Regional Haze

The Federal EPA issued a Clean Air Visibility Rule (CAVR)~~, detailing how the CAA’s requirement that certain~~ in 2005, which could require power plants and other facilities to install best available retrofit technology ~~(BART) will~~to address regional haze in federal parks and other protected areas. ~~BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants.~~ CAVR ~~will be~~is implemented by the states, through SIPs, or ~~if SIPs are not adequate or are not developed on schedule,~~by the Federal EPA, through FIPs. In ~~January~~ 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.~~programs. Petitions for review of the final rule revisions have been filed in the U.S. Court of Appeals for the District of Columbia Circuit.

The Federal EPA proposed disapproval of regional haze SIPs in a few states, including Arkansas and Texas. In March 2012, the Federal EPA disapproved certain portions of the Arkansas regional haze SIP. In April 2015, the Federal EPA published a proposed FIP to replace the disapproved portions, including revised BART determinations for the Flint Creek Plant that were consistent with the environmental controls under construction. In September 2016, the Federal EPA published a final FIP that retains its BART determinations, but accelerates the schedule for implementation of certain required controls. The final rule is being challenged in the courts. In March 2017, the Federal EPA filed a motion that was granted by the U.S. Court of Appeals for the Eighth Circuit to hold the case in abeyance for 90 days to allow the parties to engage in settlement negotiations. Arkansas issued a proposed SIP revision to allow sources to participate in the CSAPR ozone season program in lieu of the source-specific NO_x ~~BART requirements in the FIP, and the Federal EPA has approved that SIP revision. Arkansas issued a second proposal to revise the SO~~₂ BART determinations, and the public comment period on that action has closed. The Federal EPA has asked the Eighth Circuit to continue to hold litigation in abeyance to facilitate settlement discussions. Arkansas and other affected parties filed motions to stay the compliance deadlines pending further action from the Federal EPA and the motion was granted. Management cannot predict the outcome of these proceedings.

~~In January 2016, the~~ Federal EPA disapproved portions of the Texas regional haze SIP and promulgated a final FIP that did not include any BART determinations. That rule was challenged and stayed by the U.S. Court of Appeals for the Fifth Circuit. The parties engaged in a settlement discussion but were unable to reach an agreement. In March 2017, the U.S. Court of Appeals for the Fifth Circuit granted partial remand of the final rule. In January 2017, the Federal EPA proposed source-specific BART requirements for SO₂ from sources in Texas, including Welsh Plant, Unit 1. Management submitted comments on the proposal and engaged in discussions with the Texas Commission on Environmental Quality (TCEQ) regarding the development of an alternative to source-specific BART. In September 2017, the Federal EPA issued a final rule withdrawing Texas from the annual CSAPR budget programs and reaffirming CSAPR as a BART alternative. The Federal EPA then issued a separate rule finalizing the regional haze requirements for electric generating units in Texas and confirmed TCEQ’s determination that no new PM limitations are required for regional haze. The Federal EPA also finalized a FIP that allows participation in the CSAPR ozone season program to satisfy the NO_xXregional haze obligations for electric generating ~~units.~~units in Texas. Additionally, the Federal EPA finalized an intrastate SO₂ emissions trading program based on CSAPR allowance ~~allocations as an alternative~~allocations. Legal challenges to ~~source-specific SO~~₂ requirements. The proposed source-specific approach called for a wet FGD system to be installed on Welsh Plant, Unit 1. The opportunity to use emissions trading to satisfy the regional haze requirements for NO_x ~~and SO~~₂ ~~at AEP’s affected generating units provides greater flexibility and lower cost compliance options than the original proposal. A challenge to the FIP has been filed~~these various rulemakings are pending in both the U.S. Court of Appeals for the Fifth Circuit ~~by various intervenors. The Federal EPA~~ and petitioners filed a joint motion to hold the case in abeyance pending the Federal EPA’s review of challengers’ petition for reconsideration. In March 2018, that motion was granted. Management supports the intrastate trading program contained in the FIP as a compliance alternative to source-specific controls.

~~In June 2012, the Federal EPA published revisions to the regional haze rules to allow states participating in the CSAPR trading programs to use those programs in place of source-specific BART for SO~~₂ ~~and NO~~_x ~~emissions based on its determination that CSAPR results in greater visibility improvements than source-specific BART in the CSAPR states. The rule was challenged in~~ the U.S. Court of Appeals for the District of Columbia Circuit. ~~In March 2018,~~Management cannot predict the ~~U.S. Court~~outcome of ~~Appeals for~~that litigation, although management supports the ~~District~~intrastate trading program as a compliance alternative to source-specific controls and has intervened in the litigation in support of ~~Columbia Circuit affirmed~~the Federal EPA.

Cross-State Air Pollution Rule

CSAPR is a regional trading program that the Federal EPA ~~rule.~~

~~CSAPR~~

~~In 2011, the Federal EPA issued CSAPR as a replacement for the CAIR, a regional trading program~~began implementing in 2015, which was originally designed to address interstate transport of emissions that ~~contributed~~contribute significantly to ~~downwind nonattainment~~non-attainment and interfere with maintenance of the 1997 ozone NAAQS and ~~PM NAAQS. Certain revisions to~~ the ~~rule were finalized~~1997 and 2006 PM2.5 NAAQS in ~~2012.~~downwind states. CSAPR relies on ~~newly-created~~ SO₂ and NO_xXallowances 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.

Numerous affected entities, states and other parties filed petitions to review the CSAPR in the U.S. Court of Appeals for the District of Columbia Circuit. The court stayed implementation of the rule. Following extended proceedings in the U.S. Court of Appeals for the District of Columbia Circuit and the U.S. Supreme Court, but while the litigation was still pending, the U.S. Court of Appeals for the District of Columbia Circuit granted the Federal EPA’s motion to lift the stay and allow Phase I of CSAPR to take effect on January 1, 2015 and Phase II to take effect on January 1, 2017. In July 2015, the U.S. Court of Appeals for the District of Columbia Circuit found that the Federal EPA over-controlled the SO₂~~and/or NO~~_xbudgets of 14 states. The U.S. Court of Appeals for the District of Columbia Circuit remanded the rule to the Federal EPA to timely revise the rule consistent with the court’s opinion while CSAPR remains in place.

In October 2016, a final rule was issued to address the remand and to incorporate additional changes necessary to address the 2008 ozone standard. The final rule significantly reduces ozone season budgets in many states and discounts the value of banked CSAPR ozone season allowances beginning with the 2017 ozone season. The rule has been challenged in the courts and petitions for administrative reconsideration have been filed. In March 2018, the U.S. Court of Appeals for the District of Columbia Circuit denied the petitions and other challenges to the rule. Management has been complying with the more stringent ozone season budgets while these petitions were pending. In a related case, other parties challenged in the U.S. Court of Appeals for the District of Columbia Circuit a final rule withdrawing Texas from the CSAPR annual program and reaffirming that compliance with CSAPR remained better than compliance with BART. The U.S. Court of Appeals for the District of Columbia Circuit granted a motion in March 2018 to hold the case in abeyance until completion of the Federal EPA’s review of pending petitions for reconsideration of the Texas regional haze rule discussed above.

~~Mercury and Other Hazardous Air Pollutants (HAPs) Regulation~~

In 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants. The rule establishes unit-specific emission rates for units burning coal on a 30-day rolling average basis for mercury, PM (as a surrogate for particles of nonmercury metals) and hydrogen chloride (as a surrogate for acid gases). In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans. Compliance was required within three years. Management obtained administrative extensions for up to one year at several units to facilitate the installation of controls or to avoid a serious reliability problem.

In April 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied all of the petitions for review of the April 2012 final rule. Industry trade groups and several states filed petitions for further review in the U.S. Supreme Court and the court granted those petitions in November 2014.

In June 2015, the U.S. Supreme Court reversed the decision of the U.S. Court of Appeals for the District of Columbia Circuit. The U.S. Court of Appeals for the District of Columbia Circuit remanded the MATS rule for further proceedings consistent with the U.S. Supreme Court’s decision that the Federal EPA was unreasonable in refusing to consider costs in its determination whether to regulate emissions of HAPs from power plants. The Federal EPA issued notice of a supplemental finding concluding that it is appropriate and necessary to regulate HAP emissions from coal-fired and oil-fired units. Management submitted comments on the proposal. In April 2016, the Federal EPA affirmed its determination that regulation of HAPs from electric generating units is necessary and appropriate. Petitions for review of the Federal EPA’s April 2016 determination have been filed in the U.S. Court of Appeals for the District of Columbia Circuit. Oral argument was scheduled for May 2017, but in April 2017 the Federal EPA requested that oral argument be postponed to facilitate its review of the rule. The rule remains in effect.

~~Climate Change, CO~~₂ ~~Regulation and Energy Policy~~

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. Management is taking steps to comply with these requirements, including increasing wind and solar installations and power purchases and broadening the AEP System’s portfolio of energy efficiency programs.

In October 2015, the Federal EPA published the final standards for new, modified and reconstructed fossil fuel fired steam generating units and combustion turbines, and final guidelines for the development of state plans to regulate CO₂ ~~emissions from existing sources. The final standard for new combustion turbines is 1,000 pounds of CO~~₂ ~~per MWh and the final standard for new fossil steam units is 1,400 pounds of CO~~₂ per MWh. Reconstructed turbines are subject to the same standard as new units and no standard for modified combustion turbines was issued. Reconstructed fossil steam units are subject to a standard of 1,800 pounds of CO₂ ~~per MWh for larger units and 2,000 pounds of CO~~₂ ~~per MWh for smaller units. Modified fossil steam units will be subject to a site specific standard no lower than the standards that would be applied if the units were reconstructed.~~

The final emissions guidelines for existing sources, known as the Clean Power Plan (CPP), are based on a series of declining emission rates that are implemented beginning in 2022 through 2029. The final emission rate is 771 pounds of CO₂ ~~per MWh for existing natural gas combined cycle units and 1,305 pounds of CO~~₂ ~~per MWh for existing fossil steam units in 2030 and thereafter. The Federal EPA also developed a set of rate-based and mass-based state goals.~~

The Federal EPA also published proposed “model” rules that could be adopted by the states that would allow sources within “trading ready” state programs to trade, bank or sell allowances or credits issued by the states. These rules would also be the basis for any federal plan issued by the Federal EPA in a state that fails to submit or receive approval for a state plan. In June 2016, the Federal EPA issued a separate proposal for the Clean Energy Incentive Program (CEIP) that was included in the model rules.

The final rules are being challenged in the courts. In February 2016, the U.S. Supreme Court issued a stay on the final CPP, including all of the deadlines for submission of initial or final state plans. The stay will remain in effect until a final decision is issued by the U.S. Court of Appeals for the District of Columbia Circuit and the U.S. Supreme Court considers any petition for review. In April 2017, the Federal EPA withdrew its previously issued proposals for model trading rules and a CEIP.

In March 2017, the Federal EPA filed in the U.S. Court of Appeals for the District of Columbia Circuit notice of: (a) an Executive Order from the President of the United States titled “Promoting Energy Independence and Economic Growth” directing the Federal EPA to review the CPP and related rules; (b) the Federal EPA’s initiation of a review of the CPP and (c) a forthcoming rulemaking related to the CPP consistent with the Executive Order, if the Federal EPA determines appropriate. In this same filing, the Federal EPA also presented a motion to hold the litigation in abeyance until 30 days after the conclusion of review of any resulting rulemaking. The District of Columbia Circuit granted the Federal EPA’s motion in part and has requested periodic status reports. In October 2017, the Federal EPA issued a proposed rule repealing the CPP and withdrawing the legal memoranda issued in connection with the rule. The Federal EPA has ~~re-examined its legal interpretation of~~revised, or updated, the “best system of emission reduction” and found that based on the statutory text, legislative history, use of similar terms elsewhere in the CAA and its own historic implementation of Section 111 that a narrower interpretation of the term limits it to those designs, processes, control technologies and other systems that can be applied directly to or at the source. Since the primary systems relied on in the CPP are not consistent with that interpretation,CSAPR trading programs several times since they were established.

In January 2021, the Federal EPA ~~proposes that~~finalized a revised CSAPR, which substantially reduced the ~~rule be withdrawn. The comment period on the proposed repeal~~ozone season NOX budgets for several states, including states where AEP operates, beginning in ozone season 2021. AEP has been ~~extended~~able to ~~April 2018.~~ meet the requirements of the revised rule over the first few years of implementation, and is evaluating its compliance options for later years, when the budgets are further reduced.

In ~~December 2017,~~addition, in February 2023, the Federal EPA ~~issued an advanced notice~~Administrator finalized the disapproval of ~~proposed rulemaking seeking information that should be considered~~interstate transport SIPs submitted by 19 states, including Texas, addressing the 2015 Ozone NAAQS. The Federal EPA disapproved interstate transport SIPs submitted by additional states soon thereafter. Disapproval of the SIPs provided the Federal EPA with authority to impose a FIP for those states, replacing the SIPs that were disapproved. In August 2023, a FIP went into effect that further revised the ozone season NOX budgets under the existing CSAPR program in ~~developing guidelines~~states to which the FIP applies. Several states and industry parties initiated legal challenges to the Federal EPA’s SIP disapprovals, and at the request of those parties, the courts have stayed SIP disapprovals for ~~state programs.~~several states, including some states in which AEP operates. The Federal EPA has issued interim rules staying the FIP for states where the courts have stayed the underlying SIP disapprovals for the period while the judicial stays of the SIP disapprovals remain in place. The disapproval of SIPs and implementation of FIPs continues to be subject to extensive litigation. Management ~~is actively monitoring these rulemakings~~will continue to monitor the outcome of this litigation and ~~participating in~~ the development of SIPs for any potential impact to operations.

Climate Change, CO2 Regulation and Energy Policy

In April 2024, the Administrator of the Federal EPA signed new ~~guidelines.~~greenhouse gas standards and guidelines for new and existing fossil-fuel fired sources. The rule relies on carbon capture and sequestration and natural gas co-firing as means to reduce CO2 emissions from coal fired plants and carbon capture and sequestration to reduce CO2 emissions from new gas turbines. The Federal EPA deferred the finalization of standards for existing gas turbines until later in 2024. AEP is in the early stages of evaluating and identifying the best strategy for complying with this and other new rules, discussed below, while ensuring the adequacy of resources to meet customer needs. AEP is also evaluating potential legal challenges to the rule.

Even in the absence of federal regulatory requirements to reduce CO2 emissions, AEP has already taken action to reduce and offset CO₂ emissions from its generating ~~fleet and~~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. Certain states where AEP has generating facilities have passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements that can assist in reducing carbon emissions.

AEP routinely submits IRPs in various regulatory jurisdictions to address future generation and capacity needs. These IRPs take into account economics, customer demand, grid reliability and resilience, regulations and RTO capacity requirements. The objective of the IRPs is to recommend future generation and capacity resources that provide the most cost-efficient and reliable power to customers. In ~~February 2018,~~October 2022, AEP announced new intermediate and long-term CO₂ emission reduction ~~goals, based on the output~~

of the company’s integrated resource plans, which take into account economics, customer demand, regulations, and grid reliability and resiliency, and reflect the company’s current business strategy. The intermediate goal isgoals. AEP adjusted its near-term CO2 emission reduction target from a ~~60% reduction from~~ 2000 CO₂ ~~emission levels from AEP generating facilities by 2030; the long-term goal is an~~baseline to a 2005 baseline, upgraded its 80% reduction ~~of CO~~₂by 2030 target to include full Scope 1 emissions ~~from AEP generating facilities from 2000 levels~~and accelerated its net-zero goal by ~~2050.~~five years to 2045 for Scope 1 and Scope 2 emissions. AEP’s total ~~projected CO~~₂Scope 1 GHG estimated emissions in ~~2018 are~~2023 were approximately 9044.5 million metric tons, a ~~46%~~67% reduction according to the GHG Protocol, which excludes emission reductions that result from assets that have been sold, or a 71% reduction from AEP’s ~~2000~~2005 Scope 1 GHG emissions (inclusive of emission reductions that result from plants that have been sold).

AEP has made significant progress in reducing CO₂ emissions ~~of approximately 167 million metric tons.~~

~~Federal~~from its power generation fleet and ~~state legislation or regulations that mandate limits~~expects its emissions to continue to decline over the long-term. AEP also expects Scope 1 GHG emissions to vary annually depending on the ~~emission~~mix of CO₂ ~~could result in significant increases in capital expenditures~~its own generation and ~~operating~~purchased power used to serve customers. AEP’s ability to achieve these goals is dependent upon a number of factors including continuing to provide the most cost-efficient and reliable power to customers, having regulatory support to execute on renewable resource plans, evolving RTO requirements, the advancement of carbon-free generation technologies, customer demand for carbon-free energy, potential tariffs, carbon policy and regulation, operational performance of renewable generation and supply chain costs ~~which in turn, could lead to increased liquidity needs~~ and ~~higher financing costs.~~ constraints.

Excessive costs to comply with ~~future legislation or~~environmental regulations ~~might~~have led to the announcement of early plant closures across the country. The Federal EPA’s new GHG rules and the suite of other new rules announced simultaneously and directed at the fossil-fuel fired electric utility industry, see discussion of other rules below, and could force AEP to close ~~some~~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 ~~could lead to possible impairment of assets.~~cash flows and impact financial condition.

~~Coal Combustion Residual~~MATS Rule

In April ~~2015,~~2024, the Federal EPA ~~published~~issued a ~~final~~revised MATS rule ~~to regulate~~for power plants. The rule includes a more stringent standard for emissions of filterable PM for coal-fired electric generating units, as well as a new mercury standard for lignite-fired electric generating units. The rule also requires the installation and operation of continuous emissions monitors for PM. Management is evaluating the impacts of the rule, but does not anticipate any significant challenges complying with the rule.

CCR Rule

The Federal EPA’s CCR rule regulates the disposal and beneficial re-use of ~~coal combustion residuals (CCR),~~CCR, including fly ash and bottom ash ~~generated at~~created from coal-fired ~~electric~~ generating units and ~~also~~ FGD gypsum generated at some coal-fired plants. The ~~final~~original rule ~~has been challenged in the courts.~~

~~The final rule became effective in October 2015. CCR are regulated as non-hazardous solid wastes~~applied to active and ~~facilities managing CCR must meet new minimum federal solid waste management standards. The rule applies to new and existing active~~inactive CCR landfills and ~~CCR~~ surface impoundments at ~~operating~~facilities of active electric utility or independent power ~~production facilities. The~~producers. With revisions announced in April 2024, the scope of the rule ~~imposes construction and operating obligations, including location restrictions, liner criteria, structural integrity~~has expanded significantly, to include inactive impoundments at inactive facilities (“legacy CCR surface impoundments”) as well as to establish requirements for ~~impoundments, operating criteria and additional groundwater monitoring requirements to be implemented~~currently exempt solid waste management units that involve the direct placement of CCR on ~~a schedule spanning an approximate four year implementation period. Certain records must be posted to a publicly available internet site.~~the land (“CCR management units”).

In ~~December 2016, the U.S. Congress passed legislation authorizing states to submit programs to regulate CCR facilities, and~~2020, the Federal EPA revised the original CCR rule to ~~approve~~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 ~~programs if they are no less stringent than~~an extension requires a satisfactory demonstration of the ~~minimum federal standards. 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 various plants.

In January 2022, the Federal EPA ~~may also enforce~~proposed to deny several extension requests filed by the other utilities based on allegations that those utilities are not in compliance with the ~~minimum standards until a state program is approved or if states fail to adopt their own programs.~~CCR Rule (the January Actions). In ~~September 2017,~~November 2022, the Federal EPA ~~granted industry petitions to reconsider~~finalized one of these denials (the Gavin Denial, discussed above). The Federal EPA’s allegations of noncompliance rely on new interpretations of the CCR ~~rule~~Rule requirements. The January Actions of the Federal EPA and ~~asked that litigation regarding~~ the ~~rule be held~~Gavin Denial have been challenged in ~~abeyance. The~~the U.S. Court of Appeals for the District of Columbia Circuit ~~heard oral argument in November 2017. In March 2018,~~as unlawful rulemaking that revises the ~~Federal EPA issued a proposed rule to modify certain provisions of the solid waste management standards~~existing CCR Rule requirements without proper notice and provide additional flexibility to facilities regulated under approved state programs. The comment period is open until the end of April 2018. Management supports the adoption of more flexible compliance alternatives subject to the Federal EPA or state oversight.

Other utilities and industrial sources have been engaged in litigation with environmental advocacy groups who claim that releases of contaminants from wells, CCR units, pipelines and other facilities to ground waters that have a hydrologic connection to a surface water body represents an “unpermitted discharge” under the Clean Water Act. The Federal EPA has opened a rulemaking docket to solicit information to determine whether it should provide additional clarification of the scope of Clean Water Act permitting requirementswithout opportunity for ~~discharges to ground water. Comments are due in May 2018.~~comment. Management is unable to predict the outcome of ~~these cases on~~that litigation or how it may impact the Federal EPA’s ~~rulemaking, but they could impose significant~~interpretation of the CCR Rule.

In July 2022, the Federal EPA proposed conditional approval of the pending extension request for APCo’s Mountaineer Plant. The Federal EPA alleged that the Mountaineer Plant was not fully compliant with the CCR Rule. In December 2022, AEP withdrew the pending extension request for the Mountaineer Plant as work to construct new CCR disposal facilities was completed and the extension was no longer needed. In addition, AEP ceased receiving ash in the other ponds subject to the extension requests, completed construction of new, CCR Rule compliant facilities and withdrew all of the remaining applications for additional ~~costs~~time to develop alternative disposal capacity.

Under the second option for obtaining an extension of the April 11, 2021 deadline to cease operation of unlined impoundments, a generating facility may continue operating its existing impoundments without developing alternative CCR disposal, provided the facility commits to cease combustion of coal by a date certain. Under this option, a generating facility had until October 17, 2023 to cease coal-fired operations and to close CCR storage ponds 40 acres or less in size, or through October 17, 2028 for facilities with CCR storage ponds greater than 40 acres in size. Pursuant to this option, AEP informed the Federal EPA of its intent to retire the Pirkey Plant and cease using coal at the Welsh Plant. In March 2023, the Pirkey Plant was retired. To date, the Federal EPA has not taken any action on ~~AEP’s facilities.~~the pending extension request for the Welsh Plant.

~~Because AEP~~In April 2024, the Federal EPA finalized revisions to the CCR Rule to expand the scope of the rule to include inactive impoundments at inactive facilities (“legacy CCR surface impoundments”) as well as to establish requirements for currently ~~uses~~exempt solid waste management units that involve the direct placement of CCR on the land (“CCR management units”). The Federal EPA is requiring that owners and operators of legacy surface impoundments comply with all of the existing CCR Rule requirements applicable to inactive CCR surface impoundments at active facilities, except for the location restrictions and ~~landfills~~liner design criteria. The rule establishes compliance deadlines for legacy surface impoundments to ~~manage CCR materials~~meet regulatory requirements, including a requirement to initiate closure within five years after the effective date of the final rule. The rule requires evaluations to be completed at ~~generating~~both active facilities ~~significant~~and inactive facilities with one or more legacy surface impoundments. AEP is evaluating the applicability of the rule to current and former plant sites and is working to develop estimates of compliance costs, ~~will~~which are expected to be ~~incurred~~material, including costs to upgrade or close and replace ~~these existing~~legacy CCR surface impoundments and to conduct any required remedial actions including removal of coal ash.

Closure and post-closure estimated costs for facilities ~~at some point~~subject to the original CCR Rule have been included in ARO in accordance with the requirements in the ~~future as~~Federal EPA’s original CCR rule. Material ARO revisions will be necessary to address the ~~new rule is implemented. Management recorded a $95 million increase in asset retirement obligations in 2015 primarily due~~expanded scope of facilities subject to the ~~publication~~revised rule. Additional material ARO revisions may occur on a site-by-site basis if groundwater monitoring activities conclude that corrective actions are required to mitigate groundwater impacts. AEP may incur significant additional costs complying with the Federal EPA’s CCR Rule, including costs to upgrade or close and replace surface impoundments and landfills used to manage CCR and to conduct any required remedial actions including removal of ~~the final rule. Management will continue~~coal ash.

AEP would need to ~~evaluate the rule’s~~seek cost recovery through regulated rates, including proposing new regulatory mechanisms for cost recovery where existing mechanisms are not applicable, for which regulatory approval cannot be assured. The rule could have a material adverse impact on ~~operations.~~net income, cash flows and financial condition if AEP cannot ultimately recover any additional costs of compliance. Management is also evaluating potential legal challenges to the revised rule.

Clean Water Act ~~(CWA)~~ Regulations

~~In 2014, the~~The Federal ~~EPA issued a final~~EPA’s ELG rule ~~setting forth standards~~ for existing power plants that is intended to reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water. Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress. The final rule affects all plants withdrawing more than two million gallons of cooling water per day. The rule offers seven technology options to comply with the impingement standard and requires site-specific studies to determine appropriate entrainment compliance measures atgenerating facilities withdrawing more than 125 million gallons per day. Additional requirements may be imposed as a result of consultation with other federal agencies to protect threatened and endangered species and their habitats. Facilities with existing closed cycle recirculating cooling systems, as defined in the rule, are not expected to require any technology changes. Facilities subject to both the impingement standard and site-specific entrainment studies will typically be given at least three years to conduct and submit the results of those studies to the permit agency. Compliance timeframes will then be established by the permit agency through each facility’s NPDES permit for installation of any required technology changes, as those permits are renewed over the next five to eight years. Petitions for review of the final rule were filed by industry and environmental groups and are currently pending in the U.S. Court of Appeals for the Second Circuit.

~~In addition, the Federal EPA developed revised effluent limitation guidelines for electricity generating facilities. A final rule was issued in November 2015. The final rule~~ establishes limits onfor FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater, which are to ~~be imposed as soon as possible after November 2018 and no later than December 2023. These new requirements will~~ be implemented through each facility’s wastewater discharge permit. ~~The~~A revision to the ELG rule, ~~has been challenged~~published in ~~the U.S. Court~~October 2020, established additional options for reusing and discharging small volumes of Appeals for the Fifth Circuit. In March 2017, industry associations filed a petition for reconsideration of the rule with the Federal EPA. In April 2017, the Federal EPA granted reconsideration of the rule and issued a stay of the rule’s future compliance deadlines, which has now expired. In April 2017, the U.S. Court of Appeals for the Fifth Circuit granted a stay of the litigation for 120 days. In June 2017, the Federal EPA also issued a proposal to temporarily postpone certain compliance deadlines in the rule. A final rule revising the compliance deadlines for FGD wastewater and bottom ash transport water, provided an exception for retiring units and extended the compliance deadline to bea date as soon as possible beginning one year after the rule was published but no ~~earlier~~later than ~~2020 was issued in September 2017.~~December 2025. Management ~~submitted comments supporting the proposed postponement. Management continues to assess~~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. Management is actively participating~~permitting for FGD wastewater and bottom ash transport water. For affected facilities that must install additional technologies to meet the ELG rule limits, permit modifications were filed in January 2021 that reflect the ~~reconsideration proceedings.~~

outcome of that assessment. AEP continues to work with state agencies to finalize permit terms and conditions. Other facilities opted to file Notices of Planned Participation (NOPP), pursuant to which the facilities are not required to install additional controls to meet ELG limits provided they make commitments to cease coal combustion by a date certain. In ~~June 2015,~~April 2024, the Federal EPA finalized further revisions to the ELG rule that establish a zero liquid discharge standard for FGD wastewater, bottom ash transport water, and managed combustion residual leachate, as well as more stringent discharge limits for unmanaged combustion residual leachate. The revised rule provides a new compliance alternative that would avoid the ~~U.S. Army Corps of Engineers jointly issued a final~~need to install zero liquid discharge systems for facilities that comply with the 2020 rule’s control technology requirements and commit to retire by 2024. Management is evaluating the compliance alternatives in the rule, ~~to clarify~~taking into consideration the ~~scope~~requirements of the ~~regulatory~~other new rules and their combined impacts to operations. Management is also evaluating potential legal challenges to the rule.

The definition of “waters of the United States” has been subject to rule making and litigation which has led to inconsistent scope among the states. Management will continue to monitor developments in ~~light~~rule making and litigation for any potential impact to operations.

Impact of ~~recent U.S. Supreme Court cases.~~ Environmental Regulation on Coal-Fired Generation

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

The ~~CWA provides~~table below summarizes the net book value, as of March 31, 2024, of generating facilities retired or planned for ~~federal jurisdiction over “navigable waters” defined as “the waters~~early retirement in advance of the ~~United States.” This~~retirement date currently authorized for ratemaking purposes:


Company	Plant	Net Investment (a)		Accelerated Depreciation Regulatory Asset			Actual/Projected Retirement Date			Current Authorized Recovery Period	Annual Depreciation (b)
		(in millions)							(in millions)
PSO	Northeastern Plant, Unit 3	$	96.7	$	20.7		2026			(c)	$	15.1


SWEPCo	Pirkey Plant	—		121.0		(d)	2023			(e)	—
SWEPCo	Welsh Plant, Units 1 and 3	335.6		58.1			2028	(f)		(g)	39.2

(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)Represents Arkansas and Texas jurisdictional definition applies to all CWA programs, potentially impacting generation, transmission and distribution permitting and compliance requirements. Among those programs are permits for wastewater and storm water discharges, permits for impacts to wetlands and water bodies and oil spill prevention planning. The final definition continues to recognize traditional navigable watersshare.

(e)As part of the ~~U.S. as jurisdictional as well as certain exclusions.~~2021 Arkansas Base Rate Case, the APSC granted SWEPCo regulatory asset treatment. SWEPCo will request recovery including a weighted average cost of capital carrying charge through a future proceeding. The ~~rule also contains~~Texas share of the Pirkey Plant will be addressed in SWEPCo’s next base rate case. See the “Coal-Fired Generation Plants” section of Note 4 for additional information.

(f)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028. Management is evaluating a ~~number of new specific definitions and criteria~~potential conversion to natural gas after 2028 for ~~determining whether certain other waters are jurisdictional because of a “significant nexus.” Management believes that clarity and efficiency~~both units.

(g)Welsh Plant, Unit 1 is being recovered through 2027 in the ~~permitting process is needed. Management remains concerned that~~Louisiana jurisdiction and through 2037 in the ~~rule introduces new concepts~~Arkansas and ~~could subject more of AEP’s operations to CWA jurisdiction, thereby increasing the time and complexity of permitting. The final rule~~Texas jurisdictions. Welsh Plant, Unit 3 is being challenged in both courts of appeal and district courts. The U.S. Court of Appeals for the Sixth Circuit granted a nationwide stay of the rule pending jurisdictional determinations. In February 2016, the U.S. Court of Appeals for the Sixth Circuit issued a decision holding that it has exclusive jurisdiction to decide the challenges to the “waters of the United States” rule. Industry, state and related associations filed petitions for a rehearing of the jurisdictional decision. In April 2016, the U.S. Court of Appeals for the Sixth Circuit denied the petitions. In January 2017, the decision was appealed to the U.S. Supreme Court, which granted certiorari to review the jurisdictional issue. Oral argument was heard in October 2017. In January 2018, the U.S. Supreme Court ruled that challenges to the definition of “waters of the United States” must be filedrecovered through 2032 in the ~~federal district court,~~Louisiana jurisdiction and ~~remanded~~through 2042 in the ~~case to~~Arkansas and Texas jurisdictions.

Management is seeking or will seek regulatory recovery, as necessary, for any net book value remaining when the ~~U.S. Court~~plants are retired. To the extent the net book value of ~~Appeals for the Sixth Circuit with directions to dismiss the petitions for review for lack of jurisdiction. The stay has been lifted~~these generation assets is not deemed recoverable, it could materially reduce future net income, cash flows and ~~the Sixth Circuit case has been dismissed. Challenges to the rule will proceed in federal district courts.~~impact financial condition.

In March 2017, the Federal EPA published a notice of intent to review the rule and provide an advanced notice of a proposed rulemaking consistent with the Executive Order of the President of the United States directing the Federal EPA and U.S. Army Corps of Engineers to review and rescind or revise the rule. In June 2017, the agencies signed a notice of proposed rule to rescind the definition of “waters of the United States” that was adopted in June 2015, and to re-codify the definition of that phrase as it existed immediately prior to that action. This action would effectively retain the status quo until a new rule is adopted by the agencies. The Federal EPA and U.S. Army Corps of Engineers also finalized a new rule to extend the applicability date of the 2015 rule by two years before the nationwide stay issued by the U.S. Court of Appeals for the Sixth Circuit was lifted. Challenges to the applicability date rule have been filed by third parties in several federal district courts. Management will participate in further rulemaking activities.

RESULTS OF OPERATIONS

~~SEGMENTS~~AEP’s Reportable 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:~~as follows:

•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 SSO 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 returns on equity.~~

Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity.

•Generation & Marketing

~~Competitive generation in ERCOT and PJM.~~

~~Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO.~~

~~Contracted renewable energy investments and management services.~~

The remainder of AEP’s activities isare presented as Corporate and ~~Other. While~~Other, which is 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.segment. See Note 8 - Business Segments for additional information on AEP’s segments.

The following discussion of AEP’s results of operations by operating segment ~~includes an analysis~~provides a comparison of ~~Gross Margin, which is a non-GAAP financial measure. Gross Margin includes Total Revenues less~~Earnings Attributable to AEP Common Shareholders for the ~~costs of Fuel~~three months ended March 31, 2024 as compared to the three months ended March 31, 2023. For AEP’s Vertically Integrated Utilities and ~~Other Consumables Used for Electric Generation as well as Purchased Electricity for Resale~~Transmission and ~~Amortization of Generation Deferrals as presented in~~Distribution Utilities segment and subsidiary registrants within these segments, the ~~Registrants statements of income as applicable. Under~~results include revenues from rate rider mechanisms designed to recover fuel, purchased power and other recoverable expenses such that the ~~various state utility rate making processes,~~revenues and expenses associated with these ~~expenses are~~items generally ~~reimbursable directly from~~offset and ~~billed to customers. As a result, they~~ do not ~~typically impact Operating Income or~~affect Earnings Attributable to AEP Common Shareholders. ~~Management believes that Gross Margin provides a useful measure~~For additional information regarding the financial results for ~~investors~~the three months ended March 31, 2024 and ~~other financial statement users to analyze AEP’s financial performance in that it excludes~~2023 see the ~~effect on Total Revenues caused~~discussions of Results of Operations 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.Subsidiary Registrant.

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



	Three Months Ended March 31,
	2024		2023
	(in millions)
Vertically Integrated Utilities	$	560.8	$	261.0
Transmission and Distribution Utilities	150.3		125.7
AEP Transmission Holdco	208.7		181.5
Generation & Marketing	137.6		(157.7)
Corporate and Other	(54.3)		(13.5)
Earnings Attributable to AEP Common Shareholders	$	1,003.1	$	397.0

Three Months Ended March 31,
2018 2017
(in millions)
Vertically Integrated Utilities $ 231.2
$ 219.5
Transmission and Distribution Utilities 125.4
119.1
AEP Transmission Holdco 104.0
71.8
Generation & Marketing 18.2
186.2
Corporate and Other (24.4 ) (4.4 )
Earnings Attributable to AEP Common Shareholders $ 454.4
$ 592.2


Three Months Ended March 31, 2024
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing
	(in millions)
Revenues	$	2,947.9	$	1,490.2	$	497.3	$	563.5
Fuel, Purchased Electricity and Other	999.1		305.3		—		372.6

Other Operation and Maintenance	885.3		519.2		37.1		31.5



Depreciation and Amortization	453.6		222.5		108.1		8.2
Taxes Other Than Income Taxes	139.7		190.8		75.0		0.2
Operating Income	470.2		252.4		277.1		151.0


Other Income	5.1		0.5		2.4		11.0
Allowance for Equity Funds Used During Construction	11.7		14.1		17.8		—
Non-Service Cost Components of Net Periodic Benefit Cost	25.9		11.1		1.0		5.8
Interest Expense	(157.2)		(96.2)		(56.9)		(6.0)
Income Before Income Tax Expense (Benefit) and Equity Earnings (Loss)	355.7		181.9		241.4		161.8
Income Tax Expense (Benefit)	(206.2)		31.5		54.3		25.1
Equity Earnings (Loss) of Unconsolidated Subsidiary	0.4		(0.1)		22.7		0.9
Net Income	562.3		150.3		209.8		137.6
Net Income Attributable to Noncontrolling Interests	1.5		—		1.1		—
Earnings Attributable to AEP Common Shareholders	$	560.8	$	150.3	$	208.7	$	137.6


Three Months Ended March 31, 2023
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing
	(in millions)
Revenues	$	2,857.8	$	1,464.2	$	455.5	$	327.0
Fuel, Purchased Electricity and Other	976.2		392.7		—		382.3

Other Operation and Maintenance	832.2		491.9		36.7		43.0


Loss on the Sale of the Competitive Contracted Renewable Portfolio	—		—		—		112.0
Depreciation and Amortization	473.5		186.2		97.5		18.2
Taxes Other Than Income Taxes	132.4		178.8		76.8		2.8
Operating Income (Loss)	443.5		214.6		244.5		(231.3)


Other Income	7.2		0.5		1.9		9.0
Allowance for Equity Funds Used During Construction	5.8		9.1		16.4		—
Non-Service Cost Components of Net Periodic Benefit Cost	31.8		14.0		1.6		6.6
Interest Expense	(172.9)		(88.1)		(47.2)		(24.3)
Income (Loss) Before Income Tax Expense (Benefit) and Equity Earnings	315.4		150.1		217.2		(240.0)
Income Tax Expense (Benefit)	53.5		24.4		52.3		(78.1)
Equity Earnings of Unconsolidated Subsidiary	0.3		—		17.5		5.5
Net Income (Loss)	262.2		125.7		182.4		(156.4)
Net Income Attributable to Noncontrolling Interests	1.2		—		0.9		1.3
Earnings (Loss) Attributable to AEP Common Shareholders	$	261.0	$	125.7	$	181.5	$	(157.7)

~~AEP CONSOLIDATED~~

~~First Quarter of 2018 Compared to First Quarter of 2017~~

~~Earnings Attributable to AEP Common Shareholders decreased from $592 million in 2017 to $454 million in 2018 primarily due to:~~

~~A decrease in earnings in the Generation & Marketing segment primarily due to the 2017 gain resulting from the sale of certain merchant generation assets.~~

~~This decrease was partially offset by:~~

~~An increase in transmission investment primarily at AEP Transmission Holdco, which resulted in higher revenues and income.~~

~~An increase in weather-related usage.~~

~~Favorable rate proceedings in AEP’s various jurisdictions.~~

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

VERTICALLY INTEGRATED UTILITIES

Three Months Ended March 31,
Vertically Integrated Utilities 2018 2017
(in millions)
Revenues $ 2,408.0
$ 2,290.4
Fuel and Purchased Electricity 857.8
788.4
Gross Margin 1,550.2
1,502.0
Other Operation and Maintenance 740.0
660.1
Depreciation and Amortization 313.3
278.3
Taxes Other Than Income Taxes 109.9
101.1
Operating Income 387.0
462.5
Interest and Investment Income 2.6
3.1
Carrying Costs Income 2.8
4.1
Allowance for Equity Funds Used During Construction 7.4
6.2
Non-Service Cost Components of Net Periodic Benefit Cost 18.1
5.9
Interest Expense (137.9 ) (134.9 )
Income Before Income Tax Expense and Equity Earnings 280.0
346.9
Income Tax Expense 47.7
127.7
Equity Earnings of Unconsolidated Subsidiaries 0.5
1.3
Net Income 232.8
220.5
Net Income Attributable to Noncontrolling Interests 1.6
1.0
Earnings Attributable to AEP Common Shareholders $ 231.2
$ 219.5

Summary of KWh Energy Sales for Vertically Integrated Utilities



	Three Months Ended March 31,
	2024	2023
	(in millions of KWhs)
Retail:
Residential	8,560	8,099
Commercial	5,769	5,372
Industrial	8,252	8,295
Miscellaneous	538	521
Total Retail	23,119	22,287

Wholesale (a)	3,763	3,260

Total KWhs	26,882	25,547

Three Months Ended March 31,
2018 2017
(in millions of KWhs)
Retail:

Residential 9,572
8,239
Commercial 5,868
5,689
Industrial 8,497
8,264
Miscellaneous 553
536
Total Retail 24,490
22,728

Wholesale (a) 5,738
6,507

Total KWhs 30,228
29,235

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

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

Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities


	Three Months Ended March 31,

	2024	2023
	(in degree days)
Eastern Region
Actual – Heating (a)	1,221	1,131
Normal – Heating (b)	1,605	1,608

Actual – Cooling (c)	1	5
Normal – Cooling (b)	4	4

Western Region
Actual – Heating (a)	738	637
Normal – Heating (b)	876	881

Actual – Cooling (c)	55	58
Normal – Cooling (b)	30	28

(a)Heating degree days are calculated on a 55 degree temperature base.

(b)Normal Heating/Cooling represents the thirty-year average of degree days.

(c)Cooling degree days are calculated on a 65 degree temperature base.

Three Months Ended March 31,
2018 2017
(in degree days)
Eastern Region

Actual – Heating (a)
1,637
1,181
Normal – Heating (b)
1,602
1,615

Actual – Cooling (c)
6
1
Normal – Cooling (b)
5
5

Western Region

Actual – Heating (a)
881
530
Normal – Heating (b)
875
892

Actual – Cooling (c)
36
82
Normal – Cooling (b)
27
24

Reconciliation of First Quarter of 2023 to First Quarter of 2024

~~(a)~~

~~Heating degree days are calculated on a 55 degree temperature base.~~

	Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
~~(b)~~									~~Normal Heating/Cooling represents the thirty-year average of degree days.~~

	(in millions)
~~(c)~~		~~Cooling degree days are calculated on a 65 degree temperature base.~~

First Quarter of 2023			$	261.0

Changes in Revenues:
Retail Revenues			56.2
Off-system Sales			3.7
Transmission Revenues			10.2
Other Revenues			20.0
Total Change in Revenues			90.1

Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation			(22.9)
Other Operation and Maintenance			(53.1)


Depreciation and Amortization			19.9
Taxes Other Than Income Taxes			(7.3)


Other Income			(2.1)
Allowance for Equity Funds Used During Construction			5.9
Non-Service Cost Components of Net Periodic Pension Cost			(5.9)
Interest Expense			15.7
Total Change in Expenses and Other			(49.8)

Income Tax Expense			259.7
Equity Earnings of Unconsolidated Subsidiary			0.1
Net Income Attributable to Noncontrolling Interests			(0.3)

First Quarter of 2024			$	560.8

~~First Quarter of 2018 Compared to First Quarter of 2017~~

Reconciliation of First Quarter of 2017 to First Quarter of 2018
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)

First Quarter of 2017 $ 219.5

Changes in Gross Margin:
Retail Margins 49.5
Off-system Sales 1.0
Transmission Revenues 2.7
Other Revenues (5.0 )
Total Change in Gross Margin 48.2

Changes in Expenses and Other:
Other Operation and Maintenance (79.9 )
Depreciation and Amortization (35.0 )
Taxes Other Than Income Taxes (8.8 )
Interest and Investment Income (0.5 )
Carrying Costs Income (1.3 )
Allowance for Equity Funds Used During Construction 1.2
Non-Service Cost Components of Net Periodic Pension Cost 12.2
Interest Expense (3.0 )
Total Change in Expenses and Other (115.1 )

Income Tax Expense 80.0
Equity Earnings (0.8 )
Net Income Attributable to Noncontrolling Interests (0.6 )

First Quarter of 2018 $ 231.2

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~~Revenues were as follows:

•Retail ~~Margins~~Revenues increased ~~$50~~$56 million primarily due to the following:

~~An $89~~•A $46 million increase in rider revenues at APCo.

•A $24 million increase in weather-related usage primarily in the ~~eastern region.~~residential class driven by an 11% increase in heating degree days.

~~The effect of rate proceedings in AEP’s service territories which included:~~

•A ~~$25~~$19 million increase ~~for I&M from~~in base rate ~~proceedings primarily in Indiana.~~and rider revenues at PSO.

•A ~~$22~~$15 million increase ~~for SWEPCo due to~~in rider ~~and base rate revenue increases in Texas and Louisiana.~~revenues at KPCo.

~~An $11~~•A $5 million increase ~~for APCo primarily due to increases from rate riders~~ in ~~Virginia.~~

~~A $4 million increase for PSO due to new rates implemented in March 2018, inclusive of a $2 million decrease due to the change in the corporate federal tax rate.~~

~~For the rate increases described above, $26 million relate to riders/trackers, which have corresponding increases in expense items below.~~rider revenues at I&M.

These increases were partially offset by:

•A ~~$71~~$45 million decrease in fuel revenues primarily due to decreases at PSO and SWEPCo, partially offset by increases at APCo and I&M.

•A $13 million decrease due to ~~the 2018 provisions~~a regulatory provision for ~~customer refunds~~refund at I&M.

•Transmission Revenues increased $10 million primarily ~~related to Tax Reform. This decrease is offset in Income Tax Expense below.~~due to:

•A ~~$16~~$6 million ~~decrease~~increase primarily due to lower ~~weather-normalized margins, primarily due to SWEPCo and I&M wholesale customer load loss~~PJM rates in 2023 for certain point-to-point transmission service resulting from ~~contracts that expired at the end of 2017.~~a December 2022 FERC approved settlement agreement.

