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

July 22, 2021 at 07:46 am EDT

EXECUTIVE OVERVIEW

Impacts of Severe Winter Weather

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

Storm Restoration Costs



The impact of the severe winter weather resulted in power outages and extensive
damage to transmission and distribution infrastructures across the service
territories of APCo, KPCo and SWEPCo. As of June 30, 2021, an estimated $65
million of capital expenditures and $144 million of restoration expenses have
been incurred related to the severe winter weather. Approximately $138 million
of the expenses represent incremental restoration expenses and have been
deferred as regulatory assets. The KPSC and LPSC issued orders authorizing the
deferral of incremental restoration expenses as regulatory assets. KPCo intends
to seek recovery of these incremental storm restoration costs in their next base
rate case while APCo and SWEPCo are expected to seek recovery in separate
filings. If any of the restoration costs are not recoverable, it could reduce
future net income and cash flows and impact financial condition.

Impacts in SPP



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

Retail Customers



As of June 30, 2021, PSO and SWEPCo have deferred regulatory assets of $669
million and $453 million, respectively, relating to natural gas expenses and
purchases of electricity incurred from February 9, 2021, to February 20, 2021,
as a result of severe winter weather. SWEPCo's deferred regulatory asset
consists of $116 million, $161 million and $176 million related to the Arkansas,
Louisiana and Texas jurisdictions, respectively. PSO and SWEPCo have active fuel
clauses that allow for the recovery of prudently incurred fuel and purchased
power expenses. Given the significance of these costs, PSO and SWEPCo expect the
costs to be subject to prudency reviews. Management believes these costs are
probable of future recovery, but expects the recovery period to be extended to
mitigate the impact on customer bills.

In March 2021, the APSC issued an order authorizing recovery of the Arkansas
jurisdictional share of the retail customer fuel costs over five years, with the
appropriate carrying charge to be determined at a later date. Accordingly, in
April 2021, SWEPCo began recovery of its Arkansas jurisdictional share of these
fuel costs, which are subject to true-up by the APSC. Also in April 2021, SWEPCo
filed testimony supporting a five-year recovery with a pretax rate of return of
6.05% which has been supported by APSC staff. Various other parties have
recommended recovery periods ranging from 5-20 years with a pretax rate of
return of 1.65%. In July 2021, the APSC ordered more testimony regarding the
option of utilizing securitization to recover the fuel costs. Once testimony
concludes, a hearing will be scheduled. The prudency of these fuel costs is
expected to be addressed in a separate proceeding.

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

In April 2021, the OCC approved a waiver for PSO allowing the deferral of the
extraordinary fuel and purchase of electricity costs, including carrying costs
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 to
securitize the extraordinary fuel and purchase of electricity costs impacting
the utilities within the state. Under the legislation, the OCC has the authority
to determine, after receiving an application from a rate-regulated utility, if
the extraordinary fuel and purchase of electricity costs incurred in February
2021 may be mitigated through securitization to reduce the impact on customer
bills. PSO has filed an application for a financing order to pursue
securitization.

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

Wholesale Customers



During the first quarter of 2021, SWEPCo billed wholesale customers $104 million
resulting from the severe winter weather events. SWEPCo worked with wholesale
customers to establish payment terms for the outstanding accounts receivable. As
of June 30, 2021, $63 million of accounts receivable from wholesale customers
are outstanding. Management believes these receivables are probable of future
collection.

PSO and SWEPCo Cash Flow Implications



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

Although the February 2021 severe winter weather did not materially impact AEP's
results of operations for the three and six months ended June 30, 2021, if
either PSO or SWEPCo is unable to recover these fuel and purchased power costs,
or obtain authorization of a reasonable carrying charge on these costs, it could
reduce future net income and cash flows and impact financial condition.

COVID-19



In 2020, COVID-19 was declared a pandemic by the World Health Organization and
the Centers for Disease Control and Prevention. Its rapid spread around the
world and throughout the United States prompted many countries, including the
United States, to institute restrictions on travel, public gatherings and
certain business operations. These restrictions significantly disrupted economic
activity in AEP's service territory and resulted in reduced demand for energy,
particularly from commercial and industrial customers. In 2021,
weather-normalized customer demand has improved from the pandemic levels
experienced in 2020. Management expects continued improvement during the
remainder of 2021 as additional vaccinations occur and economic activity
improves.

During 2020, AEP's electric operating companies informed both retail customers
and state regulators that disconnections for non-payment were temporarily
suspended. Shortly thereafter, AEP's state regulators also imposed temporary
moratoria on customary disconnection practices. As of June 30, 2021, AEP's
electric operating companies have resumed customary disconnection practices in
all regulated jurisdictions with the exception of Virginia. AEP continues to
work with regulators and stakeholders in Virginia and management currently
anticipates resuming customary disconnection practices in the third quarter of
2021.
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AEP has been and continues to be proactive in engaging with customers to collect
payments or establish payment arrangements for outstanding balances. As of
June 30, 2021, AEP currently does not expect accounts receivable aging to have a
material adverse impact on the Registrants' allowance for uncollectible accounts
based on considerations of the COVID-19 impacts and past trends during times of
economic instability. Management continues to monitor developments that could
have an impact on customer collections.

The Registrants continue to take steps to mitigate the potential risks to
customers, suppliers and employees posed by the spread of COVID-19. As of
June 30, 2021, there has been no material adverse impact to the Registrants'
business operations and customer service as a result of the current remote work
model. In the second quarter of 2021, management announced a Future of Work
model designating employees as: (a) On-Site employees, (b) Hybrid employees and
(c) Remote employees. Management currently expects to begin transitioning
On-Site employees back to their AEP workplace and Hybrid employees with set
schedules back to their AEP workplace in August 2021. Remote employees will
begin transitioning back to their AEP workplace in September 2021 on an
as-needed basis. Management will continue to review and modify plans as
conditions change.

In 2021, the Registrants have experienced certain supply chain disruptions
driven by several factors including staffing and travel issues caused by the
COVID-19 pandemic, the economic recovery from the pandemic, labor shortages 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. Management has implemented risk mitigation strategies in an
attempt to mitigate the impacts of these supply chain disruptions. However, a
prolonged continuation or a future increase in the severity of supply chain
disruptions could impact the cost of certain goods and services and extend lead
times which could reduce future net income and cash flows and impact financial
condition.

Customer Demand

AEP's weather-normalized retail sales volumes for the second quarter of 2021
increased by 6.3% from the second quarter of 2020. Weather-normalized
residential sales decreased by 3.1% in the second quarter of 2021 from the
second quarter of 2020. AEP's second quarter 2021 industrial sales volumes
increased by 12.8% compared to the second quarter of 2020. The increase in
industrial sales was spread across many industries. Weather-normalized
commercial sales increased 10% in the second quarter of 2021 from the second
quarter of 2020.

AEP's weather-normalized retail sales volumes for the six months ended June 30,
2021 increased by 1.9% compared to the six months ended June 30, 2020.
Weather-normalized residential sales decreased by 0.5% for the six months ended
June 30, 2021 compared to the six months ended June 30, 2020. AEP's industrial
sales volumes for the six months ended June 30, 2021 increased by 2.8% compared
to the six months ended June 30, 2020. The recovery in industrial sales volumes
was spread across many industries. Weather-normalized commercial sales increased
3.9% for the six months ended June 30, 2021 compared to the six months ended
June 30, 2020.

The increase in industrial and commercial sales volumes is primarily the result
of the COVID-19 pandemic's impact on the second quarter of 2020 when public
health restrictions significantly disrupted economic activity and demand for
energy in AEP's service territory. Similarly, the decline in weather-normalized
residential sales volumes is driven by the cessation of stay at home
restrictions that were in place in 2020 and the gradual return of customers to
the workplace.


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Regulatory Matters

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

•2017-2019 Virginia Triennial Review - In November 2020, the Virginia SCC issued
an order on APCo's 2017-2019 Triennial Review filing concluding that APCo earned
above its authorized ROE but within its ROE band for the 2017-2019 period,
resulting in no refund to customers and no change to APCo base rates on a
prospective basis. The Virginia SCC approved a prospective 9.2% ROE for APCo's
2020-2022 triennial review period with the continuation of a 140 basis point
band (8.5% bottom, 9.2% midpoint, 9.9% top).

In December 2020, an intervenor filed a petition at the Virginia SCC requesting
reconsideration of: (a) the failure of the Virginia SCC to apply a threshold
earnings test to the approved regulatory asset for APCo's closed coal-fired
generation assets, (b) the Virginia SCC's use of a 2011 benchmark study to
measure the replacement value of capacity for purposes of APCo's 2017 - 2019
earnings test and (c) the reasonableness and prudency of APCo's investments in
AMI meters.

In December 2020, APCo filed a petition at the Virginia SCC requesting
reconsideration of: (a) certain issues related to APCo's going-forward rates and
(b) the Virginia SCC's decision to deny APCo tariff changes that align rates
with underlying costs. For APCo's going-forward rates, APCo requested that the
Virginia SCC clarify its final order and clarify whether APCo's current rates
will allow it to earn a fair return. If the Virginia SCC's order did conclude on
APCo's ability to earn a fair return through existing base rates, APCo further
requested that the Virginia SCC clarify whether it has the authority to also
permit an increase in base rates.

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

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

APCo ultimately seeks an increase in base rates through its appeal to the
Virginia Supreme Court. Among other issues, this appeal includes APCo's request
for proper treatment of the closed coal-fired plant assets in APCo's 2017-2019
triennial period, reducing APCo's earnings below the bottom of its authorized
ROE band. If APCo's appeals regarding treatment of the closed coal plants are
granted by the Virginia Supreme Court, it could initially reduce future net
income and impact financial condition. The initial negative impact for the
write-off of closed coal-fired plant asset balances would potentially be
partially offset by an increase in base rates for earning below APCo's 2017-2019
authorized ROE band.
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•2020 Ohio Base Rate Case - In June 2020, OPCo filed a request with the PUCO for
a $42 million annual increase in base rates based upon a proposed 10.15% ROE net
of existing riders. In March 2021, OPCo, the PUCO staff and various intervenors
filed a joint stipulation and settlement agreement with the PUCO based upon an
annual revenue decrease of $68 million and an ROE of 9.7%. The difference
between OPCo's requested annual base rate increase and the agreed upon decrease
is primarily due to a reduction in the requested ROE, the removal of proposed
future energy efficiency costs and a decrease in vegetation management expenses
moved to recovery in riders. In addition, the joint stipulation and settlement
agreement includes an increased fixed monthly residential customer charge, the
discontinuation of rate decoupling and the continuation of the DIR with annual
revenue caps of $57 million in 2021, $91 million in 2022, $116 million in 2023
and $51 million for the first five months of 2024. Annual revenue caps for the
DIR can be increased if OPCo achieves certain reliability standards. A hearing
took place with the PUCO in May 2021 and initial briefs were filed in June 2021
followed by reply briefs in July 2021. An order from the PUCO is expected by the
end of 2021.

