSS sharing arrangement.
•Transmission Revenues increased $67 million primarily due to the following:
•A $47 million increase in continued investment in transmission assets and
increased load.
•A $20 million increase in formula rate true-up activity.
•Other Revenues increased $21 million primarily due to the following:
•A $7 million increase at APCo primarily due to business development revenue.
This increase was partially offset in Other Operation and Maintenance expenses
below.
•A $6 million increase at I&M primarily due to a gain on sale of allowances and
economic hedging activities. The gain on the sale of allowances was partially
offset in Retail Margins above.
•A $3 million increase at KPCo primarily due to rental revenue from pole
attachments, a gain on the sale of allowances and business development revenue.

Expenses and Other and Income Tax Expense changed between years as follows:

•Other Operation and Maintenance expenses increased $143 million primarily due
to the following:
•A $96 million increase in PJM transmission services. This increase was
partially offset in Retail Margins above.
•A $62 million increase in generation expenses primarily due to outages and
maintenance at APCo, I&M and PSO.
•A $25 million increase in SPP transmission services. This increase was
partially offset in Retail Margins above.
•A $16 million increase in storm restoration expenses.
•A $12 million increase in Energy Efficiency/Demand Response expenses. This
increase was partially offset in Retail Margins above.
•An $11 million increase in employee-related expenses.
•An $11 million increase due to the expensing of cancelled capital projects.
These increases were partially offset by:
•A $108 million decrease due to the modification of the Rockport Plant, Unit 2
lease which resulted in a change in lease classification from an operating lease
to a finance lease in December 2021 at AEGCo and I&M. This decrease is offset in
Depreciation and Amortization expense below.
•Asset Impairments and Other Related Charges increased $25 million at APCo due
to the write-off of a regulatory asset in accordance with the August 2022
Virginia Supreme Court opinion related to the 2017-2019 Virginia Triennial
review.
•Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset increased
$37 million at APCo due to the establishment of a regulatory asset based on an
August 2022 Virginia Supreme Court opinion and resulting under-earning during
the 2017-2019 Triennial Review.
•Depreciation and Amortization expenses increased $223 million primarily due to
the following:
•A $117 million increase due to the modification of the Rockport Plant, Unit 2
lease which resulted in a change in lease classification from an operating lease
to a finance lease in December 2021 at AEGCo and I&M. This increase was
partially offset in Other Operation and Maintenance expenses above.
•A $106 million increase due to a higher depreciable base primarily at APCo,
I&M, PSO and SWEPCo, the implementation of new rates and the timing of refunds
to customers under rate rider mechanisms at PSO and in Arkansas and Texas for
SWEPCo. The increase due to implementation of new rates and the timing of
refunds to customers under rate rider mechanisms at PSO was partially offset in
Retail Margins above.
                                       32
--------------------------------------------------------------------------------


•Taxes Other Than Income Taxes increased $8 million primarily due to the
following:
•A $13 million increase at PSO and SWEPCo primarily due to increased property
taxes and a new infrastructure fee at PSO implemented by the City of Tulsa in
March 2022. This increase was partially offset in Retail Margins above.
•A $4 million increase at APCo primarily due to an increase in property taxes
driven by additional investments in transmission and distribution assets and
higher tax rates.
These increases were partially offset by:
•An $8 million decrease at I&M primarily due to the repeal of the Indiana
Utility Receipts Tax in July 2022. This decrease was partially offset in Retail
Margins above.
•Other Income increased $15 million primarily due to carrying charges on
regulatory assets resulting from the February 2021 severe winter weather event
at PSO and SWEPCo.
•Allowance for Equity Funds Used During Construction decreased $10 million
primarily due to a decrease in AFUDC equity rates primarily at APCo.
•Non-Service Cost Components of Net Periodic Benefit Cost decreased $31 million
primarily due to an increase in discount rates, an increase in the expected
return on plan assets and favorable plan returns in 2021.
•Interest Expense increased $52 million primarily due to higher long-term debt
balances at APCo, PSO and SWEPCo, increased Advances from Affiliates at SWEPCo,
higher interest rates at APCo and a debt issuance at I&M in April 2021.
•Income Tax Expense decreased $45 million primarily due to the following:
•An $81 million increase in PTCs. This increase was partially offset in Retail
Margins above.
•A $7 million decrease in state taxes.
These decreases were partially offset by:
•A $19 million increase due to an increase in pretax book income.
•A $14 million decrease in amortization of Excess ADIT. The decrease in
amortization of Excess ADIT was partially offset in Gross Margin above.
•A $14 million decrease in Parent Company Loss Benefit.
                                       33
--------------------------------------------------------------------------------

TRANSMISSION AND DISTRIBUTION UTILITIES

                                                             Three Months Ended                     Nine Months Ended
                                                                September 30,                         September 30,
    Transmission and Distribution Utilities                2022            