•A $4$3 million ~~decrease primarily~~increase due to increased ~~fuel and other variable production costs not recovered through fuel clauses or other trackers.~~transmission investment.

~~A $4 million decrease for I&M in FERC generation wholesale municipal and cooperative revenues primarily due to changes to the annual formula rate.~~

~~Transmission~~•Other Revenues increased $3$20 million primarily due to ~~an increase~~pole attachment revenue at APCo, increases in ~~transmission investments in SPP.~~associated business development at PSO and SWEPCo and increased affiliated rent revenue at PSO.

~~Other Revenues~~ ~~decreased $5 million primarily due to reduced rates for KPCo Demand Side Management programs beginning in 2018. This decrease is partially offset in Other Operation and Maintenance expense below.~~

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $23 million primarily due to increases at APCo and I&M, partially offset by decreases at PSO and SWEPCo.

•Other Operation and Maintenance expenses increased ~~$80~~$53 million primarily due to:

•A $39 million increase in transmission services.

•A $14 million increase primarily due to a disallowance recorded at SWEPCo on the remaining net book value of the Dolet Hills Power Station as a result of an LPSC approved settlement agreement in April 2024.

•Depreciation and Amortization decreased $20 million primarily due to a $17 million decrease at I&M due to the deferral of Excess ADIT as a result of the PLR received regarding the treatment of stand alone NOLCs and the timing of refunds to customers under rate rider mechanisms.

•Taxes Other Than Income Taxes increased $7 million primarily due to an increase in the Virginia state minimum tax liability at APCo and increased property taxes driven by additional investments and higher tax rates at I&M.

•Allowance for Equity Funds Used During Construction increased $6 millionprimarily due to higher CWIP and AFUDC equity rates.

•Non-Service Cost Components of Net Periodic Pension Cost increased $6 million primarily due to a decrease in the expected return on asset assumption, an increase in loss amortization, changes in prior service credit amortization, partially offset by lower loss amortization resulting from favorable asset returns during 2023 and lower interest costs due to lower interest rates.

•Interest Expense decreased $16 million primarily due to:

•A $49 million decrease due to the recognition of debt carrying charges as a result of the IRS PLR received regarding the treatment of stand alone NOLCs in retail rate making.

This decrease was partially offset by:

•A $17 million increase due to higher long-term debt balances and interest rates.

•A $14 million increase due to a decrease in carrying charges at SWEPCo on storm-related regulatory assets due to a prior year settlement agreement in Louisiana.

•Income Tax Expense decreased $260 million primarily due to the following:

•A ~~$45~~$212 million ~~increase~~decrease due to a reduction in ~~recoverable expenses, primarily fuel support~~Excess ADIT regulatory liabilities at I&M, PSO, and ~~PJM expenses fully recovered~~SWEPCo as a result of the PLR received regarding the treatment of stand alone NOLCs.

•A $32 million decrease due to a reduction in ~~rate recovery riders/trackers in Gross Margins above.~~Excess ADIT regulatory liabilities as a result of the APSC’s denial of SWEPCo’s request to allow the merchant portion of the Turk Plant to serve Arkansas customers.

•A $15 million ~~increase in plant maintenance primarily for I&M, KPCo and SWEPCo.~~

~~A $14 million increase due to the Wind Catcher Project for SWEPCo and PSO.~~

~~A $10 million increase in transmission services primarily in SPP.~~

~~A $9 million increase~~decrease due to an increase in ~~estimated expense for claims related to asbestos exposure.~~PTCs.

~~These increases were partially offset by:~~

~~A $7 million decrease due to an increased Nuclear Electric Insurance Limited distribution in 2018.~~

~~A $6 million decrease in distribution expenses primarily due to distribution system improvements in 2017.~~

~~Depreciation and Amortization~~ ~~expenses increased $35 millionprimarily due to a higher depreciable base.~~

~~Taxes Other Than Income Taxes~~ ~~increased $9 million primarily due to:~~

~~A $4 million increase in state gross receipts tax due to a prior period refund.~~

~~A $3 million increase in property tax driven by an increase in utility plant.~~

~~Non-Service Cost Components of Net Periodic Benefit Cost~~ ~~decreased $12 million~~primarily due to favorable asset returns for the funded Pension and OPEB plans and by moving to a Medicare Advantage arrangement for post-65 retirees in the Non-UMWA OPEB plan. Additionally, the decrease was partially due to the implementation of ASU 2017-07 in 2018, which eliminated AEP’s ability to capitalize a portion of its non-service cost components.

~~Income TaxExpense~~ decreased $80 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, amortization of excess accumulated deferred income taxes associated with certain depreciable property and a decrease in pretax book income.

TRANSMISSION AND DISTRIBUTION UTILITIES

Three Months Ended March 31,
Transmission and Distribution Utilities 2018 2017
(in millions)
Revenues $ 1,162.4
$ 1,086.4
Purchased Electricity 244.6
223.4
Amortization of Generation Deferrals 58.6
60.9
Gross Margin 859.2
802.1
Other Operation and Maintenance 352.7
287.9
Depreciation and Amortization 172.6
156.2
Taxes Other Than Income Taxes 137.4
126.9
Operating Income 196.5
231.1
Interest and Investment Income 1.4
3.5
Carrying Costs Income 0.7
1.9
Allowance for Equity Funds Used During Construction 8.0
4.2
Non-Service Cost Components of Net Periodic Benefit Cost 8.2
2.2
Interest Expense (60.1 ) (60.0 )
Income Before Income Tax Expense 154.7
182.9
Income Tax Expense 29.3
63.8
Net Income 125.4
119.1
Net Income Attributable to Noncontrolling Interests —
—
Earnings Attributable to AEP Common Shareholders $ 125.4
$ 119.1

Summary of KWh Energy Sales for Transmission and Distribution Utilities


	Three Months Ended March 31,


	2024	2023
	(in millions of KWhs)
Retail:
Residential	6,280	6,266
Commercial	7,991	6,744
Industrial	6,812	6,526
Miscellaneous	180	168
Total Retail (a)	21,263	19,704

Wholesale (b)	590	453

Total KWhs	21,853	20,157

Three Months Ended March 31,
2018 2017
(in millions of KWhs)
Retail:

Residential 6,797
5,894
Commercial 5,864
5,753
Industrial 5,514
5,476
Miscellaneous 153
160
Total Retail (a) 18,328
17,283

Wholesale (b) 667
798

Total KWhs 18,995
18,081

(a)Represents energy delivered to distribution customers.

(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold ~~into~~to PJM.

Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities



	Three Months Ended March 31,

	2024	2023
	(in degree days)
Eastern Region
Actual – Heating (a)	1,463	1,344
Normal – Heating (b)	1,871	1,891

Actual – Cooling (c)	—	—
Normal – Cooling (b)	3	3

Western Region
Actual – Heating (a)	161	141
Normal – Heating (b)	195	194

Actual – Cooling (d)	146	271
Normal – Cooling (b)	137	127

Three Months Ended March 31,
2018 2017
(in degree days)
Eastern Region

Actual – Heating (a)
1,884
1,403
Normal – Heating (b)
1,884
1,899

Actual – Cooling (c)
4
3
Normal – Cooling (b)
3
3

Western Region

Actual – Heating (a)
230
102
Normal – Heating (b)
191
195

Actual – Cooling (d)
196
258
Normal – Cooling (b)
119
113

(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.

~~First Quarter of 2018 Compared to First Quarter of 2017~~

Reconciliation of First Quarter of 2017 to First Quarter of 2018
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)

First Quarter of 2017 $ 119.1

Changes in Gross Margin:
Retail Margins 53.8
Off-System Sales 5.5
Transmission Revenues (4.0 )
Other Revenues 1.8
Total Change in Gross Margin 57.1

Changes in Expenses and Other:
Other Operation and Maintenance (64.8 )
Depreciation and Amortization (16.4 )
Taxes Other Than Income Taxes (10.5 )
Interest and Investment Income (2.1 )
Carrying Costs Income (1.2 )
Allowance for Equity Funds Used During Construction 3.8
Non-Service Cost Components of Net Periodic Benefit Cost 6.0
Interest Expense (0.1 )
Total Change in Expenses and Other (85.3 )

Income Tax Expense 34.5

First Quarter of 2018 $ 125.4


Reconciliation of First Quarter of 2023 to First Quarter of 2024
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)


First Quarter of 2023	$	125.7

Changes in Revenues:
Retail Revenues	3.3
Off-system Sales	(3.6)
Transmission Revenues	12.9
Other Revenues	13.4
Total Change in Revenues	26.0

Changes in Expenses and Other:
Purchased Electricity for Resale	134.0
Purchased Electricity from AEP Affiliates	(46.6)
Other Operation and Maintenance	(27.3)
Depreciation and Amortization	(36.3)

Taxes Other Than Income Taxes	(12.0)



Allowance for Equity Funds Used During Construction	5.0
Non-Service Cost Components of Net Periodic Benefit Cost	(2.9)
Interest Expense	(8.1)
Total Change in Expenses and Other	5.8

Income Tax Expense	(7.1)
Equity Earnings of Unconsolidated Subsidiary	(0.1)

First Quarter of 2024	$	150.3

The major components of the increase in ~~Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals~~Revenues were as follows:

•Retail ~~Margins~~Revenues increased ~~$54~~$3 million primarily due to the following:

•A $39 million net increase in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset by a corresponding increase in Other Operation and Maintenance below.

~~A $21~~$105 million increase in ~~Ohio revenues associated with the Universal Service Fund (USF). This increase was offset by a corresponding increase in Other Operation and Maintenance expenses below.~~rider revenues.

•A ~~$10 million increase in Texas weather-related usage primarily driven by a 125% increase in heating degree days partially offset by a 24% decrease in cooling degree days.~~

~~A $10~~$20 million increase in weather-normalized ~~margins,~~revenues primarily in the residential and commercial ~~classes.~~classes in Texas.

•A $9$16 million increase in ~~Texas revenues associated with the Transmission Cost Recovery Factor revenue rider. This increase was partially offset~~weather-related usage driven by ana 9% increase in ~~Other Operation and Maintenance expenses below.~~

~~A $7 million increase~~heating degree days in ~~Texas revenues associated with the Distribution Cost Recovery Factor revenue rider.~~

~~A $6 million increase in Ohio rider revenues associated with the DIR. This increase was partially offset in various expenses below.~~

~~A $4 million net increase in Ohio RSR revenues less associated amortizations.~~Ohio.

These increases were partially offset by:

•A ~~$21~~$122 million decrease due to ~~the 2018 provisions for~~lower customer ~~refunds primarily related to Tax Reform. This decrease is~~participation in OPCo’s SSO, partially offset ~~in Income Tax Expense below.~~by higher prices.

~~An $11~~•A $9 million decrease in ~~Energy Efficiency/Peak Demand Reduction rider~~weather-normalized revenues in ~~Ohio. This decrease was~~the residential and industrial classes, partially offset by ~~a corresponding decrease~~the commercial class in ~~Other Operation and Maintenance expenses below.~~Ohio.

~~A $10~~•An $8 million decrease in ~~margin for the Ohio Phase-In-Recovery Rider including associated amortizations.~~

~~A $7 million~~weather-related usage primarily due to a 46% decrease in ~~Ohio due to the recovery of lower current year losses from a power contract with OVEC. This decrease was offset by a corresponding increase~~cooling degree days in ~~Margins from Off-system Sales below.~~Texas.

~~A $7 million decrease in Ohio revenues associated with smart grid riders. This decrease was partially offset by a corresponding decrease in various expenses below.~~

~~Margins from Off-system Sales~~•Transmission Revenues increased $6$13 million primarily due to ~~lower current year losses from a power contract with OVEC~~interim rate increases driven by increased transmission investments in ~~Ohio which was offset in Retail Margins above as a result of the OVEC PPA rider beginning in January 2017.~~

Texas.

~~Transmission~~•Other Revenues ~~decreased $4~~ increased $13 million primarily due to the following:

~~An $11 million decrease mainly due to the 2018 provisions for customer refunds primarily due to Tax Reform. This decrease is offset in Income Tax Expense below.~~

~~This decrease was partially offset by:~~

•A $7$10 million increase due to third-party Legacy Generation Resource Rider revenue related to the recovery of ~~increased transmission investment~~OVEC costs.

•A $6 million increase in ~~ERCOT.~~refundable sales of renewable energy credits in Ohio.

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

~~Other Operation and Maintenance~~•Purchased Electricity for Resale expenses ~~increased $65~~decreased $134 million primarily due to the following:

•A ~~$44~~$177 million decrease due to lower auction volumes driven by lower customer participation in OPCo’s SSO, partially offset by higher prices.

This decrease was partially offset by:

•A $30 million decrease in deferrals of recoverable OVEC costs.

•Purchased Electricity from AEP Affiliates expenses increased $47 million primarily due to increased purchases in OPCo’s SSO auction.

•Other Operation and Maintenance expenses increased $27 million primarily due to the following:

•A $27 million increase in transmission expenses ~~that were fully recovered~~primarily due to an increase in ~~rate recovery riders/trackers within Gross Margins above.~~recoverable PJM expenses in Ohio.

•A ~~$21~~$16 million increase in ~~remitted USF surcharge payments~~distribution expenses primarily related to ~~the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset by a corresponding increase~~recoverable storm restoration costs and recoverable vegetation management expenses in ~~Retail Margins above.~~Ohio.

These increases were partially offset by:

•A $9$5 million decrease in ~~Ohio Energy Efficiency/Peak Demand Reduction~~distribution-related expenses ~~that were fully recovered~~ in ~~rate recovery riders/trackers within Retail Margins above.~~Texas.

•A $3 million decrease in recoverable transmission expenses in Texas.

•Depreciation and Amortization expenses increased ~~$16~~$36 million primarily due to ~~the following:~~

a higher depreciable base and an increase in recoverable rider depreciable expenses in Ohio.

A•Taxes Other Than Income Taxes increased $12 million primarily due to property taxes as a result of increased transmission and distribution investment and higher tax rates in Ohio.

•Interest Expense increased $8 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense increased $7 million ~~increase in depreciation expense~~primarily due to an increase in ~~depreciable base of transmission and distribution assets.~~

~~A $6 million increase in recoverable DIR depreciation expense in Ohio. This increase was offset in Retail Margins above.~~

~~A $5 million increase due to securitization amortizations related to Texas securitized transition funding. This increase was offset in Other Revenues above and in Interest Expense below.~~

~~Taxes Other Than Income Taxes~~ ~~increased $11 million primarily due to the following:~~

~~A $6 million increase in property taxes due to additional investments in transmission and distribution assets and higher tax rates.~~

~~A $4 million increase in state excise taxes due to an increase in metered KWhs. This increase was offset in Retail Margins above.~~

~~Allowance for Equity Funds Used During Construction~~ ~~increased $4 million due to increased transmission projects in Texas.~~

~~Non-Service Cost Components of Net Periodic Benefit Cost~~ decreased $6 million primarily due to favorable asset returns for the funded Pension and OPEB plans and by moving to a Medicare Advantage arrangement for post-65 retirees in the Non-UMWA OPEB plan. Additionally, the decrease was partially due to the implementation of ASU 2017-07 in 2018, which eliminated AEP’s ability to capitalize a portion of its non-service cost components.

~~Income TaxExpense~~ ~~decreased $35 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and a decrease in~~ pretax book ~~income.~~income in Texas.

AEP TRANSMISSION HOLDCO

Three Months Ended March 31,
AEP Transmission Holdco 2018 2017
(in millions)
Transmission Revenues $ 205.5
$ 156.1
Other Operation and Maintenance 21.9
14.1
Depreciation and Amortization 31.8
24.6
Taxes Other Than Income Taxes 32.7
28.0
Operating Income 119.1
89.4
Interest and Investment Income 0.3
0.2
Allowance for Equity Funds Used During Construction 15.3
10.8
Non-Service Cost Components of Net Periodic Benefit Cost 0.7
0.1
Interest Expense (21.1 ) (17.3 )
Income Before Income Tax Expense and Equity Earnings 114.3
83.2
Income Tax Expense 27.5
36.4
Equity Earnings of Unconsolidated Subsidiaries 18.0
26.0
Net Income 104.8
72.8
Net Income Attributable to Noncontrolling Interests 0.8
1.0
Earnings Attributable to AEP Common Shareholders $ 104.0
$ 71.8

Summary of Investment in Transmission Assets for AEP Transmission Holdco


	March 31,
	2024		2023
	(in millions)
Plant in Service	$	14,740.7	$	13,376.3
Construction Work in Progress	1,980.2		1,959.1
Accumulated Depreciation and Amortization	1,405.8		1,128.2
Total Transmission Property, Net	$	15,315.1	$	14,207.2

As of March 31,
2018 2017
(in millions)
Plant in Service $ 5,912.8
$ 4,476.5
Construction Work in Progress 1,533.7
1,188.8
Accumulated Depreciation and Amortization 200.0
120.6
Total Transmission Property, Net $ 7,246.5
$ 5,544.7


Reconciliation of First Quarter of 2023 to First Quarter of 2024
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)


First Quarter of 2023	$	181.5

Changes in Transmission Revenues:
Transmission Revenues	41.8
Total Change in Transmission Revenues	41.8

Changes in Expenses and Other:
Other Operation and Maintenance	(0.4)
Depreciation and Amortization	(10.6)
Taxes Other Than Income Taxes	1.8
Interest and Investment Income	0.5

Allowance for Equity Funds Used During Construction	1.4
Non-Service Cost Components of Net Periodic Pension Cost	(0.6)
Interest Expense	(9.7)
Total Change in Expenses and Other	(17.6)

Income Tax Expense	(2.0)
Equity Earnings of Unconsolidated Subsidiary	5.2
Net Income Attributable to Noncontrolling Interests	(0.2)

First Quarter of 2024	$	208.7

~~First Quarter of 2018 Compared to First Quarter of 2017~~

~~Reconciliation of First Quarter of 2017 to First Quarter of 2018~~

~~Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco~~

~~(in millions)~~

First Quarter of 2017 $ 71.8

Changes in Transmission Revenues:
Transmission Revenues 49.4
Total Change in Transmission Revenues 49.4

Changes in Expenses and Other:
Other Operation and Maintenance (7.8 )
Depreciation and Amortization (7.2 )
Taxes Other Than Income Taxes (4.7 )
Interest and Investment Income 0.1
Allowance for Equity Funds Used During Construction 4.5
Non-Service Cost Components of Net Periodic Pension Cost 0.6
Interest Expense (3.8 )
Total Change in Expenses and Other (18.3 )

Income Tax Expense 8.9
Equity Earnings of Unconsolidated Subsidiaries (8.0 )
Net Income Attributable to Noncontrolling Interests 0.2

First Quarter of 2018 $ 104.0

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

•Transmission Revenues increased $42 million primarily due to continued investment in transmission assets.

Expenses and Other and Equity Earnings of Unconsolidated Subsidiary changed between years as follows:

•Depreciation and Amortization expenses increased $11 million primarily due to a higher depreciable base.

•Interest Expense increased $10 million primarily due to higher long-term debt balances and interest rates.

•Equity Earnings of Unconsolidated Subsidiary increased $5 million primarily due to higher pretax equity earnings for ETT.

~~Transmission~~

GENERATION & MARKETING


Reconciliation of First Quarter of 2023 to First Quarter of 2024
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)


First Quarter of 2023	$	(157.7)

Changes in Revenues:
Merchant Generation	(5.0)
Renewable Generation	(20.8)
Retail, Trading and Marketing	262.3
Total Change in Revenues	236.5

Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	9.7
Other Operation and Maintenance	11.5

Loss on the Sale of the Competitive Contracted Renewables Portfolio	112.0
Depreciation and Amortization	10.0
Taxes Other Than Income Taxes	2.6
Interest and Investment Income	2.0


Non-Service Cost Components of Net Periodic Benefit Cost	(0.8)
Interest Expense	18.3
Total Change in Expenses and Other	165.3

Income Tax Benefit	(103.2)
Equity Earnings of Unconsolidated Subsidiaries	(4.6)
Net Loss Attributable to Noncontrolling Interests	1.3

First Quarter of 2024	$	137.6

The major components of the increase in Revenues ~~increased $49~~were as follows:

•Merchant Generation decreased $5 million primarily due to lower market prices in 2024.

•Renewable Generation decreased $21 million primarily due to the ~~following:~~

sale of the competitive contracted renewables portfolio in August 2023.

~~Formula rate increases of $68~~•Retail, Trading and Marketing increased $262 million primarily due to a $145 million unrealized loss on economic hedge activity in 2023 and $91 million unrealized hedging gains in 2024 driven by ~~continued investment~~changes in ~~transmission assets.~~commodity prices.

~~This increase was partially offset by:~~

~~A $19 million decrease due to the 2018 provisions for customer refunds primarily related to Tax Reform. This decrease is offset in Income Tax Expense below.~~

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

•Purchased Electricity, Fuel and Other ~~Operation and Maintenance~~ ~~expenses increased $8 million primarily due to increased transmission investment.~~

~~Depreciation and Amortization~~ ~~expenses increased $7 million primarily due to a higher depreciable base.~~

~~Taxes Other Than Income Taxes~~ ~~increased $5 million primarily due to higher property taxes as a result of increased transmission investment.~~

~~Allowance~~Consumables Used for ~~Equity Funds Used During Construction~~ ~~increased $5 million primarily due to increased transmission investment resulting in a higher CWIP balance.~~

~~Interest Expense~~ ~~increased $4 million primarily due to higher outstanding long-term debt balances.~~

~~Income Tax Expense~~ decreased $9 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, partially offset by an increase in pretax book income.

~~Equity Earnings of Unconsolidated Subsidiaries~~ ~~decreased $8 million primarily due to lower earnings at ETT resulting from decreased revenues driven by Tax Reform and by an ETT rate reduction that went into effect in March 2017, increased operating~~Electric Generation expenses decreased ~~AFUDC and increased interest expense.~~

~~GENERATION & MARKETING~~

Three Months Ended March 31,
Generation & Marketing 2018 2017
(in millions)
Revenues $ 505.1
$ 591.4
Fuel, Purchased Electricity and Other 408.8
405.2
Gross Margin 96.3
186.2
Other Operation and Maintenance 67.6
99.8
Gain on Sale of Merchant Generation Assets —
(226.5 )
Depreciation and Amortization 6.9
5.7
Taxes Other Than Income Taxes 3.2
2.0
Operating Income 18.6
305.2
Interest and Investment Income 2.5
2.2
Non-Service Cost Components of Net Periodic Benefit Cost 3.9
2.3
Interest Expense (3.9 ) (6.5 )
Income Before Income Tax Expense 21.1
303.2
Income Tax Expense 3.0
117.0
Net Income 18.1
186.2
Net Loss Attributable to Noncontrolling Interests (0.1 ) —
Earnings Attributable to AEP Common Shareholders $ 18.2
$ 186.2

~~Summary of MWhs Generated for Generation & Marketing~~

Three Months Ended March 31,
2018 2017
(in millions of MWhs)
Fuel Type:

Coal 4
6
Natural Gas —
2
Total MWhs 4
8

~~First Quarter of 2018 Compared to First Quarter of 2017~~

Reconciliation of First Quarter of 2017 to First Quarter of 2018
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)

First Quarter of 2017 $ 186.2

Changes in Gross Margin:
Generation (53.6 )
Retail, Trading and Marketing (37.7 )
Other 1.4
Total Change in Gross Margin (89.9 )

Changes in Expenses and Other:
Other Operation and Maintenance 32.2
Gain on Sale of Merchant Generation Assets (226.5 )
Depreciation and Amortization (1.2 )
Taxes Other Than Income Taxes (1.2 )
Interest and Investment Income 0.3
Non-Service Cost Components of Net Periodic Benefit Cost 1.6
Interest Expense 2.6
Total Change in Expenses and Other (192.2 )

Income Tax Expense 114.0
Net Loss Attributable to Noncontrolling Interests 0.1

First Quarter of 2018 $ 18.2

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:

~~Generation~~ ~~decreased $54 million primarily due to the reduction of revenues associated with the sale of certain merchant generation assets in 2017.~~

~~Retail, Trading and Marketing~~ ~~decreased $38 million primarily due to reduced wholesale trading and marketing revenues, mark-to-market hedge losses and lower retail margins.~~

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

~~Other Operation and Maintenance~~ ~~expenses decreased $32 million primarily due to the following:~~

•~~A $21 million decrease in expenses due to the sale of certain merchant generation assets in 2017.~~

•~~An $11 million decrease in expenses due to an impairment of certain merchant generation assets in 2017.~~

~~Gain on Sale of Merchant Generation Assets~~ ~~decreased $227 million due to the sale of certain merchant generation assets in 2017.~~

~~Income Tax Expense~~ ~~decreased $114~~$10 million primarily due to a reduction in ~~pretax book income~~energy costs in 2024.

•Other Operation and Maintenance expenses decreased $12 million primarily due to the ~~gain on~~ sale of ~~certain merchant generation assets~~the competitive contracted renewables portfolio in ~~2017~~August 2023.

•Loss on the Sale of the Competitive Contracted Renewables Portfolio increased $112 million due to the pretax loss on the sale in 2023.

•Depreciation and Amortization decreased $10 million primarily due to the ~~change~~sale of the competitive contracted renewables portfolio in ~~corporate federal income tax rate~~August 2023.

•Interest Expense decreased $18 million primarily due to lower advances from ~~35%~~affiliates.

•Income Tax Benefit decreased $103 million primarily due to:

•An $83 million decrease due to increased pretax book income.

•A $19 million decrease due to an decrease in ~~2017~~PTCs.

•A $9 million decrease due to ~~21%~~the amortization of deferred ITCs from the sale of the competitive contracted renewables portfolio in ~~2018 as a result~~2023.

These decreases were partially offset by:

•A $12 million increase due to the amortization of ~~Tax Reform.~~deferred ITCs from the sale of NMRD.

•Equity Earnings of Unconsolidated Subsidiaries decreased $5 million primarily due to the sale of the competitive contracted renewables portfolio in August 2023.

CORPORATE AND OTHER

First Quarter of ~~2018~~2024 Compared to First Quarter of ~~2017~~2023

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $4$14 million in ~~2017~~2023 to a loss of ~~$24~~$54 million in ~~2018. The loss~~2024 primarily due to:

•A $23 million decrease in ~~2018 is~~interest income, primarily due to ~~a $20 million impairment of an equity investment and related assets and a $12~~lower advances to affiliates.

•A $14 million increase in interest expense due to higher interest rates and an increase in long-term debt balances.

•A $10 million increase in corporate expenses, primarily due to prior-year adjustments driven by the termination of the sale of the Kentucky operations.

These decreases in earnings were partially offset by a $9$5 million decrease in ~~general corporate expenses.~~Income Tax Expense due to the following:

•A $15 million decrease due to a decrease in pretax book income.

•A $10 million decrease due to an increase in PTCs.

These decreases in Income Tax Expense were partially offset by:

•A $12 million increase due to the impact of the termination of the sale of the Kentucky operations in 2023.

•An $8 million increase due to a decrease in amortization of Excess ADIT.

AEP ~~SYSTEM~~CONSOLIDATED INCOME TAXES

First Quarter of ~~2018~~2024 Compared to First Quarter of ~~2017~~2023

Income Tax Expense decreased ~~$241~~$152 million primarily due to:

•A $224 million decrease due to ~~the change~~a reduction in ~~the corporate federal income tax rate from 35% in 2017 to 21% in 2018~~Excess ADIT regulatory liabilities at I&M, PSO, and SWEPCo as a result of ~~Tax Reform,~~ the ~~amortization~~PLRs received regarding the treatment of ~~excess accumulated deferred income taxes associated with certain depreciable property~~stand alone NOLCs in ~~2018 and~~retail rate making.

•A $32 million decrease due to the reversal of a ~~decrease~~regulatory liability related to the merchant portion of Turk Plant Excess ADIT as a result of the APSC's March 2024 denial of SWEPCo's request to allow the merchant portion of the Turk Plant to serve Arkansas customers.

These decreases were partially offset by:

•A $95 million increase due to an increase in pretax book income.

FINANCIAL CONDITION

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

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization


	March 31, 2024				December 31, 2023
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	39,835.9	57.4	%	$	40,143.2	58.8	%
Short-term Debt	3,737.6		5.4		2,830.2		4.2
Total Debt	43,573.5		62.8		42,973.4		63.0
AEP Common Equity	25,803.3		37.2		25,246.7		37.0
Noncontrolling Interests	40.4		—		39.2		—
Total Debt and Equity Capitalization	$	69,417.2	100.0	%	$	68,259.3	100.0	%

March 31, 2018 December 31, 2017
(dollars in millions)
Long-term Debt, including amounts due within one year $ 21,461.0
50.3 % $ 21,173.3
51.5 %
Short-term Debt 2,658.8
6.2
1,638.6
4.0
Total Debt 24,119.8
56.5
22,811.9
55.5
AEP Common Equity 18,483.3
43.4
18,287.0
44.4
Noncontrolling Interests 28.3
0.1
26.6
0.1
Total Debt and Equity Capitalization $ 42,631.4
100.0 % $ 41,125.5
100.0 %

AEP’s ratio of debt-to-total capital ~~increased~~decreased slightly from ~~55.5%~~63.0% to 62.8% as of December 31, ~~2017 to 56.5% as of~~2023 and March 31, ~~2018~~2024, respectively, primarily due to an increase in ~~short-term~~earnings in 2024, partially offset by an increase in debt ~~due~~ to ~~increasing construction expenditures for~~support distribution, transmission and ~~transmission investments.~~renewable investment growth in addition to working capital needs.

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.~~liquidity. As of March 31, ~~2018,~~2024, AEP had ~~a $3~~$6 billion of revolving credit ~~facility commitment~~facilities to support its ~~operations.~~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, ~~sale-leaseback or~~ leasing agreements, hybrid securities or common stock. AEP and its utilities finance its operations with commercial paper and other variable rate instruments that are subject to fluctuations in interest rates. To the extent that there is an increase in interest rates, it could reduce future net income and cash flows and impact financial condition.

Market volatility and reduced liquidity in the financial markets could affect AEP’s ability to raise capital on reasonable terms to fund capital needs, including construction costs and refinancing maturing indebtedness. AEP is also monitoring the current bank environment and any impacts thereof. AEP was not materially impacted by these conditions during the three months ended March 31, 2024.

~~Commercial Paper Credit Facilities~~AEP continues to address the cash flow implications of increased fuel and purchased power costs, see “Deferred Fuel Costs” section of Executive Overview for additional information.

Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments. As of March 31, ~~2018,~~2024, available liquidity was approximately ~~$1.3~~$3.4 billion as illustrated in the table below:

Amount

Maturity (a)

Commercial Paper Backup:

(in millions)

Revolving Credit Facility

5,000.0

March 2029

Revolving Credit Facility

1,000.0

March 2027

Cash and Cash Equivalents

230.7

Total Liquidity Sources

6,230.7

Less:

AEP Commercial Paper Outstanding

2,832.2

Net Available Liquidity

3,398.5

(a)In March 2024, AEP increased its $4 billion Revolving Credit Facility to $5 billion and extended the maturity date from March 2027 to March 2029. Also, in March 2024, AEP extended the maturity date of its $1 billion Revolving Credit Facility from March 2025 to March 2027.

Amount Maturity
(in millions)
Commercial Paper Backup:

Revolving Credit Facility $ 3,000.0
June 2021
Cash and Cash Equivalents 183.4

Total Liquidity Sources 3,183.4

Less: AEP Commercial Paper Outstanding 1,886.2

Net Available Liquidity $ 1,297.2

AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program ~~is used to fund both~~funds a Utility Money Pool, which funds ~~the~~AEP’s utility ~~subsidiaries, and~~subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility ~~subsidiaries. In addition, the program also funds, as direct borrowers,~~subsidiaries; and the short-term debt requirements of ~~other~~ subsidiaries that are not ~~participants~~participating in either money pool for regulatory or operational ~~reasons.~~reasons, as direct borrowers. The maximum amount of commercial paper outstanding during the first three months of ~~2018~~2024 was ~~$2.2~~$2.9 billion. The weighted-average interest rate for AEP’s commercial paper during ~~2018~~2024 was ~~2.07%~~5.62%.

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 ~~four~~six uncommitted facilities totaling ~~$305 million. In March 2018, one of the uncommitted credit facilities was reduced by $40~~$450 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of March 31, ~~2018~~2024 was ~~$81~~$247 millionwith maturities ranging from ~~May 2018~~April 2024 to March ~~2019.~~2025.

Securitized Accounts Receivables

~~AEP’s~~AEP Credit’s receivables securitization agreement provides a commitment of ~~$750~~$900 million from bank conduits to purchase receivables and expires in ~~June 2019.~~September 2025. As of March 31, 2024, the affiliated utility subsidiaries were in compliance with all requirements under the agreement.

Debt Covenants and Borrowing Limitations

AEP’s credit agreements contain certain covenants and require it to maintain a percentage of ~~debt to total~~debt-to-total capitalization at a level that does not exceed 67.5%. The method for calculating outstanding debt and capitalization is ~~contractually defined~~contractually-defined in AEP’s credit agreements. Debt as defined in the revolving credit ~~agreements~~agreement excludes securitization bonds and debt of AEP Credit. As of March 31, ~~2018~~,2024,this contractually-defined percentage was ~~54.8%~~60.2%. ~~Nonperformance~~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~~$100 million, would cause an event of default under these credit agreements. This condition also applies, at the more restrictive level of $50 million of debt outstanding, in a majority of AEP’s ~~non-exchange traded~~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~~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.

ATM Program

AEP participates in an ATM offering program that allows AEP to issue, from time to time, up to an aggregate of $1.7 billion of its common stock, including shares of common stock that may be sold pursuant to an equity forward sales agreement. There were no issuances under the ATM program for the three months ended March 31, 2024. As of March 31, 2024, approximately $1.7 billion of equity is available for issuance under the ATM offering program. See Note 12 - Financing Activities for additional information.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of ~~$0.62~~$0.88 per share in April ~~2018.~~2024. 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.

CASH FLOW

AEP relies primarily on cash flows from operations, debt issuances and its existing cash and cash equivalents to fund its liquidity and investing activities. AEP’s investing and capital requirements are primarily capital expenditures, repaying of long-term debt and paying dividends to shareholders. AEP uses short-term debt, including commercial paper, as a bridge to long-term debt financing. The levels of borrowing may vary significantly due to the timing of long-term debt financings and the impact of fluctuations in cash flows.


	Three Months Ended March 31,
	2024		2023
	(in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	$	379.0	$	556.5
Net Cash Flows from Operating Activities	1,442.2		717.8
Net Cash Flows Used for Investing Activities	(1,669.3)		(2,245.2)
Net Cash Flows from Financing Activities	129.9		1,364.4

Net Decrease in Cash and Cash Equivalents	(97.2)		(163.0)
Cash, Cash Equivalents and Restricted Cash at End of Period	$	281.8	$	393.5

Three Months Ended
March 31,
2018 2017
(in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period $ 412.6
$ 403.5
Net Cash Flows from Operating Activities 802.2
806.8
Net Cash Flows from (Used for) Investing Activities (1,927.8 ) 776.2
Net Cash Flows from (Used for) Financing Activities 1,029.5
(1,687.1 )
Net Decrease in Cash, Cash Equivalents and Restricted Cash (96.1 ) (104.1 )
Cash, Cash Equivalents and Restricted Cash at End of Period $ 316.5
$ 299.4

Operating Activities


	Three Months Ended March 31,
	2024		2023
	(in millions)
Net Income	$	1,005.7	$	400.4
Non-Cash Adjustments to Net Income (a)	630.2		924.2
Mark-to-Market of Risk Management Contracts	40.9		(82.0)

Property Taxes	(89.2)		(101.6)
Deferred Fuel Over/Under-Recovery, Net	43.4		128.0


Change in Other Noncurrent Assets	(74.5)		(96.0)
Change in Other Noncurrent Liabilities	61.8		(58.7)
Change in Certain Components of Working Capital	(176.1)		(396.5)
Net Cash Flows from Operating Activities	$	1,442.2	$	717.8

Three Months Ended
March 31,
2018 2017
(in millions)
Net Income $ 456.7
$ 594.2
Non-Cash Adjustments to Net Income (a) 623.7
405.5
Mark-to-Market of Risk Management Contracts (0.7 ) 6.0
Property Taxes (63.7 ) (44.4 )
Deferred Fuel Over/Under Recovery, Net (61.2 ) 19.3
Recovery of Ohio Capacity Costs, Net 18.0
30.2
Provision for Refund - Global Settlement, Net (5.4 ) —
Change in Other Noncurrent Assets (59.8 ) (99.1 )
Change in Other Noncurrent Liabilities 133.3
45.0
Change in Certain Components of Working Capital (238.7 ) (149.9 )
Net Cash Flows from Operating Activities $ 802.2
$ 806.8


~~(a)~~	Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Deferred Income Taxes, Allowance for Equity Funds Used During Construction, Amortization of Nuclear Fuel and Gain on Sale of Merchant Generation Assets.

(a)Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Deferred Income Taxes, Loss on the Sale of the Competitive Contracted Renewables Portfolio and AFUDC.

Net Cash Flows from Operating Activities ~~decreased~~ increased by $5$724 million primarily due to the following:

An $89 million decrease in cash from Changes in Certain Components of Working Capital. This decrease is primarily due to changes in accrued federal taxes and timing of receivables and payables, partially offset by lower employee-related payments.

~~An $81 million decrease in cash from Deferred Fuel Over/Under Recovery, Net, primarily due to fluctuations of fuel and purchase power costs at APCo.~~

~~These decreases in cash were partially offset by:~~

~~An $88 million increase in Change in Other Noncurrent Liabilities primarily due to increased Accumulated Provisions for Rate Refunds as a result of Tax Reform.~~

~~An $81~~•A $311 million increase in cash from Net Income, after non-cash adjustments. See Results of Operations for ~~additional information.~~further detail.

~~Investing Activities~~

Three Months Ended
March 31,
2018 2017
(in millions)
Construction Expenditures $ (1,905.8 ) $ (1,365.8 )
Acquisitions of Nuclear Fuel (23.8 ) (3.7 )
Proceeds from Sale of Merchant Generation Assets —
2,159.6
Other 1.8
(13.9 )
Net Cash Flows from (Used for) Investing Activities $ (1,927.8 ) $ 776.2

~~Net Cash Flows~~•A $220 million increase in cash from ~~(Used for) Investing Activities~~ ~~decreased by $2.7 billion~~the Change in Certain Components of Working Capital. The increase is primarily due to the ~~following:~~

~~A $2.2 billion decrease~~timing of accounts payable, decreases in ~~cash due to~~fuel, material and supplies driven by coal inventory on hand and proceeds received from the sale of ~~certain merchant generation~~transferable tax credits. These increases were partially offset by the timing of accounts receivable collections.

•A $142 million increase in cash from Changes in Other Noncurrent Assets and Liabilities. This increase is primarily due to changes in regulatory assets and liabilities driven by timing differences between collections from and refunds to customers under rate rider mechanisms.

•A $123 million increase primarily due to an increase in ~~2017. See Note 6 - Dispositions and Impairments for additional information.~~collateral held associated with risk management contracts driven by a change in commodity prices.

~~A $540~~These increases in cash were partially offset by:

•An $85 million decrease in cash ~~due to increased construction expenditures,~~ primarily due to ~~increases~~the timing of fuel and purchase power revenues and expenses.

Investing Activities


	Three Months Ended March 31,
	2024		2023
	(in millions)
Construction Expenditures	$	(1,761.7)	$	(2,090.1)
Acquisitions of Nuclear Fuel	(33.7)		(1.7)
Acquisitions of Renewable Energy Facilities	—		(145.7)

Proceeds from Sale of Equity Method Investment	114.0		—
Other	12.1		(7.7)
Net Cash Flows Used for Investing Activities	$	(1,669.3)	$	(2,245.2)

Net Cash Flows Used for Investing Activities decreased by $576 million primarily due to the following:

•A $328 million decrease in Construction Expenditures, primarily due to decreases in Transmission and Distribution Utilities of ~~$343~~$140 million, ~~and~~ AEP Transmission Holdco of ~~$168~~$76 million and Vertically Integrated Utilities of $74 million.

•A $146 million decrease due to the 2023 acquisition of the Rock Falls Wind Facility. See “Rock Falls Wind Facility” section of Note 6 for additional information.

•A $114 million increase in Proceeds from Sale of Equity Method Investment. See “Disposition of NMRD” section of Note 6 for additional information.

Financing Activities


	Three Months Ended March 31,
	2024		2023
	(in millions)
Issuance of Common Stock	$	40.6	$	41.1
Issuance/Retirement of Debt, Net	605.1		1,837.7

Dividends Paid on Common Stock	(466.9)		(431.8)
Other	(48.9)		(82.6)
Net Cash Flows from Financing Activities	$	129.9	$	1,364.4

Three Months Ended
March 31,
2018 2017
(in millions)
Issuance of Common Stock, Net $ 32.2
$ —
Issuance/Retirement of Debt, Net 1,317.2
(1,336.4 )
Dividends Paid on Common Stock (306.1 ) (291.4 )
Other (13.8 ) (59.3 )
Net Cash Flows from (Used for) Financing Activities $ 1,029.5
$ (1,687.1 )

Net Cash Flows from ~~(Used for)~~ Financing Activities ~~increased~~ decreased by ~~$2.7~~$1.2 billion primarily due to the following:

•A ~~$1.2~~$2 billion ~~increase~~decrease in ~~cash from short-term debt primarily due to increased borrowings of commercial paper. See Note 12 - Financing Activities for additional information.~~

~~A $758 million increase in cash due to increased~~ issuances of long-term debt. See Note 12 - Financing Activities for additional information.

•A ~~$698~~$643 million increase in ~~cash due to decreased~~ retirements of long-term debt. See Note 12 - Financing Activities for additional information.

~~A $32 million increase in cash due to increased proceeds from issuances of common stock.~~

These ~~increases~~decreases in cash were partially offset by:

•A ~~$15 million decrease~~$1.4 billion increase due to ~~increased common stock dividend~~changes in short-term debt. See Note 12 - Financing Activities for additional information.

See the “Long-term Debt Subsequent Events” section of Note 12 for Long-term debt and other securities issued, retired and principal payments ~~primarily due~~made after March 31, 2024 through April 30, 2024, the date that the first quarter 10-Q was filed.

BUDGETED CAPITAL EXPENDITURES

Management forecasts approximately $7.5 billion of capital expenditures in 2024. For the four year period, 2025 through 2028, management forecasts capital expenditures of $35 billion. The expenditures are generally for transmission, generation, distribution, regulated renewables and required environmental investment to ~~increased dividends per share~~comply with the Federal EPA rules. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, supply chain issues, weather, legal reviews, inflation and the ability to access capital. Management expects to fund these capital expenditures through cash flows from ~~2017~~operations, proceeds from the strategic sale of assets and financing activities. Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to ~~2018.~~

~~In April 2018, AEP Texas retired $30 million of 5.89% Senior Unsecured Notes due in 2018.~~

~~In April 2018, I&M retired $2 million of Notes Payable related to DCC Fuel.~~

~~OFF-BALANCE SHEET ARRANGEMENTS~~

AEP’s current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements that AEP enters in the normal course of business. The following identifies significant off-balance sheet arrangements:

March 31,
2018 December 31,
2017
(in millions)
Rockport Plant, Unit 2 Future Minimum Lease Payments $ 738.4
$ 738.4
Railcars Maximum Potential Loss from Lease Agreement 15.4
17.9

fund these expenditures until long-term funding is arranged. For complete information ~~on each~~ of ~~these off-balance sheet arrangements,~~forecasted capital expenditures, see ~~the “Off-balance Sheet Arrangements”~~“Budgeted Capital Expenditures” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the ~~2017~~2023 Annual Report.

~~CONTRACTUAL OBLIGATION INFORMATION~~SIGNIFICANT CASH REQUIREMENTS

A summary of ~~contractual obligations~~significant cash requirements is included in the ~~2017~~2023 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.

~~CYBER SECURITY~~

The electric utility industry is an identified critical infrastructure function with mandatory cyber security requirements under the authority of FERC. The North American Electric Reliability Corporation (NERC), which FERC certified as the nation’s Electric Reliability Organization, developed mandatory critical infrastructure protection cyber security reliability standards. AEP began participating in the NERC grid security and emergency response exercises, GridEx,

in 2013 and continues to participate in the bi-yearly exercises. These efforts, led by NERC, test and further develop the coordination, threat sharing and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid. In 2014, the U.S. Department of Energy published an Energy Sector Cyber Security Framework Implementation Guide for utilities to use in adopting and implementing the National Institute of Standards and Technology framework. AEP continues to be actively engaged in the framework process. In addition to these enterprise-wide initiatives, the operations of AEP’s electric utility subsidiaries are subject to extensive and rigorous mandatory cyber security requirements that are developed and enforced by NERC to protect grid security and reliability.