•Hurricane Laura - In August 2020, Hurricane Laura hit the coasts of Louisiana
and Texas, causing power outages to more than 130,000 customers across SWEPCo's
service territories. Prior to Hurricane Laura, SWEPCo did not have a catastrophe
reserve or automatic deferral authority within any of its jurisdictions. In
October 2020, the LPSC issued an order allowing Louisiana utilities, including
SWEPCo, to establish a regulatory asset to track and defer expenses associated
with Hurricane Laura. In October 2020, as part of the 2020 Texas Base Rate Case,
SWEPCo requested deferral authority of incremental other operation and
maintenance expenses. As of June 30, 2021, management estimates that SWEPCo has
incurred incremental other operation and maintenance expenses of $83 million
($81 million of which has been deferred as a regulatory asset related to the
Louisiana jurisdiction) and incremental capital expenditures of $30 million, all
of which is related to the Louisiana jurisdiction. Management expects to request
recovery of these storm costs in a filing inclusive of SWEPCo's various other
storm costs.

•2012 Texas Base Rate Case - In 2012, SWEPCo filed a request with the PUCT to
increase annual base rates primarily due to the completion of the Turk Plant. In
2013, the PUCT issued an order affirming the prudence of the Turk Plant. In July
2018, the Texas Third Court of Appeals reversed the PUCT's judgment affirming
the prudence of the Turk Plant and remanded the issue back to the PUCT. In
January 2019, SWEPCo and the PUCT filed petitions for review with the Texas
Supreme Court. In March 2021, the Texas Supreme Court issued an opinion
reversing the July 2018 judgment of the Texas Third Court of Appeals and
agreeing with the PUCT's judgment affirming the prudence of the Turk Plant. No
parties filed a motion for rehearing with the Texas Supreme Court. As of
June 30, 2021, the net book value of Turk Plant was $1.4 billion, before cost of
removal, including materials and supplies inventory and CWIP. SWEPCo's Texas
jurisdictional share of the Turk Plant investment is approximately 33%.

•In July 2019, Ohio House Bill 6 (HB 6), which offered incentives for
power-generating facilities with zero or reduced carbon emissions, was signed
into law by the Ohio Governor.  HB 6 phased out current energy efficiency
programs as of December 31, 2020, including OPCo's shared savings revenues of
$26 million annually and renewable mandates after 2026. HB 6 also provided for
the recovery of existing renewable energy contracts on a bypassable basis
through 2032 and included a provision for recovery of OVEC costs through 2030
which will be allocated to all electric distribution utilities on a
non-bypassable basis.  OPCo's Inter-Company Power Agreement for OVEC terminates
in June 2040. In July 2020, an investigation led by the U.S. Attorney's Office
resulted in a federal grand jury indictment of the Speaker of the Ohio House of
Representatives, Larry Householder, four other individuals, and Generation Now,
an entity registered as a 501(c)(4) social welfare organization, in connection
with an alleged racketeering conspiracy involving the adoption of HB 6. Certain
defendants in that case have since pleaded guilty. In August 2020, an AEP
shareholder filed a putative class action lawsuit against AEP and certain of its
officers for alleged violations of securities laws in connection with HB 6. On
May 10, 2021, the defendants filed a motion to dismiss the securities litigation
for failure to state a claim, and under the Court's briefing schedule the motion
will be fully briefed by July 26, 2021. In addition, four AEP shareholders have
filed derivative actions purporting
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to 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,
rescinded the payments to the nonaffiliated owner of Ohio's nuclear power plants
that were previously authorized under HB 6. The new legislation, House Bill 128,
went into effect after 90 days and leaves unchanged other provisions of HB 6
regarding energy efficiency programs, recovery of renewable energy costs and
recovery of OVEC costs. To the extent that OPCo is unable to recover the costs
of renewable energy contracts on a bypassable basis by the end of 2032, recover
costs of OVEC after 2030 or incurs significant costs associated with the
securities class action or the derivative actions, it could reduce future net
income and cash flows and impact financial condition.

•In December 2020, APCo and WPCo filed a proposal with the WVPSC to implement an
investment tracker surcharge mechanism for recovering costs associated with
capital investment made between base rate cases. The initial filing requests a
total annual increase of $50 million ($41 million related to APCo), which
represents recovery of costs associated with infrastructure investments made
over an approximate three-year period since the companies' last base rate case
filing in 2018. The filing also proposes that APCo and WPCo could submit annual
filings with requested increases capped to a percentage of total retail revenues
(3.5% in the first year and 3% in subsequent filings with an overall cap of
9.5%). If a future base rate case is filed, the surcharge would reset to zero on
implementation of the new rates.

In July 2021, the WVPSC issued an order approving the investment tracker
mechanism with an initial annual revenue requirement of $44 million ($35 million
related to APCo) effective September 2021 based on a 9.25% ROE. Under the
conditions of the order, APCo and WPCo would not be permitted to file a base
rate case before June 30, 2024. The order also allows APCo and WPCo to request
future year investment tracker increases for assets placed in service during the
most recent 12-month period ending September 30th, subject to an annual three
percent rider increase cap on base year total retail revenues. APCo and WPCo
filed a petition for reconsideration with the WVPSC to reconsider and modify
certain parts of the order, including the condition that APCo and WPCo will not
file a base rate case before June 30, 2024. The companies request certain
exceptions to be recognized that allow for base rate case filings in certain
circumstances.

•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 is subject to a 60 day comment
period followed by a 30 day period for reply comments. A final rule could be
issued in the fourth quarter of 2021.

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

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
impact on AEP's transmission owning subsidiaries whose RTO membership is not
voluntary, including OPCo and AEP Ohio Transmission Company.
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If the FERC modifies its RTO Incentive policy, it would be applied, as
applicable, to AEP's PJM, SPP and MISO transmission owning subsidiaries on a
prospective basis, and could affect future net income and cash flows and impact
financial condition. Based on management's preliminary estimates, if a final
rule is adopted consistent with the April 2021 supplemental NOPR, it could
reduce AEP's pretax income by approximately $55 million to $70 million on an
annual basis.

Utility Rates and Rate Proceedings



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

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

Completed Base Rate Case Proceedings



                                           Approved Revenue

Approved New Rates


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

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

Pending Base Rate Case Proceedings


                                                                                                                                          Commission Staff/
                                                   Filing                 Requested Revenue                    Requested                 Intervenor Range of
   Company             Jurisdiction                 Date                 Requirement Increase                     ROE                      Recommended ROE
                                                                            (in millions)
     OPCo                  Ohio                   June 2020            $                42.3                     10.15%                8.76%-9.78%           (a)
    SWEPCo                 Texas                October 2020                           105.0    (b)              10.35%                  9%-9.22%            (c)
    SWEPCo               Louisiana              December 2020                          114.0                     10.35%                 9.1%-9.8%            (d)
     PSO                 Oklahoma                April 2021                            172.4                      10%                      (e)
     I&M                  Indiana                 July 2021                            104.0     (f)              10%                      (g)



(a)In March, 2021 a joint stipulation and settlement agreement was filed with
the PUCO which included a $68 million decrease in base rates based upon an ROE
of 9.7%.
(b)The request would move transmission and distribution interim revenues
recovered through riders into base rates. Eliminating these riders would result
in a net annual requested base rate increase of $90 million primarily due to
increased investments.
(c)Staff and intervenors recommended base rate increases ranged from $20 million
to $70 million.
(d)Staff recommended a base rate increase of $6 million.
(e)Intervenor testimony is expected in the third quarter of 2021.
(f)Proposed to be phased-in with a $73 million annual increase effective May
2022 and the remaining $31 million annual increase effective January 2023.
(g)Intervenor testimony is expected in the fourth quarter of 2021.
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Renewable Generation

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

Contracted Renewable Generation Facilities



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

As of June 30, 2021, subsidiaries within AEP's Generation & Marketing segment
had approximately 1,633 MWs of contracted renewable generation projects
in-service.  In addition, as of June 30, 2021, these subsidiaries had
approximately 155 MWs of renewable generation projects under construction with
total estimated capital costs of $221 million related to these projects.

Regulated Renewable Generation Facilities



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

In June 2021, the IRS issued a notice extending the "Continuity Safe Harbor"
deadlines for qualifying renewable energy projects. Under the June 2021 IRS
notice, the Continuity Safe Harbor for qualifying renewable energy projects that
began construction in calendar years 2016 through 2019 is extended to six years.
Additionally, the Continuity Safe Harbor is extended to five years for
qualifying projects that began construction in calendar year 2020. Provided that
each facility does satisfy the Continuity Safe Harbor, under the current IRS
guidance, the Sundance wind facility will qualify for 100% of the federal PTC,
and the Maverick and Traverse wind facilities will qualify for 80% of the
federal PTC.

In April 2021, PSO and SWEPCo acquired respective undivided ownership interests
in the entity that owned Sundance during its development and construction for
$270 million, the first of the three NCWF acquisitions. Immediately following
the acquisition, PSO and SWEPCo liquidated the entity and simultaneously
distributed the Sundance assets in proportion to their undivided ownership
interests. Sundance was placed in-service in April 2021. The total investment in
Sundance is estimated to be $291 million inclusive of previously capitalized
pre-construction costs. The Maverick wind facility is targeted to be acquired
and placed in-service in December 2021 and the Traverse wind facility is
targeted to be acquired and placed in-service between December 2021 and April
2022. See Note 6 - Acquisitions for additional information.

In June 2021, SWEPCo issued requests for proposals to acquire up to 3,000 MWs of
wind and 300 MWs of solar generation resources. The wind and solar generation
projects would be subject to regulatory approval.