  2021               2022               2021
                                                                                   (in millions)
Revenues                                               $ 1,530.2          $ 1,200.3          $ 4,078.6          $ 3,391.8
Purchased Electricity                                      399.5              188.1              884.8              561.6

Gross Margin                                             1,130.7            1,012.2            3,193.8            2,830.2
Other Operation and Maintenance                            503.6              442.6            1,373.2            1,168.6

Depreciation and Amortization                              188.3              164.6              559.5              515.8
Taxes Other Than Income Taxes                              176.7              167.5              504.9              483.5
Operating Income                                           262.1              237.5              756.2              662.3

Other Income                                                 1.4                0.5                3.7                2.2
Allowance for Equity Funds Used During
Construction                                                 9.3               11.3               23.6               24.3
Non-Service Cost Components of Net Periodic
Benefit Cost                                                11.9                7.3               35.7               21.8
Interest Expense                                           (85.4)             (77.3)            (242.2)            (228.8)
Income Before Income Tax Expense and Equity
Earnings                                                   199.3              179.3              577.0              481.8
Income Tax Expense                                          33.8               23.4               94.7               57.8
Equity Earnings of Unconsolidated Subsidiary                   -                  -                0.8                  -
Net Income                                                 165.5              155.9              483.1              424.0
Net Income Attributable to Noncontrolling
Interests                                                      -                  -                  -                  -

Earnings Attributable to AEP Common Shareholders $ 165.5 $

   155.9          $   483.1          $   424.0



    Summary of KWh Energy Sales for Transmission and Distribution Utilities

                                    Three Months Ended                   Nine Months Ended
                                      September 30,                        September 30,
                                2022                 2021            2022                  2021
                                                     (in millions of KWhs)
       Retail:
       Residential             8,033                8,093          21,599                21,082
       Commercial              7,538                7,125          20,478                19,189
       Industrial              6,554                6,048          19,131                17,667
       Miscellaneous             210                  207             578                   558
       Total Retail (a)       22,335               21,473          61,786                58,496

       Wholesale (b)             587                  644           1,723                 1,692

       Total KWhs             22,922               22,117          63,509                60,188

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

                                       34
--------------------------------------------------------------------------------


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                Nine Months Ended
                                          September 30,                     September 30,
                                     2022                2021          2022                2021
                                                          (in degree days)
        Eastern Region
        Actual - Heating (a)           8                   1         2,078               1,993
        Normal - Heating (b)           5                   5         2,077               2,071

        Actual - Cooling (c)         755                 787         1,115               1,148
        Normal - Cooling (b)         688                 689           989                 996

        Western Region
        Actual - Heating (a)           -                   -           278                 319
        Normal - Heating (b)           -                   -           193                 188

        Actual - Cooling (d)       1,478               1,308         2,701               2,278
        Normal - Cooling (b)       1,382               1,379         2,433               2,436



(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.

                                       35
--------------------------------------------------------------------------------

Third Quarter of 2022 Compared to Third Quarter of 2021

                  Reconciliation of Third Quarter of 2021 to Third Quarter 

of 2022

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

Third Quarter of 2021                                                                $      155.9

Changes in Gross Margin:
Retail Margins                                                                               74.9
Margins from Off-system Sales                                                                21.8
Transmission Revenues                                                                        11.4
Other Revenues                                                                               10.4
Total Change in Gross Margin                                                                118.5

Changes in Expenses and Other:
Other Operation and Maintenance                                                             (61.0)
Depreciation and Amortization                                                               (23.7)

Taxes Other Than Income Taxes                                                                (9.2)

Other Income                                                                                  0.9
Allowance for Equity Funds Used During Construction                                          (2.0)
Non-Service Cost Components of Net Periodic Benefit Cost                                      4.6
Interest Expense                                                                             (8.1)
Total Change in Expenses and Other                                                          (98.5)

Income Tax Expense                                                                          (10.4)


Third Quarter of 2022                                                                $      165.5

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

•Retail Margins increased $75 million primarily due to the following:
•A $31 million increase due to interim rate increases driven by increased
distribution and transmission investment in Texas.
•A $21 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 $7 million increase in weather-related usage in Texas primarily due to a 13%
increase in cooling degree days.
•A $6 million increase in revenue from rate riders in Texas. This increase was
partially offset in other expense items below.
•A $4 million increase in weather-related usage in Ohio primarily due to the end
of decoupling.
•Margins from Off-system Sales increased $22 million primarily due to the
following:
•A $17 million increase in off-system sales at OVEC in Ohio due to higher market
prices. This increase was offset in Retail Margins above and Other Revenues
below.
•A $5 million increase in deferrals of OVEC costs in Ohio. This increase was
offset in Retail Margins above and Other Revenues below.
•Transmission Revenues increased $11 million primarily due to interim rate
increases driven by increased transmission investment in Texas.