Critical cyber assets, such as data centers, power plants, transmission operations centers and business networks are protected using multiple layers of cyber security and authentication. Cyber hackers have been successful in breaching a number of very secure facilities, including federal agencies, banks and retailers. As these events become known and develop, AEP continually assesses its cyber security tools and processes to determine where to strengthen its defenses.

AEP has undertaken a variety of actions to monitor and address cyber-related risks. Cyber security and the effectiveness of AEP’s cyber security processes are discussed at Board and Audit Committee meetings. AEP’s strategy for managing cyber-related risks is integrated within its enterprise risk management processes.

AEP’s Chief Security Officer (CSO) leads the cyber security and physical security teams and is responsible for the design, implementation, and execution of AEP’s security risk management strategy, including cyber security. AEP operates a Cyber Security Intelligence and Response Center (cyber security team) responsible for monitoring the AEP System for cyber threats. Among other things, the CSO and the cyber security team actively monitor best practices, perform penetration testing, lead response exercises and internal campaigns, and provide training and communication across the organization.

The cyber security team constantly scans the AEP System for risks and threats. It also continually reviews its business continuity plan to develop an effective recovery strategy that seeks to decrease response times, limit financial impacts and maintain customer confidence during any business interruption. The cyber security team works closely with a broad range of departments, including legal, regulatory, corporate communications and audit services and information technology.

The cyber security team collaborates with partners from both industry and government, and routinely participates in industry-wide programs that exchange knowledge of threats with utility peers, industry and federal agencies. AEP is a member of a number of industry specific threat and information sharing communities including the Department of Homeland Security and the Electricity Information Sharing and Analysis Center.

AEP has partnered in the past with a major defense contractor with significant cyber security experience and technical capabilities developed through their work with the U.S. Department of Defense. AEP continues to work with a nonaffiliated entity to conduct several discussions each year about recognizing and investigating cyber vulnerabilities.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING ~~PRONOUNCEMENTS~~STANDARDS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

See the “Critical Accounting Policies and Estimates” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the ~~2017~~2023 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting ~~pronouncements.~~standards and SEC rulemaking activity.

ACCOUNTING ~~PRONOUNCEMENTS~~STANDARDS

See Note 2 - New Accounting ~~Pronouncements~~Standards for information related to accounting ~~pronouncements adopted in 2018~~standards and ~~pronouncements effective in the future.~~SEC rulemaking activity.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

The Vertically Integrated Utilities segment is exposed to certain market risks as a major power producer and through transactions in power, coal, natural gas and marketing contracts. These risks include commodity price risks which may be subject to capacity risk, credit risk as well as interest rate risk. ~~In addition, this segment is exposed to foreign currency exchange risk from occasionally procuring various services and materials used in its energy business from foreign suppliers.~~ These risks represent the risk of loss that may impact this segment due to changes in the underlying market prices or rates.

The Transmission and Distribution Utilities segment is exposed to energy procurement risk and interest rate risk.

The Generation & Marketing segment conducts marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. This segment is exposed to certain market risks as a marketer of wholesale and retail electricity. These risks include commodity price risks which may be subject to capacity risk, credit risk as well as interest rate risk. These risks represent the risk of loss that may impact this segment due to changes in the underlying market prices or rates. In addition, the Generation & Marketing segment is also exposed to certain market risks as a ~~major~~ power producer and through transactions in wholesale electricity, natural gas and marketing contracts.

Management employs risk management contracts including physical forward and financial forward purchase-and-sale contracts. Management engages in risk management of power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. As a result, AEP is subject to price risk. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the ~~Commercial Operations~~Regulated Risk Committee ~~(Regulated Risk Committee)~~ and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Financial Officer, Chief Commercial Officer, Executive Vice

President ~~of Generation,~~Utilities, Executive Vice President Grid Solutions & Government Affairs, Senior Vice President of Regulated Commercial Operations, Senior Vice President of Treasury and Risk and Chief Risk Officer. The Competitive

Risk Committee consists of AEPSC’s Chief Financial Officer, Chief Commercial Officer, Senior Vice President of Treasury and Risk, Senior Vice President of Competitive Commercial Operations and Chief Risk ~~Officer in addition to Energy Supply’s~~

~~President and Vice President.~~Officer. When commercial activities exceed predetermined limits, positions are modified to reduce the risk to be within the limits unless specifically approved by the respective committee.

The following table summarizes the reasons for changes in total MTM value as compared to December 31, ~~2017:~~2023:


MTM Derivative Contract Net Assets (Liabilities)

Three Months Ended March 31, 2024

	Vertically Integrated Utilities		Transmission and Distribution Utilities		Generation & Marketing		Total
	(in millions)
Total MTM Risk Management Contracts - Commodity Net Assets (Liabilities) as of December 31, 2023	$	16.9	$	(51.0)	$	92.4	$	58.3
(Gain)/Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period	(26.9)		2.3		39.1		14.5
Fair Value of New Contracts at Inception When Entered During the Period (a)	—		—		1.3		1.3

Changes in Fair Value Due to Market Fluctuations During the Period (b)	(25.8)		—		23.1		(2.7)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)	(5.1)		8.0		—		2.9
Total MTM Risk Management Contracts - Commodity Net Assets (Liabilities) as of March 31, 2024	$	(40.9)	$	(40.7)	$	155.9	74.3
Commodity Cash Flow Hedge Contracts							110.7
Interest Rate Cash Flow Hedge Contracts							6.6
Fair Value Hedge Contracts							(114.8)
Collateral Deposits							(73.6)

Total MTM Derivative Contract Net Assets as of March 31, 2024							$	3.2

MTM Risk Management Contract Net Assets (Liabilities)
Three Months Ended March 31, 2018

Vertically
Integrated
Utilities

Transmission
and
Distribution
Utilities

Generation
&
Marketing
Total
(in millions)
Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2017 $ 42.1
$ (131.3 ) $ 163.9
$ 74.7
Gain from Contracts Realized/Settled During the Period and Entered in a Prior Period (30.5 ) (1.1 ) (9.2 ) (40.8 )
Fair Value of New Contracts at Inception When Entered During the Period (a) —
—
6.1
6.1
Changes in Fair Value Due to Market Fluctuations During the Period (b) —
—
(22.4 ) (22.4 )
Changes in Fair Value Allocated to Regulated Jurisdictions (c) 5.8
34.8
—
40.6
Total MTM Risk Management Contract Net Assets (Liabilities) as of March 31, 2018 $ 17.4
$ (97.6 ) $ 138.4
58.2
Commodity Cash Flow Hedge Contracts

(33.4 )
Fair Value Hedge Contracts

(20.6 )
Collateral Deposits

16.8
Total MTM Derivative Contract Net Assets as of March 31, 2018

$ 21.0
(a)Reflects fair value on primarily auctions or long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location and delivery term. A significant portion of the total volumetric position has been economically hedged.

(b)Market fluctuations are attributable to various factors such as supply/demand, weather, etc.


~~(a)~~	Reflects fair value on primarily long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location and delivery term. A significant portion of the total volumetric position has been economically hedged.


~~(b)~~	~~Market fluctuations are attributable to various factors such as supply/demand, weather, etc.~~


~~(c)~~	~~Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable.~~

(c)Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable on the balance sheet.

See Note 9 – Derivatives and Hedging and Note 10 – Fair Value Measurements for additional information related to risk management contracts. The following tables and discussion provide information on credit risk and market volatility risk.

Credit Risk

Credit risk is mitigated in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses ~~Moody’s Investors Service Inc., S&P Global Inc.~~credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

AEP has risk management contracts (includes non-derivative contracts) with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, exposures change daily. As of March 31, ~~2018,~~2024, credit exposure net of collateral to sub investment grade counterparties was approximately 7%7.7%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).

As of March 31, ~~2018,~~2024, the following table approximates AEP’s counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:


Counterparty Credit Quality	Exposure Before Credit Collateral		Credit Collateral		Net Exposure		Number of Counterparties >10% of Net Exposure	Net Exposure of Counterparties >10%
	(in millions, except number of counterparties)
Investment Grade	$	595.2	$	86.4	$	508.8	3	$	278.9
Split Rating	17.8		—		17.8		1	17.8

No External Ratings:
Internal Investment Grade	21.0		—		21.0		3	13.2
Internal Noninvestment Grade	102.2		56.4		45.8		2	40.5
Total as of March 31, 2024	$	736.2	$	142.8	$	593.4

All exposure in the table above relates to AEPSC and AEPEP as AEPSC is agent for and transacts on behalf of certain AEP subsidiaries, including the Registrant Subsidiaries and AEPEP is agent for and transacts on behalf of other AEP subsidiaries.

Counterparty Credit Quality
Exposure
Before
Credit
Collateral

Credit
Collateral

Net
Exposure
Number of
Counterparties
>10% of
Net Exposure
Net Exposure
of
Counterparties
>10%
(in millions, except number of counterparties)
Investment Grade $ 502.5
$ —
$ 502.5
3
$ 273.6
Split Rating 3.5
—
3.5
1
3.5
Noninvestment Grade 0.8
0.8
—
—
—
No External Ratings:

Internal Investment Grade 114.7
—
114.7
3
72.3
Internal Noninvestment Grade 57.3
10.5
46.8
2
30.6
Total as of March 31, 2018 $ 678.8
$ 11.3
$ 667.5

In addition, AEP is exposed to credit risk related to participation in RTOs. For each of the RTOs in which AEP participates, this risk is generally determined based on the proportionate share of member gross activity over a specified period of time.

Value at Risk (VaR) Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates VaR, to measure AEP’s commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, as of March 31, ~~2018,~~2024, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition.

Management calculates the VaR for both a trading and non-trading portfolio. The trading portfolio consists primarily of contracts related to energy trading and marketing activities. The non-trading portfolio consists primarily of economic hedges of generation and retail supply activities.

The following tables show the end, high, average and low market risk as measured by VaR for the periods indicated:

VaR Model

Trading Portfolio


Three Months Ended								Twelve Months Ended
March 31, 2024								December 31, 2023
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	0.2	$	1.7	$	0.4	$	0.1	$	0.2	$	0.9	$	0.2	$	0.1

Three Months Ended Twelve Months Ended
March 31, 2018 December 31, 2017
End High Average Low End High Average Low
(in millions) (in millions)
$ 0.2
$ 1.8
$ 0.4
$ 0.1
$ 0.2
$ 0.5
$ 0.2
$ 0.1

VaR Model

Non-Trading Portfolio


Three Months Ended								Twelve Months Ended
March 31, 2024								December 31, 2023
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	14.6	$	98.6	$	25.0	$	11.9	$	17.7	$	32.7	$	16.4	$	6.1

Three Months Ended Twelve Months Ended
March 31, 2018 December 31, 2017
End High Average Low End High Average Low
(in millions) (in millions)
$ 1.4
$ 6.9
$ 2.8
$ 1.0
$ 4.1
$ 6.5
$ 1.0
$ 0.3

Management back-tests VaR results against performance due to actual price movements. Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.

As the VaR calculation captures recent price movements, management also performs regular stress testing of the trading portfolio to understand AEP’s exposure to extreme price movements. A historical-based method is employed whereby

the current trading portfolio is subjected to actual, observed price movements from the last several years in order to ascertain which historical price movements translated into the largest potential MTM loss. Management then researches the underlying positions, price movements and market events that created the most significant exposure and reports the findings to the Risk Executive Committee, Regulated Risk Committee or Competitive Risk Committee as appropriate.

Interest Rate Risk

AEP is exposed to interest rate market fluctuations in the normal course of business operations. Prior to 2022, interest rates remained at low levels and the Federal Reserve maintained the federal funds target range at 0.0% to 0.25% for much of 2021. During 2022 and 2023, the Federal Reserve approved 11 rate increases for a cumulative total of 5.25% increase. AEP has outstanding ~~short-~~short and long-term debt which is subject to a variable ~~rate.~~rates. AEP manages interest rate risk by limiting variable-rate exposures to a percentage of total debt, by entering into interest rate derivative instruments and by monitoring the effects of market changes in interest rates. For the three months ended March 31, ~~2018~~2024 and ~~2017,~~2023, a 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact ~~pre-tax~~pretax interest expense annually by ~~$25~~$40 million and ~~$35~~$43 million, respectively.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions, except per-share and share amounts)

(Unaudited)



	Three Months Ended March 31,

	2024		2023
REVENUES
Vertically Integrated Utilities	$	2,901.2	$	2,816.3
Transmission and Distribution Utilities	1,483.2		1,455.3
Generation & Marketing	515.9		326.9
Other Revenues	125.4		92.4
TOTAL REVENUES	5,025.7		4,690.9

EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	1,575.8		1,706.4

Other Operation	762.3		680.0
Maintenance	317.5		317.3

Loss on the Sale of the Competitive Contracted Renewables Portfolio	—		112.0



Depreciation and Amortization	787.1		775.5
Taxes Other Than Income Taxes	410.4		394.9
TOTAL EXPENSES	3,853.1		3,986.1

OPERATING INCOME	1,172.6		704.8

Other Income (Expense):


Other Income	13.6		14.7
Allowance for Equity Funds Used During Construction	43.6		31.3
Non-Service Cost Components of Net Periodic Benefit Cost	45.1		55.5

Interest Expense	(435.6)		(415.7)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS	839.3		390.6

Income Tax Expense (Benefit)	(141.9)		10.4
Equity Earnings of Unconsolidated Subsidiaries	24.5		20.2





NET INCOME	1,005.7		400.4

Net Income Attributable to Noncontrolling Interests	2.6		3.4

EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	1,003.1	$	397.0

WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING	526,552,036		514,176,648



TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	1.91	$	0.77

WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING	527,596,395		515,598,090



TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	1.90	$	0.77



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Three Months Ended March 31,
2018 2017
REVENUES
Vertically Integrated Utilities $ 2,381.5
$ 2,269.8
Transmission and Distribution Utilities 1,141.2
1,066.4
Generation & Marketing 477.5
558.8
Other Revenues 48.1
38.3
TOTAL REVENUES 4,048.3
3,933.3

EXPENSES

Fuel and Other Consumables Used for Electric Generation 501.8
635.6
Purchased Electricity for Resale 990.3
769.6
Other Operation 726.4
623.7
Maintenance 298.5
303.5
Gain on Sale of Merchant Generation Assets —
(226.5 )
Depreciation and Amortization 539.7
481.9
Taxes Other Than Income Taxes 285.6
259.8
TOTAL EXPENSES 3,342.3
2,847.6

OPERATING INCOME 706.0
1,085.7

Other Income (Expense):

Interest and Investment Income 2.1
8.0
Carrying Costs Income 3.4
5.9
Allowance for Equity Funds Used During Construction 30.7
21.2
Non-Service Cost Components of Net Periodic Benefit Cost 32.0
11.4
Interest Expense (234.0 ) (221.8 )

INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS 540.2
910.4

Income Tax Expense 102.0
343.2
Equity Earnings of Unconsolidated Subsidiaries 18.5
27.0

NET INCOME 456.7
594.2

Net Income Attributable to Noncontrolling Interests 2.3
2.0

EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $ 454.4
$ 592.2

WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING 492,267,402
491,712,042

TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $ 0.92
$ 1.20

WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING 493,127,300
492,031,975

TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $ 0.92
$ 1.20

CASH DIVIDENDS DECLARED PER SHARE $ 0.62
$ 0.59



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)



	Three Months Ended March 31,
		2024		2023
Net Income		$	1,005.7	$	400.4

OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $(1.6) and $(40.5) in 2024 and 2023, Respectively		(6.2)		(152.4)

Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.2) and $(4.3) in 2024 and 2023, Respectively		(0.6)		(16.1)
Reclassifications of KPCo Pension and OPEB Regulatory Assets, Net of Tax of $0 and $4.4 in 2024 and 2023, Respectively		—		16.7

TOTAL OTHER COMPREHENSIVE LOSS		(6.8)		(151.8)

TOTAL COMPREHENSIVE INCOME		998.9		248.6

Total Comprehensive Income Attributable To Noncontrolling Interests		2.6		3.4

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS		$	996.3	$	245.2

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Three Months Ended March 31,
2018 2017
Net Income $ 456.7
$ 594.2

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES

Cash Flow Hedges, Net of Tax of $0.7 and $(8.7) in 2018 and 2017, Respectively 2.7
(16.1 )
Securities Available for Sale, Net of Tax of $0 and $0.6 in 2018 and 2017, Respectively —
1.2
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.4) and $0.1 in 2018 and 2017, Respectively (1.4 ) 0.2

TOTAL OTHER COMPREHENSIVE INCOME (LOSS) 1.3
(14.7 )

TOTAL COMPREHENSIVE INCOME 458.0
579.5

Total Comprehensive Income Attributable to Noncontrolling Interests 2.3
2.0

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $ 455.7
$ 577.5



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)


	AEP Common Shareholders
	Common Stock								Accumulated Other Comprehensive Income (Loss)
	Shares	Amount		Paid-in Capital		Retained Earnings					Noncontrolling Interests		Total
TOTAL EQUITY – DECEMBER 31, 2022	525.1	$	3,413.1	$	8,051.0	$	12,345.6		$	83.7	$	229.0	$	24,122.4

Issuance of Common Stock	0.8	5.1		36.0									41.1
Common Stock Dividends						(428.8)		(a)			(3.0)		(431.8)
Other Changes in Equity				(12.7)							0.2		(12.5)
Net Income						397.0					3.4		400.4
Other Comprehensive Loss									(151.8)				(151.8)
TOTAL EQUITY – MARCH 31, 2023	525.9	$	3,418.2	$	8,074.3	$	12,313.8		$	(68.1)	$	229.6	$	23,967.8
















TOTAL EQUITY – DECEMBER 31, 2023	527.4	$	3,427.9	$	9,073.9	$	12,800.4		$	(55.5)	$	39.2	$	25,285.9

Issuance of Common Stock	0.8	5.4		35.2									40.6
Common Stock Dividends						(465.5)		(b)			(1.4)		(466.9)
Other Changes in Equity				(14.8)									(14.8)

Net Income						1,003.1					2.6		1,005.7
Other Comprehensive Loss									(6.8)				(6.8)
TOTAL EQUITY – MARCH 31, 2024	528.2	$	3,433.3	$	9,094.3	$	13,338.0		$	(62.3)	$	40.4	$	25,843.7

AEP Common Shareholders
Common Stock
Accumulated
Other
Comprehensive
Income (Loss)

Shares Amount
Paid-in
Capital

Retained
Earnings

Noncontrolling
Interests
Total
TOTAL EQUITY – DECEMBER 31, 2016 512.0
$ 3,328.3
$ 6,332.6
$ 7,892.4
$ (156.3 ) $ 23.1
$ 17,420.1

Common Stock Dividends

(290.3 )
(1.1 ) (291.4 )
Other Changes in Equity

2.9

0.6
3.5
Net Income 592.2

2.0
594.2
Other Comprehensive Loss

(14.7 )
(14.7 )
TOTAL EQUITY – MARCH 31, 2017 512.0
$ 3,328.3
$ 6,335.5
$ 8,194.3
$ (171.0 ) $ 24.6
$ 17,711.7

TOTAL EQUITY – DECEMBER 31, 2017 512.2
$ 3,329.4
$ 6,398.7
$ 8,626.7
$ (67.8 ) $ 26.6
$ 18,313.6

Issuance of Common Stock 0.5
3.3
28.9

32.2
Common Stock Dividends

(305.5 )
(0.6 ) (306.1 )
Other Changes in Equity 16.9

16.9
ASU 2018-02 Adoption 14.0
(17.0 ) (3.0 )
ASU 2016-01 Adoption 11.9
(11.9 ) —
Net Income 454.4

2.3
456.7
Other Comprehensive Income

1.3

1.3
TOTAL EQUITY – MARCH 31, 2018 512.7
$ 3,332.7
$ 6,444.5
$ 8,801.5
$ (95.4 ) $ 28.3
$ 18,511.6

(a) Cash dividends declared per AEP common share were $0.83.

(b) Cash dividends declared per AEP common share were $0.88.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page ~~120~~99.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, ~~2018~~2024 and December 31, ~~2017~~2023

(in millions)

(Unaudited)


	March 31,		December 31,
	2024		2023
CURRENT ASSETS
Cash and Cash Equivalents	$	230.7	$	330.1
Restricted Cash (March 31, 2024 and December 31, 2023 Amounts Include $51.1 and $48.9, Respectively, Related to Transition Funding, Restoration Funding and Appalachian Consumer Rate Relief Funding)	51.1		48.9
Other Temporary Investments (March 31, 2024 and December 31, 2023 Amounts Include $206.1 and $205, Respectively, Related to EIS and Transource Energy)	217.0		214.3
Accounts Receivable:
Customers	1,000.0		1,029.9
Accrued Unbilled Revenues	220.9		179.5
Pledged Accounts Receivable – AEP Credit	1,206.8		1,249.4
Miscellaneous	47.2		48.7
Allowance for Uncollectible Accounts	(59.6)		(60.1)
Total Accounts Receivable	2,415.3		2,447.4
Fuel	749.9		853.7
Materials and Supplies	1,020.4		1,025.8
Risk Management Assets	152.7		217.5
Accrued Tax Benefits	89.4		156.2
Regulatory Asset for Under-Recovered Fuel Costs	550.3		514.0


Prepayments and Other Current Assets	372.8		274.2
TOTAL CURRENT ASSETS	5,849.6		6,082.1

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	24,404.1		24,329.5
Transmission	36,253.1		35,934.1
Distribution	29,476.3		28,989.9
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	6,557.2		6,484.9
Construction Work in Progress	6,142.1		5,508.0
Total Property, Plant and Equipment	102,832.8		101,246.4
Accumulated Depreciation and Amortization	25,036.8		24,553.0
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	77,796.0		76,693.4

OTHER NONCURRENT ASSETS
Regulatory Assets	5,034.1		5,092.4
Securitized Assets	309.7		336.3
Spent Nuclear Fuel and Decommissioning Trusts	4,112.6		3,860.2
Goodwill	52.5		52.5
Long-term Risk Management Assets	314.4		321.2
Operating Lease Assets	603.0		620.2
Deferred Charges and Other Noncurrent Assets	3,672.7		3,625.7
TOTAL OTHER NONCURRENT ASSETS	14,099.0		13,908.5

TOTAL ASSETS	$	97,744.6	$	96,684.0

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

March 31, December 31,
2018 2017
CURRENT ASSETS

Cash and Cash Equivalents $ 183.4
$ 214.6
Restricted Cash
(March 31, 2018 and December 31, 2017 Amounts Relate to Transition Funding, Ohio Phase-in-Recovery Funding and Appalachian Consumer Rate Relief Funding)
133.1
198.0
Other Temporary Investments
(March 31, 2018 and December 31, 2017 Amounts Include $155.8 and $155.4, Respectively, Related to EIS, Transource Energy and Sabine)
167.9
161.7
Accounts Receivable:

Customers 635.6
643.9
Accrued Unbilled Revenues 213.4
230.2
Pledged Accounts Receivable – AEP Credit 975.3
954.2
Miscellaneous 66.5
101.2
Allowance for Uncollectible Accounts (39.3 ) (38.5 )
Total Accounts Receivable 1,851.5
1,891.0
Fuel 359.6
387.7
Materials and Supplies 563.2
565.5
Risk Management Assets 89.6
126.2
Regulatory Asset for Under-Recovered Fuel Costs 352.3
292.5
Margin Deposits 154.2
105.5
Prepayments and Other Current Assets 280.2
310.4
TOTAL CURRENT ASSETS 4,135.0
4,253.1

PROPERTY, PLANT AND EQUIPMENT

Electric:

Generation 20,824.0
20,760.5
Transmission 19,239.9
18,972.5
Distribution 20,160.5
19,868.5
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 3,812.5
3,706.3
Construction Work in Progress 4,759.4
4,120.7
Total Property, Plant and Equipment 68,796.3
67,428.5
Accumulated Depreciation and Amortization 17,431.2
17,167.0
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 51,365.1
50,261.5

OTHER NONCURRENT ASSETS

Regulatory Assets 3,516.9
3,587.6
Securitized Assets 1,146.6
1,211.2
Spent Nuclear Fuel and Decommissioning Trusts 2,510.6
2,527.6
Goodwill 52.5
52.5
Long-term Risk Management Assets 271.2
282.1
Deferred Charges and Other Noncurrent Assets 2,611.6
2,553.5
TOTAL OTHER NONCURRENT ASSETS 10,109.4
10,214.5

TOTAL ASSETS $ 65,609.5
$ 64,729.1



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

March 31, ~~2018~~2024 and December 31, ~~2017~~2023

(~~dollars~~ in ~~millions)~~millions, except per-share and share amounts)

(Unaudited)


			March 31,		December 31,
			2024		2023
CURRENT LIABILITIES
Accounts Payable			$	1,990.9	$	2,032.5
Short-term Debt:
Securitized Debt for Receivables – AEP Credit			900.0		888.0
Other Short-term Debt			2,837.6		1,942.2
Total Short-term Debt			3,737.6		2,830.2
Long-term Debt Due Within One Year (March 31, 2024 and December 31, 2023 Amounts Include $201.5 and $207.2, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)			1,198.6		2,490.5
Risk Management Liabilities			184.4		229.6
Customer Deposits			436.2		423.7
Accrued Taxes			1,675.6		1,800.1
Accrued Interest			507.3		410.2
Obligations Under Operating Leases			107.1		115.7


Other Current Liabilities			1,068.9		1,251.1
TOTAL CURRENT LIABILITIES			10,906.6		11,583.6

NONCURRENT LIABILITIES
Long-term Debt (March 31, 2024 and December 31, 2023 Amounts Include $528.9 and $556.3, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)			38,637.3		37,652.7
Long-term Risk Management Liabilities			279.5		241.8
Deferred Income Taxes			9,662.1		9,415.7
Regulatory Liabilities and Deferred Investment Tax Credits			8,089.4		8,182.4
Asset Retirement Obligations			2,972.9		2,972.5
Employee Benefits and Pension Obligations			230.8		241.7
Obligations Under Operating Leases			509.3		519.4
Deferred Credits and Other Noncurrent Liabilities			561.4		545.8
TOTAL NONCURRENT LIABILITIES			60,942.7		59,772.0

TOTAL LIABILITIES			71,849.3		71,355.6

Rate Matters (Note 4)
Commitments and Contingencies (Note 5)

MEZZANINE EQUITY

Contingently Redeemable Performance Share Awards			51.6		42.5
TOTAL MEZZANINE EQUITY			51.6		42.5

EQUITY
Common Stock – Par Value – $6.50 Per Share:
	2024	2023
Shares Authorized	600,000,000	600,000,000
Shares Issued	528,199,306	527,369,157
(1,184,572 Shares were Held in Treasury as of March 31, 2024 and December 31, 2023, Respectively)			3,433.3		3,427.9
Paid-in Capital			9,094.3		9,073.9
Retained Earnings			13,338.0		12,800.4
Accumulated Other Comprehensive Income (Loss)			(62.3)		(55.5)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY			25,803.3		25,246.7

Noncontrolling Interests			40.4		39.2

TOTAL EQUITY			25,843.7		25,285.9

TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY			$	97,744.6	$	96,684.0

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

March 31, December 31,
2018 2017
CURRENT LIABILITIES
Accounts Payable $ 1,449.6
$ 2,065.3
Short-term Debt:
Securitized Debt for Receivables – AEP Credit 750.0
718.0
Other Short-term Debt 1,908.8
920.6
Total Short-term Debt 2,658.8
1,638.6
Long-term Debt Due Within One Year
(March 31, 2018 and December 31, 2017 Amounts Include $406.5 and $406.9, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and Sabine)
2,616.1
1,753.7
Risk Management Liabilities 57.1
61.6
Customer Deposits 365.5
357.0
Accrued Taxes 1,081.4
1,115.5
Accrued Interest 273.1
234.5
Regulatory Liability for Over-Recovered Fuel Costs 9.8
11.9
Other Current Liabilities 960.0
1,033.2
TOTAL CURRENT LIABILITIES 9,471.4
8,271.3

NONCURRENT LIABILITIES
Long-term Debt
(March 31, 2018 and December 31, 2017 Amounts Include $1,253 and $1,410.5, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy and Sabine)
18,844.9
19,419.6
Long-term Risk Management Liabilities 282.7
322.0
Deferred Income Taxes 6,943.9
6,813.9
Regulatory Liabilities and Deferred Investment Tax Credits 8,394.5
8,422.3
Asset Retirement Obligations 1,933.7
1,925.5
Employee Benefits and Pension Obligations 330.9
398.1
Deferred Credits and Other Noncurrent Liabilities 808.2
830.9
TOTAL NONCURRENT LIABILITIES 37,538.8
38,132.3

TOTAL LIABILITIES 47,010.2
46,403.6

Rate Matters (Note 4)

Commitments and Contingencies (Note 5)

MEZZANINE EQUITY
Redeemable Noncontrolling Interest 70.7
—
Contingently Redeemable Performance Share Awards 17.0
11.9
TOTAL MEZZANINE EQUITY 87.7
11.9

EQUITY
Common Stock – Par Value – $6.50 Per Share:
2018 2017
Shares Authorized 600,000,000 600,000,000
Shares Issued 512,716,170 512,210,644
(20,204,160 and 20,205,046 Shares were Held in Treasury as of March 31, 2018 and December 31, 2017, Respectively) 3,332.7
3,329.4
Paid-in Capital 6,444.5
6,398.7
Retained Earnings 8,801.5
8,626.7
Accumulated Other Comprehensive Income (Loss) (95.4 ) (67.8 )
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY 18,483.3
18,287.0

Noncontrolling Interests 28.3
26.6

TOTAL EQUITY 18,511.6
18,313.6

TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY $ 65,609.5
$ 64,729.1



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)


	Three Months Ended March 31,
	2024		2023
OPERATING ACTIVITIES
Net Income	$	1,005.7	$	400.4


Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	787.1		775.5

Deferred Income Taxes	(113.3)		68.0

Loss on the Sale of the Competitive Contracted Renewables Portfolio	—		112.0


Allowance for Equity Funds Used During Construction	(43.6)		(31.3)
Mark-to-Market of Risk Management Contracts	40.9		(82.0)


Property Taxes	(89.2)		(101.6)
Deferred Fuel Over/Under-Recovery, Net	43.4		128.0




Change in Other Noncurrent Assets	(74.5)		(96.0)
Change in Other Noncurrent Liabilities	61.8		(58.7)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	34.9		348.4
Fuel, Materials and Supplies	104.3		(115.9)
Accounts Payable	(99.5)		(255.9)
Accrued Taxes, Net	(57.7)		(150.9)
Other Current Assets	(91.3)		(94.6)
Other Current Liabilities	(66.8)		(127.6)
Net Cash Flows from Operating Activities	1,442.2		717.8

INVESTING ACTIVITIES
Construction Expenditures	(1,761.7)		(2,090.1)

Purchases of Investment Securities	(590.0)		(537.3)
Sales of Investment Securities	572.5		517.6
Acquisitions of Nuclear Fuel	(33.7)		(1.7)

Acquisitions of Renewable Energy Facilities	—		(145.7)

Proceeds from Sale of Equity Method Investment	114.0		—
Other Investing Activities	29.6		12.0
Net Cash Flows Used for Investing Activities	(1,669.3)		(2,245.2)

FINANCING ACTIVITIES
Issuance of Common Stock	40.6		41.1
Issuance of Long-term Debt	859.9		2,847.3
Issuance of Short-term Debt with Original Maturities greater than 90 Days	376.6		97.4
Change in Short-term Debt with Original Maturities less than 90 Days, Net	840.9		(433.7)
Retirement of Long-term Debt	(1,162.2)		(519.5)

Redemption of Short-term Debt with Original Maturities Greater than 90 Days	(310.1)		(153.8)
Principal Payments for Finance Lease Obligations	(17.0)		(26.8)
Dividends Paid on Common Stock	(466.9)		(431.8)

Other Financing Activities	(31.9)		(55.8)
Net Cash Flows from Financing Activities	129.9		1,364.4





Net Decrease in Cash and Cash Equivalents	(97.2)		(163.0)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	379.0		556.5
Cash, Cash Equivalents and Restricted Cash at End of Period	$	281.8	$	393.5

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	368.3	$	311.9
Net Cash Paid for Income Taxes	16.1		15.8
Cash Received from Sale of Transferable Tax Credits	(62.0)		—
Noncash Acquisitions Under Finance Leases	7.0		12.5
Construction Expenditures Included in Current Liabilities as of March 31,	837.0		1,076.1


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Three Months Ended March 31,
2018 2017
OPERATING ACTIVITIES

Net Income $ 456.7
$ 594.2
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 539.7
481.9
Deferred Income Taxes 87.3
136.2
Allowance for Equity Funds Used During Construction (30.7 ) (21.2 )
Mark-to-Market of Risk Management Contracts (0.7 ) 6.0
Amortization of Nuclear Fuel 27.4
35.1
Property Taxes (63.7 ) (44.4 )
Deferred Fuel Over/Under-Recovery, Net (61.2 ) 19.3
Gain on Sale of Merchant Generation Assets —
(226.5 )
Recovery of Ohio Capacity Costs 18.0
30.2
Provision for Refund - Global Settlement, Net (5.4 ) —
Change in Other Noncurrent Assets (59.8 ) (99.1 )
Change in Other Noncurrent Liabilities 133.3
45.0
Changes in Certain Components of Working Capital:
Accounts Receivable, Net 39.7
235.8
Fuel, Materials and Supplies 28.5
13.4
Accounts Payable (129.3 ) (250.7 )
Accrued Taxes, Net (74.3 ) 186.8
Other Current Assets (40.1 ) (45.9 )
Other Current Liabilities (63.2 ) (289.3 )
Net Cash Flows from Operating Activities 802.2
806.8

INVESTING ACTIVITIES
Construction Expenditures (1,905.8 ) (1,365.8 )
Purchases of Investment Securities (525.9 ) (506.0 )
Sales of Investment Securities 508.6
487.9
Acquisitions of Nuclear Fuel (23.8 ) (3.7 )
Proceeds from Sale of Merchant Generation Assets —
2,159.6
Other Investing Activities 19.1
4.2
Net Cash Flows from (Used for) Investing Activities (1,927.8 ) 776.2

FINANCING ACTIVITIES
Issuance of Common Stock, Net 32.2
—
Issuance of Long-term Debt 841.0
82.9
Commercial Paper and Credit Facility Borrowings 205.6
—
Change in Short-term Debt, Net 814.6
(177.0 )
Retirement of Long-term Debt (544.0 ) (1,242.3 )
Make Whole Payment on Extinguishment of Long-term Debt —
(44.9 )
Principal Payments for Capital Lease Obligations (16.8 ) (16.6 )
Dividends Paid on Common Stock (306.1 ) (291.4 )
Other Financing Activities 3.0
2.2
Net Cash Flows from (Used for) Financing Activities 1,029.5
(1,687.1 )

Net Decrease in Cash, Cash Equivalents and Restricted Cash (96.1 ) (104.1 )
Cash, Cash Equivalents and Restricted Cash at Beginning of Period 412.6
403.5
Cash, Cash Equivalents and Restricted Cash at End of Period $ 316.5
$ 299.4

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts $ 188.0
$ 205.9
Net Cash Paid (Received) for Income Taxes (0.9 ) (88.8 )
Noncash Acquisitions Under Capital Leases 21.4
11.4
Construction Expenditures Included in Current Liabilities as of March 31, 799.9
515.6
Noncash Contribution of Assets by Noncontrolling Interest 84.0
—
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage 0.1
1.0



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

~~AEP TEXAS INC.~~

~~AND SUBSIDIARIES~~

AEP TEXAS INC. AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales



	Three Months Ended March 31,
	2024	2023
	(in millions of KWhs)
Retail:
Residential	2,529	2,532
Commercial	3,307	2,744
Industrial	3,273	3,108
Miscellaneous	151	138
Total Retail	9,260	8,522

Three Months Ended March 31,
2018 2017
(in millions of KWhs)
Retail:

Residential 2,664
2,201
Commercial 2,312
2,325
Industrial 1,960
1,907
Miscellaneous 122
128
Total Retail 7,058
6,561

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.

Summary of Heating and Cooling Degree Days



	Three Months Ended March 31,
	2024	2023
	(in degree days)
Actual – Heating (a)	161	141
Normal – Heating (b)	195	194

Actual – Cooling (c)	146	271
Normal – Cooling (b)	137	127

Three Months Ended March 31,
2018 2017
(in degree days)
Actual – Heating (a) 230
102
Normal – Heating (b) 191
195

Actual – Cooling (c) 196
258
Normal – Cooling (b) 119
113

(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 6570 degree temperature base.

~~First Quarter of 2018 Compared to First Quarter of 2017~~

Reconciliation of First Quarter of 2017 to First Quarter of 2018
Net Income
(in millions)

First Quarter of 2017 $ 33.3

Changes in Gross Margin:
Retail Margins 18.6
Off-system Sales (1.6 )
Transmission Revenues 2.4
Other Revenues 2.7
Total Change in Gross Margin 22.1

Changes in Expenses and Other:
Other Operation and Maintenance (11.3 )
Depreciation and Amortization (7.2 )
Taxes Other Than Income Taxes (4.1 )
Interest Income (0.5 )
Allowance for Equity Funds Used During Construction 3.7
Non-Service Cost Components of Net Periodic Benefit Cost 2.2
Interest Expense —
Total Change in Expenses and Other (17.2 )

Income Tax Expense 8.6

First Quarter of 2018 $ 46.8


AEP Texas Inc. and Subsidiaries
Reconciliation of First Quarter of 2023 to First Quarter of 2024
Net Income
(in millions)


First Quarter of 2023	$	47.6

Changes in Revenues:
Retail Revenues	28.8

Transmission Revenues	9.6
Other Revenues	(1.5)
Total Change in Revenues	36.9

Changes in Expenses and Other:
Other Operation and Maintenance	8.4
Depreciation and Amortization	(5.7)
Taxes Other Than Income Taxes	3.5

Interest Income	0.1

Allowance for Equity Funds Used During Construction	2.3
Non-Service Cost Components of Net Periodic Benefit Cost	(1.1)
Interest Expense	(4.6)
Total Change in Expenses and Other	2.9

Income Tax Expense	(7.7)

First Quarter of 2024	$	79.7

The major components of the increase in ~~Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals~~Revenues were as follows:

•Retail ~~Margins~~Revenues increased ~~$19~~$29 million primarily due to the following:

•A ~~$10~~$20 million increase in ~~weather-related usage~~weather-normalized revenues primarily ~~driven by a 125% increase~~ in ~~heating degree days partially offset by a 24% decrease in cooling degree days.~~the residential and commercial classes.

•A $9$16 million increase in ~~revenues associated with the Transmission Cost Recovery Factor~~ revenue ~~rider. This increase was partially offset by an increase in Other Operation and Maintenance expenses below.~~

~~A $7 million increase in revenues associated with the Distribution Cost Recovery Factor revenue rider.~~from rate riders.

These increases were partially offset by:

~~A $5~~•An $8 million decrease ~~due to the 2018 provisions for customer refunds primarily related to Tax Reform. This decrease is offset~~ in ~~Income Tax Expense below.~~

~~Transmission Revenues~~ ~~increased by $2 million~~weather-related usage primarily due to ~~the following:~~

a 46% decrease in cooling degree days.

~~A $7~~•Transmission Revenues increased $10 million ~~increase~~ due to ~~recovery of~~interim rate increases driven by increased transmission ~~investment in ERCOT.~~investments.

~~This increase was partially offset by:~~

~~A $5 million decrease due to the 2018 provisions for customer refunds primarily due to Tax Reform. This decrease is offset in Income Tax Expense below.~~

~~Other Revenues~~ ~~increased $3 million primarily due to securitization revenue related to Transition Funding. This increase was offset in Depreciation and Amortization and Interest Expense below.~~

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

•Other Operation and Maintenance expenses ~~increased $11~~decreased $8 million primarily due to ~~an increase~~the following:

•A $5 million decrease in ~~ERCOT transmission~~distribution-related expenses. ~~This increase was partially offset by an increase in Retail Margins above.~~

~~Depreciation and Amortization~~ ~~expenses increased $7 million primarily due to securitization amortizations related to Transition Funding. This increase was offset in Other Revenues above and in Interest Expense below.~~

~~Taxes Other Than Income Taxes~~ ~~increased $4 million primarily due to increased property taxes as a result of additional capital investment and increased tax rates.~~

~~Interest Expense~~ ~~was unchanged primarily due to:~~

•A $3 million decrease in ~~securitization assets related to Transition Funding. This decrease was offset above in Other Revenues and in~~ recoverable transmission expenses.

•Depreciation and ~~Amortization.~~

~~A $2 million decrease due to higher debt component of AFUDC from~~Amortization expenses increased ~~transmission projects.~~

~~These decreases were offset by:~~

~~A $5 million increase in interest due to the issuance of long-term debt in September 2017.~~

~~Allowance for Equity Funds Used During Construction~~ ~~increased $4 million due to increased transmission projects.~~

~~Income Tax Expense~~ ~~decreased $9~~$6 million primarily due to ~~the change in the corporate federal income tax rate from 35% in 2017~~ a higher depreciable base.