Strategic Evaluation of KPCo and AEP Kentucky Transmission Company, Inc. (KTCo)



AEP has initiated a strategic evaluation for its ownership in KPCo, a
wholly-owned regulated generation, transmission and distribution utility with
approximately 166,000 retail customers in eastern Kentucky and KTCo, an AEPTCo
wholly-owned regulated transmission only utility. Potential alternatives may
include continued ownership or a sale of KPCo and KTCo. Management is currently
evaluating the potential alternatives and expects a decision will be made during
2021. As of June 30, 2021, KPCo has total assets of approximately $2.8 billion
and total equity of approximately $847 million and KTCo has total assets of
approximately $157 million and total equity of approximately $73 million.
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Racine

In February 2021, AEP signed an agreement to sell Racine to a nonaffiliated
party. As of June 30, 2021, the net book value of Racine was $45 million. The
sale of Racine requires approval from the FERC and the U.S. Army Corps of
Engineers. The sale is expected to close in the third quarter of 2021 and result
in an immaterial gain. Racine was not presented as Held for Sale on AEP's
balance sheets due to immateriality.

Dolet Hills Power Station and Related Fuel Operations



DHLC provides 100% of the fuel supply to Dolet Hills Power Station. During the
second quarter of 2019, the Dolet Hills Power Station initiated a seasonal
operating schedule. 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. Based on these actions, management revised the estimated useful
life of DHLC's and Oxbow's assets to coincide with the date at which extraction
was discontinued in the second quarter of 2020 and the date at which delivery of
lignite is expected to cease in September 2021. In addition, management also
revised the useful life of the Dolet Hills Power Station to 2021 based on the
remaining estimated fuel supply available for continued seasonal operation. In
April 2020, SWEPCo and CLECO jointly filed a notification letter to the LPSC
providing notice of the cessation of lignite mining.

The Dolet Hills Power Station non-fuel costs are recoverable by SWEPCo through
base rates. SWEPCo's share of the net investment in the Dolet Hills Power
Station is $147 million, including CWIP and materials and supplies, before cost
of removal.

Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo
through active fuel clauses. Under the fuel agreements, SWEPCo's fuel inventory
and unbilled fuel costs from mining related activities were $119 million as of
June 30, 2021. Also, as of June 30, 2021, SWEPCo had a net over-recovered fuel
balance of $17 million, excluding impacts of the February 2021 severe winter
weather event, which includes fuel consumed at the Dolet Hills Power Station.
Additional operational, reclamation and other land-related costs incurred by
DHLC and Oxbow will be billed to SWEPCo and included in future fuel clauses.

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

In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $20
million of fuel costs in 2021 and defer approximately $30 million of additional
costs with a recovery period to be determined at a later date.

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

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


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Pirkey Power Plant and Related Fuel Operations



In 2020, management announced plans to retire the Pirkey Power Plant in 2023.
The Pirkey Power Plant non-fuel costs are recoverable by SWEPCo through base
rates and fuel costs are recovered through active fuel clauses. SWEPCo's share
of the net investment in the Pirkey Power Plant is $206 million, including CWIP,
before cost of removal. Sabine is a mining operator providing mining services to
the Pirkey Power Plant. Under the provisions of the mining agreement, SWEPCo is
required to pay, as part of the cost of lignite delivered, an amount equal to
mining costs plus a management fee. SWEPCo expects fuel deliveries, including
billings of all fixed and operating costs, from Sabine to cease during the first
quarter of 2023. Under the fuel agreements, SWEPCo's fuel inventory and unbilled
fuel costs from mining related activities were $148 million as of June 30, 2021.
Also, as of June 30, 2021, SWEPCo had a net over-recovered fuel balance of $17
million, excluding impacts of the February 2021 severe winter weather event,
which includes fuel consumed at the Pirkey Power Plant. Additional operational,
reclamation and other land-related costs incurred by Sabine will be billed to
SWEPCo and included in future fuel clauses. If any of these costs are not
recoverable, it could reduce future net income and cash flows and impact
financial condition.

LITIGATION



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

Rockport Plant Litigation



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

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

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

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

On April 20, 2021, I&M and AEGCo reached an agreement to acquire 100% of the
interests in Rockport Plant, Unit 2 for $115.5 million from certain financial
institutions that own the unit through trusts established by Wilmington Trust,
the nonaffiliated owner trustee of the ownership interests in the unit, with
closing to occur as of the end of the Rockport Plant, Unit 2 lease in December
2022. As a result, 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
agreement is subject to customary closing conditions, including regulatory
approvals, and as of the closing will result in a final settlement of, and
release of claims in, the lease litigation. Management believes its financial
statements appropriately reflect the expected resolution of the pending
litigation.

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



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

Litigation Related to Ohio House Bill 6 (HB 6)



In 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, the Company, with assistance from outside advisors, conducted
a review of the circumstances surrounding the passage of the bill. We do 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 alleges misrepresentations or omissions by AEP regarding: (a) its
alleged participation in or connection to public corruption with respect to the
passage of HB 6 and (b) its regulatory, legislative, political contribution,
501(c)(4) organization contribution and lobbying activities in Ohio. The
complaint seeks monetary damages, among other forms of relief. On May 10, 2021,
the defendants filed a motion to dismiss the securities litigation for failure
to state a claim, and under the Court's briefing schedule the motion will be
fully briefed by July 26, 2021. The company will continue to defend against the
claims. Management is unable to determine a range of potential losses that is
reasonably possible of occurring.

In January 2021, an AEP shareholder filed a derivative action in the United
States District Court for the Southern District of Ohio purporting to assert
claims on behalf of AEP against certain AEP officers and directors. In February
2021, a second AEP shareholder filed a similar derivative action in the Court of
Common Pleas of Franklin County, Ohio. In April 2021, a third AEP shareholder
filed a similar derivative action in the U.S. District Court for the Southern
District of Ohio and a fourth AEP shareholder filed a similar derivative action
in the
                                       11
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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 first three derivative actions have
been stayed pending the resolution of the motion to dismiss the securities
litigation. The fourth has been stayed until such time as the court determines
to lift the stay. The company will continue to defend against the claims.
Management is unable to determine a range of potential losses that is reasonably
possible of occurring.

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

In May 2021, AEP received a subpoena from the SEC's Division of Enforcement
seeking various documents, including documents relating to the benefits to AEP
from the passage of HB 6 and documents relating to AEP's financial processes and
controls. AEP is cooperating fully with the SEC's subpoena. Although we cannot
predict the outcome of the SEC's investigation, we do not believe the results of
this inquiry will have a material impact on our 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 June 30, 2021, the AEP System owned generating capacity of
approximately 24,700 MWs, of which approximately 12,100 MWs were
coal-fired. Management continues to refine the cost estimates of complying with
these rules and other impacts of the environmental proposals on fossil
generation. Based upon management estimates, AEP's future investment to meet
these existing and proposed requirements ranges from approximately $350 million
to $700 million through 2027.

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

Obligations under the New Source Review Litigation Consent Decree



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

Clean Air Act Requirements



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

National Ambient Air Quality Standards



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

Regional Haze



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

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



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

Cross-State Air Pollution Rule



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

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

Climate Change, CO2 Regulation and Energy Policy



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

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

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

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

Excessive costs to comply with future legislation or regulations 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.

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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 August 2020, the Federal EPA revised the CCR rule to include a requirement
that unlined CCR storage ponds cease operations and initiate closure by April
11, 2021. The revised rule provides two options that allow facilities to extend
the date by which they must cease receipt of coal ash and close the ponds.

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             $             237.1                     2028
APCo                                   Amos                                                  2,930                         2,128.5                     2040
APCo                                   Mountaineer                                           1,320                           966.4                     2040
I&M                                    Rockport Plant, Unit 1                                  655                           541.6     (b)             2028
KPCo                                   Mitchell Plant                                          780                           591.9                     2040
SWEPCo                                 Flint Creek Plant                                       258                           271.9                     2038
WPCo                                   Mitchell Plant                                          780                           594.4                     2040



(a)Net book value before cost of removal including CWIP and inventory.
(b)Amount includes a $181 million regulatory asset related to the retired
Tanners Creek Plant. The IURC and MPSC authorized recovery of the Tanners Creek
Plant regulatory asset over the useful life of Rockport Plant, Unit 1 in 2015
and 2014, respectively.

In December 2020, APCo filed requests with the Virginia SCC and WVPSC to obtain
the regulatory approvals necessary to implement CCR and ELG compliance plans and
seek recovery of the estimated $240 million investment for the Amos and
Mountaineer plants. In July 2021, a Virginia Senior Hearing Examiner recommended
that the Virginia SCC deny, at this time, APCo's request for approval of the ELG
investments at the Amos and Mountaineer Plants. The judge also recommended that
if the Virginia SCC ultimately does not grant APCo approval of the ELG
investments, the Virginia SCC should delay consideration of the reasonableness
and prudency of previously incurred ELG costs until a future case. Intervenors
in Virginia and West Virginia along with the Virginia Senior Hearing Examiner
recommended that only the CCR-related investments be constructed at Amos and
Mountaineer, which could cause APCo to close these generating facilities at the
end of 2028. If any of APCo's CCR/ELG costs are not approved for recovery, it
would reduce future net income and cash flows and impact financial condition.
See "APCo and WPCo Rate Matters" section of Note 4 for additional information.

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 through 2040. 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 May 2021, intervenors in Kentucky and West
Virginia submitted testimony with recommendations that only the CCR-related
investments be constructed at the Mitchell Plant. In July 2021, the KPSC issued
an order approving the CCR only alternative and rejecting the full CCR and ELG
compliance plan. As of June 30, 2021, the total of the Mitchell Plant CCR and
ELG investment balances in CWIP, was $2 million and $4 million, respectively,
split equally between KPCo and WPCo. If any of the CCR and ELG compliance plan
costs are not approved for recovery and/or the retirement date of the Mitchell
Plant is accelerated to 2028 without
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commensurate cost recovery, it would reduce future net income and cash flows and impact financial condition. See "KPCo Rate Matters" section of Note 4 for additional information.



The second option is a retirement option, which provides a generating facility
an extended operating time without developing alternative CCR disposal. Under
the retirement option, a generating facility would have until October 17, 2023
to cease operation and to close CCR storage ponds 40 acres or less in size, or
through October 17, 2028 for facilities with CCR storage ponds greater than 40
acres in size. Pursuant to this option, AEP informed the Federal EPA of its
intent to retire the Pirkey Power Plant and cease using coal at the Welsh Plant:
                                                                                                                         Accelerated
                                                                    Generating                 Net Investment            Depreciation                 Projected
     Company                         Plant Name and Unit             Capacity                        (a)               Regulatory Asset             Retirement Date
                                                                     (in MWs)                                (in millions)
SWEPCo                               Pirkey Power Plant                        580             $      157.1          $            49.4                 2023 (b)
                                     Welsh Plants, Units
SWEPCo                               1 and 3                                 1,053                    511.2                       24.9               2028 (c)(d)



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

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

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

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

Clean Water Act Regulations



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

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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 costs and permits. Management continuously
evaluates cost estimates of complying with these regulations which may result in
a decision to retire coal-fired generating facilities earlier than their
currently estimated useful lives.