                                       36
--------------------------------------------------------------------------------


•Other Revenues increased $10 million primarily due to the following:
•A $19 million increase in securitization revenues due to AEP Texas Central
Transition Funding II LLC bonds that matured in July 2020 and final refunds that
were completed in 2021. This increase was offset in Depreciation and
Amortization expenses and Interest Expense below.
This increase was partially offset by:
•A $13 million decrease due to third-party Legacy Generation Resource Rider
revenue related to the recovery of OVEC costs in Ohio. This decrease was offset
in Retail Margins and Margins from Off-system Sales above.

Expenses and Other and Income Tax Expense changed between years as follows:

•Other Operation and Maintenance expenses increased $61 million primarily due to
the following:
•A $21 million increase in ERCOT transmission expenses. This increase was
partially offset in Retail Margins and Transmission Revenues above.
•A $14 million increase in transmission expenses in Ohio primarily due to an
increase in recoverable PJM expenses. This increase was offset in Retail Margins
above.
•A $6 million increase in distribution-related expenses in Texas.
•A $5 million increase in remitted Universal Service Fund surcharge payments to
the Ohio Department of Development to fund an energy assistance program for
qualified Ohio customers. This increase was offset in Retail Margins 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 increased $24 million primarily due to
the following:
•A $19 million increase in securitization amortizations primarily due to prior
year AEP Texas Central Transition Funding II LLC bonds that matured in July 2020
and final refunds that were completed in 2021. This increase was offset in Other
Revenues above.
•A $6 million increase due to a higher depreciable base of transmission and
distribution assets in Texas.
•A $4 million increase in recoverable advanced metering system depreciable
expenses in Texas.
These increases were partially offset by:
•A $6 million decrease in recoverable Distribution Investment Rider depreciable
expenses in Ohio. This decrease was offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $9 million primarily due to property
taxes as a result of increased distribution and transmission investment and
higher tax rates.
•Non-Service Cost Components of Net Periodic Benefit Cost decreased $5 million
primarily due to an increase in discount rates, an increase in the expected
return on plan assets and favorable plan returns in 2021.
•Interest Expense increased $8 million primarily due to the following:
•An $11 million increase in Texas primarily due to higher long-term debt
balances and higher interest rates.
This increase was partially offset by:
•A $3 million decrease in Ohio primarily due to the retirement of a higher rate
bond, partially offset by the issuance of a lower rate bond in 2021.
•Income Tax Expense increased $10 million primarily due to an increase in pretax
book income and a decrease in amortization of Excess ADIT. The decrease in
amortization of Excess ADIT was offset in Gross Margin above.
                                       37
--------------------------------------------------------------------------------

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021

Reconciliation of Nine Months Ended September 30, 2021 to Nine Months Ended September 30, 2022

Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities

                                            (in millions)

Nine Months Ended September 30, 2021                                                   $      424.0

Changes in Gross Margin:
Retail Margins                                                                                290.0
Margins from Off-system Sales                                                                  47.8
Transmission Revenues                                                                          50.0
Other Revenues                                                                                (24.2)
Total Change in Gross Margin                                                                  363.6

Changes in Expenses and Other:
Other Operation and Maintenance                                                              (204.6)
Depreciation and Amortization                                                                 (43.7)

Taxes Other Than Income Taxes                                                                 (21.4)

Other Income                                                                                    1.5
Allowance for Equity Funds Used During Construction                                            (0.7)
Non-Service Cost Components of Net Periodic Benefit Cost                                       13.9
Interest Expense                                                                              (13.4)
Total Change in Expenses and Other                                                           (268.4)

Income Tax Expense                                                                            (36.9)
Equity Earnings of Unconsolidated Subsidiary                                                    0.8

Nine Months Ended September 30, 2022                                                   $      483.1

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

•Retail Margins increased $290 million primarily due to the following:
•An $85 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 $70 million increase due to interim rate increases driven by increased
distribution and transmission investment in Texas.
•A $31 million increase due to prior year refunds of Excess ADIT to customers in
Texas. This increase was offset in Income Tax Expense below.
•A $28 million increase in weather-normalized margins primarily from the
commercial class.
•A $25 million increase related to various rider revenues in Ohio. This increase
was partially offset in Margins from Off-system Sales, Other Revenues and other
expense items below.
•A $20 million increase in revenue from rate riders in Texas. This increase was
partially offset in other expense items below.
•A $15 million increase in weather-related usage in Texas primarily due to a 19%
increase in cooling degree days, partially offset by a 13% decrease in heating
degree days.
•An $8 million increase in weather-related usage in Ohio primarily due to the
end of decoupling.
•Margins from Off-system Sales increased $48 million primarily due to the
following:
•A $54 million increase in off-system sales at OVEC in Ohio due to higher market
prices and volume. This increase was offset in Retail Margins above and Other
Revenues below.