•Income Tax Expense increased $8 million primarily due to ~~21% in 2018 as a result of Tax Reform and amortization of excess accumulated deferred income taxes associated with certain depreciable property, partially offset by~~ an increase in pretax book income.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2024		2023
REVENUES
Electric Transmission and Distribution	$	463.0	$	427.7
Sales to AEP Affiliates	1.3		1.2
Other Revenues	2.1		0.6
TOTAL REVENUES	466.4		429.5

EXPENSES

Other Operation	140.8		146.9
Maintenance	22.1		24.4
Depreciation and Amortization	116.7		111.0
Taxes Other Than Income Taxes	40.0		43.5
TOTAL EXPENSES	319.6		325.8

OPERATING INCOME	146.8		103.7

Other Income (Expense):
Interest Income	0.5		0.4

Allowance for Equity Funds Used During Construction	8.6		6.3

Non-Service Cost Components of Net Periodic Benefit Cost	3.7		4.8
Interest Expense	(61.5)		(56.9)

INCOME BEFORE INCOME TAX EXPENSE	98.1		58.3

Income Tax Expense	18.4		10.7

NET INCOME	$	79.7	$	47.6

The common stock of AEP Texas is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Three Months Ended March 31,
2018 2017
REVENUES
Electric Transmission and Distribution $ 352.4
$ 328.9
Sales to AEP Affiliates 18.2
14.1
Other Revenues 1.0
0.6
TOTAL REVENUES 371.6
343.6

EXPENSES

Fuel and Other Consumables Used for Electric Generation 8.9
3.0
Other Operation 117.0
108.8
Maintenance 21.5
18.4
Depreciation and Amortization 110.0
102.8
Taxes Other Than Income Taxes 32.4
28.3
TOTAL EXPENSES 289.8
261.3

OPERATING INCOME 81.8
82.3

Other Income (Expense):

Interest Income 0.5
1.0
Allowance for Equity Funds Used During Construction 5.5
1.8
Non-Service Cost Components of Net Periodic Benefit Cost 3.1
0.9
Interest Expense (35.0 ) (35.0 )

INCOME BEFORE INCOME TAX EXPENSE 55.9
51.0

Income Tax Expense 9.1
17.7

NET INCOME $ 46.8
$ 33.3

~~The common stock of AEP Texas Inc. is wholly-owned by Parent.~~

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2024		2023
Net Income	$	79.7	$	47.6

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $1.0 and $0 in 2024 and 2023, Respectively	3.9		—
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $(0.1) in 2024 and 2023, Respectively	—		(0.6)

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	3.9		(0.6)

TOTAL COMPREHENSIVE INCOME	$	83.6	$	47.0

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Three Months Ended March 31,
2018 2017
Net Income $ 46.8
$ 33.3

OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 in 2018 and 2017, Respectively 0.2
0.2
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 in 2018 and 2017, Respectively 0.1
0.1

TOTAL OTHER COMPREHENSIVE INCOME 0.3
0.3

TOTAL COMPREHENSIVE INCOME $ 47.1
$ 33.6

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)


	Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2022	$	1,558.2	$	2,354.7	$	(8.6)	$	3,904.3

Capital Contribution from Parent	100.0						100.0

Net Income			47.6				47.6
Other Comprehensive Loss					(0.6)		(0.6)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2023	$	1,658.2	$	2,402.3	$	(9.2)	$	4,051.3











TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2023	$	2,079.6	$	2,725.1	$	(8.6)	$	4,796.1


Net Income			79.7				79.7
Other Comprehensive Income					3.9		3.9
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2024	$	2,079.6	$	2,804.8	$	(4.7)	$	4,879.7













See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Paid-in
Capital

Retained
Earnings

Accumulated
Other
Comprehensive
Income (Loss)
Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2016 $ 857.9
$ 814.1
$ (14.9 ) $ 1,657.1

Capital Contribution from Parent 200.0

200.0
Net Income
33.3

33.3
Other Comprehensive Income

0.3
0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2017 $ 1,057.9
$ 847.4
$ (14.6 ) $ 1,890.7

TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017 $ 1,057.9
$ 1,124.6
$ (12.6 ) $ 2,169.9

Capital Contribution from Parent 100.0
100.0
ASU 2018-02 Adoption 1.8
(2.7 ) (0.9 )
Net Income
46.8
46.8
Other Comprehensive Income
0.3
0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 $ 1,157.9
$ 1,173.2
$ (15.0 ) $ 2,316.1

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, ~~2018~~2024 and December 31, ~~2017~~2023

(in millions)

(Unaudited)


	March 31,		December 31,
	2024		2023
CURRENT ASSETS
Cash and Cash Equivalents	$	0.1	$	0.1
Restricted Cash (March 31, 2024 and December 31, 2023 Amounts Include $42.7 and $34, Respectively, Related to Transition Funding and Restoration Funding)	42.7		34.0
Advances to Affiliates	7.0		7.1
Accounts Receivable:
Customers	167.8		176.5
Affiliated Companies	21.2		23.8
Accrued Unbilled Revenues	85.2		82.3
Miscellaneous	0.7		0.8
Allowance for Uncollectible Accounts	(4.2)		(4.9)
Total Accounts Receivable	270.7		278.5

Materials and Supplies	194.0		190.4


Prepayments and Other Current Assets	10.6		10.0
TOTAL CURRENT ASSETS	525.1		520.1

PROPERTY, PLANT AND EQUIPMENT
Electric:

Transmission	6,896.6		6,812.6
Distribution	5,903.8		5,798.8
Other Property, Plant and Equipment	1,148.8		1,145.9
Construction Work in Progress	1,062.7		904.6
Total Property, Plant and Equipment	15,011.9		14,661.9
Accumulated Depreciation and Amortization	1,932.5		1,887.9
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	13,079.4		12,774.0

OTHER NONCURRENT ASSETS
Regulatory Assets	317.4		315.3
Securitized Assets (March 31, 2024 and December 31, 2023 Amounts Include $183.1 and $202.9, Respectively, Related to Transition Funding and Restoration Funding)	183.1		202.9

Deferred Charges and Other Noncurrent Assets	262.5		178.4
TOTAL OTHER NONCURRENT ASSETS	763.0		696.6

TOTAL ASSETS	$	14,367.5	$	13,990.7

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

March 31, December 31,
2018 2017
CURRENT ASSETS
Cash and Cash Equivalents $ 0.1
$ 2.0
Restricted Cash for Securitized Transition Funding 107.1
155.2
Advances to Affiliates 8.1
111.9
Accounts Receivable:
Customers 117.7
105.3
Affiliated Companies 9.0
12.3
Accrued Unbilled Revenues 65.7
75.8
Miscellaneous 0.3
1.3
Allowance for Uncollectible Accounts (0.5 ) (0.7 )
Total Accounts Receivable 192.2
194.0
Fuel 6.4
3.6
Materials and Supplies 49.4
52.0
Risk Management Assets 0.3
0.5
Accrued Tax Benefits 66.4
41.0
Prepayments and Other Current Assets 5.8
3.6
TOTAL CURRENT ASSETS 435.8
563.8

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation 350.9
350.7
Transmission 3,097.6
3,053.6
Distribution 3,854.2
3,718.6
Other Property, Plant and Equipment 475.4
461.0
Construction Work in Progress 951.6
835.7
Total Property, Plant and Equipment 8,729.7
8,419.6
Accumulated Depreciation and Amortization 1,617.4
1,594.5
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
7,112.3
6,825.1

OTHER NONCURRENT ASSETS
Regulatory Assets 379.4
378.7
Securitized Transition Assets
(March 31, 2018 and December 31, 2017 Amounts Include $819.2 and $869.5, Respectively, Related to Transition Funding)
838.9
891.2
Deferred Charges and Other Noncurrent Assets 134.0
114.8
TOTAL OTHER NONCURRENT ASSETS 1,352.3
1,384.7

TOTAL ASSETS $ 8,900.4
$ 8,773.6

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, ~~2018~~2024 and December 31, ~~2017~~2023

(in millions)

(Unaudited)


	March 31,		December 31,
	2024		2023
CURRENT LIABILITIES
Advances from Affiliates	$	267.9	$	103.7
Accounts Payable:
General	253.5		192.3
Affiliated Companies	30.9		27.7

Long-term Debt Due Within One Year – Nonaffiliated (March 31, 2024 and December 31, 2023 Amounts Include $96.2 and $95.9, Respectively, Related to Transition Funding and Restoration Funding)	96.2		96.0


Accrued Taxes	139.5		99.1
Accrued Interest (March 31, 2024 and December 31, 2023 Amounts Include $1.7 and $2, Respectively, Related to Transition Funding and Restoration Funding)	81.5		49.2

Obligations Under Operating Leases	24.7		28.7

Other Current Liabilities	147.7		152.7
TOTAL CURRENT LIABILITIES	1,041.9		749.4

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated (March 31, 2024 and December 31, 2023 Amounts Include $114 and $125.9, Respectively, Related to Transition Funding and Restoration Funding)	5,782.5		5,793.8

Deferred Income Taxes	1,238.7		1,227.8
Regulatory Liabilities and Deferred Investment Tax Credits	1,261.2		1,261.4

Obligations Under Operating Leases	50.1		50.9
Deferred Credits and Other Noncurrent Liabilities	113.4		111.3
TOTAL NONCURRENT LIABILITIES	8,445.9		8,445.2

TOTAL LIABILITIES	9,487.8		9,194.6

Rate Matters (Note 4)
Commitments and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Paid-in Capital	2,079.6		2,079.6
Retained Earnings	2,804.8		2,725.1
Accumulated Other Comprehensive Income (Loss)	(4.7)		(8.6)
TOTAL COMMON SHAREHOLDER’S EQUITY	4,879.7		4,796.1

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	14,367.5	$	13,990.7

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

March 31, December 31,
2018 2017
CURRENT LIABILITIES
Advances from Affiliates $ 232.7
$ —
Accounts Payable:
General 209.0
379.4
Affiliated Companies 22.7
30.2
Long-term Debt Due Within One Year – Nonaffiliated
(March 31, 2018 and December 31, 2017 Amounts Include $243.1 and $236.1, Respectively, Related to Transition Funding)
273.1
266.1
Accrued Taxes 89.7
77.2
Accrued Interest
(March 31, 2018 and December 31, 2017 Amounts Include $10.2 and $15.9, Respectively, Related to Transition Funding)
48.0
42.2
Other Current Liabilities 70.7
76.4
TOTAL CURRENT LIABILITIES 945.9
871.5

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated
(March 31, 2018 and December 31, 2017 Amounts Include $686.8 and $790.1, Respectively, Related to Transition Funding)
3,280.2
3,383.2
Deferred Income Taxes 913.1
913.1
Regulatory Liabilities and Deferred Investment Tax Credits 1,320.2
1,320.5
Oklaunion Purchase Power Agreement 51.8
52.0
Deferred Credits and Other Noncurrent Liabilities 73.1
63.4
TOTAL NONCURRENT LIABILITIES 5,638.4
5,732.2

TOTAL LIABILITIES 6,584.3
6,603.7

Rate Matters (Note 4)

Commitments and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Paid-in Capital 1,157.9
1,057.9
Retained Earnings 1,173.2
1,124.6
Accumulated Other Comprehensive Income (Loss) (15.0 ) (12.6 )
TOTAL COMMON SHAREHOLDER’S EQUITY 2,316.1
2,169.9

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $ 8,900.4
$ 8,773.6

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)


	Three Months Ended March 31,
	2024		2023
OPERATING ACTIVITIES
Net Income	$	79.7	$	47.6
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	116.7		111.0
Deferred Income Taxes	6.6		6.4
Allowance for Equity Funds Used During Construction	(8.6)		(6.3)
Mark-to-Market of Risk Management Contracts	(0.2)		0.4

Property Taxes	(84.3)		(88.8)

Change in Other Noncurrent Assets	(17.2)		(18.3)
Change in Other Noncurrent Liabilities	3.0		(0.8)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	7.8		24.6
Materials and Supplies	(3.6)		(1.1)
Accounts Payable	11.6		3.6

Accrued Taxes, Net	42.6		44.5
Accrued Interest	32.3		23.9
Other Current Assets	1.4		0.9
Other Current Liabilities	(20.0)		(10.9)
Net Cash Flows from Operating Activities	167.8		136.7

INVESTING ACTIVITIES
Construction Expenditures	(331.2)		(450.4)
Change in Advances to Affiliates, Net	0.1		0.1

Other Investing Activities	21.1		7.3
Net Cash Flows Used for Investing Activities	(310.0)		(443.0)

FINANCING ACTIVITIES
Capital Contribution from Parent	—		100.0



Change in Advances from Affiliates, Net	164.2		354.3
Retirement of Long-term Debt – Nonaffiliated	(11.9)		(136.7)
Principal Payments for Finance Lease Obligations	(1.8)		(1.8)

Other Financing Activities	0.4		0.3
Net Cash Flows from Financing Activities	150.9		316.1

Net Increase in Cash, Cash Equivalents and Restricted Cash	8.7		9.8
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	34.1		32.8
Cash, Cash Equivalents and Restricted Cash at End of Period	$	42.8	$	42.6

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	26.9	$	31.6

Noncash Acquisitions Under Finance Leases	1.1		1.8
Construction Expenditures Included in Current Liabilities as of March 31,	158.3		177.5

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Three Months Ended March 31,
2018 2017
OPERATING ACTIVITIES

Net Income $ 46.8
$ 33.3
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:

Depreciation and Amortization 110.0
102.8
Deferred Income Taxes (4.4 ) 40.8
Allowance for Equity Funds Used During Construction (5.5 ) (1.8 )
Mark-to-Market of Risk Management Contracts 0.2
0.1
Property Taxes (56.1 ) (46.2 )
Change in Other Noncurrent Assets (12.7 ) (12.7 )
Change in Other Noncurrent Liabilities 6.5
4.8
Changes in Certain Components of Working Capital:

Accounts Receivable, Net 1.8
3.7
Fuel, Materials and Supplies (0.2 ) 0.4
Accounts Payable (25.9 ) (13.4 )
Accrued Taxes, Net 25.2
(3.5 )
Other Current Assets (1.6 ) (0.3 )
Other Current Liabilities (5.1 ) (25.9 )
Net Cash Flows from Operating Activities 79.0
82.1

INVESTING ACTIVITIES

Construction Expenditures (481.6 ) (200.2 )
Change in Advances to Affiliates, Net 103.8
0.3
Other Investing Activities 13.4
4.6
Net Cash Flows Used for Investing Activities (364.4 ) (195.3 )

FINANCING ACTIVITIES

Capital Contribution from Parent 100.0
200.0
Change in Advances from Affiliates, Net 232.7
(43.0 )
Retirement of Long-term Debt – Nonaffiliated (96.5 ) (89.9 )
Principal Payments for Capital Lease Obligations (1.1 ) (0.9 )
Other Financing Activities 0.3
0.6
Net Cash Flows from Financing Activities 235.4
66.8

Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding (50.0 ) (46.4 )
Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding at Beginning of Period 157.2
146.9
Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding at End of Period $ 107.2
$ 100.5

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts $ 27.8
$ 33.7
Noncash Acquisitions Under Capital Leases 4.0
2.0
Construction Expenditures Included in Current Liabilities as of March 31, 169.3
65.5

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

~~AEP TRANSMISSION COMPANY, LLC~~

~~AND SUBSIDIARIES~~

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

Summary of Investment in Transmission Assets for AEPTCo


	As of March 31,
	2024		2023
	(in millions)
Plant In Service	$	14,335.9	$	12,971.3
Construction Work in Progress	1,805.0		1,831.9
Accumulated Depreciation and Amortization	1,362.7		1,091.2
Total Transmission Property, Net	$	14,778.2	$	13,712.0

As of March 31,
2018 2017
(in millions)
Plant In Service $ 5,595.4
$ 4,162.3
Construction Work in Progress 1,512.6
1,184.4
Accumulated Depreciation and Amortization 192.7
117.8
Total Transmission Property, Net $ 6,915.3
$ 5,228.9


AEP Transmission Company, LLC and Subsidiaries
Reconciliation of First Quarter of 2023 to First Quarter of 2024
Net Income
(in millions)


First Quarter of 2023	$	162.7

Changes in Transmission Revenues:
Transmission Revenues	41.2
Total Change in Transmission Revenues	41.2

Changes in Expenses and Other:
Other Operation and Maintenance	(1.3)
Depreciation and Amortization	(10.7)
Taxes Other Than Income Taxes	1.4
Interest Income	0.4
Allowance for Equity Funds Used During Construction	1.5
Interest Expense	(9.6)
Total Change in Expenses and Other	(18.3)

Income Tax Expense	(4.4)

First Quarter of 2024	$	181.2

~~First Quarter of 2018 Compared to First Quarter of 2017~~

Reconciliation of First Quarter of 2017 to First Quarter of 2018
Net Income
(in millions)

First Quarter of 2017 $ 57.0

Changes in Transmission Revenues:
Transmission Revenues 40.8
Total Change in Transmission Revenues 40.8

Changes in Expenses and Other:
Other Operation and Maintenance (7.0 )
Depreciation and Amortization (7.3 )
Taxes Other Than Income Taxes (4.3 )
Interest Income 0.2
Allowance for Equity Funds Used During Construction 4.4
Interest Expense (3.9 )
Total Change in Expenses and Other (17.9 )

Income Tax Expense 6.0

First Quarter of 2018 $ 85.9

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

•Transmission Revenues increased $41 million primarily due to ~~the following:~~

~~Formula rate increases of $60 million driven by~~ continued investment in transmission assets.

~~This increase was partially offset by:~~

~~A $19 million decrease due to the 2018 provisions for customer refunds primarily related to Tax Reform.~~

~~This decrease is offset in Income Tax Expense below.~~

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

~~Other Operation~~•Depreciation and ~~Maintenance~~Amortization expenses increased ~~$7 million primarily due to increased transmission investment.~~

~~Depreciation and Amortization~~ ~~expenses increased $7~~$11 million primarily due to a higher depreciable base.

~~Taxes Other Than Income Taxes~~•Interest Expense increased $4$10 million ~~primarily~~ due to higher ~~property taxes as a result of increased transmission investment.~~

~~Allowance for Equity Funds Used During Construction~~ ~~increased $4 million primarily due to increased transmission investment resulting in a higher CWIP balance.~~

~~Interest Expense~~ ~~increased $4 million primarily due to higher outstanding~~ long-term debt ~~balances.~~balances and interest rates.

~~Income Tax Expense~~ decreased $6 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, partially offset by an increase in pretax book income.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2024		2023
REVENUES
Transmission Revenues	$	98.4	$	90.0
Sales to AEP Affiliates	389.4		357.4
Provision for Refund – Affiliated	(6.0)		(4.8)
Provision for Refund – Nonaffiliated	(1.4)		(1.0)
Other Revenues	2.4		—
TOTAL REVENUES	482.8		441.6

EXPENSES
Other Operation	29.9		29.0
Maintenance	5.3		4.9
Depreciation and Amortization	105.9		95.2
Taxes Other Than Income Taxes	73.4		74.8
TOTAL EXPENSES	214.5		203.9

OPERATING INCOME	268.3		237.7

Other Income (Expense):
Interest Income - Affiliated	1.9		1.5
Allowance for Equity Funds Used During Construction	17.9		16.4

Interest Expense	(54.8)		(45.2)

INCOME BEFORE INCOME TAX EXPENSE	233.3		210.4

Income Tax Expense	52.1		47.7

NET INCOME	$	181.2	$	162.7

AEPTCo is wholly-owned by AEP Transmission Holdco.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Three Months Ended March 31,
2018 2017
REVENUES
Transmission Revenues $ 31.3
$ 19.2
Sales to AEP Affiliates 162.1
133.4
Other Revenues 0.1
0.1
TOTAL REVENUES 193.5
152.7

EXPENSES
Other Operation 16.6
9.1
Maintenance 2.6
3.1
Depreciation and Amortization 30.6
23.3
Taxes Other Than Income Taxes 31.1
26.8
TOTAL EXPENSES 80.9
62.3

OPERATING INCOME 112.6
90.4

Other Income (Expense):
Interest Income 0.4
0.2
Allowance for Equity Funds Used During Construction 15.3
10.9
Interest Expense (19.9 ) (16.0 )

INCOME BEFORE INCOME TAX EXPENSE 108.4
85.5

Income Tax Expense 22.5
28.5

NET INCOME $ 85.9
$ 57.0

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

MEMBER’S EQUITY

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)


	Paid-in Capital		Retained Earnings		Total
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2022	$	3,022.3	$	2,850.7	$	5,873.0

Capital Contribution from Member	25.0				25.0
Dividends Paid to Member			(55.0)		(55.0)
Net Income			162.7		162.7
TOTAL MEMBER'S EQUITY – MARCH 31, 2023	$	3,047.3	$	2,958.4	$	6,005.7












TOTAL MEMBER'S EQUITY – DECEMBER 31, 2023	$	3,043.4	$	3,289.9	$	6,333.3

Capital Contribution from Member	25.0				25.0
Dividends Paid to Member			(40.0)		(40.0)
Net Income			181.2		181.2
TOTAL MEMBER'S EQUITY – MARCH 31, 2024	$	3,068.4	$	3,431.1	$	6,499.5













See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Paid-in
Capital

Retained
Earnings
Total Member’s Equity
TOTAL MEMBER’S EQUITY – DECEMBER 31, 2016 $ 1,455.0
$ 502.6
$ 1,957.6

Capital Contributions from Member 125.5
125.5
Net Income 57.0
57.0
TOTAL MEMBER’S EQUITY – MARCH 31, 2017 $ 1,580.5
$ 559.6
$ 2,140.1

TOTAL MEMBER’S EQUITY – DECEMBER 31, 2017 $ 1,816.6
$ 788.7
$ 2,605.3

Capital Contributions from Member 65.0
65.0
Net Income 85.9
85.9
TOTAL MEMBER’S EQUITY – MARCH 31, 2018 $ 1,881.6
$ 874.6
$ 2,756.2

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, ~~2018~~2024 and December 31, ~~2017~~2023

(in millions)

(Unaudited)


	March 31,		December 31,
	2024		2023
CURRENT ASSETS
Advances to Affiliates	$	298.0	$	67.1
Accounts Receivable:
Customers	80.6		82.2
Affiliated Companies	131.1		125.5

Total Accounts Receivable	211.7		207.7



Prepayments and Other Current Assets	11.2		4.0
TOTAL CURRENT ASSETS	520.9		278.8

TRANSMISSION PROPERTY
Transmission Property	13,832.4		13,723.9
Other Property, Plant and Equipment	503.5		501.4
Construction Work in Progress	1,805.0		1,563.7
Total Transmission Property	16,140.9		15,789.0
Accumulated Depreciation and Amortization	1,362.7		1,291.3
TOTAL TRANSMISSION PROPERTY – NET	14,778.2		14,497.7

OTHER NONCURRENT ASSETS

Regulatory Assets	2.4		3.1
Deferred Property Taxes	250.1		286.4
Deferred Charges and Other Noncurrent Assets	7.4		6.5
TOTAL OTHER NONCURRENT ASSETS	259.9		296.0

TOTAL ASSETS	$	15,559.0	$	15,072.5

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

March 31, December 31,
2018 2017
CURRENT ASSETS
Advances to Affiliates $ 32.1
$ 146.3
Accounts Receivable:
Customers 20.5
19.1
Affiliated Companies 102.0
93.2
Miscellaneous 1.2
1.3
Total Accounts Receivable 123.7
113.6
Materials and Supplies 15.5
13.6
Accrued Tax Benefits 40.1
46.6
Prepayments and Other Current Assets 2.8
7.6
TOTAL CURRENT ASSETS 214.2
327.7

TRANSMISSION PROPERTY
Transmission Property 5,458.3
5,336.1
Other Property, Plant and Equipment 137.1
131.4
Construction Work in Progress 1,512.6
1,312.7
Total Transmission Property 7,108.0
6,780.2
Accumulated Depreciation and Amortization 192.7
170.4
TOTAL TRANSMISSION PROPERTY – NET
6,915.3
6,609.8

OTHER NONCURRENT ASSETS
Regulatory Assets 8.9
11.7
Deferred Property Taxes 100.5
117.8
Deferred Charges and Other Noncurrent Assets 1.0
1.1
TOTAL OTHER NONCURRENT ASSETS 110.4
130.6

TOTAL ASSETS $ 7,239.9
$ 7,068.1

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND MEMBER’S EQUITY

March 31, ~~2018~~2024 and December 31, ~~2017~~

~~(in millions)~~2023

(Unaudited)


	March 31,		December 31,
	2024		2023
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	28.8	$	174.3
Accounts Payable:
General	289.6		274.7
Affiliated Companies	120.7		107.9

Long-term Debt Due Within One Year – Nonaffiliated	145.0		95.0
Accrued Taxes	505.3		568.6
Accrued Interest	56.8		39.6
Obligations Under Operating Leases	1.3		1.3

Other Current Liabilities	20.4		24.7
TOTAL CURRENT LIABILITIES	1,167.9		1,286.1

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	5,715.7		5,319.4
Deferred Income Taxes	1,175.4		1,147.7
Regulatory Liabilities	809.4		783.7
Obligations Under Operating Leases	1.2		1.4
Deferred Credits and Other Noncurrent Liabilities	189.9		200.9
TOTAL NONCURRENT LIABILITIES	7,891.6		7,453.1

TOTAL LIABILITIES	9,059.5		8,739.2

Rate Matters (Note 4)
Commitments and Contingencies (Note 5)

MEMBER’S EQUITY
Paid-in Capital	3,068.4		3,043.4
Retained Earnings	3,431.1		3,289.9
TOTAL MEMBER’S EQUITY	6,499.5		6,333.3

TOTAL LIABILITIES AND MEMBER’S EQUITY	$	15,559.0	$	15,072.5

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

March 31, December 31,
2018 2017

CURRENT LIABILITIES
Advances from Affiliates $ 282.1
$ 15.7
Accounts Payable:
General 210.5
473.2
Affiliated Companies 41.3
52.9
Long-term Debt Due Within One Year – Nonaffiliated 50.0
50.0
Accrued Taxes 185.3
225.4
Accrued Interest 38.3
15.0
Provision for Refund 47.6
—
Other Current Liabilities 2.6
4.1
TOTAL CURRENT LIABILITIES 857.7
836.3

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated 2,500.7
2,500.4
Deferred Income Taxes 621.3
601.7
Regulatory Liabilities 497.2
493.7
Deferred Credits and Other Noncurrent Liabilities 6.8
30.7
TOTAL NONCURRENT LIABILITIES 3,626.0
3,626.5

TOTAL LIABILITIES 4,483.7
4,462.8

Rate Matters (Note 4)

Commitments and Contingencies (Note 5)

MEMBER’S EQUITY
Paid-in Capital 1,881.6
1,816.6
Retained Earnings 874.6
788.7
TOTAL MEMBER’S EQUITY 2,756.2
2,605.3

TOTAL LIABILITIES AND MEMBER’S EQUITY $ 7,239.9
$ 7,068.1

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)


	Three Months Ended March 31,
	2024		2023
OPERATING ACTIVITIES
Net Income	$	181.2	$	162.7
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	105.9		95.2
Deferred Income Taxes	25.0		20.6
Allowance for Equity Funds Used During Construction	(17.9)		(16.4)
Property Taxes	36.3		34.6

Change in Other Noncurrent Assets	(0.4)		0.9
Change in Other Noncurrent Liabilities	(6.1)		6.6
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(4.0)		(12.5)
Materials and Supplies	—		(4.1)
Accounts Payable	5.4		41.0
Accrued Taxes, Net	(63.2)		(59.9)

Other Current Assets	1.0		1.0
Other Current Liabilities	10.8		29.6
Net Cash Flows from Operating Activities	274.0		299.3

INVESTING ACTIVITIES
Construction Expenditures	(336.5)		(439.7)
Change in Advances to Affiliates, Net	(230.9)		(293.1)


Other Investing Activities	7.8		(0.8)
Net Cash Flows Used for Investing Activities	(559.6)		(733.6)

FINANCING ACTIVITIES
Capital Contribution from Member	25.0		25.0

Issuance of Long-term Debt – Nonaffiliated	446.1		689.2
Change in Advances from Affiliates, Net	(145.5)		(224.9)
Dividends Paid to Member	(40.0)		(55.0)

Net Cash Flows from Financing Activities	285.6		434.3

Net Change in Cash and Cash Equivalents	—		—
Cash and Cash Equivalents at Beginning of Period	—		—
Cash and Cash Equivalents at End of Period	$	—	$	—

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	33.3	$	16.2

Construction Expenditures Included in Current Liabilities as of March 31,	191.0		305.4

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Three Months Ended March 31,
2018 2017
OPERATING ACTIVITIES
Net Income $ 85.9
$ 57.0
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 30.6
23.3
Deferred Income Taxes 15.7
74.1
Allowance for Equity Funds Used During Construction (15.3 ) (10.9 )
Property Taxes 17.3
16.8
Change in Other Noncurrent Assets 2.7
2.2
Change in Other Noncurrent Liabilities 23.9
8.3
Changes in Certain Components of Working Capital:
Accounts Receivable, Net (10.1 ) (39.0 )
Materials and Supplies (1.9 ) (3.8 )
Accounts Payable (12.3 ) (8.2 )
Accrued Taxes, Net (33.6 ) (79.1 )
Accrued Interest 23.3
17.6
Other Current Assets 0.3
0.2
Other Current Liabilities 0.6
—
Net Cash Flows from Operating Activities 127.1
58.5

INVESTING ACTIVITIES
Construction Expenditures (571.8 ) (390.4 )
Change in Advances to Affiliates, Net 114.2
56.9
Acquisitions of Assets (1.8 ) (0.6 )
Other Investing Activities 1.0
—
Net Cash Flows Used for Investing Activities (458.4 ) (334.1 )

FINANCING ACTIVITIES
Capital Contributions from Member 65.0
125.5
Change in Advances from Affiliates, Net 266.4
150.9
Other Financing Activities (0.1 ) (0.8 )
Net Cash Flows from Financing Activities 331.3
275.6

Net Change in Cash and Cash Equivalents —
—
Cash and Cash Equivalents at Beginning of Period —
—
Cash and Cash Equivalents at End of Period $ —
$ —

SUPPLEMENTARY INFORMATION
Net Cash Paid (Received) for Income Taxes $ —
$ (0.6 )
Construction Expenditures Included in Current Liabilities as of March 31, 210.6
189.2

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

~~APPALACHIAN POWER COMPANY~~

~~AND SUBSIDIARIES~~

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales



	Three Months Ended March 31,
	2024	2023
	(in millions of KWhs)
Retail:
Residential	3,265	3,059
Commercial	1,475	1,403
Industrial	2,102	2,109
Miscellaneous	211	200
Total Retail	7,053	6,771

Wholesale	654	489

Total KWhs	7,707	7,260

Three Months Ended March 31,
2018 2017
(in millions of KWhs)
Retail:

Residential 3,845
3,250
Commercial 1,694
1,591
Industrial 2,377
2,299
Miscellaneous 224
210
Total Retail 8,140
7,350

Wholesale 495
806

Total KWhs 8,635
8,156

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.

Summary of Heating and Cooling Degree Days



	Three Months Ended March 31,
	2024	2023
	(in degree days)
Actual – Heating (a)	981	859
Normal – Heating (b)	1,310	1,321

Actual – Cooling (c)	2	8
Normal – Cooling (b)	6	6

Three Months Ended March 31,
2018 2017
(in degree days)
Actual – Heating (a) 1,389
955
Normal – Heating (b) 1,317
1,328

Actual – Cooling (c) 8
2
Normal – Cooling (b) 7
7

(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.

~~First Quarter of 2018 Compared to First Quarter of 2017~~

Reconciliation of First Quarter of 2017 to First Quarter of 2018
Net Income
(in millions)

First Quarter of 2017 $ 110.6

Changes in Gross Margin:
Retail Margins 15.0
Off-system Sales (0.2 )
Transmission Revenues (1.9 )
Other Revenues (2.2 )
Total Change in Gross Margin 10.7

Changes in Expenses and Other:
Other Operation and Maintenance (25.1 )
Depreciation and Amortization (7.9 )
Taxes Other Than Income Taxes (3.6 )
Carrying Costs Income 0.2
Allowance for Equity Funds Used During Construction 1.1
Non-Service Cost Components of Net Periodic Benefit Cost 3.2
Interest Expense 0.7
Total Change in Expenses and Other (31.4 )

Income Tax Expense 35.6

First Quarter of 2018 $ 125.5


Appalachian Power Company and Subsidiaries
Reconciliation of First Quarter of 2023 to First Quarter of 2024
Net Income
(in millions)


First Quarter of 2023	$	112.5

Changes in Revenues:
Retail Revenues	90.4
Off-system Sales	(0.6)
Transmission Revenues	6.4
Other Revenues	9.1
Total Change in Revenues	105.3

Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	(57.1)
Other Operation and Maintenance	(27.7)


Depreciation and Amortization	(6.8)
Taxes Other Than Income Taxes	(4.2)
Interest Income	0.2

Allowance for Equity Funds Used During Construction	0.5
Non-Service Cost Components of Net Periodic Benefit Cost	(1.0)
Interest Expense	(2.8)
Total Change in Expenses and Other	(98.9)

Income Tax Expense	17.6

First Quarter of 2024	$	136.5

•Retail ~~Margins~~Revenues increased ~~$15~~$90 million primarily due to the following:

•A ~~$50~~$46 million increase in rider revenues.

•A $28 million increase in fuel revenue primarily due to authorized fuel rate increases in West Virginia.

•A $17 million increase in weather-related usage ~~primarily due to~~driven by a ~~45%~~14% increase in heating degree days.

~~An $11~~•Transmission Revenues increased $6 million ~~increase~~ primarily due to ~~increases~~lower PJM rates in 2023 for certain point-to-point transmission services resulting from ~~rate riders in Virginia. This increase is partially offset by~~ a ~~corresponding increase in~~ December 2022 FERC approved settlement agreement.

•Other ~~Operation and Maintenance expenses.~~

~~These increases were partially offset by:~~

~~A $32~~Revenues increased $9 million ~~decrease~~primarily due to ~~the 2018 provisions for customer refunds primarily related to Tax Reform. This decrease is offset in Income Tax Expense below.~~pole attachment revenue.

~~A $5 million decrease in weather-normalized margins occurring primarily in the residential and industrial classes.~~

~~A $4 million decrease due to increased fuel and other variable production costs not recovered through fuel or other trackers.~~

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $57 million primarily due to a $37 million increase in West Virginia fuel over-recovery and a $21 million increase in load.

•Other Operation and Maintenance expenses increased ~~$25~~$28 million primarily due to the following:

•A ~~$12~~$23 million increase in transmission expenses primarily due to an increase in recoverable PJM ~~transmission~~ expenses. ~~This~~

•A $10 million increase isin distribution expenses primarily due to vegetation management expenses.

These increases were partially offset ~~within Retail Margins above.~~by:

•A $5 million ~~increase in estimated expense for claims~~decrease due to the January 2024 completion of regulatory asset amortization related to ~~asbestos exposure.~~under-earnings during the 2017-2019 Triennial Review.

~~A $4 million increase in employee-related expenses.~~

•Depreciation and Amortization expenses increased $8$7 million primarily due to a higher depreciable base.

~~Taxes Other Than~~ •Income ~~Taxes~~ ~~increased $4~~Tax Expense decreased $18 million primarily due ~~to the following:~~

~~A $2~~a $14 million increase in ~~property taxes driven by an increase in utility plant.~~

~~A $2 million increase in state gross receipts tax due to a prior period refund.~~amortization of Excess ADIT.

~~Non-Service Cost Components of Net Periodic Cost~~ decreased $3 million primarily due to favorable asset returns for the funded Pension and OPEB plans and by moving to a Medicare Advantage arrangement for post-65 retirees in the Non-UMWA OPEB plan. Additionally, the decrease was partially due to the implementation of ASU 2017-07 in 2018, which eliminated APCo’s ability to capitalize a portion of its non-service cost components.

~~Income Tax Expense~~ ~~decreased $36 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and a decrease in pretax book income.~~

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)


	Three Months Ended March 31,

		2024		2023
REVENUES
Electric Generation, Transmission and Distribution		$	1,024.3	$	914.5
Sales to AEP Affiliates		63.1		69.6
Other Revenues		5.6		3.6
TOTAL REVENUES		1,093.0		987.7

EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation		396.8		339.7



Other Operation		212.6		191.8
Maintenance		80.0		73.1


Depreciation and Amortization		149.8		143.0
Taxes Other Than Income Taxes		46.0		41.8
TOTAL EXPENSES		885.2		789.4

OPERATING INCOME		207.8		198.3

Other Income (Expense):
Interest Income		0.8		0.6

Allowance for Equity Funds Used During Construction		2.9		2.4
Non-Service Cost Components of Net Periodic Benefit Cost		7.1		8.1
Interest Expense		(68.1)		(65.3)

INCOME BEFORE INCOME TAX EXPENSE		150.5		144.1

Income Tax Expense		14.0		31.6

NET INCOME		$	136.5	$	112.5

The common stock of APCo is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Three Months Ended March 31,
2018 2017
REVENUES
Electric Generation, Transmission and Distribution $ 767.5
$ 745.0
Sales to AEP Affiliates 49.4
42.4
Other Revenues 3.5
5.4
TOTAL REVENUES 820.4
792.8

EXPENSES

Fuel and Other Consumables Used for Electric Generation 69.0
167.2
Purchased Electricity for Resale 205.9
90.8
Other Operation 138.2
113.9
Maintenance 72.0
71.2
Depreciation and Amortization 108.5
100.6
Taxes Other Than Income Taxes 33.8
30.2
TOTAL EXPENSES 627.4
573.9

OPERATING INCOME 193.0
218.9

Other Income (Expense):

Interest Income 0.3
0.3
Carrying Costs Income 0.5
0.3
Allowance for Equity Funds Used During Construction 2.6
1.5
Non-Service Cost Components of Net Periodic Benefit Cost 4.5
1.3
Interest Expense (47.4 ) (48.1 )

INCOME BEFORE INCOME TAX EXPENSE 153.5
174.2

Income Tax Expense 28.0
63.6

NET INCOME $ 125.5
$ 110.6



~~The common stock of APCo is wholly-owned by Parent.~~

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)


	Three Months Ended March 31,

		2024		2023
Net Income		$	136.5	$	112.5

OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) in 2024 and 2023, Respectively		(0.2)		(0.2)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.2) in 2024 and 2023, Respectively		(0.3)		(0.8)

TOTAL OTHER COMPREHENSIVE LOSS		(0.5)		(1.0)

TOTAL COMPREHENSIVE INCOME		$	136.0	$	111.5

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Three Months Ended March 31,
2018 2017
Net Income $ 125.5
$ 110.6

OTHER COMPREHENSIVE LOSS, NET OF TAXES

Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) in 2018 and 2017, Respectively (0.2 ) (0.2 )
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.2) and $(0.2) in 2018 and 2017, Respectively (0.8 ) (0.3 )

TOTAL OTHER COMPREHENSIVE LOSS (1.0 ) (0.5 )

TOTAL COMPREHENSIVE INCOME $ 124.5
$ 110.1



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)


	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2022	$	260.4	$	1,828.7	$	2,891.1	$	(4.8)	$	4,975.4



Net Income					112.5				112.5
Other Comprehensive Loss							(1.0)		(1.0)
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2023	$	260.4	$	1,828.7	$	3,003.6	$	(5.8)	$	5,086.9













TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2023	$	260.4	$	1,834.5	$	3,185.5	$	(3.7)	$	5,276.7


Capital Contribution from Parent			100.0						100.0
Net Income					136.5				136.5
Other Comprehensive Loss							(0.5)		(0.5)
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2024	$	260.4	$	1,934.5	$	3,322.0	$	(4.2)	$	5,512.7












See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Common
Stock

Paid-in
Capital

Retained
Earnings

Accumulated
Other
Comprehensive
Income (Loss)
Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2016 $ 260.4
$ 1,828.7
$ 1,502.8
$ (8.4 ) $ 3,583.5

Common Stock Dividends

(30.0 )
(30.0 )
Net Income

110.6

110.6
Other Comprehensive Loss

(0.5 ) (0.5 )
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2017 $ 260.4
$ 1,828.7
$ 1,583.4
$ (8.9 ) $ 3,663.6

TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017 $ 260.4
$ 1,828.7
$ 1,714.1
$ 1.3
$ 3,804.5

Common Stock Dividends

(40.0 )
(40.0 )
ASU 2018-02 Adoption 0.1
0.3
0.4
Net Income

125.5

125.5
Other Comprehensive Loss

(1.0 ) (1.0 )
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 $ 260.4
$ 1,828.7
$ 1,799.7
$ 0.6
$ 3,889.4



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, ~~2018~~2024 and December 31, ~~2017~~2023

(in millions)

(Unaudited)


	March 31,		December 31,
	2024		2023
CURRENT ASSETS
Cash and Cash Equivalents	$	7.6	$	5.0
Restricted Cash for Securitized Funding	8.4		14.9
Advances to Affiliates	37.4		18.9
Accounts Receivable:
Customers	191.1		170.3
Affiliated Companies	100.9		98.8
Accrued Unbilled Revenues	59.8		70.8
Miscellaneous	0.5		0.6
Allowance for Uncollectible Accounts	(2.3)		(2.0)
Total Accounts Receivable	350.0		338.5
Fuel	293.6		315.0
Materials and Supplies	139.8		148.4
Risk Management Assets	8.7		22.4

Regulatory Asset for Under-Recovered Fuel Costs	148.4		155.4

Prepayments and Other Current Assets	25.9		40.5
TOTAL CURRENT ASSETS	1,019.8		1,059.0

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	7,065.3		7,041.3
Transmission	4,747.5		4,711.8
Distribution	5,238.5		5,176.6
Other Property, Plant and Equipment	1,023.1		981.3
Construction Work in Progress	754.5		709.2
Total Property, Plant and Equipment	18,828.9		18,620.2
Accumulated Depreciation and Amortization	5,776.0		5,688.7
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	13,052.9		12,931.5

OTHER NONCURRENT ASSETS
Regulatory Assets	1,107.4		1,155.1
Securitized Assets	126.7		133.4
Employee Benefits and Pension Assets	176.3		171.7

Operating Lease Assets	72.0		73.7
Deferred Charges and Other Noncurrent Assets	197.3		187.5
TOTAL OTHER NONCURRENT ASSETS	1,679.7		1,721.4

TOTAL ASSETS	$	15,752.4	$	15,711.9

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

March 31, December 31,
2018 2017
CURRENT ASSETS
Cash and Cash Equivalents $ 1.2
$ 2.9
Restricted Cash for Securitized Funding 10.1
16.3
Advances to Affiliates 23.5
23.5
Accounts Receivable:
Customers 137.9
123.1
Affiliated Companies 67.6
69.3
Accrued Unbilled Revenues 75.1
74.1
Miscellaneous 1.0
1.1
Allowance for Uncollectible Accounts (3.5 ) (3.7 )
Total Accounts Receivable 278.1
263.9
Fuel 72.1
89.3
Materials and Supplies 97.4
99.5
Risk Management Assets 8.0
24.9
Regulatory Asset for Under-Recovered Fuel Costs 179.5
88.8
Margin Deposits 32.1
14.4
Prepayments and Other Current Assets 11.2
12.7
TOTAL CURRENT ASSETS 713.2
636.2

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation 6,466.9
6,446.9
Transmission 3,032.5
3,019.9
Distribution 3,795.8
3,763.8
Other Property, Plant and Equipment 440.2
427.9
Construction Work in Progress 558.8
483.0
Total Property, Plant and Equipment 14,294.2
14,141.5
Accumulated Depreciation and Amortization 3,956.8
3,896.4
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
10,337.4
10,245.1

OTHER NONCURRENT ASSETS
Regulatory Assets 552.3
573.9
Securitized Assets 276.4
282.3
Long-term Risk Management Assets 2.6
1.1
Deferred Charges and Other Noncurrent Assets 195.1
190.0
TOTAL OTHER NONCURRENT ASSETS 1,026.4
1,047.3

TOTAL ASSETS $ 12,077.0
$ 11,928.6



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, ~~2018~~2024 and December 31, ~~2017~~2023

(Unaudited)


	March 31,		December 31,
	2024		2023
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	—	$	339.6
Accounts Payable:
General	286.7		280.4
Affiliated Companies	107.0		121.3
Long-term Debt Due Within One Year – Nonaffiliated	153.3		538.8

Risk Management Liabilities	18.4		15.9
Customer Deposits	81.4		80.0

Accrued Taxes	146.9		117.6
Accrued Interest	83.0		58.9
Obligations Under Operating Leases	14.3		14.6

Other Current Liabilities	132.3		118.8
TOTAL CURRENT LIABILITIES	1,023.3		1,685.9

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	5,517.6		5,049.5



Deferred Income Taxes	2,019.8		2,011.9
Regulatory Liabilities and Deferred Investment Tax Credits	1,082.5		1,081.9
Asset Retirement Obligations	441.5		442.5
Employee Benefits and Pension Obligations	31.6		32.8
Obligations Under Operating Leases	58.3		59.8
Deferred Credits and Other Noncurrent Liabilities	65.1		70.9
TOTAL NONCURRENT LIABILITIES	9,216.4		8,749.3

TOTAL LIABILITIES	10,239.7		10,435.2

Rate Matters (Note 4)
Commitments and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 30,000,000 Shares
Outstanding – 13,499,500 Shares	260.4		260.4
Paid-in Capital	1,934.5		1,834.5
Retained Earnings	3,322.0		3,185.5
Accumulated Other Comprehensive Income (Loss)	(4.2)		(3.7)
TOTAL COMMON SHAREHOLDER’S EQUITY	5,512.7		5,276.7

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	15,752.4	$	15,711.9

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

March 31, December 31,
2018 2017
(in millions)
CURRENT LIABILITIES
Advances from Affiliates $ 245.9
$ 186.0
Accounts Payable:

General 218.1
264.9
Affiliated Companies 88.1
92.7
Long-term Debt Due Within One Year – Nonaffiliated 249.5
249.2
Risk Management Liabilities 0.6
1.3
Customer Deposits 86.5
86.1
Accrued Taxes 119.0
94.5
Accrued Interest 62.9
40.5
Other Current Liabilities 111.3
109.0
TOTAL CURRENT LIABILITIES 1,181.9
1,124.2

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated 3,719.8
3,730.9
Long-term Risk Management Liabilities 0.4
0.2
Deferred Income Taxes 1,586.0
1,565.7
Regulatory Liabilities and Deferred Investment Tax Credits 1,444.3
1,454.9
Asset Retirement Obligations 98.4
100.2
Employee Benefits and Pension Obligations 68.6
73.3
Deferred Credits and Other Noncurrent Liabilities 88.2
74.7
TOTAL NONCURRENT LIABILITIES 7,005.7
6,999.9

TOTAL LIABILITIES 8,187.6
8,124.1

Rate Matters (Note 4)

Commitments and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 30,000,000 Shares

Outstanding – 13,499,500 Shares 260.4
260.4
Paid-in Capital 1,828.7
1,828.7
Retained Earnings 1,799.7
1,714.1
Accumulated Other Comprehensive Income (Loss) 0.6
1.3
TOTAL COMMON SHAREHOLDER’S EQUITY 3,889.4
3,804.5

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $ 12,077.0
$ 11,928.6



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)


	Three Months Ended March 31,
	2024		2023
OPERATING ACTIVITIES
Net Income	$	136.5	$	112.5
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	149.8		143.0
Deferred Income Taxes	(12.8)		10.3



Allowance for Equity Funds Used During Construction	(2.9)		(2.4)
Mark-to-Market of Risk Management Contracts	11.8		60.1


Deferred Fuel Over/Under-Recovery, Net	62.4		26.0

Change in Other Noncurrent Assets	3.9		(5.5)
Change in Other Noncurrent Liabilities	6.5		(33.0)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(10.6)		54.5
Fuel, Materials and Supplies	30.0		(59.3)
Margin Deposits	11.0		(11.1)
Accounts Payable	(24.7)		(156.1)
Accrued Taxes, Net	33.0		23.6
Other Current Assets	—		2.9
Other Current Liabilities	12.4		(1.2)
Net Cash Flows from Operating Activities	406.3		164.3

INVESTING ACTIVITIES
Construction Expenditures	(236.0)		(287.4)

Change in Advances to Affiliates, Net	(18.5)		1.1

Other Investing Activities	3.6		1.5
Net Cash Flows Used for Investing Activities	(250.9)		(284.8)

FINANCING ACTIVITIES
Capital Contribution from Parent	100.0		—
Issuance of Long-term Debt – Nonaffiliated	395.8		—
Change in Advances from Affiliates, Net	(339.6)		128.0
Retirement of Long-term Debt – Nonaffiliated	(313.4)		(13.0)


Principal Payments for Finance Lease Obligations	(2.2)		(2.0)

Other Financing Activities	0.1		0.2
Net Cash Flows from (Used for) Financing Activities	(159.3)		113.2

Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding	(3.9)		(7.3)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period	19.9		21.9
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period	$	16.0	$	14.6

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	41.5	$	37.9


Noncash Acquisitions Under Finance Leases	0.3		0.6
Construction Expenditures Included in Current Liabilities as of March 31,	107.3		122.6

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Three Months Ended March 31,
2018 2017
OPERATING ACTIVITIES

Net Income $ 125.5
$ 110.6
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:

Depreciation and Amortization 108.5
100.6
Deferred Income Taxes 11.0
52.2
Allowance for Equity Funds Used During Construction (2.6 ) (1.5 )
Mark-to-Market of Risk Management Contracts 14.9
6.8
Deferred Fuel Over/Under-Recovery, Net (90.7 ) 1.1
Change in Other Noncurrent Assets 3.9
1.0
Change in Other Noncurrent Liabilities 37.9
(3.7 )
Changes in Certain Components of Working Capital:

Accounts Receivable, Net (14.2 ) (2.2 )
Fuel, Materials and Supplies 19.3
(6.9 )
Accounts Payable (21.6 ) (12.7 )
Accrued Taxes, Net 17.8
9.4
Other Current Assets (15.8 ) 7.8
Other Current Liabilities 5.6
(3.5 )
Net Cash Flows from Operating Activities 199.5
259.0

INVESTING ACTIVITIES

Construction Expenditures (218.5 ) (223.7 )
Change in Advances to Affiliates, Net —
0.4
Other Investing Activities 4.4
1.4
Net Cash Flows Used for Investing Activities (214.1 ) (221.9 )

FINANCING ACTIVITIES

Change in Advances from Affiliates, Net 59.9
102.8
Retirement of Long-term Debt – Nonaffiliated (11.7 ) (115.9 )
Principal Payments for Capital Lease Obligations (1.7 ) (1.8 )
Dividends Paid on Common Stock (40.0 ) (30.0 )
Other Financing Activities 0.2
0.3
Net Cash Flows from (Used for) Financing Activities 6.7
(44.6 )

Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding (7.9 ) (7.5 )
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period 19.2
18.5
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period $ 11.3
$ 11.0

SUPPLEMENTARY INFORMATION

Cash Paid for Interest, Net of Capitalized Amounts $ 23.4
$ 23.8
Noncash Acquisitions Under Capital Leases 1.8
0.5
Construction Expenditures Included in Current Liabilities as of March 31, 94.5
63.7



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

~~INDIANA MICHIGAN POWER COMPANY~~

~~AND SUBSIDIARIES~~

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales



	Three Months Ended March 31,
	2024	2023
	(in millions of KWhs)
Retail:
Residential	1,438	1,463
Commercial	1,275	1,189
Industrial	1,808	1,804
Miscellaneous	14	16
Total Retail	4,535	4,472

Wholesale	1,620	1,417

Total KWhs	6,155	5,889

Three Months Ended March 31,
2018 2017
(in millions of KWhs)
Retail:

Residential 1,623
1,492
Commercial 1,176
1,157
Industrial 1,904
1,896
Miscellaneous 20
20
Total Retail 4,723
4,565

Wholesale 2,926
2,954

Total KWhs 7,649
7,519

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.