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

The table below summarizes the net book value, as of June 30, 2021, of generating facilities retired or planned for early retirement:


                                                                                                           Accelerated                           Actual/Projected                        Current Authorized
                                                                                      Net                  Depreciation                             Retirement                                Recovery                   Annual
      Company                           Plant                                   Investment (a)           Regulatory Asset                              Date                                    Period               Depreciation (b)
                                                                                                 (in millions)                                                          (in millions)
PSO                       Northeastern Plant, Unit 3                           $        183.2          $           119.2                               2026                                      (c)                $         14.9
PSO                       Oklaunion Power Station                                           -                       33.5                               2020                                      (d)                           1.9
SWEPCo                    Dolet Hills Power Station                                      27.3                      114.3                               2021                                      (e)                           7.8
SWEPCo                    Pirkey Power Plant                                            138.5                       49.4                               2023                                      (f)                          13.6
SWEPCo                    Welsh Plant, Units 1 and 3                                    500.6                       24.9                             2028 (g)                                    (h)                          33.2
SWEPCo                    Welsh Plant, Unit 2                                               -                       35.2                               2016                                      (i)                             -



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

Management is seeking or will seek regulatory recovery, as necessary, for any
net book value remaining when the plants are retired. To the extent the net book
value of these generation assets are not deemed recoverable, it could materially
reduce future net income, cash flows and impact financial condition.
                                       17
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RESULTS OF OPERATIONS

SEGMENTS

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

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

Vertically Integrated Utilities

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

Transmission and Distribution Utilities



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

AEP Transmission Holdco

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

Generation & Marketing

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



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

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

                                       18
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The following table presents Earnings (Loss) Attributable to AEP Common Shareholders by segment:


                                                       Three Months Ended                       Six Months Ended
                                                            June 30,                                June 30,
                                                     2021                 2020               2021               2020
                                                                             (in millions)
Vertically Integrated Utilities                $    228.2             $   255.9          $   498.6          $   501.2
Transmission and Distribution Utilities             153.7                 139.5              268.1              255.7
AEP Transmission Holdco                             168.7                  91.5              340.7              232.1
Generation & Marketing                               52.4                  65.9               89.0               94.3
Corporate and Other                                 (24.8)                (32.0)             (43.2)             (67.3)
Earnings Attributable to AEP Common
Shareholders                                   $    578.2             $   520.8          $ 1,153.2          $ 1,016.0



AEP CONSOLIDATED

Second Quarter of 2021 Compared to Second Quarter of 2020

Earnings Attributable to AEP Common Shareholders increased from $521 million in 2020 to $578 million in 2021 primarily due to:



•Favorable rate proceedings in AEP's various jurisdictions.
•An increase in transmission investment, which resulted in higher revenues and
income.
•Unrealized gains on AEP's investment in ChargePoint.

These increases were partially offset by:

•An increase in Other Operation and Maintenance expenses driven by the COVID-19 pandemic which resulted in lower expenses in the second quarter of 2020.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020

Earnings Attributable to AEP Common Shareholders increased from $1,016 million in 2020 to $1,153 million in 2021 primarily due to:



•Favorable rate proceedings in AEP's various jurisdictions.
•An increase in weather-related usage.
•An increase in transmission investment, which resulted in higher revenues and
income.
•Unrealized gains on AEP's investment in ChargePoint.

These increases were partially offset by:

•An increase in Other Operation and Maintenance expenses driven by the COVID-19 pandemic which resulted in lower expenses in 2020.


                                       19
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VERTICALLY INTEGRATED UTILITIES


                                                             Three Months Ended                     Six Months Ended
                                                                  June 30,                              June 30,
         Vertically Integrated Utilities                   2021               2020               2021               2020
                                                                                   (in millions)
Revenues                                               $ 2,260.6          $ 2,092.0          $ 4,797.9          $ 4,318.7
Fuel and Purchased Electricity                             650.4              582.1            1,509.4            1,253.3

Gross Margin                                             1,610.2            1,509.9            3,288.5            3,065.4
Other Operation and Maintenance                            703.5              624.6            1,443.7            1,315.9

Depreciation and Amortization                              433.8              393.3              865.9              775.0
Taxes Other Than Income Taxes                              128.0              117.5              251.5              234.6
Operating Income                                           344.9              374.5              727.4              739.9

Other Income                                                 5.1                1.4                5.8                3.0
Allowance for Equity Funds Used During
Construction                                                10.8                9.0               20.7               17.2
Non-Service Cost Components of Net Periodic
Benefit Cost                                                17.0               17.1               34.0               34.0
Interest Expense                                          (141.6)            (141.8)            (281.2)            (286.3)
Income Before Income Tax Expense and Equity
Earnings                                                   236.2              260.2              506.7              507.8
Income Tax Expense                                           8.2                4.6                8.0                6.7
Equity Earnings of Unconsolidated Subsidiary                 0.8                0.7                1.5                1.5
Net Income                                                 228.8              256.3              500.2              502.6
Net Income Attributable to Noncontrolling
Interests                                                    0.6                0.4                1.6                1.4

Earnings Attributable to AEP Common Shareholders $ 228.2 $

   255.9          $   498.6          $   501.2



        Summary of KWh Energy Sales for Vertically Integrated Utilities
                                   Three Months Ended                   Six Months Ended
                                        June 30,                            June 30,
                               2021                 2020            2021                 2020
                                                   (in millions of KWhs)
         Retail:
         Residential          6,525                6,976          16,006                15,238
         Commercial           5,670                5,150          10,928                10,516
         Industrial           8,611                7,699          16,313                16,174
         Miscellaneous          549                  511           1,068                 1,041
         Total Retail        21,355               20,336          44,315                42,969

         Wholesale (a)        4,487                4,924           9,129                 8,542

         Total KWhs          25,842               25,260          53,444                51,511

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





                                       20
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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              Six Months Ended
                                              June 30,                       June 30,
                                       2021              2020         2021               2020
                                                          (in degree days)
           Eastern Region
           Actual - Heating (a)       170               212         1,709               1,453
           Normal - Heating (b)       138               137         1,738               1,748

           Actual - Cooling (c)       359               324           362                 337
           Normal - Cooling (b)       339               337           343                 342

           Western Region
           Actual - Heating (a)        35                49           993                 698
           Normal - Heating (b)        34                34           900                 901

           Actual - Cooling (c)       652               673           678                 724
           Normal - Cooling (b)       699               700           727                 728

(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.


                                       21
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Second Quarter of 2021 Compared to Second Quarter of 2020


                  Reconciliation of Second Quarter of 2020 to Second

Quarter of 2021


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

Second Quarter of 2020                                                                 $      255.9

Changes in Gross Margin:
Retail Margins                                                                                 96.4
Margins from Off-system Sales                                                                   5.6
Transmission Revenues                                                                           0.9
Other Revenues                                                                                 (2.6)
Total Change in Gross Margin                                                                  100.3

Changes in Expenses and Other:
Other Operation and Maintenance                                                               (78.9)

Depreciation and Amortization                                                                 (40.5)
Taxes Other Than Income Taxes                                                                 (10.5)

Other Income                                                                                    3.7
Allowance for Equity Funds Used During Construction                                             1.8
Non-Service Cost Components of Net Periodic Pension Cost                                       (0.1)
Interest Expense                                                                                0.2
Total Change in Expenses and Other                                                           (124.3)

Income Tax Expense                                                                             (3.6)
Equity Earnings of Unconsolidated Subsidiary                                                    0.1
Net Income Attributable to Noncontrolling Interests                                            (0.2)

Second Quarter of 2021                                                                 $      228.2

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



•Retail Margins increased $96 million primarily due to the following:
•A $36 million increase at I&M due to wholesale true-up, increase in rider
revenues and the Indiana base rate case. This increase was partially offset in
other expense items below.
•A $17 million increase in revenue from rate riders at PSO. This increase was
partially offset in other expense items below.
•A $12 million increase at KPCo due to rider revenues. This increase was
partially offset in other expense items below.
•A $9 million increase at APCo and WPCo due to rider revenue primarily in West
Virginia. This increase was partially offset in other expense items below.
•An $8 million increase in weather-normalized retail margins driven by a $34
million increase in the commercial and industrial customer classes partially
offset by a $27 million decrease in the residential customer class.
•A $5 million increase at KPCo due to base rate case revenues implemented in
January 2021.
These increases were partially offset by:
•A $7 million decrease in weather-normalized wholesale margins, including the
loss of a significant wholesale contract at I&M.
•Margins from Off-system Sales increased $6 million primarily due to favorable
market prices in both PJM and SPP.
                                       22
--------------------------------------------------------------------------------




•Transmission Revenues increased $1 million due to a $10 million increase in
transmission investment primarily at APCo offset by a $9 million decrease as a
result of the annual formula rate true-up. This increase is partially offset in
Depreciation and Amortization expenses below.

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



•Other Operation and Maintenance expenses increased $79 million primarily due to
the following:
•A $47 million increase in PJM transmission services including the annual
formula rate true-up.
•A $25 million increase in SPP transmission services including the annual
formula rate true-up.
•A $23 million increase in employee-related expenses.
These increases were partially offset by:
•A $20 million decrease in storms primarily at KPCo, APCo and PSO.
•Depreciation and Amortization expenses increased $41 million primarily due to a
higher depreciable base and an increase in depreciation rates at APCo. This
increase was partially offset in Gross Margin above.
•Taxes Other Than Income Taxes increased $11 million primarily due to the
following:
•A $5 million increase in property taxes at SWEPCo resulting from the expiration
of the Louisiana Industrial Tax Exemption related to the Stall Plant.
•A $4 million increase at I&M primarily due to property taxes driven by an
increase in utility plant.
•Other Income increased $4 million primarily due to increased interest income
related the February 2021 severe winter weather event at SWEPCo.
•Income Tax Expense increased $4 million primarily due to a decrease in
amortization of Excess ADIT. The decrease in amortization of Excess ADIT is
partially offset above in Retail Margins.