                                       38
--------------------------------------------------------------------------------


This increase was partially offset by:
•A $6 million decrease in deferrals of OVEC costs in Ohio. This decrease was
offset in Retail Margins above and Other Revenues below.
•Transmission Revenues increased $50 million primarily due to the following:
•A $46 million increase due to interim rate increases driven by increased
transmission investment in Texas.
•A $7 million increase due to prior year refunds to customers associated with
the most recent base rate case in Texas. This increase was offset in Other
Revenues below.
•A $7 million increase due to continued investment in transmission assets in
Ohio.
These increases were partially offset by:
•An $11 million decrease due to transmission formula rate true-up activity in
Ohio.
•Other Revenues decreased $24 million primarily due to the following:
•A $29 million decrease primarily due to third-party Legacy Generation Resource
Rider revenue related to the recovery of OVEC costs in Ohio. This decrease was
offset in Retail Margins and Margins from Off-system Sales above.
•A $12 million decrease due to prior year refunds to customers associated with
the most recent base rate case in Texas. This decrease was partially offset in
Retail Margins and Transmission Revenues above.
•A $5 million decrease in energy efficiency revenues in Texas.
These decreases were partially offset by:
•A $20 million increase in securitization revenues due to AEP Texas Central
Transition Funding II LLC bonds that matured in July 2020 and final refunds that
were completed in 2021. This increase was offset in Depreciation and
Amortization expenses and Interest Expense below.

Expenses and Other and Income Tax Expense changed between years as follows:

•Other Operation and Maintenance expenses increased $205 million primarily due
to the following:
•A $67 million increase in transmission expenses in Ohio primarily due to the
following:
•A $67 million increase in recoverable PJM expenses. This increase was offset in
Retail Margins above.
•A $6 million increase in transmission vegetation management expenses.
These increases were partially offset by:
•A $10 million decrease in transmission formula rate true-up activity.
•A $46 million increase in ERCOT transmission expenses. This increase was
partially offset in Retail Margins and Transmission Revenues above.
•A $20 million increase in employee-related expenses.
•A $19 million increase in bad debt-related expenses, including $8 million in
2022 due to Bad Debt Rider over-recovery in Ohio. This increase was offset in
Retail Margins above.
•A $15 million increase in recoverable distribution expenses in Ohio primarily
related to vegetation management. This increase was offset in Retail Margins
above.
•A $14 million increase in remitted Universal Services Fund surcharge payments
to the Ohio Department of Development to fund an energy assistance program for
qualified Ohio customers. This increase was offset in Retail Margins above.
•A $13 million increase in distribution-related expenses in Texas.
•Depreciation and Amortization expenses increased $44 million primarily due to
the following:
•A $24 million increase due to a higher depreciable base and amortizations of
transmission and distribution assets in Texas.
•A $19 million increase in securitization amortizations primarily due to prior
year AEP Texas Central Transition Funding II LLC bonds that matured in July 2020
and final refunds that were completed in 2021. This increase was offset in Other
Revenues above.
•An $11 million increase in recoverable advanced metering system depreciable
expenses in Texas.
These increases were partially offset by:
•A $6 million decrease in recoverable smart grid depreciable expenses in Ohio.
This decrease was offset in Retail Margins above.
                                       39
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•A $6 million decrease in recoverable Distribution Investment Rider depreciable
expenses in Ohio. This decrease was offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $21 million primarily due to increased
property taxes driven by additional investments in transmission and distribution
assets and higher tax rates.
•Non-Service Cost Components of Net Periodic Benefit Cost decreased $14 million
primarily due to an increase in discount rates, an increase in the expected
return on plan assets and favorable plan returns in 2021.
•Interest Expense increased $13 million primarily due to the following:
•A $21 million increase in Texas primarily due to higher long-term debt balances
and higher interest rates.
This increase was partially offset by:
•A $7 million decrease in Ohio primarily due to the retirement of a higher rate
bond, partially offset by the issuance of a lower rate bond in 2021.
•Income Tax Expense increased $37 million primarily due to an increase in pretax
book income and a decrease in amortization of Excess ADIT. The decrease in
amortization of Excess ADIT is partially offset in Gross Margin above.
                                       40
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AEP TRANSMISSION HOLDCO

                                                              Three Months Ended                      Nine Months Ended
                                                                 September 30,                          September 30,
            AEP Transmission Holdco                          2022                2021              2022               2021
                                                                                    (in millions)
Transmission Revenues                                  $    430.9             $ 391.6          $ 1,221.1          $ 1,146.8
Other Operation and Maintenance                              46.5                40.3              114.4               96.9
Depreciation and Amortization                                89.5                78.1              262.7              225.5
Taxes Other Than Income Taxes                                70.5                62.7              207.9              183.4
Operating Income                                            224.4               210.5              636.1              641.0
Interest and Investment Income                                0.7                 0.3                1.1                0.7