Summary of Heating and Cooling Degree Days



	Three Months Ended March 31,
	2024	2023
	(in degree days)
Actual – Heating (a)	1,685	1,687
Normal – Heating (b)	2,181	2,182

Actual – Cooling (c)	—	—
Normal – Cooling (b)	1	1

Three Months Ended March 31,
2018 2017
(in degree days)
Actual – Heating (a) 2,157
1,648
Normal – Heating (b) 2,168
2,185

Actual – Cooling (c) —
—
Normal – Cooling (b) 2
2

(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.

~~First Quarter of 2018 Compared to First Quarter of 2017~~

Reconciliation of First Quarter of 2017 to First Quarter of 2018
Net Income
(in millions)

First Quarter of 2017 $ 68.4

Changes in Gross Margin:
Retail Margins 3.2
Off-system Sales 0.4
Transmission Revenues 2.8
Other Revenues (2.7 )
Total Change in Gross Margin 3.7

Changes in Expenses and Other:
Other Operation and Maintenance (12.1 )
Depreciation and Amortization (9.3 )
Taxes Other Than Income Taxes (2.1 )
Interest Income (0.9 )
Carrying Cost Income (1.0 )
Allowance for Equity Funds Used During Construction (0.3 )
Non-Service Cost Components of Net Periodic Benefit Cost 3.0
Interest Expense (2.0 )
Total Change in Expenses and Other (24.7 )

Income Tax Expense 16.8

First Quarter of 2018 $ 64.2


Indiana Michigan Power Company and Subsidiaries
Reconciliation of First Quarter of 2023 to First Quarter of 2024
Net Income
(in millions)


First Quarter of 2023	$	102.8

Changes in Revenues:
Retail Revenues	(1.9)
Off-system Sales	1.2
Transmission Revenues	4.5
Other Revenues	0.6
Total Change in Revenues	4.4

Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	(23.4)
Purchased Electricity from AEP Affiliates	(16.4)
Other Operation and Maintenance	(2.3)
Depreciation and Amortization	16.9
Taxes Other Than Income Taxes	(3.8)
Other Income	2.6

Non-Service Cost Components of Net Periodic Benefit Cost	(1.3)
Interest Expense	7.0
Total Change in Expenses and Other	(20.7)

Income Tax Expense	58.5

First Quarter of 2024	$	145.0

•Retail ~~Margins~~ ~~increased $3~~Revenues decreased $2 million primarily due to the following:

•A ~~$25~~$13 million ~~increase from rate proceedings in the I&M service territory. The increase in Retail Margins relating to riders has corresponding increases in other items below.~~

~~A $14 million increase in weather-related usage primarily~~decrease due to a ~~31% increase~~regulatory provision for refund.

•An $11 million decrease in ~~heating degree days.~~weather-normalized retail margins primarily in the residential and industrial classes.

These ~~increases~~decreases were partially offset by:

•A ~~$16~~$15 million ~~decrease related to the 2018 provisions for customer refunds primarily related to Tax Reform. This decrease is offset~~increase in ~~Income Tax Expense below.~~

~~An $8 million decrease related to over/under recovery of riders.~~

~~A $4 million decrease due to lower weather-normalized margins primarily due to wholesale customer load loss from contracts that expired at the end of 2017.~~

~~A $4 million decrease in FERC generation wholesale municipal and cooperative~~fuel revenues primarily due to ~~changes to the annual formula rate.~~an increase in generation at Rockport Plant.

•A $3$5 million ~~decrease due to increased fuel and other variable production costs not recovered through fuel clauses or other trackers.~~increase in rider revenues.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $23 million primarily due to an increase in generation at Rockport Plant and a purchased power disallowance in the April 2024 MPSC order on I&M’s 2021 PSCR reconciliation.

•Purchased Electricity from AEP Affiliates increased $16 million primarily due to an increase in purchased electricity from Rockport Plant.

•Other Operation and Maintenance expenses increased ~~$12~~$2 million primarily due to the following:

~~A $12~~•An $11 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.

This increase was partially offset ~~within Retail Margins above.~~by:

•A $4 million ~~increase~~decrease in nuclear expenses at Cook Plant ~~refueling outage amortization expense,~~ primarily due to ~~increased costs of outages.~~lower refueling outage expenses.

~~These increases were partially offset by:~~

•A $7$3 million decrease due to an increased Nuclear Electric Insurance Limited distribution in ~~2018.~~2024.

•A $3 million decrease in vegetation management expenses.

•Depreciation and Amortization expenses~~increased $9 million primarily due to a higher depreciable base.~~

~~Non-Service Cost Components of Net Periodic Benefit Cost~~ decreased $3 million primarily due to favorable asset returns for the funded Pension and OPEB plans and by moving to a Medicare Advantage arrangement for post-65 retirees in the Non-UMWA OPEB plan. Additionally, the decrease was partially due to the implementation of ASU 2017-07 in 2018, which eliminated I&M’s ability to capitalize a portion of its non-service cost components.

~~Income Tax Expense~~decreased $17 million primarily due to the ~~change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018~~deferral of Excess ADIT as a result of the PLR received regarding the treatment of stand alone NOLCs and the timing of refunds to customers under rate rider mechanisms.

•Interest Expense decreased $7 millionprimarily due to the recognition of debt carrying charges as a result of the IRS PLR received regarding the treatment of stand alone NOLCs in retail rate making.

•Income Tax ~~Reform and~~Expense decreased $59 million primarily due to a ~~decrease~~reduction in ~~pretax book income.~~Excess ADIT regulatory liabilities as a result of the IRS PLR received regarding the treatment of stand alone NOLCs in retail rate making.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2024		2023
REVENUES
Electric Generation, Transmission and Distribution	$	647.8	$	642.8
Sales to AEP Affiliates	1.8		1.2
Other Revenues – Affiliated	15.0		15.9
Other Revenues – Nonaffiliated	2.8		3.1
TOTAL REVENUES	667.4		663.0

EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	122.6		99.2

Purchased Electricity from AEP Affiliates	61.5		45.1
Other Operation	178.2		169.7
Maintenance	52.4		58.6

Depreciation and Amortization	108.3		125.2
Taxes Other Than Income Taxes	23.3		19.5
TOTAL EXPENSES	546.3		517.3

OPERATING INCOME	121.1		145.7

Other Income (Expense):
Other Income	3.2		0.6



Non-Service Cost Components of Net Periodic Benefit Cost	6.7		8.0
Interest Expense	(26.2)		(33.2)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	104.8		121.1

Income Tax Expense (Benefit)	(40.2)		18.3

NET INCOME	$	145.0	$	102.8

The common stock of I&M is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Three Months Ended March 31,
2018 2017
REVENUES
Electric Generation, Transmission and Distribution $ 553.9
$ 538.5
Sales to AEP Affiliates 4.7
0.6
Other Revenues – Affiliated 13.2
18.1
Other Revenues – Nonaffiliated 5.0
3.3
TOTAL REVENUES 576.8
560.5

EXPENSES

Fuel and Other Consumables Used for Electric Generation 77.5
90.7
Purchased Electricity for Resale 55.6
37.3
Purchased Electricity from AEP Affiliates 61.4
53.9
Other Operation 146.1
137.1
Maintenance 54.5
51.4
Depreciation and Amortization 59.3
50.0
Taxes Other Than Income Taxes 25.0
22.9
TOTAL EXPENSES 479.4
443.3

OPERATING INCOME 97.4
117.2

Other Income (Expense):

Interest Income 0.2
1.1
Carrying Costs Income 2.4
3.4
Allowance for Equity Funds Used During Construction 1.8
2.1
Non-Service Cost Components of Net Periodic Benefit Cost 4.5
1.5
Interest Expense (29.7 ) (27.7 )

INCOME BEFORE INCOME TAX EXPENSE 76.6
97.6

Income Tax Expense 12.4
29.2

NET INCOME $ 64.2
$ 68.4

~~The common stock of I&M is wholly-owned by Parent.~~

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2024		2023
Net Income	$	145.0	$	102.8

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $(0.2) for 2024 and 2023, Respectively	0.1		(0.7)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $(0.5) for 2024 and 2023, Respectively	—		(1.9)

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	0.1		(2.6)

TOTAL COMPREHENSIVE INCOME	$	145.1	$	100.2

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Three Months Ended March 31,
2018 2017
Net Income $ 64.2
$ 68.4

OTHER COMPREHENSIVE INCOME, NET OF TAXES

Cash Flow Hedges, Net of Tax of $0.1 and $0.2 in 2018 and 2017, Respectively 0.4
0.3

TOTAL COMPREHENSIVE INCOME $ 64.6
$ 68.7

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)


	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2022	$	56.6	$	988.8	$	1,963.2	$	(0.3)	$	3,008.3


Common Stock Dividends					(31.2)				(31.2)
Net Income					102.8				102.8
Other Comprehensive Loss							(2.6)		(2.6)
TOTAL COMMON SHAREHOLDER'S EQUITY -MARCH 31, 2023	$	56.6	$	988.8	$	2,034.8	$	(2.9)	$	3,077.3













TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2023	$	56.6	$	997.6	$	2,086.6	$	(0.6)	$	3,140.2


Common Stock Dividends					(37.5)				(37.5)
Net Income					145.0				145.0
Other Comprehensive Income							0.1		0.1
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2024	$	56.6	$	997.6	$	2,194.1	$	(0.5)	$	3,247.8













See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Common
Stock Paid-in
Capital Retained
Earnings Accumulated
Other
Comprehensive
Income (Loss) Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2016 $ 56.6
$ 980.9
$ 1,130.5
$ (16.2 ) $ 2,151.8

Common Stock Dividends

(31.3 )
(31.3 )
Net Income

68.4

68.4
Other Comprehensive Income

0.3
0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2017 $ 56.6
$ 980.9
$ 1,167.6
$ (15.9 ) $ 2,189.2

TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017 $ 56.6
$ 980.9
$ 1,192.2
$ (12.1 ) $ 2,217.6

Common Stock Dividends

(33.5 )
(33.5 )
ASU 2018-02 Adoption 0.3
(2.7 ) (2.4 )
Net Income

64.2

64.2
Other Comprehensive Income

0.4
0.4
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 $ 56.6
$ 980.9
$ 1,223.2
$ (14.4 ) $ 2,246.3

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, ~~2018~~2024 and December 31, ~~2017~~2023

(in millions)

(Unaudited)


	March 31,		December 31,
	2024		2023
CURRENT ASSETS
Cash and Cash Equivalents	$	5.5	$	2.1

Accounts Receivable:
Customers	51.1		66.9
Affiliated Companies	87.4		65.0
Accrued Unbilled Revenues	0.2		0.2
Miscellaneous	4.2		8.2

Total Accounts Receivable	142.9		140.3
Fuel	72.8		88.1
Materials and Supplies	202.2		208.2
Risk Management Assets	11.2		27.8

Regulatory Asset for Under-Recovered Fuel Costs	3.8		14.8


Prepayments and Other Current Assets	41.6		46.7
TOTAL CURRENT ASSETS	480.0		528.0

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	5,664.8		5,646.8
Transmission	1,917.0		1,906.4
Distribution	3,322.7		3,254.0
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	891.3		898.5
Construction Work in Progress	314.4		301.7
Total Property, Plant and Equipment	12,110.2		12,007.4
Accumulated Depreciation, Depletion and Amortization	4,459.0		4,378.4
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	7,651.2		7,629.0

OTHER NONCURRENT ASSETS
Regulatory Assets	498.2		406.3
Spent Nuclear Fuel and Decommissioning Trusts	4,112.6		3,860.2

Operating Lease Assets	51.2		53.8
Deferred Charges and Other Noncurrent Assets	318.3		330.7
TOTAL OTHER NONCURRENT ASSETS	4,980.3		4,651.0

TOTAL ASSETS	$	13,111.5	$	12,808.0

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

March 31, December 31,
2018 2017
CURRENT ASSETS
Cash and Cash Equivalents $ 0.6
$ 1.3
Advances to Affiliates 12.5
12.4
Accounts Receivable:
Customers 48.7
56.4
Affiliated Companies 49.9
50.0
Accrued Unbilled Revenues 8.1
7.3
Miscellaneous 5.4
2.0
Allowance for Uncollectible Accounts —
(0.1 )
Total Accounts Receivable 112.1
115.6
Fuel 35.2
31.4
Materials and Supplies 161.6
160.6
Risk Management Assets 3.3
7.6
Accrued Tax Benefits 65.0
58.4
Regulatory Asset for Under-Recovered Fuel Costs 12.4
15.0
Accrued Reimbursement of Spent Nuclear Fuel Costs 6.2
10.8
Margin Deposits 25.6
11.5
Prepayments and Other Current Assets 13.6
9.4
TOTAL CURRENT ASSETS 448.1
434.0

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation 4,464.5
4,445.9
Transmission 1,523.5
1,504.0
Distribution 2,097.3
2,069.3
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 610.9
595.2
Construction Work in Progress 503.5
460.2
Total Property, Plant and Equipment 9,199.7
9,074.6
Accumulated Depreciation, Depletion and Amortization 3,073.1
3,024.2
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
6,126.6
6,050.4

OTHER NONCURRENT ASSETS
Regulatory Assets 589.2
579.4
Spent Nuclear Fuel and Decommissioning Trusts 2,510.6
2,527.6
Long-term Risk Management Assets 2.0
0.7
Deferred Charges and Other Noncurrent Assets 168.4
179.9
TOTAL OTHER NONCURRENT ASSETS 3,270.2
3,287.6

TOTAL ASSETS $ 9,844.9
$ 9,772.0

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, ~~2018~~2024 and December 31, ~~2017~~2023

(dollars in millions)

(Unaudited)


	March 31,		December 31,
	2024		2023
CURRENT LIABILITIES
Advances from Affiliates	$	73.2	$	63.3
Accounts Payable:
General	182.1		225.8
Affiliated Companies	115.9		107.3
Long-term Debt Due Within One Year – Nonaffiliated (March 31, 2024 and December 31, 2023 Amounts Include $74.8 and $81.4, Respectively, Related to DCC Fuel)	76.9		83.7

Customer Deposits	52.1		72.2
Accrued Taxes	133.5		104.7
Accrued Interest	38.1		41.3

Obligations Under Operating Leases	14.9		16.8
Regulatory Liability for Over-Recovered Fuel Costs	22.3		23.2
Other Current Liabilities	74.3		91.9
TOTAL CURRENT LIABILITIES	783.3		830.2

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	3,401.6		3,415.7

Deferred Income Taxes	1,190.6		1,169.9
Regulatory Liabilities and Deferred Investment Tax Credits	2,262.3		2,052.3
Asset Retirement Obligations	2,123.0		2,104.3
Obligations Under Operating Leases	37.1		37.7
Deferred Credits and Other Noncurrent Liabilities	65.8		57.7
TOTAL NONCURRENT LIABILITIES	9,080.4		8,837.6

TOTAL LIABILITIES	9,863.7		9,667.8

Rate Matters (Note 4)
Commitments and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 2,500,000 Shares
Outstanding – 1,400,000 Shares	56.6		56.6
Paid-in Capital	997.6		997.6
Retained Earnings	2,194.1		2,086.6
Accumulated Other Comprehensive Income (Loss)	(0.5)		(0.6)
TOTAL COMMON SHAREHOLDER’S EQUITY	3,247.8		3,140.2

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	13,111.5	$	12,808.0

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

March 31, December 31,
2018 2017
CURRENT LIABILITIES
Advances from Affiliates $ 314.1
$ 211.6
Accounts Payable:
General 164.8
154.5
Affiliated Companies 81.4
98.3
Long-term Debt Due Within One Year – Nonaffiliated
(March 31, 2018 and December 31, 2017 Amounts Include $88.1 and $96.3, Respectively, Related to DCC Fuel)
941.5
474.7
Risk Management Liabilities 3.8
3.5
Customer Deposits 38.0
37.7
Accrued Taxes 89.6
81.3
Accrued Interest 14.8
37.5
Obligations Under Capital Leases 5.8
5.8
Other Current Liabilities 102.7
106.4
TOTAL CURRENT LIABILITIES 1,756.5
1,211.3

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated 1,775.7
2,270.4
Long-term Risk Management Liabilities 0.2
0.1
Deferred Income Taxes 978.3
953.8
Regulatory Liabilities and Deferred Investment Tax Credits 1,660.2
1,708.7
Asset Retirement Obligations 1,336.0
1,321.6
Deferred Credits and Other Noncurrent Liabilities 91.7
88.5
TOTAL NONCURRENT LIABILITIES 5,842.1
6,343.1

TOTAL LIABILITIES 7,598.6
7,554.4

Rate Matters (Note 4)

Commitments and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 2,500,000 Shares
Outstanding – 1,400,000 Shares 56.6
56.6
Paid-in Capital 980.9
980.9
Retained Earnings 1,223.2
1,192.2
Accumulated Other Comprehensive Income (Loss) (14.4 ) (12.1 )
TOTAL COMMON SHAREHOLDER’S EQUITY 2,246.3
2,217.6

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $ 9,844.9
$ 9,772.0

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)


	Three Months Ended March 31,
	2024		2023
OPERATING ACTIVITIES
Net Income	$	145.0	$	102.8
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	108.3		125.2

Deferred Income Taxes	(60.3)		(3.3)
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net	(11.8)		18.1


Allowance for Equity Funds Used During Construction	(3.3)		(0.5)
Mark-to-Market of Risk Management Contracts	27.1		8.8
Amortization of Nuclear Fuel	24.4		25.0

Deferred Fuel Over/Under-Recovery, Net	10.1		3.8
Change in Other Noncurrent Assets	(34.0)		(4.3)
Change in Other Noncurrent Liabilities	35.3		3.7
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(2.1)		52.7
Fuel, Materials and Supplies	21.3		(24.1)

Accounts Payable	(13.5)		(27.8)

Accrued Taxes, Net	28.8		21.1


Other Current Assets	11.9		(1.9)
Other Current Liabilities	(37.3)		(41.8)
Net Cash Flows from Operating Activities	249.9		257.5

INVESTING ACTIVITIES
Construction Expenditures	(142.3)		(141.7)
Change in Advances to Affiliates, Net	—		(37.0)
Purchases of Investment Securities	(588.5)		(536.3)
Sales of Investment Securities	569.5		517.6
Acquisitions of Nuclear Fuel	(33.7)		(1.7)

Other Investing Activities	2.7		3.3
Net Cash Flows Used for Investing Activities	(192.3)		(195.8)

FINANCING ACTIVITIES


Issuance of Long-term Debt – Nonaffiliated	—		499.8
Change in Advances from Affiliates, Net	9.9		(249.9)
Retirement of Long-term Debt – Nonaffiliated	(25.4)		(274.3)
Principal Payments for Finance Lease Obligations	(1.6)		(1.9)
Dividends Paid on Common Stock	(37.5)		(31.2)
Other Financing Activities	0.4		0.1
Net Cash Flows Used for Financing Activities	(54.2)		(57.4)

Net Increase in Cash and Cash Equivalents	3.4		4.3
Cash and Cash Equivalents at Beginning of Period	2.1		4.2
Cash and Cash Equivalents at End of Period	$	5.5	$	8.5

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	38.7	$	44.4
Net Cash Paid for Income Taxes	—		2.4
Noncash Acquisitions Under Finance Leases	0.5		2.2
Construction Expenditures Included in Current Liabilities as of March 31,	63.1		61.3



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Three Months Ended March 31,
2018 2017
OPERATING ACTIVITIES

Net Income $ 64.2
$ 68.4
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:

Depreciation and Amortization 59.3
50.0
Deferred Income Taxes 13.7
48.8
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net (12.3 ) 16.6
Allowance for Equity Funds Used During Construction (1.8 ) (2.1 )
Mark-to-Market of Risk Management Contracts 3.4
2.3
Amortization of Nuclear Fuel 27.4
35.1
Deferred Fuel Over/Under-Recovery, Net 3.4
19.6
Change in Other Noncurrent Assets (13.4 ) (17.6 )
Change in Other Noncurrent Liabilities 33.7
13.5
Changes in Certain Components of Working Capital:

Accounts Receivable, Net 3.5
3.0
Fuel, Materials and Supplies (4.5 ) (8.5 )
Accounts Payable 1.3
(22.5 )
Accrued Taxes, Net 8.2
(6.9 )
Other Current Assets (11.1 ) 15.8
Other Current Liabilities (27.8 ) (41.2 )
Net Cash Flows from Operating Activities 147.2
174.3

INVESTING ACTIVITIES

Construction Expenditures (148.9 ) (159.7 )
Change in Advances to Affiliates, Net (0.1 ) —
Purchases of Investment Securities (525.3 ) (505.5 )
Sales of Investment Securities 508.6
487.9
Acquisitions of Nuclear Fuel (23.8 ) (3.7 )
Other Investing Activities 4.2
2.0
Net Cash Flows Used for Investing Activities (185.3 ) (179.0 )

FINANCING ACTIVITIES

Issuance of Long-term Debt – Nonaffiliated —
76.7
Change in Advances from Affiliates, Net 102.5
71.6
Retirement of Long-term Debt – Nonaffiliated (29.4 ) (109.5 )
Principal Payments for Capital Lease Obligations (2.7 ) (2.9 )
Dividends Paid on Common Stock (33.5 ) (31.3 )
Other Financing Activities 0.5
0.1
Net Cash Flows from Financing Activities 37.4
4.7

Net Decrease in Cash and Cash Equivalents (0.7 ) —
Cash and Cash Equivalents at Beginning of Period 1.3
1.2
Cash and Cash Equivalents at End of Period $ 0.6
$ 1.2

SUPPLEMENTARY INFORMATION

Cash Paid for Interest, Net of Capitalized Amounts $ 50.6
$ 44.3
Net Cash Paid for Income Taxes —
0.6
Noncash Acquisitions Under Capital Leases 1.7
1.5
Construction Expenditures Included in Current Liabilities as of March 31, 77.2
75.9
Acquisition of Nuclear Fuel Included in Current Liabilities as of March 31, 0.1
—
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage 0.1
1.0

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

OHIO POWER COMPANY AND SUBSIDIARIES

~~OHIO POWER COMPANY AND SUBSIDIARIES~~

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales



	Three Months Ended March 31,
	2024	2023
	(in millions of KWhs)
Retail:
Residential	3,751	3,734
Commercial	4,684	4,000
Industrial	3,539	3,418
Miscellaneous	29	30
Total Retail (a)	12,003	11,182

Wholesale (b)	590	453

Total KWhs	12,593	11,635

Three Months Ended March 31,
2018 2017
(in millions of KWhs)
Retail:

Residential 4,133
3,693
Commercial 3,552
3,428
Industrial 3,554
3,569
Miscellaneous 31
32
Total Retail (a) 11,270
10,722

Wholesale (b) 667

674

Total KWhs 11,937
11,396

(a)Represents energy delivered to distribution customers.

(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold ~~into~~to PJM.

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.

Summary of Heating and Cooling Degree Days



	Three Months Ended March 31,
	2024	2023
	(in degree days)
Actual – Heating (a)	1,463	1,344
Normal – Heating (b)	1,871	1,891

Actual – Cooling (c)	—	—
Normal – Cooling (b)	3	3

Three Months Ended March 31,
2018 2017
(in degree days)
Actual – Heating (a) 1,884
1,403
Normal – Heating (b) 1,884
1,899

Actual – Cooling (c) 4
3
Normal – Cooling (b) 3
3

(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.

~~First Quarter of 2018 Compared to First Quarter of 2017~~

Reconciliation of First Quarter of 2017 to First Quarter of 2018
Net Income
(in millions)

First Quarter of 2017 $ 86.2

Changes in Gross Margin:
Retail Margins 31.8
Off-system Sales 7.2
Transmission Revenues (6.4 )
Other Revenues (0.9 )
Total Change in Gross Margin 31.7

Changes in Expenses and Other:
Other Operation and Maintenance (49.9 )
Depreciation and Amortization (7.5 )
Taxes Other Than Income Taxes (6.6 )
Interest Income (1.6 )
Carrying Costs Income (1.2 )
Allowance for Equity Funds Used During Construction 0.1
Non-Service Cost Components of Net Periodic Benefit Cost 2.8
Interest Expense (0.2 )
Total Change in Expenses and Other (64.1 )

Income Tax Expense 25.8

First Quarter of 2018 $ 79.6


Ohio Power Company and Subsidiaries
Reconciliation of First Quarter of 2023 to First Quarter of 2024
Net Income
(in millions)


First Quarter of 2023	$	78.0

Changes in Revenues:
Retail Revenues	(25.5)
Off-system Sales	(3.6)
Transmission Revenues	3.3
Other Revenues	15.0
Total Change in Revenues	(10.8)

Changes in Expenses and Other:
Purchased Electricity for Resale	133.9
Purchased Electricity from AEP Affiliates	(46.6)
Other Operation and Maintenance	(36.4)
Depreciation and Amortization	(30.6)
Taxes Other Than Income Taxes	(15.5)


Other Income	(0.1)
Allowance for Equity Funds Used During Construction	2.7
Non-Service Cost Components of Net Periodic Benefit Cost	(1.0)
Interest Expense	(3.5)
Total Change in Expenses and Other	2.9

Income Tax Expense	0.5


First Quarter of 2024	$	70.6

The major components of the ~~increase~~decrease in ~~Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals~~Revenues were as follows:

•Retail ~~Margins~~ ~~increased $32~~Revenues decreased $26 million primarily due to the following:

•A ~~$39~~$122 million ~~net increase~~decrease due to lower customer participation in ~~Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was~~OPCo’s SSO, partially offset by ~~a corresponding increase~~higher prices.

•A $9 million decrease in ~~Other Operation~~weather-normalized revenues in the residential and ~~Maintenance below.~~industrial classes, partially offset by the commercial class.

~~A $21~~These decreases were partially offset by:

•An $89 million increase in ~~revenues associated with the Universal Service Fund (USF). This increase was offset by a corresponding increase in Other Operation and Maintenance expenses below.~~rider revenues.

•A $9$16 million increase in weather-related usage ~~primarily~~driven by a 9% increase in heating degree days.

•Other Revenues increased $15 million due to the ~~residential class.~~following:

•A $10 million increase due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs.

•A $6 million increase in ~~rider revenues associated with the DIR. This increase was partially offset in various expenses below.~~refundable sales of renewable energy credits.

~~A $4 million net increase in RSR revenues less associated amortizations.~~

~~These increases were partially offset by:~~

~~A $16 million decrease due to the 2018 provisions for customer refunds primarily related to Tax Reform. This decrease is offset in Income Tax Expense below.~~

~~An $11 million decrease in Energy Efficiency/Peak Demand Reduction rider revenues. This decrease was partially offset by a corresponding decrease in Other Operation and Maintenance expenses below.~~

~~A $10 million decrease in margin for the Phase-In-Recovery Rider including associated amortizations.~~

~~A $7 million decrease due to the recovery of lower current year losses from a power contract with OVEC. This decrease was offset by a corresponding increase in Margins from Off-system Sales below.~~

~~A $7 million decrease in revenues associated with smart grid riders. This decrease was partially offset by a corresponding decrease in various expenses below.~~

~~Margins from Off-system Sales~~ ~~increased $7 million primarily due to lower current year losses from a power contract with OVEC which was offset in Retail Margins above as a result of the OVEC PPA rider beginning in January 2017.~~

~~Transmission Revenues~~ ~~decreased $6 million mainly due to the 2018 provisions for customer refunds primarily due to Tax Reform. This decrease is offset in Income Tax Expense below.~~

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

~~Other Operation and Maintenance~~•Purchased Electricity for Resale expenses ~~increased $50~~decreased $134 million primarily due to the following:

•A ~~$35~~$177 million ~~increase~~decrease due to lower auction volumes driven by lower customer participation in ~~recoverable PJM expenses. This increase was~~OPCo’s SSO, partially offset by ~~a corresponding increase in Retail Margins above.~~higher prices.

~~A $21 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers.~~ This ~~increase~~decrease was ~~offset by a corresponding increase in Retail Margins above.~~

~~These increases were~~ partially offset by:

•A ~~$10~~$30 million decrease in ~~Energy Efficiency/Peak Demand Reduction rider costs~~deferrals of recoverable OVEC costs.

•Purchased Electricity from AEP Affiliates expenses increased $47 million primarily due to increased purchases in OPCo’s SSO auction.

•Other Operation and ~~associated deferrals. This decrease was offset by a decrease in Retail Margins above.~~

~~Depreciation and Amortization~~ Maintenanceexpensesincreased $8$36 million primarily due to the following:

•A $6$27 million increase in ~~recoverable DIR depreciation expense. This increase was offset in Retail Margins above.~~

~~A $3 million increase in depreciation expense~~transmission expenses primarily due to an increase in ~~depreciable base of transmission~~recoverable PJM expenses.

•A $16 million increase in distribution expenses primarily related to recoverable storm restoration costs and ~~distribution assets.~~recoverable vegetation management expenses.

~~A $2~~•Depreciation and Amortization expenses increased $31 million ~~increase~~ primarily due to ~~amortization of capitalized software costs.~~

~~These increases were partially offset by:~~

~~A $3 million decrease~~a higher depreciable base and an increase in recoverable ~~smart grid depreciation~~rider depreciable expenses. ~~This decrease was offset in Retail Margins above.~~

•Taxes Other Than Income Taxesincreased ~~by $7~~$16 million primarily due to ~~the following:~~

~~A $4 million increase in~~higher property taxes ~~due to~~driven by additional investments in transmission and distribution assets and higher tax rates.

~~A $3 million increase in state excise taxes due to an increase in metered KWh. This increase was offset by a corresponding increase in Retail Margins above.~~

~~Income Tax Expense~~ ~~decreased $26 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and a decrease in pretax book income.~~

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2024		2023
REVENUES
Electricity, Transmission and Distribution	$	1,015.4	$	1,021.8
Sales to AEP Affiliates	5.7		7.6
Other Revenues	2.7		5.2
TOTAL REVENUES	1,023.8		1,034.6

EXPENSES
Purchased Electricity for Resale	258.7		392.6
Purchased Electricity from AEP Affiliates	46.6		—

Other Operation	293.2		273.8
Maintenance	61.3		44.3
Depreciation and Amortization	105.8		75.2
Taxes Other Than Income Taxes	150.8		135.3
TOTAL EXPENSES	916.4		921.2

OPERATING INCOME	107.4		113.4

Other Income (Expense):


Other Income	—		0.1
Allowance for Equity Funds Used During Construction	5.5		2.8
Non-Service Cost Components of Net Periodic Benefit Cost	5.5		6.5
Interest Expense	(34.6)		(31.1)

INCOME BEFORE INCOME TAX EXPENSE	83.8		91.7

Income Tax Expense	13.2		13.7


NET INCOME	$	70.6	$	78.0

The common stock of OPCo is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Three Months Ended March 31,
2018 2017
REVENUES
Electricity, Transmission and Distribution $ 786.3
$ 738.4
Sales to AEP Affiliates 3.1
5.7
Other Revenues 1.5
2.0
TOTAL REVENUES 790.9
746.1

EXPENSES

Purchased Electricity for Resale 205.5
188.3
Purchased Electricity from AEP Affiliates 30.2
32.0
Amortization of Generation Deferrals 58.6
60.9
Other Operation 172.2
122.3
Maintenance 37.2
37.2
Depreciation and Amortization 64.8
57.3
Taxes Other Than Income Taxes 105.1
98.5
TOTAL EXPENSES 673.6
596.5

OPERATING INCOME 117.3
149.6

Other Income (Expense):

Interest Income 0.9
2.5
Carrying Costs Income 0.7
1.9
Allowance for Equity Funds Used During Construction 2.5
2.4
Non-Service Cost Components of Net Periodic Benefit Cost 3.9
1.1
Interest Expense (25.2 ) (25.0 )

INCOME BEFORE INCOME TAX EXPENSE 100.1
132.5

Income Tax Expense 20.5
46.3

NET INCOME $ 79.6
$ 86.2

~~The common stock of OPCo is wholly-owned by Parent.~~

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

~~OHIO POWER COMPANY AND SUBSIDIARIES~~

~~CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)~~

~~For the Three Months Ended March 31, 2018 and 2017~~

~~(in millions)~~

~~(Unaudited)~~

Three Months Ended March 31,
2018 2017
Net Income $ 79.6
$ 86.2

OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) in 2018 and 2017, Respectively (0.3 ) (0.2 )

TOTAL COMPREHENSIVE INCOME $ 79.3
$ 86.0

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)


	Common Stock		Paid-in Capital		Retained Earnings		Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2022	$	321.2	$	837.8	$	1,929.1	$	3,088.1

Capital Contribution from Parent			50.0				50.0
Net Income					78.0		78.0

TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2023	$	321.2	$	887.8	$	2,007.1	$	3,216.1













TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2023	$	321.2	$	1,012.8	$	2,237.3	$	3,571.3



Net Income					70.6		70.6

TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2024	$	321.2	$	1,012.8	$	2,307.9	$	3,641.9













See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Common
Stock Paid-in
Capital Retained
Earnings Accumulated
Other
Comprehensive
Income (Loss) Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2016 $ 321.2
$ 838.8
$ 954.5
$ 3.0
$ 2,117.5

Common Stock Dividends

(65.0 )
(65.0 )
Net Income

86.2

86.2
Other Comprehensive Loss

(0.2 ) (0.2 )
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2017 $ 321.2
$ 838.8
$ 975.7
$ 2.8
$ 2,138.5

TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017 $ 321.2
$ 838.8
$ 1,148.4
$ 1.9
$ 2,310.3

Common Stock Dividends

(112.5 )
(112.5 )
ASU 2018-02 Adoption 0.4
0.4
Net Income

79.6

79.6
Other Comprehensive Loss

(0.3 ) (0.3 )
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 $ 321.2
$ 838.8
$ 1,115.5
$ 2.0
$ 2,277.5



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, ~~2018~~2024 and December 31, ~~2017~~2023

(in millions)

(Unaudited)


	March 31,		December 31,
	2024		2023
CURRENT ASSETS
Cash and Cash Equivalents	$	12.5	$	6.4

Accounts Receivable:
Customers	70.8		39.2
Affiliated Companies	131.5		129.2

Miscellaneous	9.9		2.3

Total Accounts Receivable	212.2		170.7
Materials and Supplies	171.6		175.0
Renewable Energy Credits	13.4		8.9



Prepayments and Other Current Assets	18.9		16.8
TOTAL CURRENT ASSETS	428.6		377.8

PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission	3,438.6		3,395.1
Distribution	6,948.0		6,839.4
Other Property, Plant and Equipment	1,136.1		1,125.0
Construction Work in Progress	710.4		654.0
Total Property, Plant and Equipment	12,233.1		12,013.5
Accumulated Depreciation and Amortization	2,765.7		2,713.6
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	9,467.4		9,299.9

OTHER NONCURRENT ASSETS
Regulatory Assets	416.6		455.0

Operating Lease Assets	67.4		69.9
Deferred Charges and Other Noncurrent Assets	547.8		641.1
TOTAL OTHER NONCURRENT ASSETS	1,031.8		1,166.0

TOTAL ASSETS	$	10,927.8	$	10,843.7

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

March 31, December 31,
2018 2017
CURRENT ASSETS
Cash and Cash Equivalents $ 1.4
$ 3.1
Restricted Cash for Securitized Funding 15.9
26.6
Advances to Affiliates 200.4
—
Accounts Receivable:
Customers 42.0
67.8
Affiliated Companies 60.4
70.2
Accrued Unbilled Revenues 27.2
29.7
Miscellaneous 1.2
1.9
Allowance for Uncollectible Accounts (0.6 ) (0.6 )
Total Accounts Receivable 130.2
169.0
Materials and Supplies 41.2
41.9
Renewable Energy Credits 24.8
25.0
Risk Management Assets 0.4
0.6
Regulatory Asset for Under-Recovered Fuel Costs 89.3
115.9
Prepayments and Other Current Assets 27.1
15.8
TOTAL CURRENT ASSETS 530.7
397.9

PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission 2,440.5
2,419.2
Distribution 4,669.3
4,626.4
Other Property, Plant and Equipment 518.9
495.9
Construction Work in Progress 432.0
410.1
Total Property, Plant and Equipment 8,060.7
7,951.6
Accumulated Depreciation and Amortization 2,205.7
2,184.8
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
5,855.0
5,766.8

OTHER NONCURRENT ASSETS
Regulatory Assets 597.6
652.8
Securitized Assets 31.4
37.7
Deferred Charges and Other Noncurrent Assets 342.0
406.5
TOTAL OTHER NONCURRENT ASSETS 971.0
1,097.0

TOTAL ASSETS $ 7,356.7
$ 7,261.7



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, ~~2018~~2024 and December 31, ~~2017~~

~~(dollars in millions)~~2023

(Unaudited)


	March 31,		December 31,
	2024		2023
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	295.2	$	110.5
Accounts Payable:
General	305.2		320.7
Affiliated Companies	154.5		154.2

Risk Management Liabilities	6.0		6.8
Customer Deposits	76.1		62.0
Accrued Taxes	605.5		763.3

Obligations Under Operating Leases	13.1		13.5
Other Current Liabilities	176.3		183.3
TOTAL CURRENT LIABILITIES	1,631.9		1,614.3

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	3,367.4		3,366.8
Long-term Risk Management Liabilities	35.0		43.9
Deferred Income Taxes	1,158.9		1,152.7
Regulatory Liabilities and Deferred Investment Tax Credits	1,004.5		1,003.6

Obligations Under Operating Leases	54.5		56.7
Deferred Credits and Other Noncurrent Liabilities	33.7		34.4
TOTAL NONCURRENT LIABILITIES	5,654.0		5,658.1

TOTAL LIABILITIES	7,285.9		7,272.4

Rate Matters (Note 4)
Commitments and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Common Stock –No Par Value:
Authorized – 40,000,000 Shares
Outstanding – 27,952,473 Shares	321.2		321.2
Paid-in Capital	1,012.8		1,012.8
Retained Earnings	2,307.9		2,237.3

TOTAL COMMON SHAREHOLDER’S EQUITY	3,641.9		3,571.3

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	10,927.8	$	10,843.7

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

March 31, December 31,
2018 2017
CURRENT LIABILITIES
Advances from Affiliates $ —
$ 87.8
Accounts Payable:

General 159.9
205.8
Affiliated Companies 105.5
118.2
Long-term Debt Due Within One Year – Nonaffiliated
(March 31, 2018 and December 31, 2017 Amounts Include $47.5 and $47, Respectively, Related to Ohio Phase-in-Recovery Funding)
397.5
397.0
Risk Management Liabilities 5.3
6.4
Customer Deposits 76.5
69.2
Accrued Taxes 418.5
512.5
Accrued Interest 38.7
31.0
Other Current Liabilities 161.2
165.9
TOTAL CURRENT LIABILITIES 1,363.1
1,593.8

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated
(March 31, 2018 and December 31, 2017 Amounts Include $24.3 and $47.5, Respectively, Related to Ohio Phase-in-Recovery Funding)
1,692.2
1,322.3
Long-term Risk Management Liabilities 93.2
126.0
Deferred Income Taxes 759.0
762.9
Regulatory Liabilities and Deferred Investment Tax Credits 1,120.8
1,100.2
Deferred Credits and Other Noncurrent Liabilities 50.9
46.2
TOTAL NONCURRENT LIABILITIES 3,716.1
3,357.6

TOTAL LIABILITIES 5,079.2
4,951.4

Rate Matters (Note 4)

Commitments and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 40,000,000 Shares

Outstanding – 27,952,473 Shares 321.2
321.2
Paid-in Capital 838.8
838.8
Retained Earnings 1,115.5
1,148.4
Accumulated Other Comprehensive Income (Loss) 2.0
1.9
TOTAL COMMON SHAREHOLDER’S EQUITY 2,277.5
2,310.3

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $ 7,356.7
$ 7,261.7



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)


	Three Months Ended March 31,
	2024		2023
OPERATING ACTIVITIES
Net Income	$	70.6	$	78.0
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	105.8		75.2
Deferred Income Taxes	(0.6)		2.1

Allowance for Equity Funds Used During Construction	(5.5)		(2.8)
Mark-to-Market of Risk Management Contracts	(9.7)		7.2

Property Taxes	95.0		92.0

Change in Other Noncurrent Assets	10.1		(43.2)
Change in Other Noncurrent Liabilities	11.4		(21.7)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(40.2)		(20.3)
Materials and Supplies	(1.1)		(4.8)
Accounts Payable	(32.4)		(5.5)
Customer Deposits	14.2		(22.7)
Accrued Taxes, Net	(157.5)		(157.9)
Other Current Assets	(3.4)		(2.2)
Other Current Liabilities	1.5		(7.7)
Net Cash Flows from (Used for) Operating Activities	58.2		(34.3)

INVESTING ACTIVITIES
Construction Expenditures	(241.1)		(262.0)

Other Investing Activities	5.2		4.9
Net Cash Flows Used for Investing Activities	(235.9)		(257.1)

FINANCING ACTIVITIES
Capital Contribution from Parent	—		50.0

Change in Advances from Affiliates, Net	184.7		241.7

Principal Payments for Finance Lease Obligations	(1.3)		(1.2)

Other Financing Activities	0.4		0.4
Net Cash Flows from Financing Activities	183.8		290.9

Net Increase (Decrease) in Cash and Cash Equivalents	6.1		(0.5)
Cash and Cash Equivalents at Beginning of Period	6.4		9.6
Cash and Cash Equivalents at End of Period	$	12.5	$	9.1

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	19.1	$	20.9

Noncash Acquisitions Under Finance Leases	0.5		0.6
Construction Expenditures Included in Current Liabilities as of March 31,	104.8		109.9

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Three Months Ended March 31,
2018 2017
OPERATING ACTIVITIES

Net Income $ 79.6
$ 86.2
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:

Depreciation and Amortization 64.8
57.3
Amortization of Generation Deferrals 58.6
60.9
Deferred Income Taxes (4.9 ) 36.7
Carrying Costs Income (0.7 ) (1.9 )
Allowance for Equity Funds Used During Construction (2.5 ) (2.4 )
Mark-to-Market of Risk Management Contracts (33.7 ) 5.7
Property Taxes 62.9
58.4
Provision for Refund – Global Settlement (5.4 ) —
Change in Other Noncurrent Assets 14.3
(45.8 )
Change in Other Noncurrent Liabilities 40.6
30.6
Changes in Certain Components of Working Capital:

Accounts Receivable, Net 38.8
30.2
Materials and Supplies (1.9 ) (1.8 )
Accounts Payable (22.5 ) (34.9 )
Accrued Taxes, Net (92.8 ) (107.2 )
Other Current Assets (7.5 ) (0.3 )
Other Current Liabilities (2.9 ) (31.2 )
Net Cash Flows from Operating Activities 184.8
140.5

INVESTING ACTIVITIES

Construction Expenditures (168.2 ) (108.4 )
Change in Advances to Affiliates, Net (200.4 ) 24.2
Other Investing Activities 1.7
2.0
Net Cash Flows Used for Investing Activities (366.9 ) (82.2 )

FINANCING ACTIVITIES

Issuance of Long-term Debt – Nonaffiliated 393.3
—
Change in Advances from Affiliates, Net (87.8 ) 18.3
Retirement of Long-term Debt – Nonaffiliated (22.9 ) (22.5 )
Principal Payments for Capital Lease Obligations (0.9 ) (1.0 )
Dividends Paid on Common Stock (112.5 ) (65.0 )
Other Financing Activities 0.5
0.6
Net Cash Flows from (Used for) Financing Activities 169.7
(69.6 )

Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding (12.4 ) (11.3 )
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period 29.7
30.3
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period $ 17.3
$ 19.0

SUPPLEMENTARY INFORMATION

Cash Paid for Interest, Net of Capitalized Amounts $ 17.0
$ 17.2
Net Cash Paid for Income Taxes —
1.7
Noncash Acquisitions Under Capital Leases 1.4
1.3
Construction Expenditures Included in Current Liabilities as of March 31, 52.3
28.3



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

PUBLIC SERVICE COMPANY OF OKLAHOMA

~~PUBLIC SERVICE COMPANY OF OKLAHOMA~~

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales



	Three Months Ended March 31,
	2024	2023
	(in millions of KWhs)
Retail:
Residential	1,451	1,388
Commercial	1,232	1,104
Industrial	1,411	1,439
Miscellaneous	283	275
Total Retail	4,377	4,206

Wholesale	47	27

Total KWhs	4,424	4,233

Three Months Ended March 31,
2018 2017
(in millions of KWhs)
Retail:

Residential 1,493
1,312
Commercial 1,162
1,130
Industrial 1,340
1,306
Miscellaneous 276
273
Total Retail 4,271
4,021

Wholesale 157
81

Total KWhs 4,428
4,102

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.