                                       23
--------------------------------------------------------------------------------

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020

Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021

Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities


                                            (in millions)

Six Months Ended June 30, 2020                                                         $      501.2

Changes in Gross Margin:
Retail Margins                                                                                194.5
Margins from Off-system Sales                                                                  23.8
Transmission Revenues                                                                          11.2
Other Revenues                                                                                 (6.4)
Total Change in Gross Margin                                                                  223.1

Changes in Expenses and Other:
Other Operation and Maintenance                                                              (127.8)

Depreciation and Amortization                                                                 (90.9)
Taxes Other Than Income Taxes                                                                 (16.9)

Other Income                                                                                    2.8
Allowance for Equity Funds Used During Construction                                             3.5

Interest Expense                                                                                5.1
Total Change in Expenses and Other                                                           (224.2)

Income Tax Expense                                                                             (1.3)

Net Income Attributable to Noncontrolling Interests                                            (0.2)

Six Months Ended June 30, 2021                                                         $      498.6



•Retail Margins increased $195 million primarily due to the following:
•A $59 million increase in weather-related usage primarily in the residential
class.
•A $48 million increase at I&M due to wholesale true-up, Indiana and Michigan
base rate cases and increases in rider revenues. This increase was partially
offset in other expense items below.
•A $27 million increase at KPCo due to rider revenues. This increase was
partially offset in other expense items below.
•A $22 million increase at APCo and WPCo due to rider revenue primarily in West
Virginia. This increase was partially offset in other expense items below.
•A $19 million increase in revenue from rate riders at PSO. This increase was
partially offset in other expense items below.
•An $11 million increase at KPCo due to base rate case revenues implemented in
January 2021.
•A $10 million increase in weather-normalized wholesale margins at SWEPCo.
•An $8 million increase in recoverable fuel costs at SWEPCo primarily due to
timing of recovery.
•A $5 million increase in municipal and cooperative revenues at SWEPCo primarily
due to the annual generation formula rate true-up.
These increases were partially offset by:
•A $23 million decrease in weather-normalized margins for wholesale contracts,
including the loss of a significant wholesale contract at I&M.
•A $17 million decrease in weather-normalized retail margins driven by a $10
million decrease in the residential class and a $7 million decrease in the
industrial customer class.
•Margins from Off-system Sales increased $24 million primarily due to Turk Plant
merchant sales as a result of the February 2021 severe winter weather event at
SWEPCo.
                                       24
--------------------------------------------------------------------------------




•Transmission Revenues increased $11 million due to an increase in transmission
investment primarily at APCo, partially offset by a $9 million decrease as a
result of the transmission formula rate true-up. This increase is partially
offset in Depreciation and Amortization expenses below.
•Other Revenues decreased $6 million primarily due to business development
revenue at PSO. This decrease was partially offset in Other Operation and
Maintenance expenses below.

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



•Other Operation and Maintenance expenses increased $128 million primarily due
to the following:
•A $78 million increase in PJM transmission services including the annual
formula rate true-up.
•A $31 million increase in SPP transmission services including the annual
formula rate true-up.
•A $29 million increase in employee-related expenses.
•A $9 million increase primarily due to an increase in vegetation management
expenses.
These increases were partially offset by:
•A $15 million decrease due to storms primarily at KPCo, APCo and PSO.
•A $9 million decrease in factoring expenses.
•Depreciation and Amortization expenses increased $91 million primarily due to a
higher depreciable base and increased depreciation rates at APCo and I&M. This
increase was partially offset in Gross Margin above.
•Taxes Other Than Income Taxes increased $17 million primarily due to the
following:
•A $10 million increase at SWEPCo primarily due to increased property taxes
resulting from the expiration of the Louisiana Industrial Tax Exemption related
to Stall Plant.
•A $4 million increase at I&M primarily due to property taxes driven by an
increase in utility plant.
•Interest Expense decreased $5 million primarily due to the following:
•A $3 million decrease at PSO primarily due to lower borrowing costs in 2021.
•A $2 million decrease at I&M primarily due to a decrease in carrying charges
and a decreased interest rate on variable rate notes.

                                       25
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TRANSMISSION AND DISTRIBUTION UTILITIES


                                                             Three Months Ended                     Six Months Ended
                                                                  June 30,                              June 30,
    Transmission and Distribution Utilities                2021               2020               2021               2020
                                                                                   (in millions)
Revenues                                               $ 1,103.4          $ 1,034.5          $ 2,191.5          $ 2,141.4
Purchased Electricity                                      168.0              147.5              373.5              338.9

Gross Margin                                               935.4              887.0            1,818.0            1,802.5
Other Operation and Maintenance                            360.8              351.9              726.0              719.1

Depreciation and Amortization                              178.5              207.0              351.2              421.5
Taxes Other Than Income Taxes                              158.4              141.8              316.0              288.0
Operating Income                                           237.7              186.3              424.8              373.9
Interest and Investment Income                               0.3                0.4                0.7                1.1
Carrying Costs Income                                        0.5                0.6                1.0                1.0

Allowance for Equity Funds Used During
Construction                                                 6.2                7.7               13.0               14.7
Non-Service Cost Components of Net Periodic
Benefit Cost                                                 7.2                7.4               14.5               14.7
Interest Expense                                           (77.0)             (72.2)            (151.5)            (143.6)
Income Before Income Tax Expense (Benefit)                 174.9              130.2              302.5              261.8
Income Tax Expense (Benefit)                                21.2               (9.3)              34.4                6.1
Net Income                                                 153.7              139.5              268.1              255.7
Net Income Attributable to Noncontrolling
Interests                                                      -                  -                  -                  -

Earnings Attributable to AEP Common Shareholders $ 153.7 $

   139.5          $   268.1          $   255.7



    Summary of KWh Energy Sales for Transmission and Distribution Utilities
                                     Three Months Ended                   Six Months Ended
                                          June 30,                            June 30,
                                 2021                 2020            2021                 2020
                                                     (in millions of KWhs)
        Retail:
        Residential             6,065                6,299          12,989                12,599
        Commercial              6,488                5,559          12,064                11,432
        Industrial              6,338                5,148          11,619                11,056
        Miscellaneous             185                  180             351                   362
        Total Retail (a)       19,076               17,186          37,023                35,449

        Wholesale (b)             445                  455           1,048                   845

        Total KWhs             19,521               17,641          38,071                36,294

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


                                       26
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Heating degree days and cooling degree days are metrics commonly used in the
utility industry as a measure of the impact of weather on revenues. In general,
degree day changes in the eastern region have a larger effect on revenues than
changes in the western region due to the relative size of the two regions and
the number of customers within each region.

  Summary of Heating and Cooling Degree Days for Transmission and Distribution
                                   Utilities
                                         Three Months Ended              Six Months Ended
                                              June 30,                       June 30,
                                       2021              2020         2021               2020
                                                          (in degree days)
           Eastern Region
           Actual - Heating (a)       215               292         1,992               1,765
           Normal - Heating (b)       183               182         2,066               2,080

           Actual - Cooling (c)       361               314           361                 317
           Normal - Cooling (b)       304               301           307                 304

           Western Region
           Actual - Heating (a)         4                 6           319                  97
           Normal - Heating (b)         3                 3           188                 188

           Actual - Cooling (d)       833               936           970               1,167
           Normal - Cooling (b)       931               933         1,057               1,058



(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.

                                       27
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Second Quarter of 2021 Compared to Second Quarter of 2020


                 Reconciliation of Second Quarter of 2020 to Second Quarter

of 2021


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

Second Quarter of 2020                                                               $      139.5

Changes in Gross Margin:
Retail Margins                                                                               76.5
Margins from Off-system Sales                                                               (18.7)
Transmission Revenues                                                                        30.0
Other Revenues                                                                              (39.4)
Total Change in Gross Margin                                                                 48.4

Changes in Expenses and Other:
Other Operation and Maintenance                                                              (8.9)
Depreciation and Amortization                                                                28.5
Taxes Other Than Income Taxes                                                               (16.6)
Interest and Investment Income                                                               (0.1)
Carrying Costs Income                                                                        (0.1)
Allowance for Equity Funds Used During Construction                                          (1.5)
Non-Service Cost Components of Net Periodic Benefit Cost                                     (0.2)
Interest Expense                                                                             (4.8)
Total Change in Expenses and Other                                                           (3.7)

Income Tax Expense                                                                          (30.5)

Second Quarter of 2021                                                               $      153.7

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 $77 million primarily due to the following:
•A $30 million net increase in Ohio Basic Transmission Cost Rider revenues and
recoverable PJM expenses. This increase was partially offset in Other Operation
and Maintenance expenses below.
•A $19 million increase in usage in Ohio primarily from the commercial and
residential classes of $11 million and $6 million, respectively.
•A $19 million increase in weather-normalized margins in Texas primarily in the
residential and commercial classes.
•A $16 million increase from interim rate increases driven by increased
transmission investment in Texas.
•A $12 million increase in rider revenues in Ohio associated with the DIR. This
increase was partially offset in other expense items below.
•An $11 million increase from interim rate increases driven by increased
distribution investment in Texas.
•An $8 million increase due to a PUCO order to refund unused 2018 major storm
reserve collections to customers in the prior period. This decrease was offset
in Other Operation and Maintenance expenses below.
•A $7 million increase in the Legacy Generation Resource Rider (LGRR) in Ohio.
This increase was offset in Margins from Off-system Sales and Other Revenues
below.
•A $5 million increase in revenues associated with a vegetation management rider
in Ohio. This increase was partially offset in Other Operation and Maintenance
expenses below.
These increases were partially offset by:
•A $19 million decrease due to the ending of the Energy Efficiency and Peak
Demand Rider in Ohio in December 2020. This decrease was partially offset in
Other Operation and Maintenance expenses below.
                                       28
--------------------------------------------------------------------------------




•An $11 million decrease in revenues in Ohio associated with the Universal
Service Fund (USF). This decrease was offset in Other Operation and Maintenance
expenses below.
•A $6 million decrease in weather-related usage in Texas primarily due to an 11%
decrease in cooling degree days.
•A $4 million decrease due to refunds in Texas of Excess ADIT and excess federal
income taxes collected as a result of Tax Reform.
•Margins from Off-system Sales decreased $19 million primarily due to the
following:
•A $13 million decrease in Ohio primarily due to unfavorable deferrals of OVEC
costs. This decrease was offset in Retail Margins above and Other Revenues
below.
•A $5 million decrease in Texas primarily due to the retirement of the Oklaunion
Power Station in September 2020. This decrease was partially offset in
Depreciation and Amortization expenses below.
•Transmission Revenues increased $30 million primarily due to the following:
•A $20 million increase from interim rate increases driven by increased
transmission investment in Texas.
•A $14 million increase due to a prior year one-time credit to transmission
customers in Texas as a result of Tax Reform and the most recent base rate case.
This increase was offset in Income Tax Expense below.
These increases were partially offset by:
•A $4 million decrease due to refunds to customers associated with the most
recent base rate case in Texas. This decrease was offset in Other Revenues
below.
•Other Revenues decreased $39 million primarily due to the following:
•A $47 million decrease primarily due to securitization revenues due to the AEP
Texas Central Transition Funding II LLC bonds that matured in July 2020. This
decrease was offset below in Depreciation and Amortization expenses and Interest
Expense.
This decrease was partially offset by:
•An $8 million increase primarily due to third-party LGRR revenue related to the
recovery of OVEC costs in Ohio. This increase was offset in Retail Margins and
Margins from Off-system Sales above.