Allowance for Equity Funds Used During
Construction                                                 20.3                16.1               51.2               49.3
Non-Service Cost Components of Net Periodic
Benefit Cost                                                  1.3                 0.5                3.8                1.6
Interest Expense                                            (44.4)              (37.6)            (124.2)            (108.4)
Income Before Income Tax Expense and Equity
Earnings                                                    202.3               189.8              568.0              584.2
Income Tax Expense                                           52.1                42.0              141.9              131.2
Equity Earnings of Unconsolidated Subsidiary                 21.2                20.1               61.7               57.7
Net Income                                                  171.4               167.9              487.8              510.7
Net Income Attributable to Noncontrolling
Interests                                                     0.9                 1.1                2.4                3.2

Earnings Attributable to AEP Common Shareholders $ 170.5

  $ 166.8          $   485.4          $   507.5



    Summary of Investment in Transmission Assets for AEP Transmission Holdco

                                                                September 30,
                                                             2022            2021
                                                                (in millions)
         Plant in Service                                $ 12,455.2      $ 

11,256.0

         Construction Work in Progress                      1,752.7         

1,609.6

         Accumulated Depreciation and Amortization            986.3         

758.1

         Total Transmission Property, Net                $ 13,221.6      $ 

12,107.5

                                       41
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Third Quarter of 2022 Compared to Third Quarter of 2021

Reconciliation of Third Quarter of 2021 to Third Quarter of 2022

 Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
                                 (in millions)

        Third Quarter of 2021                                         $ 166.8

        Changes in Transmission Revenues:
        Transmission Revenues                                            39.3
        Total Change in Transmission Revenues                            39.3

        Changes in Expenses and Other:
        Other Operation and Maintenance                                  (6.2)
        Depreciation and Amortization                                   (11.4)
        Taxes Other Than Income Taxes                                    (7.8)
        Interest and Investment Income                                    0.4

        Allowance for Equity Funds Used During Construction               4.2
        Non-Service Cost Components of Net Periodic Pension Cost          0.8
        Interest Expense                                                 (6.8)
        Total Change in Expenses and Other                              (26.8)

        Income Tax Expense                                              (10.1)
        Equity Earnings of Unconsolidated Subsidiary                      1.1
        Net Income Attributable to Noncontrolling Interests               0.2

        Third Quarter of 2022                                         $ 170.5

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

•Transmission Revenues increased $39 million primarily due to continued investment in transmission assets.

Expenses and Other and Income Tax Expense changed between years as follows:

•Other Operation and Maintenance expenses increased $6 million primarily due to
cancelled capital projects.
•Depreciation and Amortization expenses increased $11 million primarily due to a
higher depreciable base.
•Taxes Other Than Income Taxes increased $8 million primarily due to higher
property taxes as a result of increased transmission investment.
•Allowance for Equity Funds Used During Construction increased $4 million
primarily due to higher CWIP.
•Interest Expense increased $7 million primarily due to higher long-term debt
balances.
•Income Tax Expense increased $10 million primarily due to an increase in pretax
book income and a decrease in parent company loss benefit.
                                       42
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Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021

Reconciliation of Nine Months Ended September 30, 2021 to Nine Months Ended

September 30, 2022
 Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
                                 (in millions)

        Nine Months Ended September 30, 2021                          $ 507.5

        Changes in Transmission Revenues:
        Transmission Revenues                                            74.3
        Total Change in Transmission Revenues                            74.3

        Changes in Expenses and Other:
        Other Operation and Maintenance                                 (17.5)
        Depreciation and Amortization                                   (37.2)
        Taxes Other Than Income Taxes                                   (24.5)
        Interest and Investment Income                                    0.4

        Allowance for Equity Funds Used During Construction               1.9
        Non-Service Cost Components of Net Periodic Pension Cost          2.2
        Interest Expense                                                (15.8)
        Total Change in Expenses and Other                              (90.5)

        Income Tax Expense                                              (10.7)
        Equity Earnings of Unconsolidated Subsidiary                      4.0
        Net Income Attributable to Noncontrolling Interests               0.8

        Nine Months Ended September 30, 2022                          $ 485.4



The major components of the increase in transmission revenues, which consists of
wholesale sales to affiliates and nonaffiliates, were as follows:
•Transmission Revenues increased $74 million primarily due to the following:
•A $117 million increase due to continued investment in transmission assets.
This increase was partially offset by:
•A $30 million decrease due to the affiliated annual transmission formula rate
true-up. This decrease was offset in Other Operation and Maintenance expense
across the other Registrant Subsidiaries.
•A $13 million decrease due to the nonaffiliated annual transmission formula
rate true-up.
Expenses and Other, Income Tax Expense and Equity Earnings of Unconsolidated
Subsidiary changed between years as follows:
•Other Operation and Maintenance expenses increased $18 million primarily due to
the following:
•A $15 million increase in employee-related expenses.
•A $5 million increase due to cancelled capital projects.
•Depreciation and Amortization expenses increased $37 million primarily due to a
higher depreciable base.
•Taxes Other Than Income Taxes increased $25 million primarily due to higher
property taxes as a result of increased transmission investment.
•Interest Expense increased $16 million primarily due to higher long-term debt
balances.
•Income Tax Expense increased $11 million primarily due to a decrease in parent
company loss benefit, partially offset by a decrease in pretax book income.
•Equity Earnings of Unconsolidated Subsidiary increased $4 million primarily due
to higher pretax equity earnings for ETT, partially offset by lower pretax
equity earnings for Pioneer.