Summary of Heating and Cooling Degree Days



	Three Months Ended March 31,
	2024	2023
	(in degree days)
Actual – Heating (a)	912	871
Normal – Heating (b)	1,046	1,055

Actual – Cooling (c)	22	10
Normal – Cooling (b)	17	17

Three Months Ended March 31,
2018 2017
(in degree days)
Actual – Heating (a) 1,032
670
Normal – Heating (b) 1,041
1,062

Actual – Cooling (c) 12
59
Normal – Cooling (b) 17
14

(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.

~~First Quarter of 2018 Compared to First Quarter of 2017~~

Reconciliation of First Quarter of 2017 to First Quarter of 2018
Net Income (Loss)
(in millions)

First Quarter of 2017 $ 4.8

Changes in Gross Margin:
Retail Margins (a) (0.2 )
Off-system Sales 0.1
Other Revenues (0.4 )
Total Change in Gross Margin (0.5 )

Changes in Expenses and Other:
Other Operation and Maintenance (11.2 )
Depreciation and Amortization (3.3 )
Taxes Other Than Income Taxes (1.0 )
Non-Service Cost Components of Net Periodic Benefit Cost 1.3
Other Income (0.5 )
Interest Expense (1.1 )
Total Change in Expenses and Other (15.8 )

Income Tax Expense 4.3

First Quarter of 2018 $ (7.2 )


Public Service Company of Oklahoma
~~(a)~~Reconciliation of First Quarter of 2023 to First Quarter of 2024
Net Income
(in millions)


First Quarter of 2023	~~Includes firm wholesale sales to municipals~~	$	(2.3)

Changes in Revenues:
Retail Revenues (a)		(35.5)

Transmission Revenues		(0.3)
Other Revenues		6.6
Total Change in Revenues		(29.2)

Changes in Expenses and ~~cooperatives.~~Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation		51.2
Other Operation and Maintenance		(3.8)
Depreciation and Amortization		(6.3)
Taxes Other Than Income Taxes		0.3
Interest Income		(0.8)

Allowance for Equity Funds Used During Construction		0.9

Non-Service Cost Components of Net Periodic Benefit Cost		(0.7)
Interest Expense		8.4
Total Change in Expenses and Other		49.2

Income Tax Benefit		54.3

First Quarter of 2024		$	72.0

(a)Includes firm wholesale sales to municipals and cooperatives.

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 and purchased electricity~~Revenues were as follows:

•Retail ~~Margins~~ ~~were consistent with the prior year~~Revenues decreased $36 million primarily due to the following:

•A $5$57 million decrease in fuel revenue primarily due to lower authorized fuel rates.

This decrease was partially offset by:

•A $19 million increase in ~~revenue from~~base rate ~~riders. This increase in Retail Margins is partially offset by a corresponding increase~~and rider revenues.

•Other Revenues increased $7 million due to ~~riders/trackers recognized in other expense items below.~~the following:

•A $4 million increase ~~due to new rates implemented~~ in ~~March 2018, inclusive of a $2 million decrease due to the change in the corporate federal tax rate.~~associated business development revenues.

•A $3 million increase in ~~weather-related usage due to a 54% increase in heating degree days.~~affiliated rent revenues.

~~These increases were partially offset by:~~

~~A $6 million decrease due to 2018 provisions for customer refunds primarily related to Tax Reform. This decrease is offset in Income Tax Expense below.~~

~~A $5 million decrease related to the System Reliability Rider (SRR) that ended in August 2017. This decrease is partially offset by a corresponding decrease recognized in other expense items below.~~

~~A $1 million decrease due to lower weather-normalized margins.~~

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

•Purchased Electricity, Fuel and Other ~~Operation~~Consumables Used for Electric Generation expenses decreased $51 millionprimarily due to the lower current year amortization of under-recovered fuel regulatory assets driven by lower authorized fuel rates.

•Depreciation and ~~Maintenance~~Amortization expenses increased ~~$11~~$6 million primarily due to an increase in the amortization of regulatory assets related to NCWF.

•Interest Expense decreased $8 million primarily due to the recognition of debt carrying charges as a result of the IRS PLR received regarding the treatment of stand alone NOLCs in retail rate making.

•Income Tax Benefit increased $54 million primarily due to the following:

•A ~~$9 million increase in transmission expenses primarily due to increased SPP transmission services.~~

~~A $4 million increase due to the Wind Catcher Project.~~

~~A $3 million increase in Energy Efficiency program costs. This increase was offset by an increase from rate riders in Retail Margins above.~~

~~These increases were partially offset by:~~

A $6 million decrease in the amortization of previously deferred vegetation management costs collected through the SRR. This decrease was partially offset by a corresponding decrease in Retail Margins above.

~~Depreciation and Amortization~~ ~~expenses increased $3 million primarily due to the following:~~

~~A $2~~$49 million increase due to a ~~higher depreciable base.~~

~~A $1 million increase due to amortization of capitalized software costs.~~

~~Income Tax Expense~~ ~~decreased $4 million primarily due to the change~~reduction in ~~the corporate federal income tax rate from 35% in 2017 to 21% in 2018~~ Excess ADIT regulatory liabilities as a result of ~~Tax Reform, amortization~~the IRS PLR received regarding the treatment of ~~excess accumulated deferred income taxes associated with certain depreciable property and a decrease~~stand alone NOLCs in ~~pretax book income.~~retail rate making.

•A $10 million increase in PTCs.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF OPERATIONS

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2024		2023
REVENUES
Electric Generation, Transmission and Distribution	$	378.1	$	414.8
Sales to AEP Affiliates	3.5		0.7
Other Revenues	6.2		1.5
TOTAL REVENUES	387.8		417.0

EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	148.9		200.1


Other Operation	96.6		92.1
Maintenance	28.1		28.8
Depreciation and Amortization	67.4		61.1
Taxes Other Than Income Taxes	17.0		17.3
TOTAL EXPENSES	358.0		399.4

OPERATING INCOME	29.8		17.6

Other Income (Expense):
Interest Income	0.2		1.0

Allowance for Equity Funds Used During Construction	2.4		1.5

Non-Service Cost Components of Net Periodic Benefit Cost	2.9		3.6
Interest Expense	(16.8)		(25.2)

INCOME (LOSS) BEFORE INCOME TAX EXPENSE (BENEFIT)	18.5		(1.5)

Income Tax Expense (Benefit)	(53.5)		0.8

NET INCOME (LOSS)	$	72.0	$	(2.3)

The common stock of PSO is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Three Months Ended March 31,
2018 2017
REVENUES
Electric Generation, Transmission and Distribution $ 335.1
$ 301.9
Sales to AEP Affiliates 1.1
1.1
Other Revenues 0.6
1.1
TOTAL REVENUES 336.8
304.1

EXPENSES

Fuel and Other Consumables Used for Electric Generation 48.4
12.3
Purchased Electricity for Resale 122.4
125.3
Other Operation 86.8
68.3
Maintenance 26.9
34.2
Depreciation and Amortization 36.8
33.5
Taxes Other Than Income Taxes 11.6
10.6
TOTAL EXPENSES 332.9
284.2

OPERATING INCOME 3.9
19.9

Other Income (Expense):

Other Income —
0.5
Non-Service Cost Components of Net Periodic Benefit Cost

2.2
0.9
Interest Expense (14.7 ) (13.6 )

INCOME (LOSS) BEFORE INCOME TAX EXPENSE (CREDIT) (8.6 ) 7.7

Income Tax Expense (Credit) (1.4 ) 2.9

NET INCOME (LOSS) $ (7.2 ) $ 4.8



~~The common stock of PSO is wholly-owned by Parent.~~

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2024		2023
Net Income (Loss)	$	72.0	$	(2.3)

OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $(0.4) in 2024 and 2023, Respectively	—		(1.5)

TOTAL COMPREHENSIVE INCOME (LOSS)	$	72.0	$	(3.8)

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Three Months Ended March 31,
2018 2017
Net Income (Loss) $ (7.2 ) $ 4.8

OTHER COMPREHENSIVE LOSS, NET OF TAXES

Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) in 2018 and 2017, Respectively (0.2 ) (0.2 )

TOTAL COMPREHENSIVE INCOME (LOSS) $ (7.4 ) $ 4.6



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)


	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2022	$	157.2	$	1,042.6	$	1,218.0	$	1.3	$	2,419.1


Common Stock Dividends					(17.5)				(17.5)

Net Loss					(2.3)				(2.3)
Other Comprehensive Loss							(1.5)		(1.5)
TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2023	$	157.2	$	1,042.6	$	1,198.2	$	(0.2)	$	2,397.8













TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2023	$	157.2	$	1,039.3	$	1,374.3	$	(0.2)	$	2,570.6

Common Stock Dividends					(35.0)				(35.0)


Net Income					72.0				72.0

TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2024	$	157.2	$	1,039.3	$	1,411.3	$	(0.2)	$	2,607.6













See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Common
Stock Paid-in
Capital Retained
Earnings Accumulated
Other
Comprehensive
Income (Loss) Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2016 $ 157.2
$ 364.0
$ 689.5
$ 3.4
$ 1,214.1

Common Stock Dividends

(17.5 )
(17.5 )
Net Income

4.8

4.8
Other Comprehensive Loss

(0.2 ) (0.2 )
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2017 $ 157.2
$ 364.0
$ 676.8
$ 3.2
$ 1,201.2

TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017 $ 157.2
$ 364.0
$ 691.5
$ 2.6
$ 1,215.3

Common Stock Dividends

(12.5 )
(12.5 )
ASU 2018-02 Adoption 0.5
0.5
Net Loss

(7.2 )
(7.2 )
Other Comprehensive Loss

(0.2 ) (0.2 )
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 $ 157.2
$ 364.0
$ 671.8
$ 2.9
$ 1,195.9



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED BALANCE SHEETS

ASSETS

March 31, ~~2018~~2024 and December 31, ~~2017~~2023

(in millions)

(Unaudited)


	March 31,		December 31,
	2024		2023
CURRENT ASSETS
Cash and Cash Equivalents	$	3.5	$	2.5

Accounts Receivable:
Customers	74.1		107.6
Affiliated Companies	69.1		31.0
Miscellaneous	1.0		0.8

Total Accounts Receivable	144.2		139.4
Fuel	32.5		33.7
Materials and Supplies	111.0		106.9
Risk Management Assets	7.9		19.0

Accrued Tax Benefits	43.7		31.0
Regulatory Asset for Under-Recovered Fuel Costs	155.8		118.3
Prepayments and Other Current Assets	34.8		18.7
TOTAL CURRENT ASSETS	533.4		469.5

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	2,704.8		2,695.5
Transmission	1,240.0		1,228.3
Distribution	3,513.0		3,450.8
Other Property, Plant and Equipment	514.6		505.9
Construction Work in Progress	336.9		313.7
Total Property, Plant and Equipment	8,309.3		8,194.2
Accumulated Depreciation and Amortization	2,119.7		2,081.9
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	6,189.6		6,112.3

OTHER NONCURRENT ASSETS
Regulatory Assets	533.1		522.7

Employee Benefits and Pension Assets	69.6		68.4
Operating Lease Assets	111.1		112.8
Deferred Charges and Other Noncurrent Assets	92.9		49.2
TOTAL OTHER NONCURRENT ASSETS	806.7		753.1

TOTAL ASSETS	$	7,529.7	$	7,334.9

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

March 31, December 31,
2018 2017
CURRENT ASSETS
Cash and Cash Equivalents $ 0.6
$ 1.6
Accounts Receivable:
Customers 30.9
32.5
Affiliated Companies 27.7
32.9
Miscellaneous 3.9
4.1
Allowance for Uncollectible Accounts —
(0.1 )
Total Accounts Receivable 62.5
69.4
Fuel 13.0
12.5
Materials and Supplies 43.2
42.0
Risk Management Assets 2.9
6.4
Accrued Tax Benefits 30.2
28.1
Regulatory Asset for Under-Recovered Fuel Costs 22.7
36.7
Prepayments and Other Current Assets 7.5
8.6
TOTAL CURRENT ASSETS 182.6
205.3

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation 1,572.4
1,577.2
Transmission 862.0
858.8
Distribution 2,475.5
2,445.1
Other Property, Plant and Equipment 297.0
287.4
Construction Work in Progress 110.3
111.3
Total Property, Plant and Equipment 5,317.2
5,279.8
Accumulated Depreciation and Amortization 1,415.5
1,393.6
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
3,901.7
3,886.2

OTHER NONCURRENT ASSETS
Regulatory Assets 366.8
368.1
Employee Benefits and Pension Assets 40.4
40.0
Deferred Charges and Other Noncurrent Assets 34.2
8.7
TOTAL OTHER NONCURRENT ASSETS 441.4
416.8

TOTAL ASSETS $ 4,525.7
$ 4,508.3



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, ~~2018~~2024 and December 31, ~~2017~~2023

(Unaudited)


	March 31,		December 31,
	2024		2023
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	264.6	$	54.4
Accounts Payable:
General	138.5		159.3
Affiliated Companies	59.8		56.7
Long-term Debt Due Within One Year – Nonaffiliated	125.6		0.6
Risk Management Liabilities	28.5		28.9
Customer Deposits	82.2		81.4
Accrued Taxes	67.3		30.7
Accrued Interest	26.3		30.7
Obligations Under Operating Leases	10.7		10.1


Other Current Liabilities	54.3		106.2
TOTAL CURRENT LIABILITIES	857.8		559.0

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	2,259.3		2,384.0

Deferred Income Taxes	881.6		831.2
Regulatory Liabilities and Deferred Investment Tax Credits	701.6		765.6
Asset Retirement Obligations	85.0		83.9

Obligations Under Operating Leases	104.7		106.8
Deferred Credits and Other Noncurrent Liabilities	32.1		33.8
TOTAL NONCURRENT LIABILITIES	4,064.3		4,205.3

TOTAL LIABILITIES	4,922.1		4,764.3

Rate Matters (Note 4)
Commitments and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Common Stock – Par Value – $15 Per Share:
Authorized – 11,000,000 Shares
Issued – 10,482,000 Shares
Outstanding – 9,013,000 Shares	157.2		157.2
Paid-in Capital	1,039.3		1,039.3
Retained Earnings	1,411.3		1,374.3
Accumulated Other Comprehensive Income (Loss)	(0.2)		(0.2)
TOTAL COMMON SHAREHOLDER’S EQUITY	2,607.6		2,570.6

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	7,529.7	$	7,334.9

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

March 31, December 31,
2018 2017
(in millions)
CURRENT LIABILITIES
Advances from Affiliates $ 179.1
$ 149.6
Accounts Payable:

General 88.7
102.4
Affiliated Companies 51.5
48.0
Long-term Debt Due Within One Year – Nonaffiliated 0.5
0.5
Customer Deposits 54.5
54.1
Accrued Taxes 42.1
22.6
Accrued Interest 19.3
14.1
Other Current Liabilities 34.8
44.7
TOTAL CURRENT LIABILITIES 470.5
436.0

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated 1,286.2
1,286.0
Deferred Income Taxes 639.6
642.0
Regulatory Liabilities and Deferred Investment Tax Credits 851.5
853.5
Asset Retirement Obligations 53.7
53.0
Deferred Credits and Other Noncurrent Liabilities 28.3
22.5
TOTAL NONCURRENT LIABILITIES 2,859.3
2,857.0

TOTAL LIABILITIES 3,329.8
3,293.0

Rate Matters (Note 4)

Commitments and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Common Stock – Par Value – $15 Per Share:
Authorized – 11,000,000 Shares

Issued – 10,482,000 Shares

Outstanding – 9,013,000 Shares 157.2
157.2
Paid-in Capital 364.0
364.0
Retained Earnings 671.8
691.5
Accumulated Other Comprehensive Income (Loss) 2.9
2.6
TOTAL COMMON SHAREHOLDER’S EQUITY 1,195.9
1,215.3

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $ 4,525.7
$ 4,508.3



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)


	Three Months Ended March 31,
	2024		2023
OPERATING ACTIVITIES
Net Income (Loss)	$	72.0	$	(2.3)
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	67.4		61.1
Deferred Income Taxes	(15.5)		12.2

Allowance for Equity Funds Used During Construction	(2.4)		(1.5)
Mark-to-Market of Risk Management Contracts	12.5		13.9

Property Taxes	(45.9)		(45.6)
Deferred Fuel Over/Under-Recovery, Net	(37.6)		49.4


Change in Other Noncurrent Assets	(18.4)		(9.7)
Change in Other Noncurrent Liabilities	1.7		1.4
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(4.8)		27.2
Fuel, Materials and Supplies	(2.9)		12.9
Accounts Payable	(4.5)		(62.8)
Accrued Taxes, Net	23.9		24.9
Other Current Assets	(16.1)		0.4
Other Current Liabilities	(46.9)		(7.5)
Net Cash Flows from (Used for) Operating Activities	(17.5)		74.0

INVESTING ACTIVITIES
Construction Expenditures	(156.9)		(146.8)

Acquisitions of Renewable Energy Facilities	—		(145.7)
Other Investing Activities	1.0		0.4
Net Cash Flows Used for Investing Activities	(155.9)		(292.1)

FINANCING ACTIVITIES


Issuance of Long-term Debt – Nonaffiliated	—		469.9
Change in Advances from Affiliates, Net	210.2		(233.5)
Retirement of Long-term Debt – Nonaffiliated	(0.1)		(0.1)

Principal Payments for Finance Lease Obligations	(0.8)		(0.8)
Dividends Paid on Common Stock	(35.0)		(17.5)
Other Financing Activities	0.1		(0.1)
Net Cash Flows from Financing Activities	174.4		217.9

Net Increase (Decrease) in Cash and Cash Equivalents	1.0		(0.2)
Cash and Cash Equivalents at Beginning of Period	2.5		4.0
Cash and Cash Equivalents at End of Period	$	3.5	$	3.8

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	30.3	$	22.3

Cash Received from Sale of Transferable Tax Credits	(24.9)		—
Noncash Acquisitions Under Finance Leases	0.4		0.2
Construction Expenditures Included in Current Liabilities as of March 31,	47.9		63.4

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Three Months Ended March 31,
2018 2017
OPERATING ACTIVITIES

Net Income (Loss) $ (7.2 ) $ 4.8
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from (Used for) Operating Activities:

Depreciation and Amortization 36.8
33.5
Deferred Income Taxes (4.5 ) 27.4
Allowance for Equity Funds Used During Construction 0.1
(0.4 )
Mark-to-Market of Risk Management Contracts 3.5
0.3
Property Taxes (30.1 ) (29.8 )
Deferred Fuel Over/Under-Recovery, Net 14.6
(13.1 )
Change in Other Noncurrent Assets —
(9.3 )
Change in Other Noncurrent Liabilities 5.7
(1.9 )
Changes in Certain Components of Working Capital:

Accounts Receivable, Net 6.9
16.6
Fuel, Materials and Supplies (1.7 ) 3.4
Accounts Payable (10.9 ) (27.7 )
Accrued Taxes, Net 22.4
(0.3 )
Other Current Assets 0.9
0.3
Other Current Liabilities (1.3 ) (22.3 )
Net Cash Flows from (Used for) Operating Activities 35.2
(18.5 )

INVESTING ACTIVITIES

Construction Expenditures (54.4 ) (75.7 )
Other Investing Activities 2.0
0.9
Net Cash Flows Used for Investing Activities (52.4 ) (74.8 )

FINANCING ACTIVITIES

Change in Advances from Affiliates, Net 29.5
111.7
Retirement of Long-term Debt – Nonaffiliated (0.1 ) (0.1 )
Principal Payments for Capital Lease Obligations (1.0 ) (1.1 )
Dividends Paid on Common Stock (12.5 ) (17.5 )
Other Financing Activities 0.3
0.1
Net Cash Flows from Financing Activities 16.2
93.1

Net Decrease in Cash and Cash Equivalents (1.0 ) (0.2 )
Cash and Cash Equivalents at Beginning of Period 1.6
1.5
Cash and Cash Equivalents at End of Period $ 0.6
$ 1.3

SUPPLEMENTARY INFORMATION

Cash Paid for Interest, Net of Capitalized Amounts $ 10.3
$ 15.9
Net Cash Paid (Received) for Income Taxes —
(2.6 )
Noncash Acquisitions Under Capital Leases 0.9
0.7
Construction Expenditures Included in Current Liabilities as of March 31, 25.4
22.3



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

~~SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED~~

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales



	Three Months Ended March 31,
	2024	2023
	(in millions of KWhs)
Retail:
Residential	1,509	1,351
Commercial	1,240	1,168
Industrial	1,227	1,203
Miscellaneous	17	17
Total Retail	3,993	3,739

Wholesale	1,374	1,270

Total KWhs	5,367	5,009

Three Months Ended March 31,
2018 2017
(in millions of KWhs)
Retail:

Residential 1,558
1,310
Commercial 1,288
1,305
Industrial 1,199
1,222
Miscellaneous 19
20
Total Retail 4,064
3,857

Wholesale 1,908
2,439

Total KWhs 5,972
6,296

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.

Summary of Heating and Cooling Degree Days



	Three Months Ended March 31,
	2024	2023
	(in degree days)
Actual – Heating (a)	555	401
Normal – Heating (b)	697	705

Actual – Cooling (c)	88	107
Normal – Cooling (b)	44	40

Three Months Ended March 31,
2018 2017
(in degree days)
Actual – Heating (a) 729
388
Normal – Heating (b) 707
720

Actual – Cooling (c) 60
106
Normal – Cooling (b) 38
34

(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.

~~First Quarter of 2018 Compared to First Quarter of 2017~~

Reconciliation of First Quarter of 2017 to First Quarter of 2018
Earnings Attributable to SWEPCo Common Shareholder
(in millions)

First Quarter of 2017 $ 16.3

Changes in Gross Margin:
Retail Margins (a) 10.2
Off-system Sales (1.1 )
Transmission Revenues 2.7
Other Revenues 0.1
Total Change in Gross Margin 11.9

Changes in Expenses and Other:
Other Operation and Maintenance (14.8 )
Depreciation and Amortization (6.6 )
Taxes Other Than Income Taxes (1.7 )
Interest Income 0.9
Allowance for Equity Funds Used During Construction 1.5
Non-Service Cost Components of Net Periodic Benefit Cost 1.4
Interest Expense (2.3 )
Total Change in Expenses and Other (21.6 )

Income Tax Expense 6.6
Equity Earnings of Unconsolidated Subsidiary (0.8 )
Net Income Attributable to Noncontrolling Interest (0.6 )

First Quarter of 2018 $ 11.8


Southwestern Electric Power Company
~~(a)~~Reconciliation of First Quarter of 2023 to First Quarter of 2024
Earnings Attributable to SWEPCo Common Shareholder
(in millions)


First Quarter of 2023	~~Includes firm wholesale sales~~	$	40.6

Changes in Revenues:
Retail Revenues (a)		(0.6)
Off-system Sales		2.5
Transmission Revenues		(2.9)
Other Revenues		1.3
Total Change in Revenues		0.3

Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation		24.7
Other Operation and Maintenance		(13.2)

Depreciation and Amortization		1.7
Taxes Other Than Income Taxes		1.9
Interest Income		(1.4)
Allowance for Equity Funds Used During Construction		2.9
Non-Service Cost Components of Net Periodic Benefit Cost		(0.8)

Interest Expense		11.5
Total Change in Expenses and Other		27.3

Income Tax Benefit		140.1
Equity Earnings of Unconsolidated Subsidiary		0.1
Net Income Attributable to ~~municipals and cooperatives.~~Noncontrolling Interest		(0.3)

First Quarter of 2024		$	208.1

(a)Includes firm wholesale sales to municipals and cooperatives.

•Retail ~~Margins~~ ~~increased $10~~Revenues decreased $1 million primarily due to the following:

•A ~~$22~~$39 million ~~increase~~decrease in fuel revenue primarily due to ~~rider~~authorized fuel rate decreases in Arkansas and ~~base rate revenue increases~~Louisiana, which were primarily driven by lower natural gas and spot market energy prices.

This decrease was partially offset by:

•A $32 million increase in ~~Texas~~weather-normalized margins primarily in the residential and ~~Louisiana.~~commercial classes.

•A ~~$14~~$5 million increase in weather-related usage primarily due to ~~an 88%~~a 38% increase in heating degree days.

~~These increases were partially offset by:~~

~~A $15 million decrease due to lower weather-normalized margins, primarily due to wholesale customer load loss from contracts that expired at the end of 2017.~~

~~A $12 million decrease due to the 2018 provisions for customer refunds primarily related to Tax Reform. This decrease is offset in Income Tax Expense below.~~

~~Transmission Revenues~~ ~~increased $3 million~~ ~~primarily due to an increase in transmission investments in SPP.~~

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $25 million primarily due to a current year decrease in amortization of under-recovered fuel regulatory assets.

•Other Operation and Maintenance expenses increased ~~$15~~$13 million primarily due to a disallowance recorded on the remaining net book value of the Dolet Hills Power Station as a result of an LPSC approved settlement agreement in April 2024.

•Interest Expense decreased $12 million primarily due to the following:

•A $28 million decrease due to the recognition of debt carrying charges as a result of the IRS PLR received regarding the treatment of stand alone NOLCs in retail rate making.

This decrease was partially offset by:

•A ~~$10~~$12 million increase due to a decrease in carrying charges on storm-related regulatory assets due to a prior year settlement agreement in Louisiana.

•Income Tax Benefit increased $140 million primarily due to the following:

•A $109 million increase due to a reduction in Excess ADIT regulatory liabilities as a result of the IRS PLR received regarding the treatment of stand alone NOLCs in retail rate making.

•A $32 million increase due to the ~~Wind Catcher Project.~~

~~A $5 million increase in SPP transmission services.~~

~~A $3 million increase in employee-related expenses.~~

~~These increases were partially offset by:~~

~~A $4 million decrease in distribution expenses primarily due to distribution system improvements in 2017.~~

~~Depreciation and Amortization~~ ~~expenses increased $7 million primarily due to~~reversal of a ~~higher depreciable base.~~

~~Income Tax Expense~~ ~~decreased $7 million primarily due~~regulatory liability related to the ~~change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018~~merchant portion of Turk Plant Excess ADIT as a result of ~~Tax Reform, amortization~~the APSC's March 2024 denial of ~~excess accumulated deferred income taxes associated with certain depreciable property and a decrease in pretax book income.~~SWEPCo's request to allow the merchant portion of the Turk Plant to serve Arkansas customers.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)

Three Months Ended March 31,
2018 2017
REVENUES
Electric Generation, Transmission and Distribution $ 413.0
$ 396.3
Sales to AEP Affiliates 6.1
4.6
Other Revenues 0.3
0.4
TOTAL REVENUES 419.4
401.3

EXPENSES

Fuel and Other Consumables Used for Electric Generation 126.8
130.9
Purchased Electricity for Resale 42.7
32.4
Other Operation 94.9
78.9
Maintenance 31.0
32.2
Depreciation and Amortization 57.4
50.8
Taxes Other Than Income Taxes 25.0
23.3
TOTAL EXPENSES 377.8
348.5

OPERATING INCOME 41.6
52.8

Other Income (Expense):

Interest Income 1.8
0.9
Allowance for Equity Funds Used During Construction 2.3
0.8
Non-Service Cost Components of Net Periodic Benefit Cost 2.3
0.9
Interest Expense (32.2 ) (29.9 )

INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS 15.8
25.5

Income Tax Expense 2.9
9.5
Equity Earnings of Unconsolidated Subsidiary 0.5
1.3

NET INCOME 13.4
17.3

Net Income Attributable to Noncontrolling Interest 1.6
1.0

EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER $ 11.8
$ 16.3


	Three Months Ended March 31,


	2024		2023
REVENUES
Electric Generation, Transmission and Distribution	$	500.2	$	503.7
Sales to AEP Affiliates	12.1		11.7

Other Revenues	3.9		0.5
TOTAL REVENUES	516.2		515.9

EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	184.6		209.3


Other Operation	112.9		99.2
Maintenance	37.2		37.7

Depreciation and Amortization	78.7		80.4
Taxes Other Than Income Taxes	34.2		36.1
TOTAL EXPENSES	447.6		462.7

OPERATING INCOME	68.6		53.2

Other Income (Expense):
Interest Income	4.0		5.4
Allowance for Equity Funds Used During Construction	3.4		0.5
Non-Service Cost Components of Net Periodic Benefit Cost	2.6		3.4

Interest Expense	(13.5)		(25.0)

INCOME BEFORE INCOME TAX BENEFIT AND EQUITY EARNINGS	65.1		37.5

Income Tax Benefit	(144.1)		(4.0)
Equity Earnings of Unconsolidated Subsidiary	0.4		0.3

NET INCOME	209.6		41.8

Net Income Attributable to Noncontrolling Interest	1.5		1.2

EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	208.1	$	40.6

The common stock of SWEPCo is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.



~~The common stock of SWEPCo is wholly-owned by Parent.~~

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)


	Three Months Ended March 31,


	2024		2023
Net Income	$	209.6	$	41.8

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0.1 in 2024 and 2023, Respectively	(0.1)		0.4
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $(0.1) in 2024 and 2023, Respectively	(0.1)		(0.3)

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(0.2)		0.1

TOTAL COMPREHENSIVE INCOME	209.4		41.9

Total Comprehensive Income Attributable to Noncontrolling Interest	1.5		1.2

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	207.9	$	40.7

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Three Months Ended March 31,
2018 2017
Net Income $ 13.4
$ 17.3

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES

Cash Flow Hedges, Net of Tax of $0.1 and $0.2 in 2018 and 2017, Respectively 0.4
0.5
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) in 2018 and 2017, Respectively (0.3 ) (0.2 )

TOTAL OTHER COMPREHENSIVE INCOME 0.1
0.3

TOTAL COMPREHENSIVE INCOME 13.5
17.6

Total Comprehensive Income Attributable to Noncontrolling Interest 1.6
1.0

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER $ 11.9
$ 16.6



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)

SWEPCo Common Shareholder
Common
Stock Paid-in
Capital Retained
Earnings Accumulated
Other
Comprehensive
Income (Loss)
Noncontrolling
Interest
Total
TOTAL EQUITY – DECEMBER 31, 2016 $ 135.7
$ 676.6
$ 1,411.9
$ (9.4 ) $ 0.4
$ 2,215.2

Common Stock Dividends (27.5 ) (27.5 )
Common Stock Dividends – Nonaffiliated

(1.1 ) (1.1 )
Net Income

16.3

1.0
17.3
Other Comprehensive Income

0.3

0.3
TOTAL EQUITY – MARCH 31, 2017 $ 135.7
$ 676.6
$ 1,400.7
$ (9.1 ) $ 0.3
$ 2,204.2

TOTAL EQUITY – DECEMBER 31, 2017 $ 135.7
$ 676.6
$ 1,426.6
$ (4.0 ) $ (0.4 ) $ 2,234.5

Common Stock Dividends

(20.0 )

(20.0 )
Common Stock Dividends – Nonaffiliated

(0.8 ) (0.8 )
ASU 2018-02 Adoption (0.4 ) (0.9 ) (1.3 )
Net Income

11.8

1.6
13.4
Other Comprehensive Income

0.1

0.1
TOTAL EQUITY – MARCH 31, 2018 $ 135.7
$ 676.6
$ 1,418.0
$ (4.8 ) $ 0.4
$ 2,225.9


	SWEPCo Common Shareholder
	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Noncontrolling Interest		Total
TOTAL EQUITY – DECEMBER 31, 2022	$	0.1	$	1,442.2	$	2,236.0	$	(4.2)	$	0.7	$	3,674.8

Capital Contribution from Parent			50.0								50.0

Common Stock Dividends – Nonaffiliated									(1.5)		(1.5)

Net Income					40.6				1.2		41.8
Other Comprehensive Income							0.1				0.1
TOTAL EQUITY – MARCH 31, 2023	$	0.1	$	1,492.2	$	2,276.6	$	(4.1)	$	0.4	$	3,765.2
















TOTAL EQUITY – DECEMBER 31, 2023	$	0.1	$	1,492.2	$	2,281.3	$	(3.4)	$	0.2	$	3,770.4


Common Stock Dividends					(50.0)						(50.0)
Common Stock Dividends – Nonaffiliated									(1.4)		(1.4)

Net Income					208.1				1.5		209.6
Other Comprehensive Loss							(0.2)				(0.2)
TOTAL EQUITY – MARCH 31, 2024	$	0.1	$	1,492.2	$	2,439.4	$	(3.6)	$	0.3	$	3,928.4





See Condensed Notes to Condensed Financial Statements of Registrants beginning on page ~~120~~99.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, ~~2018~~2024 and December 31, ~~2017~~2023

(in millions)

(Unaudited)


	March 31,		December 31,
	2024		2023
CURRENT ASSETS
Cash and Cash Equivalents	$	3.8	$	2.4
Advances to Affiliates	2.3		2.2
Accounts Receivable:
Customers	32.7		39.0
Affiliated Companies	61.2		47.2
Miscellaneous	10.3		8.3

Total Accounts Receivable	104.2		94.5
Fuel	103.4		113.8
Materials and Supplies (March 31, 2024 and December 31, 2023 Amounts Include $3.2 and $3.9, Respectively, Related to Sabine)	84.5		88.4


Accrued Tax Benefits	31.2		28.4
Regulatory Asset for Under-Recovered Fuel Costs	166.3		170.8
Prepayments and Other Current Assets	52.4		40.8
TOTAL CURRENT ASSETS	548.1		541.3

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	4,790.0		4,790.7
Transmission	2,681.1		2,660.6
Distribution	2,881.8		2,824.1
Other Property, Plant and Equipment (March 31, 2024 and December 31, 2023 Amounts Include $179.9 and $182.7, Respectively, Related to Sabine)	819.2		814.4
Construction Work in Progress	644.4		555.8
Total Property, Plant and Equipment	11,816.5		11,645.6
Accumulated Depreciation and Amortization (March 31, 2024 and December 31, 2023 Amounts Include $179.9 and $182.7, Respectively, Related to Sabine)	3,149.8		3,087.2
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	8,666.7		8,558.4

OTHER NONCURRENT ASSETS
Regulatory Assets	1,138.2		1,131.8


Deferred Charges and Other Noncurrent Assets	395.0		326.1
TOTAL OTHER NONCURRENT ASSETS	1,533.2		1,457.9

TOTAL ASSETS	$	10,748.0	$	10,557.6

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

March 31, December 31,
2018 2017
CURRENT ASSETS
Cash and Cash Equivalents

$ 0.7
$ 1.6
Advances to Affiliates 2.0
2.0
Accounts Receivable:
Customers 67.0
70.9
Affiliated Companies 18.0
30.2
Miscellaneous 13.2
25.8
Allowance for Uncollectible Accounts (0.5 ) (1.3 )
Total Accounts Receivable 97.7
125.6
Fuel
(March 31, 2018 and December 31, 2017 Amounts Include $37.7 and $41.5, Respectively, Related to Sabine)
120.5
123.6
Materials and Supplies 68.8
67.9
Risk Management Assets 1.7
6.4
Regulatory Asset for Under-Recovered Fuel Costs 16.5
14.1
Prepayments and Other Current Assets 40.2
39.2
TOTAL CURRENT ASSETS 348.1
380.4

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation 4,622.6
4,624.9
Transmission 1,715.0
1,679.8
Distribution 2,108.1
2,095.8
Other Property, Plant and Equipment
(March 31, 2018 and December 31, 2017 Amounts Include $264.9 and $266.7, Respectively, Related to Sabine)
704.4
684.1
Construction Work in Progress 266.9
233.2
Total Property, Plant and Equipment 9,417.0
9,317.8
Accumulated Depreciation and Amortization
(March 31, 2018 and December 31, 2017 Amounts Include $167.4 and $165.9, Respectively, Related to Sabine)
2,724.7
2,685.8
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
6,692.3
6,632.0

OTHER NONCURRENT ASSETS
Regulatory Assets 217.9
220.6
Deferred Charges and Other Noncurrent Assets 165.5
109.9
TOTAL OTHER NONCURRENT ASSETS 383.4
330.5

TOTAL ASSETS $ 7,423.8
$ 7,342.9



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

March 31, ~~2018~~2024 and December 31, ~~2017~~2023

(Unaudited)


	March 31,		December 31,
	2024		2023
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	254.5	$	88.7
Accounts Payable:
General	185.3		198.9
Affiliated Companies	49.3		45.9
Short-term Debt – Nonaffiliated	5.4		4.3


Customer Deposits	74.1		72.5
Accrued Taxes	128.5		58.7
Accrued Interest	37.4		39.9

Obligations Under Operating Leases	8.8		9.0


Other Current Liabilities	108.0		169.0
TOTAL CURRENT LIABILITIES	851.3		686.9

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	3,647.6		3,646.9

Deferred Income Taxes	1,254.2		1,179.3
Regulatory Liabilities and Deferred Investment Tax Credits	566.9		756.1
Asset Retirement Obligations	240.3		258.6
Employee Benefits and Pension Obligations	43.8		43.1

Obligations Under Operating Leases	120.8		122.5
Deferred Credits and Other Noncurrent Liabilities	94.7		93.8
TOTAL NONCURRENT LIABILITIES	5,968.3		6,100.3

TOTAL LIABILITIES	6,819.6		6,787.2

Rate Matters (Note 4)
Commitments and Contingencies (Note 5)

EQUITY
Common Stock – Par Value – $18 Per Share:
Authorized – 3,680 Shares
Outstanding – 3,680 Shares	0.1		0.1
Paid-in Capital	1,492.2		1,492.2
Retained Earnings	2,439.4		2,281.3
Accumulated Other Comprehensive Income (Loss)	(3.6)		(3.4)
TOTAL COMMON SHAREHOLDER’S EQUITY	3,928.1		3,770.2

Noncontrolling Interest	0.3		0.2

TOTAL EQUITY	3,928.4		3,770.4

TOTAL LIABILITIES AND EQUITY	$	10,748.0	$	10,557.6

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

March 31, December 31,
2018 2017
(in millions)
CURRENT LIABILITIES
Advances from Affiliates $ 148.6
$ 118.7
Accounts Payable:
General 118.5
160.4
Affiliated Companies 60.7
63.7
Short-term Debt – Nonaffiliated 22.6
22.0
Long-term Debt Due Within One Year – Nonaffiliated 457.2
3.7
Risk Management Liabilities 0.1
0.2
Customer Deposits 62.9
62.1
Accrued Taxes 91.1
39.0
Accrued Interest 25.9
38.9
Obligations Under Capital Leases 11.3
11.2
Other Current Liabilities 60.4
78.7
TOTAL CURRENT LIABILITIES 1,059.3
598.6

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated 2,046.5
2,438.2
Long-term Risk Management Liabilities 0.5
—
Deferred Income Taxes 924.2
917.7
Regulatory Liabilities and Deferred Investment Tax Credits 895.2
896.4
Asset Retirement Obligations 160.8
160.3
Employee Benefits and Pension Obligations 18.1
19.5
Obligations Under Capital Leases 56.9
57.8
Deferred Credits and Other Noncurrent Liabilities 36.4
19.9
TOTAL NONCURRENT LIABILITIES 4,138.6
4,509.8

TOTAL LIABILITIES 5,197.9
5,108.4

Rate Matters (Note 4)

Commitments and Contingencies (Note 5)

EQUITY
Common Stock – Par Value – $18 Per Share:
Authorized – 7,600,000 Shares
Outstanding – 7,536,640 Shares 135.7
135.7
Paid-in Capital 676.6
676.6
Retained Earnings 1,418.0
1,426.6
Accumulated Other Comprehensive Income (Loss) (4.8 ) (4.0 )
TOTAL COMMON SHAREHOLDER’S EQUITY 2,225.5
2,234.9

Noncontrolling Interest 0.4
(0.4 )

TOTAL EQUITY 2,225.9
2,234.5

TOTAL LIABILITIES AND EQUITY $ 7,423.8
$ 7,342.9



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, ~~2018~~2024 and ~~2017~~2023

(in millions)

(Unaudited)


	Three Months Ended March 31,
	2024		2023
OPERATING ACTIVITIES
Net Income	$	209.6	$	41.8
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	78.7		80.4
Deferred Income Taxes	(118.5)		10.8

Allowance for Equity Funds Used During Construction	(3.4)		(0.5)
Mark-to-Market of Risk Management Contracts	1.7		9.9

Property Taxes	(74.3)		(77.5)
Deferred Fuel Over/Under-Recovery, Net	22.8		42.9

Change in Other Noncurrent Assets	(10.2)		7.2
Change in Other Noncurrent Liabilities	(0.3)		(3.3)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(9.7)		29.9
Fuel, Materials and Supplies	9.4		(4.3)
Accounts Payable	(29.6)		(47.8)
Accrued Taxes, Net	67.0		62.3

Other Current Assets	(17.7)		7.3
Other Current Liabilities	(55.7)		(48.9)
Net Cash Flows from Operating Activities	69.8		110.2

INVESTING ACTIVITIES
Construction Expenditures	(182.6)		(201.9)
Change in Advances to Affiliates, Net	(0.1)		—

Other Investing Activities	3.0		0.4
Net Cash Flows Used for Investing Activities	(179.7)		(201.5)

FINANCING ACTIVITIES
Capital Contribution from Parent	—		50.0
Issuance of Long-term Debt – Nonaffiliated	—		347.3

Change in Short-term Debt – Nonaffiliated	1.1		16.0
Change in Advances from Affiliates, Net	165.8		(291.9)
Retirement of Long-term Debt – Nonaffiliated	—		(94.1)
Principal Payments for Finance Lease Obligations	(4.4)		(14.8)
Dividends Paid on Common Stock	(50.0)		—
Dividends Paid on Common Stock – Nonaffiliated	(1.4)		(1.5)
Other Financing Activities	0.2		0.1
Net Cash Flows from Financing Activities	111.3		11.1

Net Increase (Decrease) in Cash and Cash Equivalents	1.4		(80.2)
Cash and Cash Equivalents at Beginning of Period	2.4		88.4
Cash and Cash Equivalents at End of Period	$	3.8	$	8.2

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	41.2	$	45.3

Cash Received from the Sale of Transferable Tax Credits	(19.9)		—
Noncash Acquisitions Under Finance Leases	0.4		0.9
Construction Expenditures Included in Current Liabilities as of March 31,	79.4		113.3

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

Three Months Ended March 31,
2018 2017
OPERATING ACTIVITIES

Net Income $ 13.4
$ 17.3
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 57.4
50.8
Deferred Income Taxes 1.0
43.1
Allowance for Equity Funds Used During Construction (2.3 ) (0.8 )
Mark-to-Market of Risk Management Contracts 5.1
0.4
Property Taxes (48.8 ) (45.3 )
Deferred Fuel Over/Under-Recovery, Net (4.6 ) (3.4 )
Change in Other Noncurrent Assets 1.3
(0.6 )
Change in Other Noncurrent Liabilities 18.8
(12.1 )
Changes in Certain Components of Working Capital:
Accounts Receivable, Net 27.9
23.1
Fuel, Materials and Supplies 2.2
12.5
Accounts Payable (24.6 ) (33.5 )
Accrued Taxes, Net 55.2
11.8
Accrued Interest (13.0 ) (20.3 )
Other Current Assets (0.8 ) 3.2
Other Current Liabilities (12.5 ) (19.1 )
Net Cash Flows from Operating Activities 75.7
27.1

INVESTING ACTIVITIES
Construction Expenditures (139.7 ) (75.6 )
Change in Advances to Affiliates, Net —
167.8
Other Investing Activities (5.4 ) (4.4 )
Net Cash Flows from (Used for) Investing Activities (145.1 ) 87.8

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated 444.6
—
Change in Short-term Debt, Net – Nonaffiliated 0.6
—
Change in Advances from Affiliates, Net 29.9
167.9
Retirement of Long-term Debt – Nonaffiliated (383.4 ) (251.7 )
Principal Payments for Capital Lease Obligations (2.8 ) (2.8 )
Dividends Paid on Common Stock (20.0 ) (27.5 )
Dividends Paid on Common Stock – Nonaffiliated (0.8 ) (1.1 )
Other Financing Activities 0.4
0.3
Net Cash Flows from (Used for) Financing Activities 68.5
(114.9 )

Net Decrease in Cash and Cash Equivalents (0.9 ) —
Cash and Cash Equivalents at Beginning of Period 1.6
10.3
Cash and Cash Equivalents at End of Period $ 0.7
$ 10.3

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts $ 43.7
$ 50.6
Net Cash Paid (Received) for Income Taxes (0.1 ) —
Noncash Acquisitions Under Capital Leases 1.9
1.3
Construction Expenditures Included in Current Liabilities as of March 31, 50.3
31.8



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~120~~.