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



•Other Operation and Maintenance expenses increased $9 million primarily due to
the following:
•A $26 million increase in recoverable PJM expense in Ohio. This increase was
partially offset in Retail Margins above.
•A $17 million increase due to the prior year revision of the Oklaunion Power
Station ARO. This increase was offset in Margins from Off-system Sales above.
•A $9 million increase in PJM expenses in Ohio primarily related to the annual
formula rate true-up.
•An $8 million increase in distribution maintenance expenses in Ohio related to
the annual major storm reserve true-up. This increase was offset in Retail
Margins above.
These increases were partially offset by:
•A $19 million decrease in Texas due to the Oklaunion Power Station retirement
in September 2020 and its sale to a nonaffiliated third-party in October 2020.
This decrease was offset in Gross Margin above.
•An $11 million decrease in remitted USF surcharge payments to the Ohio
Department of Development to fund an energy assistance program for qualified
Ohio customers. This decrease was offset in Retail Margins above.
•A $9 million decrease in energy efficiency/demand side management expenses in
Ohio. This decrease was partially offset in Retail Margins above.
•A $7 million decrease in factored customer accounts receivable expenses in Ohio
primarily due to bad debt expenses and a current year adjustment to allowance
for doubtful accounts.
•Depreciation and Amortization expenses decreased $29 million primarily due to
the following:
•A $49 million decrease in securitization amortizations in Texas primarily
related to the AEP Texas Central Transition Funding II LLC bonds that matured in
July 2020. This decrease was offset in Other Revenues above.
These decreases were partially offset by:
•A $9 million increase in depreciation expense due to an increase in the
depreciable base of transmission and distribution assets.
                                       29
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•A $6 million increase in recoverable DIR depreciable expense in Ohio. This
increase was partially offset in Retail Margins above.
•A $5 million increase in amortization primarily related to capitalized software
in Ohio.
•Taxes Other Than Income Taxes increased $17 million primarily due to increased
property taxes driven by additional investments in transmission and distribution
assets and higher tax rates.
•Interest Expense increased $5 million primarily due to higher long-term debt
balances.
•Income Tax Expense increased $31 million primarily due to a decrease in
amortization of Excess ADIT and an increase in pretax book income. The decrease
in amortization of Excess ADIT is partially offset above in Gross Margin.

                                       30
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Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020

Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021

Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities


                                           (in millions)

Six Months Ended June 30, 2020                                                       $      255.7

Changes in Gross Margin:
Retail Margins                                                                              101.2
Margins from Off-system Sales                                                               (56.1)
Transmission Revenues                                                                        42.5
Other Revenues                                                                              (72.1)
Total Change in Gross Margin                                                                 15.5

Changes in Expenses and Other:
Other Operation and Maintenance                                                              (6.9)
Depreciation and Amortization                                                                70.3
Taxes Other Than Income Taxes                                                               (28.0)
Interest and Investment Income                                                               (0.4)

Allowance for Equity Funds Used During Construction                                          (1.7)
Non-Service Cost Components of Net Periodic Benefit Cost                                     (0.2)
Interest Expense                                                                             (7.9)
Total Change in Expenses and Other                                                           25.2

Income Tax Expense                                                                          (28.3)

Six Months Ended June 30, 2021

$ 268.1

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 $101 million primarily due to the following:
•An $88 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 $21 million increase from interim rate increases driven by increased
transmission investment in Texas.
•A $21 million increase from interim rate increases driven by increased
distribution investment in Texas.
•A $19 million increase in usage in Ohio from the commercial and residential
classes of $11 million and $8 million, respectively.
•A $17 million increase in rider revenues in Ohio associated with the DIR. This
increase was partially offset in other expense items below.
•A $15 million increase in the LGRR in Ohio. This increase was offset in Margins
from Off-system Sales and Other Revenues below.
•A $13 million increase in weather-related usage in Texas primarily due to a
229% increase in heating degree days, partially offset by a 17% decrease in
cooling degree days.
•A $10 million increase in revenues associated with a vegetation management
rider in Ohio. This increase was partially offset in Other Operation and
Maintenance expenses below.
•An $8 million increase due to a PUCO order to refund unused 2018 major storm
reserve collections to customers in the prior period. This increase was offset
in Other Operation and Maintenance expenses below.


                                       31
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These increases were partially offset by:
•A $46 million decrease due to the ending of the Energy Efficiency and Peak
Demand Rider in Ohio in December 2020. This decrease was partially offset in
Other Operation and Maintenance expenses below.
•A $27 million decrease in revenues in Ohio associated with the USF. This
decrease was offset in Other Operation and Maintenance expenses below.
•A $19 million decrease due to refunds in Texas of Excess ADIT and excess
federal income taxes collected as a result of Tax Reform. This decrease was
partially offset in Income Tax Expense below.
•A $6 million decrease in weather-normalized margins in Texas primarily in the
industrial and residential classes, partially offset by an increase in the
commercial class.
•Margins from Off-system Sales decreased $56 million primarily due to the
following:
•A $29 million decrease in Texas primarily due to the retirement of the
Oklaunion Power Station in September 2020. This decrease was partially offset in
Depreciation and Amortization expenses below.
•A $27 million decrease in Ohio primarily due to unfavorable deferrals of OVEC
costs. This decrease was offset in Retail Margins above and Other Revenues
below.
•Transmission Revenues increased $43 million primarily due to the following:
•A $39 million increase from interim rate increases driven by increased
transmission investment in Texas.
•A $14 million increase due to a prior year one-time credit to transmission
customers in Texas as a result of Tax Reform and the most recent base rate case.
This increase was offset in Income Tax Expense below.
These increases were partially offset by:
•A $9 million decrease due to refunds to customers associated with the most
recent base rate case in Texas. This decrease was offset in Other Revenues
below.
•Other Revenues decreased $72 million primarily due to the following:
•A $98 million decrease in securitization revenues primarily due to the AEP
Texas Central Transition Funding II LLC bonds that matured in July 2020. This
decrease was offset below in Depreciation and Amortization expenses and in
Interest Expense.
This decrease was partially offset by:
•A $13 million increase in Ohio primarily due to third-party LGRR revenue
related to the recovery of OVEC costs. This increase was offset in Retail
Margins and Margins from Off-system Sales above.
•A $10 million increase due to refunds in Texas to customers associated with the
most recent base rate case. This increase was partially offset in Retail Margins
and Transmission Revenues above.

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



•Other Operation and Maintenance expenses increased $7 million primarily due to
the following:
•A $78 million increase in recoverable PJM expenses in Ohio. This increase was
partially offset in Retail Margins above.
•A $17 million increase due to the prior year revision of the Oklaunion Power
Station ARO. This increase was offset in Margins from Off-system Sales above.
•A $10 million increase in recoverable distribution expenses related to
vegetation management in Ohio. This increase was offset in Retail Margins above.
•A $9 million increase in PJM expenses in Ohio primarily related to the annual
formula rate true-up.
•An $8 million increase in distribution maintenance expenses in Ohio related to
the annual major storm reserve true-up. This increase was offset in Retail
Margins above.
These increases were partially offset by:
•A $39 million decrease in Texas due to the Oklaunion Power Station retirement
in September 2020 and its sale to a nonaffiliated third-party in October 2020.
This decrease was offset in Gross Margin above.
•A $30 million decrease in energy efficiency/demand side management expenses in
Ohio. This decrease was partially offset in Retail Margins above.
•A $27 million decrease in remitted USF surcharge payments to the Ohio
Department of Development to fund an energy assistance program for qualified
Ohio customers. This decrease was offset in Retail Margins above.
•A $14 million decrease in factored customer accounts receivable expenses in
Ohio primarily due to bad debt expenses and a current year adjustment to
allowance for doubtful accounts.
                                       32
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•A $6 million decrease primarily related to distribution related expenses in
Texas.
•Depreciation and Amortization expenses decreased $70 million primarily due to
the following:
•A $93 million decrease in securitization amortizations in Texas primarily
related to the AEP Texas Central Transition Funding II LLC bonds that matured in
July 2020. This decrease was offset in Other Revenues above.
These decreases were partially offset by:
•A $13 million increase in depreciation expense due to an increase in the
depreciable base of transmission and distribution assets.
•A $6 million increase in recoverable DIR depreciable expense in Ohio. This
increase was partially offset in Retail Margins above.
•A $6 million increase in amortization primarily related to capitalized software
in Ohio.
•Taxes Other Than Income Taxes increased $28 million primarily due to property
taxes driven by additional investments in transmission and distribution assets
and higher tax rates.
•Interest Expense increased $8 million primarily due to higher long-term debt
balances.
•Income Tax Expense increased $28 million primarily due to a decrease in
amortization of Excess ADIT and an increase in pretax book income. The decrease
in amortization of Excess ADIT is partially offset above in Gross Margin.
                                       33
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AEP TRANSMISSION HOLDCO
                                                              Three Months Ended                     Six Months Ended
                                                                   June 30,                              June 30,
            AEP Transmission Holdco                          2021                2020              2021              2020
                                                                                   (in millions)
Transmission Revenues                                  $    378.2             $ 249.7          $   755.2          $ 559.9
Other Operation and Maintenance                              29.4                25.9               56.6             55.8
Depreciation and Amortization                                74.7                61.1              147.4            119.2
Taxes Other Than Income Taxes                                61.5                51.8              120.7            103.7
Operating Income                                            212.6               110.9              430.5            281.2
Interest and Investment Income                                0.2                 1.5                0.4              2.4

Allowance for Equity Funds Used During
Construction                                                 16.5                18.4               33.2             34.6
Non-Service Cost Components of Net Periodic
Benefit Cost                                                  0.6                 0.5                1.1              1.0
Interest Expense                                            (35.5)              (34.2)             (70.8)           (65.0)
Income Before Income Tax Expense and Equity
Earnings                                                    194.4                97.1              394.4            254.2
Income Tax Expense                                           43.4                24.7               89.2             63.1
Equity Earnings of Unconsolidated Subsidiary                 18.6                19.8               37.6             42.7
Net Income                                                  169.6                92.2              342.8            233.8
Net Income Attributable to Noncontrolling
Interests                                                     0.9                 0.7                2.1              1.7