                                       43
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GENERATION & MARKETING

                                                              Three Months Ended                      Nine Months Ended
                                                                 September 30,                          September 30,
             Generation & Marketing                          2022                2021              2022               2021
                                                                                    (in millions)
Revenues                                               $    735.4             $ 621.1          $ 2,014.3          $ 1,691.9
Fuel, Purchased Electricity and Other                       566.1               444.7            1,534.0            1,368.7

Gross Margin                                                169.3               176.4              480.3              323.2
Other Operation and Maintenance                              44.7                38.2               71.2               98.8

Gain on Sale of Mineral Rights                                  -                   -             (116.3)                 -
Depreciation and Amortization                                23.1                21.1               68.8               59.7
Taxes Other Than Income Taxes                                 3.1                 2.6                9.3                8.1
Operating Income                                             98.4               114.5              447.3              156.6
Interest and Investment Income                               12.5                 1.3               21.4                2.4

Non-Service Cost Components of Net Periodic
Benefit Cost                                                  5.1                 3.8               15.4               11.5
Interest Expense                                            (16.7)               (4.0)             (30.7)             (11.1)
Income Before Income Tax Expense (Benefit) and
Equity Loss                                                  99.3               115.6              453.4              159.4
Income Tax Expense (Benefit)                                 (5.1)                8.3              (25.3)             (31.0)
Equity Loss of Unconsolidated Subsidiaries                   (8.2)               (7.8)            (200.6)              (6.2)
Net Income                                                   96.2                99.5              278.1              184.2
Net Loss Attributable to Noncontrolling
Interests                                                    (1.3)               (1.2)              (6.2)              (5.5)

Earnings Attributable to AEP Common Shareholders $ 97.5

   $ 100.7          $   284.3          $   189.7



              Summary of MWhs Generated for Generation & Marketing

                                     Three Months Ended            Nine Months Ended
                                       September 30,                 September 30,
                                   2022              2021        2022              2021
                                                  (in millions of MWhs)
                 Fuel Type:
                 Coal               1                 1           3                 3
                 Renewables         1                 1           3                 3

                 Total MWhs         2                 2           6                 6


                                       44

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Third Quarter of 2022 Compared to Third Quarter of 2021

                   Reconciliation of Third Quarter of 2021 to Third Quarter 

of 2022

             Earnings Attributable to AEP Common Shareholders from

Generation & Marketing
                                            (in millions)

Third Quarter of 2021                                                                  $      100.7

Changes in Gross Margin:
Merchant Generation                                                                             4.5
Renewable Generation                                                                           19.2
Retail, Trading and Marketing                                                                 (30.8)
Total Change in Gross Margin                                                                   (7.1)

Changes in Expenses and Other:
Other Operation and Maintenance                                                                (6.5)

Depreciation and Amortization                                                                  (2.0)
Taxes Other Than Income Taxes                                                                  (0.5)
Interest and Investment Income                                                                 11.2

Non-Service Cost Components of Net Periodic Benefit Cost                                        1.3
Interest Expense                                                                              (12.7)
Total Change in Expenses and Other                                                             (9.2)

Income Tax Expense                                                                             13.4
Equity Earnings (Loss) of Unconsolidated Subsidiaries                                          (0.4)
Net Income Attributable to Noncontrolling Interests                                             0.1

Third Quarter of 2022                                                                  $       97.5

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 $5 million primarily due to higher market prices.
•Renewable Generation increased $19 million primarily due to higher market
prices at Texas wind facilities and new solar projects placed in service.
•Retail, Trading and Marketing decreased $31 million due to lower gains from
mark-to-market economic hedging activity.

Expenses and Other and Income Tax Expense changed between years as follows:

•Other Operation and Maintenance expenses increased $7 million primarily due to
the installment sale of Amazon substations in 2021.
•Interest and Investment Income increased $11 million primarily due to an
increase in advances to affiliates.
•Interest Expense increased $13 million due to higher interest rates in 2022.
•Income Tax Expense decreased $13 million primarily due to a decrease in pretax
book income, an increase in PTCs and a decrease in state income taxes.