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANTS

The condensed notes to condensed financial statements are a combined presentation for the Registrants. The following list indicates Registrants to which the notes apply. Specific disclosures within each note apply to all Registrants unless indicated ~~otherwise.~~

otherwise:

Note

Registrant

Page
Number

~~Note~~

~~Registrant~~

~~Page~~

~~Number~~

Significant Accounting Matters

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

~~121~~100

New Accounting ~~Pronouncements~~Standards

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

~~123~~101

Comprehensive Income

AEP

~~AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo~~

~~126~~103

Rate Matters

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

~~133~~104

Commitments, Guarantees and Contingencies

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

~~144~~117

~~Dispositions~~Acquisitions and ~~Impairments~~Dispositions

AEP, PSO

~~AEP, APCo~~

~~149~~121

Benefit Plans

AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo

~~150~~122

Business Segments

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

~~152~~123

Derivatives and Hedging

AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo

~~157~~126

Fair Value Measurements

~~AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo~~

~~167~~

~~Income Taxes~~

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

~~184~~135

~~Financing Activities~~Income Taxes

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

~~188~~148

~~Variable Interest Entities~~Financing Activities

~~AEP~~

~~195~~

~~Revenue From Contracts With Customers~~

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

150

Variable Interest Entities

AEP

~~197~~156

Revenue from Contracts with Customers

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

158

1. SIGNIFICANT ACCOUNTING MATTERS

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

General

The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair ~~presentation~~statement of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three months ended March 31, ~~2018~~2024 is not necessarily indicative of results that may be expected for the year ending December 31, ~~2018.~~2024. The condensed financial statements are unaudited and should be read in conjunction with the audited ~~2017~~2023 financial statements and notes thereto, which are included in the Registrants’ Annual Reports on Form 10-K as filed with the SEC on February ~~22, 2018.~~26, 2024.

Earnings Per Share (EPS) (Applies to AEP)

Basic EPS is calculated by dividing net earnings available to common shareholders by the ~~weighted average~~weighted-average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the ~~weighted average~~weighted-average outstanding common shares, assuming conversion of all potentially dilutive stock ~~options and~~ awards.

The following table presents AEP’s basic and diluted EPS calculations included on the statements of income:

Three Months Ended March 31,
2018 2017
(in millions, except per share data)

$/share $/share
Earnings Attributable to AEP Common Shareholders $ 454.4

$ 592.2

Weighted Average Number of Basic Shares Outstanding 492.3
$ 0.92
491.7
$ 1.20
Weighted Average Dilutive Effect of Stock-Based Awards 0.8
—
0.3
—
Weighted Average Number of Diluted Shares Outstanding 493.1
$ 0.92
492.0
$ 1.20


	Three Months Ended March 31,
	2024				2023
	(in millions, except per share data)
			$/share				$/share


Earnings Attributable to AEP Common Shareholders	$	1,003.1			$	397.0

Weighted-Average Number of Basic AEP Common Shares Outstanding	526.6		$	1.91	514.2		$	0.77
Weighted-Average Dilutive Effect of Stock-Based Awards	1.0		(0.01)		1.4		—
Weighted-Average Number of Diluted AEP Common Shares Outstanding	527.6		$	1.90	515.6		$	0.77

There were no antidilutive shares outstanding as of March 31, ~~2018~~2024 and ~~2017.~~2023.

Restricted Cash (Applies to AEP, AEP Texas ~~APCo~~ and ~~OPCo)~~APCo)

Restricted Cash primarily includes funds held by trustees for the payment of securitization bonds.

Reconciliation of Cash, Cash Equivalents and Restricted Cash

The following tables provide a reconciliation of Cash, Cash Equivalents and Restricted Cash reported within the balance ~~sheet~~sheets that sum to the total of the same amounts shown on the ~~statement~~statements of cash flows:


	March 31, 2024
	AEP		AEP Texas		APCo
	(in millions)
Cash and Cash Equivalents	$	230.7	$	0.1	$	7.6
Restricted Cash	51.1		42.7		8.4
Total Cash, Cash Equivalents and Restricted Cash	$	281.8	$	42.8	$	16.0


	December 31, 2023
	AEP		AEP Texas		APCo
	(in millions)
Cash and Cash Equivalents	$	330.1	$	0.1	$	5.0
Restricted Cash	48.9		34.0		14.9
Total Cash, Cash Equivalents and Restricted Cash	$	379.0	$	34.1	$	19.9

100

March 31, 2018
AEP AEP Texas APCo OPCo
(in millions)
Cash and Cash Equivalents $ 183.4
$ 0.1
$ 1.2
$ 1.4
Restricted Cash 133.1
107.1
10.1
15.9
Total Cash, Cash Equivalents and Restricted Cash $ 316.5
$ 107.2
$ 11.3
$ 17.3

December 31, 2017
AEP AEP Texas APCo OPCo
(in millions)
Cash and Cash Equivalents $ 214.6
$ 2.0
$ 2.9
$ 3.1
Restricted Cash 198.0
155.2
16.3
26.6
Total Cash, Cash Equivalents and Restricted Cash $ 412.6
$ 157.2
$ 19.2
$ 29.7

2. NEW ACCOUNTING ~~PRONOUNCEMENTS~~STANDARDS

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

~~During~~Management reviews the FASB’s standard-setting process and ~~upon issuance of final pronouncements, management reviews~~ the ~~new accounting literature~~SEC’s rulemaking activity to determine ~~its~~the relevance, if any, to the Registrants’ business. The following ~~pronouncements~~standards/rules will impact the Registrants’ financial statements.

SEC Climate Disclosure Rule

On March 6, 2024, the SEC adopted final rules that require Registrants to disclose certain climate-related information in registration statements and annual reports. The final rules require Registrants to disclose, among other things, material climate-related risks, activities to mitigate such risks and information about Registrant’s board of directors oversight and management’s role in managing material climate-related risks. The final rules also require the Registrants to provide information related to any climate-related targets or goals that are material to Registrant’s business, results of operations, or financial condition. A majority of the reporting requirements are applicable to the fiscal year beginning in 2025, with the addition of assurance reporting for greenhouse gas emissions starting in 2029 for large accelerated filers. Litigation challenging the new rules was filed by multiple parties in multiple jurisdictions, which have been consolidated and assigned to the U.S. Court of Appeals for the Eighth Circuit. On April 4, 2024, the SEC issued an order staying the final climate disclosure rules pending the completion of judicial review at the Court of Appeals. The Registrants are currently evaluating the impact of the final rules on their respective consolidated financial statements and related disclosures.

ASU ~~2014-09 “Revenue from Contracts with Customers”~~2023-09 “Improvements to Income Tax Disclosures” (ASU ~~2014-09)~~2023-09)

In ~~May 2014,~~December 2023, the FASB issued ASU ~~2014-09 changing~~2023-09, to address investors’ suggested enhancements to (a) better understand an entity’s exposure to potential changes in jurisdictional tax legislation and the ~~method used~~ensuing risks and opportunities, (b) assess income tax information that affects cash flow forecasts and capital allocation decisions and (c) identify potential opportunities to ~~determine~~increase future cash flows.

The new standard requires an annual rate reconciliation disclosure of the ~~timing~~following categories regardless of materiality: state and ~~requirements for revenue~~local income tax net of federal income tax effect, foreign tax effects, effect of changes in tax laws or rates enacted in the current period, effect of cross-border tax laws, tax credits, changes in valuation allowances, nontaxable or nondeductible items and changes in unrecognized tax benefits.

The new standard also requires an annual disclosure of the amount of income taxes paid (net of refunds received) disaggregated by federal, state and foreign taxes and by individual jurisdictions that are equal to or greater than 5 percent of total income taxes paid. Disclosure of income (loss) from continuing operations before income tax expense (benefit) disaggregated between domestic and foreign jurisdictions and income tax expense (benefit) from continuing operations disaggregated by federal, state and foreign jurisdictions is required.

The new standard removes the requirement to disclose the cumulative amount of each type of temporary difference when a deferred tax liability is not recognized because of the exceptions to comprehensive recognition ~~on the statements~~ of ~~income. Under~~deferred taxes related to subsidiaries and corporate joint ventures.

The amendments in the new standard ~~an entity must identify~~may be applied on either a prospective or retrospective basis for public business entities for fiscal years beginning after December 15, 2024 with early adoption permitted. Management has not yet made a decision to early adopt the ~~performance obligations in a contract, determine the transaction price and allocate the price~~amendments to ~~specific performance obligations~~this standard or how to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts.apply them.

Management adopted ASU 2014-09 effective January 1, 2018, by means of the modified retrospective approach for all contracts. The adoption of ASU 2014-09 did not have a material impact on results of operations, financial position or cash flows. In that regard, the application of the new standard did not cause any significant differences in any individual financial statement line items had those line items been presented in accordance with the guidance that was in effect prior to the adoption of the new standard. Further, given the lack of material impact to the financial statements, the adoption of the new standard did not give rise to any material changes in the Registrants’ previously established accounting policies for revenue. See Note 14 - Revenue from Contracts with Customers for additional disclosures required by the new standard.

101

ASU ~~2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities”~~2023-07 “Improvements to Reportable Segment Disclosures” (ASU ~~2016-01)~~2023-07)

In ~~January 2016,~~November 2023, the FASB issued ASU ~~2016-01 revising~~2023-07, to address investors’ observations that there is limited information disclosed about segment expenses and to better understand expense categories and amounts included in segment profit or loss. The new standard requires annual and interim disclosure of (a) the ~~reporting model for financial instruments. Under~~categories and amounts of significant segment expenses (determined by management using both qualitative and quantitative factors) that are regularly provided to the CODM and included within each reported measure of segment profit or loss, (b) the amounts and a qualitative description of “other segment items”, defined as the difference between reported segment revenues less the significant segment expenses and each reported measure of segment profit or loss disclosed, (c) reportable segment profit or loss and assets that are currently only required annually, (d) the CODM’s title and position, and an explanation of how the CODM uses the reported measure(s) of segment profit or loss in assessing segment performance and deciding how to allocate resources and (e) a requirement that entities with a single reportable segment provide all disclosures required by ASU 2023-07 and all existing segment disclosures in Topic 280. Additionally, this new standard allows disclosure of one or more of additional profit or loss measures if the CODM uses more than one measure provided that at least one of the disclosed measures is determined in a manner “most consistent with the measurement principles under GAAP”. If multiple measures are presented, additional disclosure is required about how the CODM uses each measure to assess performance and decide how to allocate resources.

The amendments in the new standard ~~equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee)~~ are required to be measured at fair value with changes in fair value recognized in net income. For equity investments that do not have a readily determinable fair value, entities are permitted to elect a practicality exception and measure the investment at cost, less impairment, plus or minus observable price changes. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheets or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowanceeffective on a ~~deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets.~~

~~The new accounting guidance is effective~~retrospective basis for all entities for fiscal years beginning after December 15, 2023 and interim ~~and annual~~periods within fiscal periods beginning after December 15, ~~2017,~~2024 with early adoption permitted for certain provisions. Management adopted ASU 2016-01 effective January 1, 2018, by means of a cumulative-effect adjustment to the balance sheet. The adoption of ASU 2016-01 resulted in an immaterial impact on results of operations and financial position of AEP, and no impact to results of operations or financial position of the Registrant Subsidiaries. There was no impact on cash flows of the Registrants.

~~ASU 2016-02 “Accounting for Leases” (ASU 2016-02)~~

In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheets and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard.

~~The new accounting guidance is effective for annual periods beginning after December 15, 2018, with early adoption~~ permitted. Initial decisions were made to apply the guidance by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented; however, the FASB is currently evaluating draft guidance which would provide an optional expedient to adopt the new lease requirements through a cumulative-effect adjustment in the period of adoption. Management continues to monitor these standard-setting activities that may impact the transition requirements of the lease standard.

During 2016 and 2017, lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Multiple lease system options were also evaluated. Management plans to elect certain of the following practical expedients upon adoption:



~~Practical Expedient~~		~~Description~~
~~Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package)~~		Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases.
~~Lease and Non-lease Components (elect by class of underlying asset)~~		~~Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component.~~
~~Short-term Lease (elect by class of underlying asset)~~		~~Elect as an accounting policy to not apply the recognition requirements to short-term leases.~~
~~Lease term~~		~~Elect to use hindsight to determine the lease term.~~
~~Existing and expired land easements not previously accounted for as leases~~		Elect optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840.

Evaluation of new lease contracts continues and the process of implementing a compliant lease system solution began in the third quarter of 2017. Management expects the new standard to impact financial position and, at this time, cannot estimate the impact. Management expects no impact to results of operations or cash flows.

Management continues to monitor industry implementation issues as well as FASB’s ongoing standard-setting activities that may result in the issuance of additional targeted improvements to the new lease guidance. Management plans to adopt ASU ~~2016-02 effective January 1, 2019.~~

~~ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13)~~

In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination.

~~The new accounting guidance is~~2023-07 effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020.2024 10-K.

102

~~ASU 2017-07 “Compensation - Retirement Benefits” (ASU 2017-07)~~

In March 2017, the FASB issued ASU 2017-07 requiring that an employer report the service cost component of pension and postretirement benefits in the same line item or items as other compensation costs. The other components of net benefit cost are required to be presented on the statements of income separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor.

Management adopted ASU 2017-07 effective January 1, 2018. Presentation of the non-service components on a separate line outside of operating income was applied on a retrospective basis, using the amounts disclosed in the benefit plan note for the estimation basis as a practical expedient. Capitalization of only the service cost component was applied on a prospective basis.

~~ASU 2017-12 “Derivatives and Hedging” (ASU 2017-12)~~

In August 2017, the FASB issued ASU 2017-12 amending the recognition and presentation requirements for hedge accounting activities. The objectives are to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and reduce the complexity of applying hedge accounting. Under the new standard, the concept of recognizing hedge ineffectiveness within the statements of income for cash flow hedges, which has historically been immaterial to AEP, will be eliminated. In addition, certain required tabular disclosures relating to fair value and cash flow hedges will be modified.

The accounting guidance is effective for interim and annual periods beginning after December 15, 2018, with early adoption permitted for any interim or annual period after August 2017. Management is analyzing the impact of this new standard, including the possibility of early adoption, and at this time, cannot estimate the impact of adoption on results of operations, financial position or cash flows.

~~ASU 2018-02 “Reclassification of Certain Tax Effects from AOCI” (ASU 2018-02)~~

In February 2018, the FASB issued ASU 2018-02 allowing a reclassification from AOCI to Retained Earnings for stranded tax effects resulting from Tax Reform. The accounting guidance for “Income Taxes” requires deferred tax assets and liabilities to be adjusted for the effect of a change in tax law or rates with the effect included in income from continuing operations in the reporting period that includes the enactment date of the tax change. This guidance is applicable for the tax effects of items in AOCI that were originally recognized in Other Comprehensive Income. As a result and absent the new guidance in this ASU, the tax effects of items within AOCI would not reflect the newly enacted corporate tax rate.

Management adopted ASU 2018-02 effective January 1, 2018, electing to reclassify the effects of the change in the federal corporate tax rate due to Tax Reform from AOCI to Retained Earnings. A portion of the reclassification was recorded to Regulatory Liabilities to adjust the tax effects of certain interest rate hedges in AEP's regulated jurisdictions that were previously deferred as a part of the accounting for Tax Reform. There were no other effects from Tax Reform that impacted AOCI. Management applied the new guidance at the beginning of the period of adoption. The adoption of the new standard did not have a material impact on the statement of financial position and did not impact results of operations or cash flows.

3. COMPREHENSIVE INCOME

The disclosures in this note apply to ~~all Registrants except for AEPTCo. AEPTCo does~~AEP only. The impact of AOCI is not ~~have any components of other comprehensive income for any period presented in~~material to the financial ~~statements.~~statements of the Registrant Subsidiaries.

Presentation of Comprehensive Income

The following tables provide ~~the~~AEP’s components of changes in AOCI and details of reclassifications from ~~AOCI for the three months ended March 31, 2018 and 2017.~~AOCI. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 - Benefit Plans for additional ~~details.~~information.

~~AEP~~


	Cash Flow Hedges				Pension
Three Months Ended March 31, 2024	Commodity		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of December 31, 2023	$	104.9	$	(8.1)	$	(152.3)	$	(55.5)
Change in Fair Value Recognized in AOCI, Net of Tax	5.5		12.4		—		17.9
Amount of (Gain) Loss Reclassified from AOCI

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)	(29.3)		—		—		(29.3)
Interest Expense (a)	—		(1.2)		—		(1.2)
Amortization of Prior Service Cost (Credit)	—		—		(1.3)		(1.3)
Amortization of Actuarial (Gains) Losses	—		—		0.5		0.5
Reclassifications from AOCI, before Income Tax Benefit	(29.3)		(1.2)		(0.8)		(31.3)
Income Tax Benefit	(6.1)		(0.3)		(0.2)		(6.6)
Reclassifications from AOCI, Net of Income Tax Benefit	(23.2)		(0.9)		(0.6)		(24.7)
Net Current Period Other Comprehensive Income (Loss)	(17.7)		11.5		(0.6)		(6.8)
Balance in AOCI as of March 31, 2024	$	87.2	$	3.4	$	(152.9)	$	(62.3)

~~Changes in Accumulated Other Comprehensive Income (Loss) by Component~~


	Cash Flow Hedges				Pension
Three Months Ended March 31, 2023	Commodity		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of December 31, 2022	$	223.5	$	0.3	$	(140.1)	$	83.7
Change in Fair Value Recognized in AOCI, Net of Tax	(195.3)		5.2		(12.9)		(203.0)
Amount of (Gain) Loss Reclassified from AOCI

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)	47.0		—		—		47.0
Interest Expense (a)	—		0.7		—		0.7
Amortization of Prior Service Cost (Credit)	—		—		(5.3)		(5.3)
Amortization of Actuarial (Gains) Losses	—		—		1.2		1.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit	47.0		0.7		(4.1)		43.6
Income Tax (Expense) Benefit	9.9		0.1		(0.9)		9.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	37.1		0.6		(3.2)		34.5
Reclassifications of KPCo Pension and OPEB Regulatory Assets from AOCI, Before Income Tax (Expense) Benefit	—		—		21.1		21.1
Income Tax (Expense) Benefit	—		—		4.4		4.4
Reclassifications of KPCo Pension and OPEB Regulatory Assets from AOCI, Net of Income Tax (Expense) Benefit	—		—		16.7		16.7
Net Current Period Other Comprehensive Income (Loss)	(158.2)		5.8		0.6		(151.8)
Balance in AOCI as of March 31, 2023	$	65.3	$	6.1	$	(139.5)	$	(68.1)

~~For~~

(a)Amounts reclassified to the ~~Three Months Ended March 31, 2018~~referenced line item on the statements of income.

103

Cash Flow Hedges
Commodity Interest Rate
Securities
Available for Sale

Pension
and OPEB
Total
(in millions)
Balance in AOCI as of December 31, 2017 $ (28.4 ) $ (13.0 ) $ 11.9
$ (38.3 ) $ (67.8 )
Change in Fair Value Recognized in AOCI 12.8
—
—
—
12.8
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity for Resale (13.1 ) —
—
—
(13.1 )
Interest Expense —
0.3
—
—
0.3
Amortization of Prior Service Cost (Credit) —
—
—
(5.0 ) (5.0 )
Amortization of Actuarial (Gains)/Losses —
—
—
3.2
3.2
Reclassifications from AOCI, before Income Tax (Expense) Credit (13.1 ) 0.3
—
(1.8 ) (14.6 )
Income Tax (Expense) Credit (2.8 ) 0.1
—
(0.4 ) (3.1 )
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (10.3 ) 0.2
—
(1.4 ) (11.5 )
Net Current Period Other Comprehensive Income (Loss) 2.5
0.2
—
(1.4 ) 1.3
ASU 2018-02 Adoption (a) (6.1 ) (2.7 ) —
(8.2 ) (17.0 )
ASU 2016-01 Adoption (a) —
—
(11.9 ) —
(11.9 )
Balance in AOCI as of March 31, 2018 $ (32.0 ) $ (15.5 ) $ —
$ (47.9 ) $ (95.4 )


~~(a)~~	~~See Note 2 - New Accounting Pronouncements for additional information.~~

~~AEP~~

~~Changes in Accumulated Other Comprehensive Income (Loss) by Component~~

~~For the Three Months Ended March 31, 2017~~

Cash Flow Hedges
Commodity Interest Rate
Securities
Available for Sale

Pension
and OPEB
Total
(in millions)
Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4
$ (125.9 ) $ (156.3 )
Change in Fair Value Recognized in AOCI (21.8 ) —
1.2
—
(20.6 )
Amount of (Gain) Loss Reclassified from AOCI

Generation & Marketing Revenues (4.7 ) —
—
—
(4.7 )
Purchased Electricity for Resale 12.8
—
—
—
12.8
Interest Expense —
0.5
—
—
0.5
Amortization of Prior Service Cost (Credit) —
—
—
(4.9 ) (4.9 )
Amortization of Actuarial (Gains)/Losses —
—
—
5.3
5.3
Reclassifications from AOCI, before Income Tax (Expense) Credit 8.1
0.5
—
0.4
9.0
Income Tax (Expense) Credit 2.8
0.1
—
0.2
3.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 5.3
0.4
—
0.2
5.9
Net Current Period Other Comprehensive Income (Loss) (16.5 ) 0.4
1.2
0.2
(14.7 )
Balance in AOCI as of March 31, 2017 $ (39.6 ) $ (15.3 ) $ 9.6
$ (125.7 ) $ (171.0 )

~~AEP Texas~~

~~Changes in Accumulated Other Comprehensive Income (Loss) by Component~~

~~For the Three Months Ended March 31, 2018~~

Cash Flow Hedge - Interest Rate
Pension
and OPEB
Total
(in millions)
Balance in AOCI as of December 31, 2017 $ (4.5 ) $ (8.1 ) $ (12.6 )
Change in Fair Value Recognized in AOCI —
—
—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense 0.3
—
0.3
Amortization of Prior Service Cost (Credit) —
—
—
Amortization of Actuarial (Gains)/Losses —
0.1
0.1
Reclassifications from AOCI, before Income Tax (Expense) Credit 0.3
0.1
0.4
Income Tax (Expense) Credit 0.1
—
0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.2
0.1
0.3
Net Current Period Other Comprehensive Income (Loss) 0.2
0.1
0.3
ASU 2018-02 Adoption (a) (0.9 ) (1.8 ) (2.7 )
Balance in AOCI as of March 31, 2018 $ (5.2 ) $ (9.8 ) $ (15.0 )


~~(a)~~	~~See Note 2 - New Accounting Pronouncements for additional information.~~

~~AEP Texas~~

~~Changes in Accumulated Other Comprehensive Income (Loss) by Component~~

~~For the Three Months Ended March 31, 2017~~

Cash Flow Hedge - Interest Rate
Pension
and OPEB
Total
(in millions)
Balance in AOCI as of December 31, 2016 $ (5.4 ) $ (9.5 ) $ (14.9 )
Change in Fair Value Recognized in AOCI —
—
—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense 0.3
—
0.3
Amortization of Actuarial (Gains)/Losses —
0.1
0.1
Reclassifications from AOCI, before Income Tax (Expense) Credit 0.3
0.1
0.4
Income Tax (Expense) Credit 0.1
—
0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.2
0.1
0.3
Net Current Period Other Comprehensive Income (Loss) 0.2
0.1
0.3
Balance in AOCI as of March 31, 2017 $ (5.2 ) $ (9.4 ) $ (14.6 )

~~APCo~~

~~Changes in Accumulated Other Comprehensive Income (Loss) by Component~~

~~For the Three Months Ended March 31, 2018~~

Cash Flow Hedges
Commodity Interest Rate
Pension
and OPEB
Total
(in millions)
Balance in AOCI as of December 31, 2017 $ —
$ 2.2
$ (0.9 ) $ 1.3
Change in Fair Value Recognized in AOCI (0.7 ) —
—
(0.7 )
Amount of (Gain) Loss Reclassified from AOCI

Purchased Electricity for Resale 0.9
—
—
0.9
Interest Expense —
(0.3 ) —
(0.3 )
Amortization of Prior Service Cost (Credit) —
—
(1.3 ) (1.3 )
Amortization of Actuarial (Gains)/Losses —
—
0.3
0.3
Reclassifications from AOCI, before Income Tax (Expense) Credit 0.9
(0.3 ) (1.0 ) (0.4 )
Income Tax (Expense) Credit 0.2
(0.1 ) (0.2 ) (0.1 )
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7
(0.2 ) (0.8 ) (0.3 )
Net Current Period Other Comprehensive Income (Loss) —
(0.2 ) (0.8 ) (1.0 )
ASU 2018-02 Adoption (a) —
0.5
(0.2 ) 0.3
Balance in AOCI as of March 31, 2018 $ —
$ 2.5
$ (1.9 ) $ 0.6


~~(a)~~	~~See Note 2 - New Accounting Pronouncements for additional information.~~

~~APCo~~

~~Changes in Accumulated Other Comprehensive Income (Loss) by Component~~

~~For the Three Months Ended March 31, 2017~~

Cash Flow Hedge - Interest Rate
Pension
and OPEB
Total
(in millions)
Balance in AOCI as of December 31, 2016 $ 2.9
$ (11.3 ) $ (8.4 )
Change in Fair Value Recognized in AOCI —
—
—
Amount of (Gain) Loss Reclassified from AOCI

Interest Expense (0.3 ) —
(0.3 )
Amortization of Prior Service Cost (Credit) —
(1.3 ) (1.3 )
Amortization of Actuarial (Gains)/Losses —
0.8
0.8
Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 )
Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 )
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 )
Net Current Period Other Comprehensive Income (Loss) (0.2 ) (0.3 ) (0.5 )
Balance in AOCI as of March 31, 2017 $ 2.7
$ (11.6 ) $ (8.9 )

~~I&M~~

~~Changes in Accumulated Other Comprehensive Income (Loss) by Component~~

~~For the Three Months Ended March 31, 2018~~

Cash Flow Hedge - Interest Rate
Pension
and OPEB
Total
(in millions)
Balance in AOCI as of December 31, 2017 $ (10.7 ) $ (1.4 ) $ (12.1 )
Change in Fair Value Recognized in AOCI —
—
—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense 0.5
—
0.5
Amortization of Prior Service Cost (Credit) —
(0.2 ) (0.2 )
Amortization of Actuarial (Gains)/Losses —
0.2
0.2
Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5
—
0.5
Income Tax (Expense) Credit 0.1
—
0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4
—
0.4
Net Current Period Other Comprehensive Income (Loss) 0.4
—
0.4
ASU 2018-02 Adoption (a) (2.4 ) (0.3 ) (2.7 )
Balance in AOCI as of March 31, 2018 $ (12.7 ) $ (1.7 ) $ (14.4 )


~~(a)~~	~~See Note 2 - New Accounting Pronouncements for additional information.~~

~~I&M~~

~~Changes in Accumulated Other Comprehensive Income (Loss) by Component~~

~~For the Three Months Ended March 31, 2017~~

Cash Flow Hedge - Interest Rate
Pension
and OPEB
Total
(in millions)
Balance in AOCI as of December 31, 2016 $ (12.0 ) $ (4.2 ) $ (16.2 )
Change in Fair Value Recognized in AOCI —
—
—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense 0.5
—
0.5
Amortization of Prior Service Cost (Credit) —
(0.2 ) (0.2 )
Amortization of Actuarial (Gains)/Losses —
0.2
0.2
Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5
—
0.5
Income Tax (Expense) Credit 0.2
—
0.2
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3
—
0.3
Net Current Period Other Comprehensive Income (Loss) 0.3
—
0.3
Balance in AOCI as of March 31, 2017 $ (11.7 ) $ (4.2 ) $ (15.9 )

~~OPCo~~

~~Changes in Accumulated Other Comprehensive Income (Loss) by Component~~

~~For the Three Months Ended March 31, 2018~~

Cash Flow Hedge - Interest Rate
(in millions)
Balance in AOCI as of December 31, 2017 $ 1.9
Change in Fair Value Recognized in AOCI —
Amount of (Gain) Loss Reclassified from AOCI

Interest Expense (0.4 )
Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 )
Income Tax (Expense) Credit (0.1 )
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 )
Net Current Period Other Comprehensive Income (Loss) (0.3 )
ASU 2018-02 Adoption (a) 0.4
Balance in AOCI as of March 31, 2018 $ 2.0


~~(a)~~	~~See Note 2 - New Accounting Pronouncements for additional information.~~

~~OPCo~~

~~Changes in Accumulated Other Comprehensive Income (Loss) by Component~~

~~For the Three Months Ended March 31, 2017~~

Cash Flow Hedge - Interest Rate
(in millions)
Balance in AOCI as of December 31, 2016 $ 3.0
Change in Fair Value Recognized in AOCI —
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (0.4 )
Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 )
Income Tax (Expense) Credit (0.2 )
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 )
Net Current Period Other Comprehensive Income (Loss) (0.2 )
Balance in AOCI as of March 31, 2017 $ 2.8

~~PSO~~

~~Changes in Accumulated Other Comprehensive Income (Loss) by Component~~

~~For the Three Months Ended March 31, 2018~~

Cash Flow Hedge - Interest Rate
(in millions)
Balance in AOCI as of December 31, 2017 $ 2.6
Change in Fair Value Recognized in AOCI —
Amount of (Gain) Loss Reclassified from AOCI

Interest Expense (0.3 )
Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 )
Income Tax (Expense) Credit (0.1 )
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 )
Net Current Period Other Comprehensive Income (Loss) (0.2 )
ASU 2018-02 Adoption (a) 0.5
Balance in AOCI as of March 31, 2018 $ 2.9


~~(a)~~	~~See Note 2 - New Accounting Pronouncements for additional information.~~

~~PSO~~

~~Changes in Accumulated Other Comprehensive Income (Loss) by Component~~

~~For the Three Months Ended March 31, 2017~~

Cash Flow Hedge - Interest Rate
(in millions)
Balance in AOCI as of December 31, 2016 $ 3.4
Change in Fair Value Recognized in AOCI —
Amount of (Gain) Loss Reclassified from AOCI

Interest Expense (0.3 )
Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 )
Income Tax (Expense) Credit (0.1 )
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 )
Net Current Period Other Comprehensive Income (Loss) (0.2 )
Balance in AOCI as of March 31, 2017 $ 3.2

~~SWEPCo~~

~~Changes in Accumulated Other Comprehensive Income (Loss) by Component~~

~~For the Three Months Ended March 31, 2018~~

Cash Flow Hedge - Interest Rate
Pension
and OPEB
Total
(in millions)
Balance in AOCI as of December 31, 2017 $ (6.0 ) $ 2.0
$ (4.0 )
Change in Fair Value Recognized in AOCI —
—
—
Amount of (Gain) Loss Reclassified from AOCI

Interest Expense 0.5
—
0.5
Amortization of Prior Service Cost (Credit) —
(0.5 ) (0.5 )
Amortization of Actuarial (Gains)/Losses —
0.1
0.1
Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5
(0.4 ) 0.1
Income Tax (Expense) Credit 0.1
(0.1 ) —
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4
(0.3 ) 0.1
Net Current Period Other Comprehensive Income (Loss) 0.4
(0.3 ) 0.1
ASU 2018-02 Adoption (a) (1.3 ) 0.4
(0.9 )
Balance in AOCI as of March 31, 2018 $ (6.9 ) $ 2.1
$ (4.8 )


~~(a)~~	~~See Note 2 - New Accounting Pronouncements for additional information.~~

~~SWEPCo~~

~~Changes in Accumulated Other Comprehensive Income (Loss) by Component~~

~~For the Three Months Ended March 31, 2017~~

Cash Flow Hedge - Interest Rate
Pension
and OPEB
Total
(in millions)
Balance in AOCI as of December 31, 2016 $ (7.4 ) $ (2.0 ) $ (9.4 )
Change in Fair Value Recognized in AOCI —
—
—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense 0.7
—
0.7
Amortization of Prior Service Cost (Credit) —
(0.5 ) (0.5 )
Amortization of Actuarial (Gains)/Losses —
0.2
0.2
Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7
(0.3 ) 0.4
Income Tax (Expense) Credit 0.2
(0.1 ) 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.5
(0.2 ) 0.3
Net Current Period Other Comprehensive Income (Loss) 0.5
(0.2 ) 0.3
Balance in AOCI as of March 31, 2017 $ (6.9 ) $ (2.2 ) $ (9.1 )

4. RATE MATTERS

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

As discussed in the ~~2017~~2023 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the ~~2017~~2023 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in ~~2018~~2024 and updates the ~~2017~~2023 Annual Report.

Regulated Generating Units (Applies to AEP, PSO and SWEPCo)

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 in balance with reliability and other factors, which has resulted in, and in the future may result in, a proposal to retire generating facilities earlier than their currently estimated useful lives.

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

Regulated Generating Units that have been Retired

SWEPCo

In December 2021, the Dolet Hills Power Station was retired. As part of the 2020 Texas Base Rate Case, the PUCT authorized recovery of SWEPCo’s Texas jurisdictional share of the Dolet Hills Power Station through 2046, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $12 million in 2021. See the “2020 Texas Base Rate Case” section below for additional information. As part of the 2021 Arkansas Base Rate Case, the APSC authorized recovery of SWEPCo’s Arkansas jurisdictional share of the Dolet Hills Power Station through 2027, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $2 million in the second quarter of 2022. Also, the APSC did not rule on the prudency of the early retirement of the Dolet Hills Power Station, which will be addressed in a future proceeding. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo’s Louisiana share of the Dolet Hills Power Station, through a separate rider, through 2032, but did not rule on the prudency of the early retirement of the plant, which is being addressed in a separate proceeding. In April 2024, the LPSC approved a unanimous settlement agreement filed by SWEPCo, LPSC staff and certain intervenors that resolved the prudency of the retirement of the Dolet Hills Power Station and resulted in a disallowance of $14 million in the first quarter of 2024.

In March 2023, the Pirkey Plant was retired. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo’s Louisiana jurisdictional share of the Pirkey Plant, through a separate rider, through 2032. As part of the 2021 Arkansas Base Rate Case, the APSC granted SWEPCo regulatory asset treatment. SWEPCo will request recovery including a weighted average cost of capital carrying charge through a future proceeding. In July 2023, Texas ALJs issued a proposal for decision that concluded the decision to retire the Pirkey Plant was prudent. In September 2023, the PUCT rejected the ALJs proposal for decision concluding the retirement of the Pirkey Plant was prudent. In the open meeting, the commissioners expressed their concerns that the analysis in support of SWEPCo’s decision to retire the Pirkey Plant was not robust enough and that SWEPCo should have re-evaluated the decision following Winter Storm Uri. The treatment of the cost of recovery of the Pirkey Plant is expected to be addressed in a future rate case. As of March 31, 2024, the Texas jurisdictional share of the net book value of the Pirkey Plant was $68 million. To the extent any portion of the Texas jurisdictional share of the net book value of the Pirkey Plant is not recoverable, it could reduce future net income and cash flows and impact financial condition.

Regulated Generating Units to be Retired

PSO

In 2014, PSO received final approval from the Federal EPA to close Northeastern Plant, Unit 3, in 2026. The plant was originally scheduled to close in 2040. As a result of the early retirement date, PSO revised the useful life of Northeastern Plant, Unit 3, to the projected retirement date of 2026 and the incremental depreciation is being deferred as a regulatory asset. As part of the 2022 Oklahoma Base Rate Case, PSO will continue to recover Northeastern Plant, Unit 3 through 2040.

104

SWEPCo

In November 2020, management announced that it will cease using coal at the Welsh Plant in 2028. As a result of the announcement, SWEPCo began recording a regulatory asset for accelerated depreciation.

The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of March 31, 2024, of generating facilities planned for early retirement:


Plant	Net Book Value		Accelerated Depreciation Regulatory Asset		Cost of Removal Regulatory Liability			Projected Retirement Date		Current Authorized Recovery Period	Annual Depreciation (a)
	(dollars in millions)
Northeastern Plant, Unit 3	$	96.7	$	168.9	$	20.7	(b)	2026		(c)	$	15.1

Welsh Plant, Units 1 and 3	335.6		135.7		58.1		(d)	2028	(e)	(f)	39.2

(a)Represents the amount of annual depreciation that has been collected from customers over the prior 12-month period.

(b)Includes Northeastern Plant, Unit 4, which was retired in 2016. Removal of Northeastern Plant, Unit 4, will be performed with the removal of Northeastern Plant, Unit 3, after retirement.

(c)Northeastern Plant, Unit 3 is currently being recovered through 2040.

(d)Includes Welsh Plant, Unit 2, which was retired in 2016. Removal of Welsh Plant, Unit 2, will be performed with the removal of Welsh Plant, Units 1 and 3, after retirement.

(e)Represents projected retirement date of coal assets, units are being evaluated for conversion to natural gas after 2028.

(f)Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.

Dolet Hills Power Station and Related Fuel Operations (Applies to AEP and SWEPCo)

In December 2021, the Dolet Hills Power Station was retired. While in operation, DHLC provided 100% of the fuel supply to Dolet Hills Power Station. The remaining book value of Dolet Hills Power Station non-fuel related assets are recoverable by SWEPCo through rate riders. As of March 31, 2024, SWEPCo’s share of the net investment in the Dolet Hills Power Station was $86 million, including materials and supplies, net of cost of removal collected in rates. Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses and are subject to prudency determinations by the various commissions. After closure of the DHLC mining operations and the Dolet Hills Power Station, additional reclamation and other land-related costs incurred by DHLC and Oxbow will continue to be billed to SWEPCo and included in existing fuel clauses. As of March 31, 2024, SWEPCo had a net under-recovered fuel balance of $72 million, inclusive of costs related to the Dolet Hills Power Station billed by DHLC, but excluding impacts of the February 2021 severe winter weather event.

In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $20 million of fuel costs in 2021 and defer approximately $35 million of additional costs with a recovery period to be determined at a later date. In August 2022, the LPSC staff filed testimony recommending fuel disallowances of up to $55 million, including denial of recovery of the $35 million deferral, with refunds to customers over five years. In February 2024, an ALJ issued a final recommendation which included a proposed $55 million refund to customers and the denial of recovery of the $35 million deferral. SWEPCo filed a motion to present oral arguments with the LPSC to dispute the ALJ’s recommendations.In April 2024, the LPSC approved a unanimous settlement agreement filed by SWEPCo, LPSC staff and certain intervenors that resolved the fuel recovery dispute and resulted in a fuel disallowance of $11 million. The remaining $24 million regulatory asset balance will be recovered over three years with interest.

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

In September 2023, the PUCT approved an unopposed settlement agreement that provides recovery of $48 million of Oxbow mine related costs through 2035.

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

105

Pirkey Plant and Related Fuel Operations (Applies to AEP and SWEPCo)

In March 2023, the Pirkey Plant was retired. SWEPCo is recovering, or will seek recovery of, the remaining net book value of Pirkey Plant non-fuel costs. As of March 31, 2024, SWEPCo’s share of the net investment in the Pirkey Plant was $185 million, including materials and supplies, net of cost of removal. See the “Regulated Generating Units that have been Retired” section above for additional information.Fuel costs are recovered through active fuel clauses and are subject to prudency determinations by the various commissions. As of March 31, 2023, SWEPCo fuel deliveries, including billings of all fixed costs, from Sabine ceased. Additionally, as of March 31, 2024, SWEPCo had a net under-recovered fuel balance of $72 million, inclusive of costs related to the Pirkey Plant billed by Sabine, but excluding impacts of the February 2021 severe winter weather event. Remaining operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in existing fuel clauses.

In July 2023, the LPSC ordered that a separate proceeding be established to review the prudence of the decision to retire the Pirkey Plant, including the costs included in fuel for years starting in 2019 and after. The LPSC established a procedural schedule stating staff and intervenor testimony is due in November 2024 and a hearing is scheduled for March 2025.

In September 2023, the PUCT approved an unopposed settlement agreement that provides recovery of $33 million of Sabine related fuel costs through 2035.

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

Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except ~~AEPTCo~~AEPTCo)


	AEP
	March 31,		December 31,
	2024		2023
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Welsh Plant, Units 1 and 3 Accelerated Depreciation	$	135.7	$	125.6
Pirkey Plant Accelerated Depreciation	121.0		114.4
Unrecovered Winter Storm Fuel Costs (a)	90.8		97.2








Other Regulatory Assets Pending Final Regulatory Approval	14.3		49.8
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	404.9		408.9


NOLC Costs	67.7		—
Other Regulatory Assets Pending Final Regulatory Approval	89.4		78.5
Total Regulatory Assets Pending Final Regulatory Approval	$	923.8	$	874.4

(a)Includes $37 million and ~~OPCo)~~$37 million of unrecovered winter storm fuel costs recorded as a current regulatory asset as of March 31, 2024 and December 31, 2023, respectively. See the “February 2021 Severe Winter Weather Impacts in SPP” section below for additional information.

106

AEP
March 31, December 31,
2018 2017
Noncurrent Regulatory Assets (in millions)

Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant $ 50.3
$ 50.3
Other Regulatory Assets Pending Final Regulatory Approval 12.5
9.6
Regulatory Assets Currently Not Earning a Return

Storm Related Costs (a) 130.3
128.0
Plant Retirement Costs - Asset Retirement Obligation Costs 39.7
39.7
Cook Plant Uprate Project 31.1
36.3
Cook Plant Turbine 11.2
15.9
Other Regulatory Assets Pending Final Regulatory Approval 32.6
42.2
Total Regulatory Assets Pending Final Regulatory Approval (b) $ 307.7
$ 322.0


	AEP Texas
	March 31,		December 31,
	2024		2023
Noncurrent Regulatory Assets	(in millions)



Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	$	38.4	$	37.7
Line Inspection Costs	7.4		5.7
Vegetation Management Program	5.2		5.2
Texas Retail Electric Provider Bad Debt Expense	4.1		4.0
Other Regulatory Assets Pending Final Regulatory Approval	12.1		11.7
Total Regulatory Assets Pending Final Regulatory Approval	$	67.2	$	64.3


~~(a)~~	~~As of March 31, 2018, AEP Texas has deferred $105 million related to Hurricane Harvey and is currently exploring recovery options, including securitization.~~

~~(b)~~

In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. APCo’s recovery of the remaining Virginia net book value for the retired plants will be considered in the Virginia SCC’s 2020 triennial review of APCo’s generation and distribution base rates. The Virginia SCC staff has requested that APCo prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018.