Earnings Attributable to AEP Common Shareholders $ 168.7

  $  91.5          $   340.7          $ 232.1



    Summary of Investment in Transmission Assets for AEP Transmission Holdco
                                                                   June 30,
                                                             2021            2020
                                                                (in millions)
         Plant in Service                                $ 11,065.2      $

9,333.7


         Construction Work in Progress                      1,486.3

1,660.5


         Accumulated Depreciation and Amortization            703.1

508.2


         Total Transmission Property, Net                $ 11,848.4      $

10,486.0


                                       34
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Second Quarter of 2021 Compared to Second Quarter of 2020

Reconciliation of Second Quarter of 2020 to Second Quarter of 2021


 Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
                                 (in millions)
        Second Quarter of 2020                                        $  91.5

        Changes in Transmission Revenues:
        Transmission Revenues                                           128.5
        Total Change in Transmission Revenues                           128.5

        Changes in Expenses and Other:
        Other Operation and Maintenance                                  (3.5)
        Depreciation and Amortization                                   (13.6)
        Taxes Other Than Income Taxes                                    (9.7)
        Interest Income                                                  (1.3)

        Allowance for Equity Funds Used During Construction              (1.9)
        Non-Service Cost Components of Net Periodic Pension Cost          0.1
        Interest Expense                                                 (1.3)
        Total Change in Expenses and Other                              (31.2)

        Income Tax Expense                                              (18.7)
        Equity Earnings of Unconsolidated Subsidiary                     (1.2)
        Net Income Attributable to Noncontrolling Interests              (0.2)

        Second Quarter of 2021                                        $ 168.7

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



•Transmission Revenues increased $129 million primarily due to the following:
•A $68 million increase due to continued investment in transmission assets.
•A $45 million increase as a result of the affiliated annual transmission
formula rate true-up which is offset in Other Operation and Maintenance expense
across the other Registrant Subsidiaries.
•A $16 million increase as a result of the non-affiliated annual transmission
formula rate true-up.
Expenses and Other and Income Tax Expense changed between years as follows:

•Other Operation and Maintenance expenses increased $4 million primarily due to
vegetation management expenses.
•Depreciation and Amortization expenses increased $14 million primarily due to a
higher depreciable base.
•Taxes Other Than Income Taxes increased $10 million primarily due to higher
property taxes as a result of increased transmission investment.
•Income Tax Expense increased $19 million primarily due to an increase in pretax
book income.
                                       35
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Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020

Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30,


                                      2021
 Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
                                 (in millions)
        Six Months Ended June 30, 2020                                $ 232.1

        Changes in Transmission Revenues:
        Transmission Revenues                                           195.3
        Total Change in Transmission Revenues                           195.3

        Changes in Expenses and Other:
        Other Operation and Maintenance                                  (0.8)
        Depreciation and Amortization                                   (28.2)
        Taxes Other Than Income Taxes                                   (17.0)
        Interest Income                                                  (2.0)

        Allowance for Equity Funds Used During Construction              (1.4)
        Non-Service Cost Components of Net Periodic Pension Cost          0.1
        Interest Expense                                                 (5.8)
        Total Change in Expenses and Other                              (55.1)

        Income Tax Expense                                              (26.1)
        Equity Earnings of Unconsolidated Subsidiary                     (5.1)
        Net Income Attributable to Noncontrolling Interests              (0.4)

        Six Months Ended June 30, 2021                                $ 340.7



The major components of the increase in transmission revenues, which consists of
wholesale sales to affiliates and nonaffiliates, were as follows:
•Transmission Revenues increased $195 million primarily due to the following:
•A $134 million increase due to continued investment in transmission assets.
•A $45 million increase as a result of the affiliated annual transmission
formula rate true-up which is offset in Other Operation and Maintenance expense
across the other Registrant Subsidiaries.
•A $16 million increase as a result of the non-affiliated annual transmission
formula rate true-up.
Expenses and Other, Income Tax Expense and Equity Earnings of Unconsolidated
Subsidiary changed between years as follows:
•Depreciation and Amortization expenses increased $28 million primarily due to a
higher depreciable base.
•Taxes Other Than Income Taxes increased $17 million primarily due to higher
property taxes as a result of increased transmission investment.
•Interest Expense increased $6 million primarily due to higher long-term debt
balances.
•Income Tax Expense increased $26 million primarily due to an increase in pretax
book income.
•Equity Earnings of Unconsolidated Subsidiary decreased $5 million primarily due
to lower pretax equity earnings at PATH-WV and ETT.
                                       36
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GENERATION & MARKETING
                                                              Three Months Ended                     Six Months Ended
                                                                   June 30,                              June 30,
             Generation & Marketing                          2021                2020              2021              2020
                                                                                   (in millions)
Revenues                                               $    436.6             $ 376.9          $ 1,070.8          $ 815.5
Fuel, Purchased Electricity and Other                       358.1               298.5              924.0            658.8

Gross Margin                                                 78.5                78.4              146.8            156.7
Other Operation and Maintenance                              32.4                16.5               60.6             57.9

Depreciation and Amortization                                20.0                17.9               38.6             35.6
Taxes Other Than Income Taxes                                 2.9                 3.7                5.5              7.1
Operating Income                                             23.2                40.3               42.1             56.1
Interest and Investment Income                                0.6                 1.2                1.1              2.2

Non-Service Cost Components of Net Periodic
Benefit Cost                                                  3.9                 3.8                7.7              7.7
Interest Expense                                             (3.8)               (8.2)              (7.1)           (16.7)
Income Before Income Tax Benefit and Equity
Earnings (Loss)                                              23.9                37.1               43.8             49.3
Income Tax Benefit                                          (24.2)              (21.0)             (39.3)           (33.4)
Equity Earnings (Loss) of Unconsolidated
Subsidiaries                                                 (1.6)                0.4                1.6              6.3
Net Income                                                   46.5                58.5               84.7             89.0
Net Loss Attributable to Noncontrolling
Interests                                                    (5.9)               (7.4)              (4.3)            (5.3)

Earnings Attributable to AEP Common Shareholders $ 52.4

  $  65.9          $    89.0          $  94.3



              Summary of MWhs Generated for Generation & Marketing
                                      Three Months Ended            Six Months Ended
                                           June 30,                     June 30,
                                    2021              2020        2021             2020
                                                  (in millions of MWhs)
                  Fuel Type:
                  Coal               1                 1           2                 2
                  Renewables         1                 1           2                 2

                  Total MWhs         2                 2           4                 4


                                       37


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Second Quarter of 2021 Compared to Second Quarter of 2020


           Reconciliation of Second Quarter of 2020 to Second Quarter of

2021


      Earnings Attributable to AEP Common Shareholders from Generation & Marketing
                                     (in millions)

  Second Quarter of 2020                                                      $ 65.9

  Changes in Gross Margin:
  Merchant Generation                                                            5.1
  Renewable Generation                                                           3.1
  Retail, Trading and Marketing                                                 (8.1)
  Total Change in Gross Margin                                                   0.1

  Changes in Expenses and Other:
  Other Operation and Maintenance                                              (15.9)

  Depreciation and Amortization                                                 (2.1)
  Taxes Other Than Income Taxes                                                  0.8
  Interest and Investment Income                                                (0.6)

  Non-Service Cost Components of Net Periodic Benefit Cost                       0.1
  Interest Expense                                                               4.4
  Total Change in Expenses and Other                                           (13.3)

  Income Tax Benefit                                                             3.2
  Equity Earnings of Unconsolidated Subsidiaries                                (2.0)
  Net Loss Attributable to Noncontrolling Interests                             (1.5)

  Second Quarter of 2021                                                      $ 52.4

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



•Merchant Generation increased $5 million primarily due to higher market prices
in PJM which drove increased generation at Cardinal Plant.
•Renewable Generation increased $3 million primarily due to higher solar and
wind production.
•Retail, Trading and Marketing decreased $8 million due to lower wholesale
marketing activity.

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



•Other Operation and Maintenance expenses increased $16 million primarily due to
the following:
•A $17 million increase related to the Oklaunion PPA with AEP Texas primarily
due to an ARO revision in 2020.
•An $8 million increase due to gains recorded in 2020 on the sale of land.
These increases were partially offset by:
•A $9 million decrease in expenses related to the retirements of Conesville
Plant Unit 4 and Oklaunion Plant in 2020.
•Interest Expense decreased $4 million due to lower borrowing costs in 2021.
•Income Tax Benefit increased $3 million due to an increase in PTCs.

                                       38
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Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020

Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021


             Earnings Attributable to AEP Common Shareholders from

Generation & Marketing


                                            (in millions)

Six Months Ended June 30, 2020                                                         $       94.3

Changes in Gross Margin:
Merchant Generation                                                                             9.1
Renewable Generation                                                                            8.4
Retail, Trading and Marketing                                                                 (27.4)
Total Change in Gross Margin                                                                   (9.9)

Changes in Expenses and Other:
Other Operation and Maintenance                                                                (2.7)

Depreciation and Amortization                                                                  (3.0)
Taxes Other Than Income Taxes                                                                   1.6
Interest and Investment Income                                                                 (1.1)

Interest Expense                                                                                9.6
Total Change in Expenses and Other                                                              4.4

Income Tax Benefit                                                                              5.9
Equity Earnings of Unconsolidated Subsidiaries                                                 (4.7)
Net Loss Attributable to Noncontrolling Interests                                              (1.0)

Six Months Ended June 30, 2021                                                         $       89.0

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 $9 million primarily due to higher market prices
in PJM which drove increased generation at Cardinal Plant.
•Renewable Generation increased $8 million primarily due to increased solar and
wind production in the ERCOT region and higher market revenues from wind assets
in the ERCOT region.
•Retail, Trading and Marketing decreased $27 million due to lower trading and
retail margins due to unprecedented cold temperatures and record ERCOT market
prices in February 2021.