                                       45
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Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021

Reconciliation of Nine Months Ended September 30, 2021 to Nine Months Ended September 30, 2022

             Earnings Attributable to AEP Common Shareholders from

Generation & Marketing

                                            (in millions)

Nine Months Ended September 30, 2021                                                   $      189.7

Changes in Gross Margin:
Merchant Generation                                                                            (6.1)
Renewable Generation                                                                           35.2
Retail, Trading and Marketing                                                                 128.0
Total Change in Gross Margin                                                                  157.1

Changes in Expenses and Other:
Other Operation and Maintenance                                                                27.6

Gain on Sale of Mineral Rights                                                                116.3
Depreciation and Amortization                                                                  (9.1)
Taxes Other Than Income Taxes                                                                  (1.2)
Interest and Investment Income                                                                 19.0

Non-Service Cost Components of Net Periodic Benefit Cost                                        3.9
Interest Expense                                                                              (19.6)
Total Change in Expenses and Other                                                            136.9

Income Tax Benefit                                                                             (5.7)
Equity Earnings (Loss) of Unconsolidated Subsidiaries                                        (194.4)
Net Loss Attributable to Noncontrolling Interests                                               0.7

Nine Months Ended September 30, 2022                                                   $      284.3

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, purchased electricity and certain cost of service for retail operations were as follows:

•Merchant Generation decreased $6 million primarily due to additional Cardinal
plant outage days in 2022 and the sale of Racine, partially offset by higher
market prices.
•Renewable Generation increased $35 million primarily due to higher market
prices at Texas wind facilities and new solar projects placed in service.
•Retail, Trading and Marketing increased $128 million due to higher
mark-to-market economic hedge activity driven by higher commodity prices.

Expenses and Other, Income Tax Benefit and Equity Earnings (Loss) of Unconsolidated Subsidiaries changed between years as follows:

•Other Operation and Maintenance expenses decreased $28 million primarily due to
higher land sales and the sale of renewable development projects.
•Gain on Sale of Mineral Rights increased $116 million due to the current year
sale of mineral rights.
•Depreciation and Amortization expenses increased $9 million due to a higher
depreciable base from increased investments in renewable energy assets.
•Interest and Investment Income increased $19 million primarily due to an
increase in advances to affiliates.
•Non-Service Cost Components of Net Periodic Benefit Cost decreased $4 million
primarily due to an increase in discount rates, an increase in the expected
return on plan assets and favorable plan returns in 2021.
•Interest Expense increased $20 million due to higher interest rates in 2022.
                                       46
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•Income Tax Benefit decreased $6 million primarily due to an increase in pretax
book income partially offset by an increase in PTCs and a favorable discrete tax
adjustment in 2022.
•Equity Earnings (Loss) of Unconsolidated Subsidiaries decreased $194 million
primarily due to the impairment of AEP's investment in Flat Ridge 2 Wind LLC.
                                       47
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CORPORATE AND OTHER

Third Quarter of 2022 Compared to Third Quarter of 2021

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $65 million in 2021 to a loss of $227 million in 2022 primarily due to:

•A $195 million pretax loss related to the anticipated sale of Kentucky
operations.
•A $35 million increase in interest expense due to higher interest rates on
short-term debt, an increase in advances from affiliates and an increase in
long-term debt outstanding.

These items were partially offset by:

•A $28 million increase due to favorable changes in gains and losses from AEP's
investment in ChargePoint. As of August 2022, AEP no longer has a direct
investment in ChargePoint.
•A $56 million decrease in Income Tax Expense primarily due to the following:
•A $45 million decrease due to a loss on the anticipated sale of Kentucky
operations.
•A $15 million decrease due to a change in Parent Company Loss Benefit.

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $108 million in 2021 to a loss of $406 million in 2022 primarily due to:

•A $263 million pretax loss related to the anticipated sale of Kentucky
operations.
•A $54 million increase in interest expense due to higher long-term debt
outstanding and higher interest rates on short-term debt.
•A $45 million decrease at EIS, primarily due to lower returns on investments
and an increase in reserves.
•A $24 million decrease in equity earnings.
•A $22 million decrease due to unfavorable changes in gains and losses from
AEP's investment in ChargePoint. As of August 2022, AEP no longer has a direct
investment in ChargePoint.

These items were partially offset by:

•A $103 million decrease in Income Tax Expense primarily due to the following:
•A $45 million decrease due to a loss on the anticipated sale of Kentucky
operations.
•A $29 million decrease due to a change in pretax book income.
•A $33 million decrease due to Parent Company Loss Benefit.

AEP SYSTEM INCOME TAXES

Third Quarter of 2022 Compared to Third Quarter of 2021

Income Tax Expense decreased $86 million primarily due to an increase in benefit from PTCs and a decrease in pretax book income.