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



•Other Operation and Maintenance expenses increased $3 million primarily due to
the following:
•A $17 million increase related to the Oklaunion PPA with AEP Texas primarily
due to an ARO revision in 2020.
This increase was partially offset by:
•A $9 million decrease due to the retirement of Conesville Plant Unit 4 in 2020.
•A $4 million decrease due to a planned outage at Cardinal Plant in 2020.
•Depreciation and Amortization expenses increased $3 million due to a higher
depreciable base from increased investments in renewable energy sources.
•Interest Expense decreased $10 million due to lower borrowing costs in 2021.
•Income Tax Benefit increased $6 million primarily due to an increase in PTCs.
•Equity Earnings of Unconsolidated Subsidiaries decreased $5 million primarily
due to lower revenues due to lower wind production from jointly owned assets.
                                       39
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CORPORATE AND OTHER

Second Quarter of 2021 Compared to Second Quarter of 2020

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $32 million in 2020 to a loss of $25 million in 2021 primarily due to:



•A $21 million gain from an investment in ChargePoint, of which $16 million is
unrealized.
•A $14 million increase in equity earnings.
•A $4 million decrease in interest expense.

These items were partially offset by:

•A $19 million increase in general corporate expenses. •A $14 million decrease in interest income due to a lower return on investments held by EIS and lower interest income from affiliates.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $67 million in 2020 to a loss of $43 million in 2021 primarily due to:



•A $38 million gain from an investment in ChargePoint, of which $33 million is
unrealized.
•A $20 million increase in equity earnings.
•A $16 million decrease in interest expense.

These items were partially offset by:



•A $28 million increase in general corporate expenses.
•A $15 million decrease in interest income primarily due to lower interest
income from affiliates.
•A $7 million increase in Income Tax Expense due to the recognition of a $19
million remeasurement of state deferred taxes as a result of newly enacted West
Virginia state legislation in 2021 partially offset by a decrease in
consolidating tax adjustments.

AEP SYSTEM INCOME TAXES

Second Quarter of 2021 Compared to Second Quarter of 2020

Income Tax Expense increased $49 million primarily due to a decrease in amortization of Excess ADIT, an increase in pretax book income and the remeasurement of state deferred taxes as a result of newly enacted West Virginia and Oklahoma state legislation in 2021.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020



Income Tax Expense increased $57 million primarily due to an increase in pretax
book income, a decrease in amortization of Excess ADIT and the remeasurement of
state deferred taxes as a result of newly enacted West Virginia and Oklahoma
state legislation in 2021, partially offset by an increase in PTCs.


                                       40
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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


                                                                June 30, 2021                              December 31, 2020
                                                                                   (dollars in millions)
Long-term Debt, including amounts due within one
year                                                 $    33,117.8                57.2  %       $       31,072.5                57.2  %
Short-term Debt                                            3,128.0                 5.4                   2,479.3                 4.6
Total Debt                                                36,245.8                62.6                  33,551.8                61.8
AEP Common Equity                                         21,378.7                37.0                  20,550.9                37.8
Noncontrolling Interests                                     251.2                 0.4                     223.6                 0.4
Total Debt and Equity Capitalization                 $    57,875.7               100.0  %       $       54,326.3               100.0  %



AEP's ratio of debt-to-total capital increased from 61.8% as of December 31,
2020 to 62.6% as of June 30, 2021 primarily due to an increase in debt to help
address the cash flow implications resulting from the February 2021 severe
winter weather event in addition to supporting distribution, transmission and
renewable investment growth.

Liquidity



Liquidity, or access to cash, is an important factor in determining AEP's
financial stability. Management believes AEP has adequate liquidity under its
existing credit facilities. As of June 30, 2021, AEP had $5 billion of revolving
credit facilities to support its commercial paper program. Additional liquidity
is available from cash from operations and a receivables securitization
agreement. Management is committed to maintaining adequate liquidity. AEP
generally uses short-term borrowings to fund working capital needs, property
acquisitions and construction until long-term funding is arranged. Sources of
long-term funding include issuance of long-term debt, leasing agreements, hybrid
securities or common stock. In February 2021, severe winter weather impacted
certain AEP service territories resulting in disruptions to SPP market
conditions. In March 2021, AEP entered into a $500 million 364-day Term Loan and
borrowed the full amount to help address the cash flow implications resulting
from the February 2021 severe winter weather event. See Note 4 - Rate Matters
for additional information.

Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments. As of June 30, 2021, available liquidity was approximately $3.3 billion as illustrated in the table below:


                                                             Amount

Maturity


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


     Cash and Cash Equivalents                                   312.7
     Total Liquidity Sources                                   5,812.7
     Less:          AEP Commercial Paper Outstanding           2,049.8
                    364-Day Term Loan                            500.0

     Net Available Liquidity                            $      3,262.9



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 six months of 2021 was $2.5 billion. The weighted-average
interest rate for AEP's commercial paper during 2021 was 0.25%.
                                       41
--------------------------------------------------------------------------------






Other Credit Facilities

An uncommitted facility gives the issuer of the facility the right to accept or
decline each request made under the facility. AEP issues letters of credit on
behalf of subsidiaries under six uncommitted facilities totaling $425 million.
The Registrants' maximum future payments for letters of credit issued under the
uncommitted facilities as of June 30, 2021 was $187 million with maturities
ranging from July 2021 to July 2022.

Securitized Accounts Receivables

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



In March 2021, AEP Credit amended its receivables securitization agreement to
extend trigger levels established in October 2020 and to also provide a step
down approach to these levels as management continues to monitor the accounts
receivable balances across the affiliated utility subsidiaries in response to
the COVID-19 pandemic. In June 2021, AEP Credit entered into a waiver for both
APCo and SWEPCo to waive certain triggers through August 2021 due to the
continuing impact of the COVID-19 pandemic. As of June 30, 2021, the affiliated
utility subsidiaries are in compliance with all requirements under the
agreement. To the extent that an affiliated utility subsidiary is deemed
ineligible under the agreement, the affiliated utility subsidiary would no
longer participate in the receivables securitization agreement and the
Registrants would need to rely on additional sources of funding for operation
and working capital, which may adversely impact liquidity. The receivables that
are ineligible under the receivables securitization agreement are financed with
short-term debt at AEP Credit.

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 June 30, 2021, this contractually-defined percentage was 59.7%.
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.

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

At-the-Market (ATM) Program

AEP participates in an ATM offering program that allows AEP to issue, from time
to time, up to an aggregate of $1 billion of its common stock, including shares
of common stock that may be sold pursuant to an equity forward sales agreement.
As of June 30, 2021, approximately $803 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.
                                       42
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In March 2019, AEP issued 16.1 million Equity Units initially in the form of
corporate units, at a stated amount of $50 per unit, for a total stated amount
of $805 million. Net proceeds from the issuance were approximately $785 million.
Each corporate unit represents a 1/20 undivided beneficial ownership interest in
$1,000 principal amount of AEP's 3.40% Junior Subordinated Notes due in 2024 and
a forward equity purchase contract which settles after three years in 2022. The
proceeds from this issuance were used to support AEP's overall capital
expenditure plans including the acquisition of Sempra Renewables LLC.

See Note 12 - Financing Activities for additional information.

Dividend Policy and Restrictions



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

Credit Ratings

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


                                       43

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Real-time Estimate Cboe BZX Other stock markets 09:51:53 2024-04-26 am EDT			5-day change	1st Jan Change
86.5 ^USD	-0.42%		+2.99%	+6.77%

Apr. 25	CMS Energy posts higher first-quarter profit helped by robust demand, lower costs	RE
Apr. 23	American Electric Power Keeps Quarterly Cash Dividend at $0.88 per Share, Payable June 10 to Holders as of May 10	MT

CMS Energy posts higher first-quarter profit helped by robust demand, lower costs	Apr. 25	RE
American Electric Power Keeps Quarterly Cash Dividend at $0.88 per Share, Payable June 10 to Holders as of May 10	Apr. 23	MT
American Electric Power Company, Inc. Declares Quarterly Dividend on Common Stock, Payable on June 10, 2024	Apr. 23	CI
Transcript : American Electric Power Company, Inc. - Shareholder/Analyst Call	Apr. 23
BMO Capital Adjusts American Electric Power Price Target to $93 From $90	Apr. 22	MT
Scotiabank Adjusts American Electric Power's Price Target to $86 From $92	Apr. 22	MT
Barclays Adjusts American Electric Power's Price Target to $84 From $83	Apr. 12	MT
JPMorgan Raises American Electric Power's Price Target to $92 From $90, Keeps Overweight Rating	Apr. 11	MT
US electric utilities brace for surge in power demand from data centers	Apr. 10	RE
GAC Group, Didi to Form Self-Driving JV	Apr. 05	MT
Duke Energy to Sell 50% Interest in Joint Venture to Invest in Clean Energy Transition	Apr. 04	DJ
North American Morning Briefing : Inflation Data -2-	Mar. 12	DJ
Sector Update: Energy Stocks Rise in Late Afternoon Trading	Mar. 11	MT
American Electric Power's Discount to Peers Could Widen Amid Leadership Transition, UBS Says	Mar. 11	MT
UBS Downgrades American Electric Power to Sell From Neutral, Cuts Price Target to $83 From $86	Mar. 11	MT
North American Morning Briefing : Stock Futures -2-	Mar. 11	DJ
Ladenburg Thalmann Downgrades American Electric Power to Sell From Neutral, Adjusts Price Target to $73 From $75.50	Mar. 08	MT
North American Morning Briefing : Fed's Preferred -2-	Feb. 29	DJ
Barclays Downgrades American Electric Power to Equalweight From Overweight , Trims Price Target to $83 From $84	Feb. 28	MT
The calm after the storm	Feb. 28
ANALYST RECOMMENDATIONS : Amex, Apollo Global Management, Crowdstrike, Workday, Abrdn...	Feb. 28
BMO Capital Adjusts Price Target on American Electric Power to $88 From $87, Maintains Outperform Rating	Feb. 27	MT
Transcript : American Electric Power Company, Inc., Q4 2023 Earnings Call, Feb 27, 2024	Feb. 27
Stocks Rise Pre-Bell as Investors Digest Latest Corporate Earnings; Asia Up, Europe Mixed	Feb. 27	MT
North American Morning Briefing : Stock Futures Pause as Investors Eye Inflation Data	Feb. 27	DJ

	1st Jan change	Capi.
AMERICAN ELECTRIC POWER COMPANY, INC.	+6.77%	45.74B
NEXTERA ENERGY	+9.89%	137B
SOUTHERN COMPANY	+5.95%	81.33B
IBERDROLA, S.A.	-2.19%	77.24B
DUKE ENERGY CORPORATION	+1.81%	76.4B
ENEL S.P.A.	-9.17%	65.93B
CONSTELLATION ENERGY CORPORATION	+60.60%	59.25B
DOMINION ENERGY, INC.	+8.30%	42.69B
GE VERNOVA INC.	0.00%	40.35B
EXELON CORPORATION	+4.09%	37.65B

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