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021

Income Tax Expense decreased $95 million primarily due to:
•A $73 million decrease due to an increase in PTCs.
•A $25 million decrease due to a decrease in pretax book income.
•A $26 million decrease due to discrete adjustments, primarily driven by the
remeasurement of state deferred taxes as a result of newly enacted West Virginia
and Oklahoma state legislation in 2021.
These decreases were partially offset by:
•A $33 million increase due to a decrease in amortization of Excess ADIT.
                                       48
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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

                                                             September 30, 2022                         December 31, 2021
                                                                                  (dollars in millions)
Long-term Debt, including amounts due within one year
(a)                                                   $  35,050.1               56.3  %       $       33,454.5               57.0  %
Short-term Debt                                           2,702.3                4.3                   2,614.0                4.4
Total Debt                                               37,752.4               60.6                  36,068.5               61.4
AEP Common Equity                                        24,278.2               39.0                  22,433.2               38.2
Noncontrolling Interests                                    234.1                0.4                     247.0                0.4
Total Debt and Equity Capitalization                  $  62,264.7              100.0  %       $       58,748.7              100.0  %


(a)Amount excludes $1.2 billion and $1.1 billion as of September 30, 2022 and
December 31, 2021, respectively, of Long-term Debt classified as Liabilities
Held for Sale on the balance sheet. See "Disposition of KPCo and KTCo" section
of Note 6 for additional information.

AEP's ratio of debt-to-total capital decreased from 61.4% as of December 31,
2021 to 60.6% as of September 30, 2022 primarily due to the settlement of the
forward equity purchase contracts related to the 2019 Equity Units, partially
offset by an increase in debt to support distribution, transmission and
renewable investment growth. See "Equity Units" section of Note 12 for
additional information.

Liquidity

Liquidity, or access to cash, is an important factor in determining AEP's
financial stability. Management believes AEP has adequate liquidity. As of
September 30, 2022, 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. AEP and
its utilities finance its operations with commercial paper and other variable
rate instruments that are subject to fluctuations in interest rates. To the
extent that the Federal Reserve continues to raise short-term interest rates, it
could reduce future net income and cash flows and impact financial condition. In
February 2021, severe winter weather impacted certain AEP service territories
resulting in disruptions to SPP market conditions. See Note 4 - Rate Matters for
additional information. 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. In
March 2022, AEP extended the maturity date of the original 364-Day Term Loan to
August 2022. In August 2022, AEP paid off the $500 million Term Loan. In 2022,
increased fuel and purchased power prices continue to lead to an increase in
under collection of fuel costs. As a result, in July 2022, APCo and KPCo entered
into term loans of $100 million and $75 million, respectively, to help address
the cash flow implications of the increased fuel and purchased power costs. See
"Deferred Fuel Costs" section of Executive Overview for additional information
on how the registrants are addressing the increase in deferred fuel regulatory
assets. In September 2022, the ODFA issued ratepayer-backed securitization bonds
for the purpose of reimbursing PSO for $687 million of extraordinary fuel costs
and purchases of electricity incurred during the February 2021 severe winter
weather event. See Note 4 - Rate Matters for additional information.


                                       49
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Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments. As
of September 30, 2022, available liquidity was approximately $3.6 billion as
illustrated in the table below:

                                                            Amount          

Maturity

    Commercial Paper Backup:                            (in millions)
                   Revolving Credit Facility           $      4,000.0       March 2027   (a)
                   Revolving Credit Facility                  1,000.0       March 2024   (a)

    Cash and Cash Equivalents                                   522.2
    Total Liquidity Sources                                   5,522.2
    Less:          AEP Commercial Paper Outstanding           1,952.3

    Net Available Liquidity                            $      3,569.9

(a)In April 2022, AEP extended the maturity dates of the Revolving Credit Facilities from March 2026 to March 2027 and from March 2023 to March 2024, respectively.

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 nine months of 2022 was $2.4 billion. The weighted-average
interest rate for AEP's commercial paper during 2022 was 1.82%.

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 five uncommitted facilities totaling $400 million.
The Registrants' maximum future payments for letters of credit issued under the
uncommitted facilities as of September 30, 2022 was $310 million with maturities
ranging from October 2022 to August 2023.

Securitized Accounts Receivables

AEP Credit's receivables securitization agreement provides a commitment of $750
million from bank conduits to purchase receivables and was amended in September
2021 to include a $125 million and a $625 million facility. The $125 million
facility was renewed in September 2022 and amended to extend the expiration date
to September 2024. The $625 million facility also expires in September 2024. As
of September 30, 2022, the affiliated utility subsidiaries are in compliance
with all requirements under the agreement.

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 September 30, 2022, this contractually-defined percentage was 57.7%.
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.

                                       50
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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.

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.
There were no issuances under the ATM program for the nine months ended
September 30, 2022. As of September 30, 2022, approximately $511 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.

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 settled 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. In January
2022, AEP successfully remarketed the notes on behalf of holders of the
corporate units and did not directly receive any proceeds therefrom. Instead,
the holders of the corporate units used the debt remarketing proceeds to settle
the forward equity purchase contract with AEP. The interest rate on the notes
was reset to 2.031% with the maturity remaining in 2024. In March 2022, AEP
issued 8,970,920 shares of AEP common stock and received proceeds totaling
$805 million under the settlement of the forward equity purchase contract. AEP
common stock held in treasury was used to settle the forward equity purchase
contract.

See Note 12 - Financing Activities for additional information.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.83 per share in
October 2022. 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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