	APCo
	March 31,		December 31,
	2024		2023
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return


Other Regulatory Assets Pending Final Regulatory Approval	$	0.7	$	0.6
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs - West Virginia	91.2		91.5

Plant Retirement Costs – Asset Retirement Obligation Costs	25.9		25.9
Other Regulatory Assets Pending Final Regulatory Approval	11.1		7.5
Total Regulatory Assets Pending Final Regulatory Approval	$	128.9	$	125.5


	I&M
	March 31,		December 31,
	2024		2023
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return

Other Regulatory Assets Pending Final Regulatory Approval	$	0.2	$	0.2
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs - Indiana	29.7		29.7
NOLC Costs - Indiana	20.2		—


Other Regulatory Assets Pending Final Regulatory Approval	4.6		3.3
Total Regulatory Assets Pending Final Regulatory Approval	$	54.7	$	33.2

107

AEP Texas
March 31, December 31,
2018 2017
Noncurrent Regulatory Assets (in millions)

Regulatory Assets Currently Not Earning a Return
Storm-Related Costs (a) $ 128.7
$ 123.3
Rate Case Expense 0.2
0.1
Total Regulatory Assets Pending Final Regulatory Approval $ 128.9
$ 123.4


~~(a)~~	~~As of March 31, 2018, AEP Texas has deferred $105 million related to Hurricane Harvey and is currently exploring recovery options, including securitization.~~


	OPCo
	March 31,		December 31,
	2024		2023
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Not Earning a Return



Storm-Related Costs	$	23.6	$	23.6


Total Regulatory Assets Pending Final Regulatory Approval	$	23.6	$	23.6

APCo
March 31, December 31,
2018 2017
Noncurrent Regulatory Assets (in millions)

Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Materials and Supplies $ 9.0
$ 9.1
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs - Asset Retirement Obligation Costs 39.7
39.7
Other Regulatory Assets Pending Final Regulatory Approval 0.6
0.6
Total Regulatory Assets Pending Final Regulatory Approval (a) $ 49.3
$ 49.4

~~(a)~~


	PSO
	March 31,		December 31,
	2024		2023
Noncurrent Regulatory Assets	(in millions)




Regulatory Assets Currently Not Earning a Return


Storm-Related Costs	$	88.8	$	88.5
NOLC Costs	12.1		—
Other Regulatory Assets Pending Final Regulatory Approval	2.9		0.2
Total Regulatory Assets Pending Final Regulatory Approval	$	103.8	$	88.7

I&M
March 31, December 31,
2018 2017
Noncurrent Regulatory Assets (in millions)

Regulatory Assets Currently Not Earning a Return
Cook Plant Uprate Project $ 31.1
$ 36.3
Deferred Cook Plant Life Cycle Management Project Costs - Michigan —
14.7
Cook Plant Turbine 11.2
15.9
Rockport Dry Sorbent Injection System - Indiana 11.3
10.4
Other Regulatory Assets Pending Final Regulatory Approval 4.5
2.0
Total Regulatory Assets Pending Final Regulatory Approval $ 58.1
$ 79.3

SWEPCo

March 31,

December 31,

2024

2023

Noncurrent Regulatory Assets

(in millions)

Regulatory Assets Currently Earning a Return

Welsh Plant, Units 1 and 3 Accelerated Depreciation

Pirkey Plant Accelerated Depreciation

Unrecovered Winter Storm Fuel Costs (a)

PSO

Dolet Hills Power Station Accelerated Depreciation (b)

March 31,

December 31,

2018

2017

Noncurrent Regulatory Assets

(in millions)

Dolet Hills Power Station Accelerated Depreciation (b)

Other Regulatory Assets Pending Final Regulatory Approval

Regulatory Assets Currently Not Earning a Return

Storm Related Costs

—

3.2

Storm-Related Costs - Louisiana, Texas

NOLC Costs

Other Regulatory Assets Pending Final Regulatory Approval

0.1

Total Regulatory Assets Pending Final Regulatory Approval

0.1

3.3

(a)Includes $37 million and $37 million of unrecovered winter storm fuel costs recorded as a current regulatory asset as of March 31, 2024 and December 31, 2023, respectively. See the “February 2021 Severe Winter Weather Impacts in SPP” section below for additional information.

(b)Amounts include the FERC jurisdiction.

SWEPCo
March 31, December 31,
2018 2017
Noncurrent Regulatory Assets (in millions)

Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant $ 50.3
$ 50.3
Other Regulatory Assets Pending Final Regulatory Approval 0.5
0.5
Regulatory Assets Currently Not Earning a Return

Rate Case Expense - Texas 4.4
4.3
Asset Retirement Obligation - Arkansas, Louisiana 4.3
4.0
Shipe Road Transmission Project - FERC 3.3
3.3
Other Regulatory Assets Pending Final Regulatory Approval 2.8
2.5
Total Regulatory Assets Pending Final Regulatory Approval $ 65.6
$ 64.9

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

108

~~Impact of Tax Reform~~

Rate and regulatory matters are impacted by federal income tax implications. In December 2017, Tax Reform was enacted, which will impact outstanding rate and regulatory matters. For additional details on the impact of Tax Reform, see Note 11 - Income Taxes.

AEP Texas Rate Matters (Applies to AEP and AEP Texas)

AEP Texas Interim Transmission and Distribution Rates

~~As of~~Through March 31, ~~2018,~~2024, AEP Texas’ cumulative revenues from interim base rate increases ~~from 2008 through 2017,~~that are subject to a prudency review ~~are estimated to be $830 million. A~~is approximately $1.1 billion. The 2024 AEP Texas base rate ~~review~~case described below could ~~produce~~result in a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition.

2024 AEP Texas Base Rate Case

In ~~March 2018,~~February 2024, AEP Texas filed an application to reduce its transmission rates by $24 million to reflect the lower federal income tax rate due to Tax Reform. The filing did not address the return of excess deferred income tax benefits to customers.

In April 2018, AEP Texas filed an application to amend its Distribution Cost Recovery Factor (DCRF). The filing sought to increase revenues by approximately $3 million, which includes capital investment additions of $24 million offset by a reduction of $21 million due to a lower federal income tax rate as a result of Tax Reform. The filing did not address the return of excess deferred income tax benefits to customers. New rates will be effective September 1, 2018.

~~In April 2018,~~request with the PUCT ~~adopted a rule requiring investor-owned utilities operating solely inside ERCOT to make periodic filings for rate proceedings. The proposal requires AEP Texas to file~~ for a ~~comprehensive~~$164 million annual base rate ~~review no later than~~increase over its adjusted test year revenues which include interim transmission and distribution rate updates. AEP Texas’s request is based upon a proposed 10.6% ROE with a capital structure of 55% debt and 45% common equity. The rate case seeks a prudence determination on all capital additions included in interim rates since 2018. The procedural schedule for this case states intervenor testimony is due May ~~1, 2019.~~

~~Hurricane Harvey~~

~~In August 2017, Hurricane Harvey hit the coast~~2024 and a hearing is scheduled for June 2024. If any of Texas, causing power outages in the AEP Texas service territory. AEP Texas has a PUCT approved catastrophe reserve in base rates and can defer incremental storm expenses. AEP Texas currently recovers approximately $1 million of stormthese costs ~~annually through base rates. As of March 31, 2018,~~

~~the total balance of AEP Texas’ deferred storm costs is approximately $129 million, inclusive of approximately $105 millionof incremental storm expenses recorded as a regulatory asset related to Hurricane Harvey. As of March 31, 2018, AEP Texas has recorded approximately $186 million~~of capital expenditures related to Hurricane Harvey. Also, as of March 31, 2018, AEP Texas has received $10 million in insurance proceeds, which were applied to the regulatory asset and property, plant and equipment. Management, in conjunction with the insurance adjusters, is reviewing all damages to determine the extent of coverage for additional insurance reimbursement. Any future insurance recoveries received will be applied to and will offset the regulatory asset and property, plant and equipment, as applicable. Management believes the amount recorded as a regulatory asset is probable of recovery and AEP Texas is currently evaluating recovery options for the regulatory asset, including securitization. The standard process for storm cost recovery in Texas requires two filings with the PUCT. Management expects the first filing by the end of the third quarter of 2018. If the ultimate costs of the incident are not ~~recovered by insurance~~recoverable or ~~through the regulatory process, it would have an adverse effect on future net income, cash flows and financial condition.~~

~~APCo Rate Matters~~ ~~(Applies to AEP and APCo)~~

~~Virginia Legislation Affecting Earnings Reviews~~

~~In 2015, amendments to Virginia law governing the regulation~~refunds of ~~investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation~~revenues collected under interim transmission and distribution ~~base~~ rates were frozen until after the Virginia SCC ruled on APCo’s next biennial review. These amendments also precluded the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017.

~~In March 2018, new Virginia legislation impacting investor-owned utilities was enacted, effective July 1, 2018, that will: (a) on a one-time basis, require APCo~~are ordered to exclude $10 million of fuel expenses from the July 2018 over/under calculation, (b) reduce APCo’s base rates by $50 million annually no later than July 30, 2018, on an interim basis and subject to true-up, to reflect the lower federal income tax rate due to Tax Reform, (c) require APCo to file its next generation and distribution base rate case by March 31, 2020 using 2017, 2018 and 2019 test years (“triennial review”), (d) require an adjustment in APCo’s base rates on April 1, 2019 to reflect actual annual reductions in corporate income taxes due to Tax Reform, (e) require APCo to obtain approval from the Virginia SCC for energy efficiency programs with projected costs in the aggregate of at least $140 million over the 10-year period from July 1, 2018 through July 1, 2028 and (f) require APCo to construct and/or acquire solar generation facilities in Virginia of at least 200 MW of aggregate capacity. Triennial reviews are subject to an earnings test which provides that any over earnings may be ~~reinvested in approved energy distribution grid transformation projects. The Virginia SCC’s triennial review of 2017-2019 APCo earnings~~returned, it could reduce future net income and cash flows and impact financial condition.

APCo and WPCo Rate Matters (Applies to AEP and APCo)

ENEC (Expanded Net Energy Cost) Filings

In January 2024, the WVPSC issued an order resolving the Companies’ 2021-2023 ENEC cases. In the order, the WVPSC: (a) disallowed $232 million in ENEC under-recovered costs as of February 28, 2023 ($136 million related to APCo) and (b) approved the recovery of $321 million of ENEC under-recovered costs as of February 28, 2023 ($174 million related to APCo) plus a 4% carrying charge rate over a ten-year recovery period starting September 1, 2024. In February 2024, the Companies filed briefs with the West Virginia Supreme Court to initiate an appeal of this order. The West Virginia Supreme Court will hear oral arguments in September 2024, after which it will issue a decision on the appeal. The Companies will submit their annual ENEC update filing with the WVPSC in the second quarter of 2024 proposing that updated ENEC rates become effective September 1, 2024.

2023 Virginia Base Rate Case

In March 2024, APCo filed a request with the Virginia SCC for a $95 million annual increase in base rates based upon a proposed 10.8% ROE and a proposed capital structure of 51% debt and 49% common equity. The requested increase in base rates is primarily due to incremental rate base, proposed capital structure changes including an increase in ROE and proposed increases in distribution and generation operation and maintenance expenses. Staff testimony is due in August 2024 and a hearing is scheduled for September 2024. An order is expected in the second half of 2024. If any costs included in this filing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

ETT Rate Matters (Applies to AEP)

ETT Interim Transmission Rates

AEP has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next ~~filed~~ base rate proceeding. Through March 31, ~~2018,~~2024, AEP’s share of ETT’s cumulative revenues that are subject to a prudency review is ~~estimated to be $781 million.~~approximately $1.7 billion.A base rate review could produce a refund to customers if ETT incurs a disallowance of the transmission investment on which an interim increase was based. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring.

~~In February 2018,~~ ETT filed an application to reduce its transmission rates by $27 million to reflect the lower federal income tax rate due to Tax Reform. The filing did not address the return of excess deferred income tax benefits to customers.

~~In April 2018, the PUCT adopted a rule requiring investor-owned utilities operating solely inside ERCOT to make periodic filings for rate proceedings. The rule requires ETT~~is required to file for a comprehensive rate review no later than February 1, ~~2021.~~2025, during which the $1.7 billion of cumulative revenues above will be subject to review.

109

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

~~2017~~Michigan Power Supply Cost Recovery (PSCR)

In April 2023, I&M received intervenor testimony in I&M’s 2021 PSCR Reconciliation for the 12-month period ending December 31, 2021 recommending disallowances of purchased power costs of $18 million associated with the OVEC Inter-Company Power Agreement (ICPA) and the Rockport Plant UPA with AEGCo that were alleged to be above market in applying the MPSC’s Code of Conduct rules. Michigan staff submitted testimony in I&M’s 2021 PSCR Reconciliation with no recommended disallowances for PSCR costs incurred, including those associated with the OVEC ICPA and the Rockport Plant UPA with AEGCo. Michigan staff also recommended several options to address I&M’s shortfall in achieving Michigan’s annual one percent energy waste reduction savings level, resulting in potential future disallowed costs of up to approximately $14 million. In June 2023, Michigan staff submitted rebuttal testimony to update their calculation of the 2021 market proxy price resulting in a recommended disallowance of approximately $1 million related to the OVEC ICPA.

In January 2024, I&M received staff testimony in I&M’s 2022 PSCR Reconciliation for the 12-month period ending December 31, 2022 recommending disallowances of purchased power costs of $2 million associated with the OVEC ICPA that were alleged to be above market in applying the MPSC’s Code of Conduct rules. Similar to the 2021 PSCR Reconciliation, Michigan staff also recommended several options to address I&M’s shortfall in achieving Michigan’s annual one percent energy waste reduction savings level, resulting in potential future disallowed costs of up to approximately $6 million. In April 2024, the MPSC issued an order on I&M’s 2021 PSCR Reconciliation that: (a) disallowed $1 million of purchased power costs associated with the OVEC ICPA that the MPSC concluded were above market, (b) disallowed $10 million of purchased power costs under the Rockport Plant UPA with AEGCo that the MPSC concluded were “energy only” and above market and (c) disallowed $497 thousand of PSCR costs due to I&M’s shortfall in achieving Michigan’s one percent energy waste reduction savings level in 2020. As of March 31, 2024, I&M’s financial statements reflect the impacts of this disallowance. I&M expects to appeal the MPSC’s order.

In March 2024, I&M submitted its 2023 PSCR Reconciliation to the MPSC. An MPSC order on I&M’s 2022 PSCR Reconciliation is expected in the second half of 2024. The MPSC has yet to issue a procedural schedule for I&M’s 2023 PSCR Reconciliation. If any PSCR costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2023 Indiana Base Rate Case

In ~~July 2017,~~August 2023, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to a temporary offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures. The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Plant Life Cycle Management Project.

In November 2017, various intervenors filed testimony that included annual revenue increase recommendations ranging from $125 million to $152 million. The recommended returns on common equity ranged from 8.65% to 9.1%. In addition, certain parties recommended longer recovery periods than I&M proposed for recovery of regulatory assets and depreciation expenses related to Rockport Plant, Units 1 and 2. In January 2018, in response to a January 2018 IURC request related to the impact of Tax Reform on I&M’s pending base rate case, I&M filed updated schedules supporting a $191$116 million annual increase in Indiana base rates ifbased upon a 2024 forecasted test year, a proposed 10.5% ROE and a proposed capital structure of 48.8% debt and 51.2% common equity. I&M proposed that the ~~effect~~annual increase in base rates be implemented in two steps, with the first increase effective in mid-2024, following an IURC order, and the second increase effective in January 2025. The proposed annual increase includes a $41 million increase related to depreciation expense, driven by increased depreciation rates and increased capital investments, and a $15 million increase related to storm expenses. I&M’s Indiana base case filing requests recovery of ~~Tax Reform was included in~~certain historical period regulatory asset balances and proposes deferral accounting for certain future investments and tax related issues, including corporate alternative minimum tax expense and PTCs related to the ~~cost of service.~~Cook Plant.

In ~~February 2018,~~December 2023, I&M and ~~all parties~~intervenors reached a settlement agreement that was submitted to the ~~case, except one industrial customer, filed~~IURC recommending a ~~Stipulation and Settlement Agreement for a $97 million annual~~two-step increase in Indiana rates ~~effective July 1, 2018 subject to~~with a temporary offsetting reduction to customer bills through December 2018 for a credit rider related to the timing of estimated in-service dates of certain capital expenditures. The one industrial customer agreed to not oppose the Stipulation and Settlement Agreement. The difference between I&M’s requested $263$28 million annual increase effective upon an IURC order and the ~~$97~~remaining $34 million annual increase effective in January 2025. The recommended revenue increase includes: (a) a 9.85% ROE, (b) a two-step update of I&M’s capital structure with a capital structure of 50% for both debt and common equity effective upon an IURC order and I&M will submit an updated capital structure in January 2025 with the ~~Stipulation and Settlement Agreement is primarily a result of: (a) the reduction in the federal income tax rate due~~common equity component adjusted to ~~Tax Reform, (b) the feedback of credits for excess deferred income taxes,~~no more than 51.2%, (c) a ~~9.95% return on equity, (d) longer recovery periods of regulatory assets, (e) lower~~$25 million increase related to depreciation expense ~~primarily for meters~~ and ~~(f)~~(d) an $11 million increase ~~in the sharing of off-system sales margins with customers from 50%~~related to ~~95%. If the Stipulation and Settlement is approved, I&M will also refund $4 million from July through December 2018 for the impact of Tax Reform for the period January through June 2018.~~ storm expenses.

A hearing ~~at the IURC~~ was held in ~~March 2018~~January 2024 and an ~~IURC~~ order is expected in the second quarter of ~~2018.~~2024. If any costs included in this filing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

110

2023 Michigan Base Rate Case

In September 2023, I&M filed a request with the MPSC for a $34 million annual increase in Michigan base rates based upon a 2024 forecasted test year, a proposed 10.5% ROE and a capital structure of 49.4% debt and 50.6% common equity. The proposed annual increase includes an $11 million annual increase in depreciation expense driven by increased capital investment. I&M’s Michigan base case filing requests recovery of certain historical period regulatory asset balances and proposes deferral accounting for certain future investments and tax related issues, including corporate alternative minimum tax (CAMT) expense and PTCs related to the Cook Plant.

In January 2024, Michigan staff and various intervenors submitted testimony recommending changes in base rates ranging from a $6 million annual decrease to a $19 million annual increase. These changes are based on ROEs ranging from 9.7% to 9.9% and capital structures ranging from 49.4% debt and 50.6% equity to 52% debt and 48% equity. Staff and intervenors also proposed in testimony certain disallowances related to regulatory assets and capital investments, the exclusion of CAMT from any future deferrals and the prospective inclusion of PTCs related to the Cook Plant in I&M’s PSCR.

A hearing was held in February 2024. If any costs included in this filing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

KPCo Rate Matters (Applies to AEP)

Investigation of the Service, Rates and Facilities of KPCo

In June 2023, the KPSC issued an order directing KPCo to show cause why it should not be subject to Kentucky statutory remedies, including fines and penalties, for failure to provide adequate service in its service territory. The KPSC’s show cause order did not make any determination regarding the adequacy of KPCo’s service. In July 2023, KPCo filed a response to the show cause order demonstrating that it has provided adequate service. In December 2023 and February 2024, KPCo and certain intervenors filed testimony with the KPSC. In February 2024, KPCo filed a motion to strike and exclude intervenor testimony. In March 2024, the KPSC denied KPCo’s February 2024 motion. A hearing is expected in 2024. If any fines or penalties are levied against KPCo relating to the show cause order, it could reduce net income and cash flows and impact financial condition.

2023 Kentucky Base Rate and Securitization Case

In June 2023, KPCo filed a request with the KPSC for a $94 million net annual increase in base rates based upon a proposed 9.9% ROE with the increase to be implemented no earlier than January 2024. In conjunction with its June 2023 filing, KPCo further requested to finance through the issuance of securitization bonds, approximately $471 million of regulatory assets. KPCo’s proposal did not address the disposition of its 50% interest in Mitchell Plant, which will be addressed in the future. As of March 31, 2024, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $543 million. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

~~2017 Michigan Base Rate Case~~

In ~~May 2017, I&M~~November 2023, KPCo filed an uncontested settlement agreement with the KPSC, that included an annual base rate increase of $75 million, based upon a 9.75% ROE. Settlement parties agreed that the KPSC should approve KPCo’s securitization request, and that the approximately $471 million regulatory assets requested for securitization are comprised of prudently incurred costs.

In January 2024, the KPSC issued an order modifying the November 2023 uncontested settlement agreement and approving an annual base rate increase of $60 million based upon a 9.75% ROE effective with billing cycles mid-January 2024. The order reduced KPCo’s base rate revenue requirement by $14 million to allow recovery of actual test year PJM transmission costs instead of KPCo’s requested annual level of costs based on PJM 2023 projected transmission revenue requirements. In February 2024, KPCo filed an appeal with the Commonwealth of Kentucky Franklin Circuit Court, challenging among other aspects of the order the $14 million base rate revenue requirement reduction.

In January 2024, consistent with the November 2023 uncontested settlement agreement, the KPSC issued a financing order approving KPCo’s request to securitize certain regulatory assets balances as of the time securitization bonds are issued and concluding that costs requested for recovery through securitization were prudently incurred. The KPSC’s financing order includes certain additional requirements related to securitization bond structuring, marketing, placement and issuance that were not reflected in KPCo’s proposal. As a result, in January 2024, KPCo filed a request for rehearing with the ~~MPSC for a $52 million annual increase in Michigan base rates based upon a proposed 10.6% return on common equity~~KPSC to clarify

111

certain aspects of these additional requirements. In February 2024, the KPSC denied KPCo’s rehearing requests. In accordance with Kentucky statutory requirements and the financing order, the issuance of the securitized bonds is subject to final review by the KPSC after bond pricing. KPCo expects to proceed with the ~~increase~~securitized bond issuance process and to complete the securitization process in the second half of 2024, subject to market conditions. As of March 31, 2024, regulatory asset balances expected to be ~~implemented no later than April 2018. The proposed annual increase includes $23~~recovered through securitization total $476 million and include: (a) $288 million of plant retirement costs, (b) $79 million of deferred storm costs related to ~~increased annual depreciation rates~~2020, 2021, 2022 and 2023 major storms, (c) $46 million of deferred purchased power expenses, (d) $62 million of under-recovered purchased power rider costs and (e) $1 million of deferred issuance-related expenses including KPSC advisor expenses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Fuel Adjustment Clause (FAC) Review

In December 2023, KPCo received intervenor testimony in its FAC review for the two-year period ending October 31, 2022, recommending a $4disallowance ranging from $44 million ~~increase related~~to $60 million of its total $432 million purchased power cost recoveries as a result of proposed modifications to the ~~amortization of certain Cook Plant regulatory assets. The increase~~ratemaking methodology that limits purchased power costs recoverable through the FAC. A hearing was held in ~~depreciation rates~~February 2024 and an order is ~~primarily due to the proposed change~~expected in the ~~expected retirement date for~~ second quarter of 2024. If any fuel costs are not recoverable or refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

Rockport ~~Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project.~~Offset Recovery

In February 2018, an MPSC ALJ issued a Proposal for Decision and recommended an annual revenue increase of $49 million, including an intervenors’ proposed capacity rate based on PJM’s net cost of new entry value of $289/MW-day and MPSC staff’s recommended calculation of depreciation expense for both units of Rockport Plant through 2028 and a return on common equity of 9.8%. If the maximum 10% of customers choose an alternate supplier starting in February 2019, the estimated annual pretax loss due to the reduced capacity rate would be approximately $9 million until adjusted in the next base rate case.

In April 2018, the MPSC issued an order that generally approved the ALJ proposal resulting in an annual revenue increase of $49 million, effective April 2018 based on a 9.9% return on common equity. The MPSC also approved the ALJ’s recommendation related to the capacity rate.

~~Rockport Plant, Unit 2 SCR~~

~~In October 2016, I&M~~January 2024, KPCo filed an application with the ~~IURC for approval~~KPSC seeking to recover an allowed cost (Rockport Offset) of ~~a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO~~_x ~~from Rockport Plant, Unit 2~~$41 million in ~~order for I&M to continue to operate that unit under current environmental requirements. The estimated cost~~accordance with the terms of the SCR project is $274 million, excluding AFUDC, to be shared equally between I&M and AEGCo. As of March 31, 2018, total costs incurred related to this project, including AFUDC, were approximately $28 million. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year period as provided by statute and other related expenses. I&M proposed recovery of these costs usingsettlement agreement in the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport UPA to I&M and KPCo and will be subject to future regulatory approval for recovery.

In March 2018, the IURC issued an order approving: (a) the CPCN, (b) the $274 million estimated cost of the SCR, excluding AFUDC, (c) deferral accounting for the Indiana jurisdictional ownership share of costs, including investment carrying costs, (d) depreciation of the SCR asset over 10 years and (e) recovery of these costs using I&M’s existing Indiana Clean Coal Technology Rider.

In April 2018, a group of intervenors filed a Petition for Reconsideration and Rehearing of the March 2018 IURC order. The intervenors requested that the IURC reopen the proceeding primarily to address whether allowing I&M any cost recovery for the SCR would constitute a cross-subsidization issue and to reverse its finding approving cost recovery for the Rockport Plant, Unit 2 SCR project. Also in April 2018, I&M filed a response to the intervenors’ petition.

~~KPCo Rate Matters~~ ~~(Applies to AEP)~~

2017 Kentucky Base Rate Case

permitting KPCo to use the level of non-fuel, non-environmental Rockport Plant UPA expense included in base rates to earn its authorized ROE in 2023 since the Rockport UPA ended in December 2022. An estimated Rockport Offset of $23 million was recovered through a rider, subject to true-up, during the 12-months ended December 2023. In ~~January 2018,~~February 2024, the KPSC issued an order ~~approving a non-unanimous settlement agreement with certain modifications resulting~~allowing KPCo to collect the remaining $18 million through interim rates, subject to refund, over twelve months starting in ~~an annual revenue increase of $12 million, effective January 2018, based on a 9.7% return on equity. The KPSC’s primary revenue requirement modification~~March 2024. In April 2024, KPCo submitted to the ~~settlement agreement was~~KPSC a ~~$14 million annual~~request for decision on the record. An order is expected in 2024. Through the first quarter of 2024, the Rockport Offset true-up is reflected in revenues to the extent amounts have been billed to customers, as KPCo has not met the requirements of alternative revenue ~~reduction for the decrease~~recognition in ~~the corporate federal income tax rate due to Tax Reform. The KPSC approved: (a) the deferral of a total of $50 million of Rockport Plant UPA expenses for the years 2018 through 2022,~~accordance with the manner and timing of recovery of the deferral to be addressed in KPCo’s next base rate case, (b) the recovery/return of 80% of certain annual PJM OATT expenses above/below the corresponding level recovered in base rates, (c) KPCo’s commitment to not file a base rate caseaccounting guidance for ~~three years with rates effective no earlier than 2021 and (d) increased depreciation expense based upon updated Big Sandy Plant, Unit 1 depreciation rates using a 20-year depreciable life.~~

In February 2018, KPCo filed with the KPSC for rehearing of the January 2018 base case order and requested an additional $2.3 million of annual revenue increases related to: (a) the calculation of federal income tax expense, (b) recovery of purchased power costs associated with forced outages and (c) capital structure adjustments. Also in February 2018, an intervenor filed for rehearing recommending that the reduced corporate federal income tax rate be reflected in lower purchased power expense related to“Regulated Operations”. If the Rockport ~~UPA. In February 2018, the KPSC issued an order granting rehearing of these items, with an exception for the capital structure adjustments, which was denied by the KPSC.~~Offset is not recoverable or refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

OPCo Rate Matters (Applies to AEP and OPCo)

OVEC Cost Recovery Audits

In December 2021, as part of OVEC cost recovery audits pending before the PUCO, intervenors filed positions claiming that costs incurred by OPCo during the 2018-2019 audit period were imprudent and should be disallowed. In May 2022, intervenors filed for rehearing on the 2016-2017 OVEC cost recovery audit period claiming the PUCO’s April 2022 order to adopt the findings of the audit report were unjust, unlawful and unreasonable for multiple reasons, including the position that OPCo recovered imprudently incurred costs. In June 2022, the PUCO granted rehearing on the 2016-2017 audit period for purposes of further consideration.

In May 2023, as part of the OVEC cost recovery audits pending before the PUCO, intervenors filed positions claiming that costs incurred by OPCo during the 2020 audit period were imprudent and should be disallowed. A hearing was held in November 2023. In the first quarter of 2024, post-hearing briefs were filed by the parties and the case currently awaits a decision on the merits.

Management disagrees with these claims and is unable to predict the impact of these disputes. If any costs are disallowed or refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

Ohio ~~Electric Security Plan~~ESP Filings

~~June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024~~

In ~~2013,~~January 2023, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments, proposed new riders and the continuation and modification of certain existing riders, including the DIR, effective June ~~2015~~2024 through May ~~2018.~~2030. The proposal ~~also involved~~includes a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA.

In 2015 and 2016, the PUCO issued orders in this proceeding. As part of the issued orders, the PUCO approved (a) the DIR with modified rate caps, (b) recovery of OVEC-related net margin incurred beginning June 2016, (c) potential additional contingent customer credits of up to $15 million to be included in the PPA rider over the final four years of the PPA rider and (d) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions. In April 2017, the PUCO rejected all pending rehearing requests. In June 2017, intervenors filed appeals to the Supreme Court of Ohio stating that the PUCO’s approval of the OVEC PPA was unlawful and does not provide customers with rate stability.

In November 2016, OPCo refiled its amended ESP extension application and supporting testimony, consistent with the terms of the modified and approved stipulation agreement and based upon a 2016 PUCO order. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity of 10.65% on capital costs for certain ~~riders, (c) the continuation of riders previously approved in the~~riders. In June ~~2015 - May 2018 ESP, (d) proposed increases in rate caps related to~~2023, intervenors filed testimony opposing OPCo’s ~~DIR and (e) the addition of~~plan for various new riders and modifications to existing riders, including ~~a Renewable Resource Rider.~~

the DIR. In ~~August 2017,~~September 2023, OPCo and ~~various~~certain intervenors filed a ~~stipulation~~settlement agreement with the ~~PUCO. The stipulation extends the term of~~PUCO addressing the ESP application. The settlement included a four year term from June 2024 through May ~~2024~~2028, an ROE of 9.7% and ~~includes: (a) an extension of the OVEC PPA rider, (b) a proposed 10% return on common equity on capital costs for certain riders, (c) the~~ continuation of ~~riders previously approved in the June 2015 - May 2018 ESP, (d) rate caps related to OPCo’s DIR ranging from $215 million to $290 million for the periods 2018 through 2021 and (e) the addition~~a number of ~~various new~~ riders including ~~a Smart City Rider and a Renewable Generation Rider.~~the DIR ~~rate caps will be reset in OPCo’s next distribution base rate case which must be filed by June 2020.~~

~~In October 2017, intervenor testimony opposing the stipulation agreement was filed recommending: (a) a return on common equity~~subject to not exceed 9.3% for riders earning a return on capital investments, (b) that OPCo should file a base distribution case concurrent with the conclusion of the current ESP in May 2018 and (c) denial of certain new riders proposed in OPCo’s ESP extension. The stipulation was reviewed by the PUCO at a hearing in November 2017.

revenue caps. In April ~~2018,~~2024, the PUCO issued an order approving the ~~stipulation agreement, with no significant changes.~~settlement agreement.

~~2016 SEET Filing~~

112

PSO Rate Matters (Applies to AEP and PSO)

Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk.

2024 Oklahoma Base Rate Case

In December 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement that was filed at the PUCO in December 2016 and subsequently approved in February 2017: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings.

In May 2017, OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group.

In January 2018, PUCO staff filed testimony that OPCo did not have significantly excessive earnings. Also in January 2018, an intervenor filed testimony recommending a $53 million refund to customers. In February 2018, OPCo and PUCO staff2024, PSO filed a ~~stipulation agreement~~request with the OCC for a $218 million annual base rate increase based upon a 10.8% ROE with a capital structure of 48.9% debt and 51.1% common equity. PSO requested an expanded transmission cost recovery rider and a mechanism to recover generation costs necessary to comply with SPP’s 2023 increased capacity planning reserve margin requirements. PSO’s request includes the 155 MW Rock Falls Wind Facility and reflects recovery of Northeastern Plant, Unit 3 through 2040. The procedural schedule for this case states intervenor testimony is due in ~~which both parties agreed that OPCo did~~May 2024 and a hearing is scheduled for July 2024. If any costs included in this filing are not ~~have significantly excessive earnings in 2016.~~

A 2016 SEET hearing was held in April 2018 and management expects to receive an order in the second half of 2018. While management believes that OPCo’s adjusted 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s proposed SEET adjustments, including treatment of the Global Settlement issues described above, adjust the comparable risk group or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings,approved for recovery, it could ~~negatively affect future SEET filings,~~ reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters (Applies to AEP and SWEPCo)

2012 Texas Base Rate Case

In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs.

Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, SWEPCo reversed $114 million of a previously recorded regulatory ~~disallowances~~disallowance in 2013. ~~The resulting annual base rate increase was approximately $52 million.~~ In ~~June~~ 2017, the Texas District Court upheld the PUCT’s 2014 ~~order. In July 2017,~~order and intervenors filed appeals with the Texas Third Court of Appeals.

In ~~April 2018, oral arguments were heard by~~August 2021, the Texas Third Court of ~~Appeals.~~

~~If certain parts~~Appeals reversed the Texas District Court judgment affirming the PUCT’s order on AFUDC, concluding that the language of the ~~PUCT~~PUCT’s original 2008 order ~~are overturned and if SWEPCo cannot ultimately recover its~~intended to include AFUDC in the Texas jurisdictional ~~share~~capital cost cap and remanded the case to the PUCT for future proceedings. In November 2021, SWEPCo and the PUCT submitted Petitions for Review with the Texas Supreme Court. In October 2022, the Texas Supreme Court denied the Petitions for Review submitted by SWEPCo and the PUCT. In December 2022, SWEPCo and the PUCT filed requests for rehearing with the Texas Supreme Court. In June 2023, the Texas Supreme Court denied SWEPCo’s request for rehearing and the case was remanded to the PUCT for future proceedings. In October 2023, SWEPCo filed testimony with the PUCT in the remanded proceeding recommending no refund or disallowance.

On December 14, 2023, the PUCT approved a preliminary order stating the PUCT will not address SWEPCo’s request that would allow the PUCT to find cause to allow SWEPCo to exceed the Texas jurisdictional capital cost cap in the current remand proceeding. As a result of the ~~Turk Plant investment,~~PUCT’s approval of the preliminary order, SWEPCo believes it is probable the PUCT will disallow capitalized AFUDC in excess of the Texas jurisdictional capital cost cap and recorded a pretax, non-cash disallowance of $86 million. Such determination may reduce SWEPCo’s future revenues by approximately $15 million on an annual basis. On December 21, 2023, SWEPCo filed a motion with the PUCT for reconsideration of the preliminary order. In January 2024, the PUCT denied the motion for reconsideration of the preliminary order.

The PUCT’s December 2023 approval of the preliminary order determined that it will address, in the ongoing PUCT remand proceeding, any potential revenue refunds to customers that may be required by future PUCT orders. In January 2024, the PUCT established a procedural schedule for the remand proceeding. On March 1, 2024, SWEPCo filed supplemental direct testimony with the PUCT in response to the December 2023 preliminary order. On March 8, 2024, intervenors and the PUCT staff filed a motion with the PUCT to strike portions of SWEPCo’s October 2023 direct testimony and March 2024 supplemental direct testimony. On March 19, 2024, The ALJ granted portions of the motion which included removal of testimony supporting SWEPCo’s position that refunds are not appropriate. On March 28, 2024, SWEPCo filed an appeal of the ALJ decision with the PUCT. A decision by the PUCT on the appeal is expected in the second quarter of 2024. In April 2024, intervenors and PUCT staff submitted testimony recommending customer refunds through December 2023 ranging from $149 million to $197 million, including ~~AFUDC,~~carrying charges, with refund periods ranging from 18 months to 48 months. A hearing is scheduled for May 2024. Although SWEPCo does not currently believe any refunds are probable of occurring, SWEPCo estimates it could ~~reduce future net income and cash flows and impact financial condition.~~be required to make customer refunds, including interest, ranging from $0 to $200 million related to revenues collected from February 2013 through March 2024.

2016 Texas Base Rate Case

In ~~December~~ 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% ~~return on common equity.~~ROE. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a ~~return on common equity~~ROE of 9.6%, effective May 2017. The final order also ~~included~~included: (a) approval to recover the Texas jurisdictional share of environmental investments placed ~~in service,~~in-service, as of June 30, 2016, at various plants, including Welsh Plant, Units 1 and 3, (b)

113

approval of recovery of, but no return on, the Texas jurisdictional share of the net book value of Welsh Plant, Unit 2, (c) approval of $2 million in additional vegetation management expenses and (d) the rejection of SWEPCo’s proposed transmission cost recovery mechanism.

As a result of the final order, in 2017 ~~SWEPCo~~SWEPCo: (a) recorded an impairment charge of $19 million, which ~~includes~~included $7 million associated with the lack of return on Welsh Plant, Unit 2 and $12 million related to other disallowed plant investments, (b) recognized $32 million of additional revenues, for the period of May 2017 through December 2017, that ~~will be~~was surcharged to customers in 2018and (c) recognized an additional $7 million of expenses consisting primarily of depreciation expense and vegetation management expense, offset by the deferral of rate case ~~expenses.~~expense. SWEPCo implemented new rates in February 2018 billings. The $32 million of additional 2017 revenues ~~will be~~was collected ~~by the end of~~during 2018. In March 2018, the PUCT clarified and corrected portions of the final order, without changing the overall decision or amounts of the rate change. ~~This~~The order ~~is subject~~has been appealed by various intervenors related to ~~appeal as early as~~limiting SWEPCo’s recovery of AFUDC on Turk Plant and recovery of Welsh Plant, Unit 2. If certain parts of the ~~second quarter 2018.~~ PUCT order are overturned, it could reduce future net income and cash flows and impact financial condition.

2020 Texas Base Rate Case

In ~~April 2018,~~October 2020, SWEPCo ~~made~~filed a request with the PUCT for a $105 million annual increase in Texas base rates based upon a proposed 10.35% ROE. The request would move transmission and distribution interim revenues recovered through riders into base rates. Eliminating these riders would result in a net annual requested base rate increase of $90 million primarily due to increased investments. SWEPCo subsequently filed a request with the PUCT lowering the requested annual increase in Texas base rates to $100 million, which would result in an ~~income tax~~$85 million net annual base rate ~~refund tariff filing which includes~~increase after moving the proposed riders to rate base.

In January 2022, the PUCT issued a final order approving an annual revenue ~~reduction~~increase of ~~approximately $18~~$39 million based upon a 9.25% ROE. The order also includes: (a) rates implemented retroactively back to ~~reflect~~March 18, 2021, (b) $5 million of the ~~difference between rates collected under~~proposed increase related to vegetation management, (c) $2 million annually to establish a storm catastrophe reserve and (d) the creation of a rider to recover the Dolet Hills Power Station as if it were in rate base until its retirement at the end of 2021 and starting in 2022 the remaining net book value to be recovered as a regulatory asset through 2046. As a result of the final order, SWEPCo recorded a disallowance of $12 million in 2021 associated with the lack of return on the Dolet Hills Power Station. In February 2022, SWEPCo filed a motion for rehearing with the PUCT challenging several errors in the order, which include challenges of the approved ROE, the denial of a reasonable return or carrying costs on the Dolet Hills Power Station and the ~~rates that would be collected under Tax Reform. The filing did not address~~calculation of the ~~return~~Texas jurisdictional share of ~~excess deferred income tax benefits to customers.~~the storm catastrophe reserve. In April 2022, the PUCT denied the motion for rehearing. In May 2022, SWEPCo filed a petition for review with the Texas District Court seeking a judicial review of the several errors challenged in the PUCT’s final order.

~~2015~~2021 Louisiana ~~Formula Rate~~Storm Cost Filing

In ~~April 2015,~~2020, Hurricanes Laura and Delta caused power outages and extensive damage to the SWEPCo ~~filed its formula rate plan for test year 2014~~service territories, primarily impacting the Louisiana jurisdiction. Following both hurricanes, the LPSC issued orders allowing Louisiana utilities, including SWEPCo, to establish regulatory assets to track and defer expenses associated with ~~the LPSC. The filing included a $14 million annual increase, which was effective August 2015.~~these storms. In February ~~2018,~~2021, severe winter weather impacted the Louisiana jurisdiction and in March 2021, the LPSC approved the deferral of incremental storm restoration expenses related to the winter storm. In March 2023, SWEPCo and the LPSC staff filed a ~~report~~joint stipulation and settlement agreement with the LPSC which confirmed the prudency of $150 million of deferred incremental storm restoration expenses. The agreement also authorized an interim carrying charge at a rate of 3.125% through March 2024. In April 2023, the LPSC issued an order approving the ~~increase as filed. This increase~~stipulation and settlement agreement. In July 2023, SWEPCo submitted additional information in phase two of this proceeding to obtain a financing order and prudency review of capital investment. In April 2024, SWEPCo and the LPSC staff filed a joint uncontested stipulation and settlement agreement with the LPSC requesting securitization of storm costs, including a storm reserve. A hearing is scheduled for May 2024. If SWEPCo is unable to recover he regulatory assets associated with these storms, it could reduce future net income and cash flows and impact financial condition.

114

February 2021 Severe Winter Weather Impacts in SPP

In February 2021, severe winter weather had a significant impact in SPP, resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system. For the time period of February 9, 2021 to February 20, 2021, SWEPCo’s natural gas expenses and purchases of electricity still to be recovered from customers are shown in the table below:



Jurisdiction	March 31, 2024		December 31, 2023		Approved Recovery Period	Approved Carrying Charge
	(in millions)
Arkansas	$	48.6	$	54.2	6 years	(a)
Louisiana	90.8		97.2		(b)	(b)
Texas	94.5		101.9		5 years	1.65%
Total	$	233.9	$	253.3

(a)SWEPCo is permitted to record carrying costs on the unrecovered balance of fuel costs at a weighted-cost of capital approved by the APSC. The APSC will conclude an audit of these costs in 2024. A hearing is scheduled for June 2024.

(b)In March 2021, the LPSC approved a special order granting a temporary modification to the FAC and shortly after SWEPCo began recovery of its Louisiana jurisdictional share of these fuel costs based on a five-year recovery period inclusive of an interim carrying charge equal to the prime rate. The special order states the fuel and purchased power costs incurred will be subject to a future LPSC audit.

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

PSO and SWEPCo Rate Matters (Applies to AEP, PSO and SWEPCo)

North Central Wind Energy Facilities

The NCWF are subject to various regulatory performance requirements, including a Net Capacity Factor (NCF) guarantee. The NCF guarantee will be measured in MWhs across all facilities on a combined basis for each five year period for the first thirty full years of operation. The first NCF guarantee five year period began in April 2022. Certain wind turbines have experienced performance issues that have prompted PSO and SWEPCo to work with a manufacturer to find a resolution. If regulatory performance requirements, such as the NCF guarantee, are not met, PSO and SWEPCo may recognize a regulatory liability to refund ~~pending commission approval.~~retail customers. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

FERC Rate Matters

Independence Energy Connection Project (Applies to AEP)

In 2016, PJM approved the Independence Energy Connection Project (IEC) and included it in its Regional Transmission Expansion Plan to alleviate congestion. Transource Energy has an ownership interest in the IEC, which is located in Maryland and Pennsylvania. In June 2020, the Maryland Public Service Commission approved a Certificate of Public Convenience and Necessity to construct the portion of the IEC in Maryland. In May 2021, the Pennsylvania Public Utility Commission (PAPUC) denied the IEC certificate for siting and construction of the portion in Pennsylvania. Transource Energy appealed the PAPUC ruling in Pennsylvania state court and challenged the ruling before the United States District Court for the Middle District of Pennsylvania. In May 2022, the Pennsylvania state court issued an order affirming the PAPUC decision as to state law claims. In December 2023, the United States District Court for the Middle District of Pennsylvania granted summary judgment in favor of Transource Energy, finding that the PAPUC decision violated federal law and the United States Constitution. In January 2024, the PAPUC filed an appeal with the United States Court of Appeals for the Third Circuit. Additional regulatory proceedings before the PAPUC are expected to resume in 2024.

In September 2021, PJM notified Transource Energy that the IEC was suspended to allow for the regulatory and related appeals process to proceed in an orderly manner without breaching milestone dates in the project agreement. At that time, PJM stated that the IEC has not been cancelled and remains necessary to alleviate congestion. PJM continues to evaluate reliability and market efficiency in the area. As of March 31, 2024, AEP’s share of IEC capital expenditures was approximately $94 million, located in Total Property, Plant and Equipment - Net on AEP’s balance sheets. The FERC has previously granted abandonment benefits for this project, allowing the full recovery of prudently incurred costs if the project is cancelled for reasons outside the control of Transource Energy. If any of ~~these~~the IEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

~~2017 Louisiana~~

115

Request to Update AEGCo Depreciation Rates (Applies to AEP and I&M)

In October 2022, AEP, on behalf of AEGCo, submitted proposed revisions to AEGCo’s depreciation rates for its 50% ownership interest in Rockport Plant, Unit 1 and Unit 2, reflected in the UPA between AEGCo and I&M. The proposed depreciation rates for these assets reflect an estimated 2028 retirement date for the Rockport Plant. AEGCo’s previous FERC-approved depreciation rates for Rockport Plant, Unit 1 were based upon a December 31, 2028 estimated retirement date while AEGCo’s previous FERC-approved depreciation rates for Rockport Plant, Unit 2 leasehold improvements were based upon a December 31, 2022 estimated retirement date in conjunction with the termination of the Rockport Plant, Unit 2 lease.

In December 2022, the FERC issued an order approving the proposed AEGCo Rockport depreciation rates effective January 1, 2023, subject to further review and a potential refund. In August 2023, AEGCo reached a settlement agreement with the FERC trial staff that resolved all issues set for hearing. In September 2023, the settlement agreement was certified to the FERC as uncontested. In March 2024, the FERC issued an order approving the uncontested settlement agreement. The results of the order did not have a material impact on financial condition, results of operations or cash flows.

FERC 2021 PJM and SPP Transmission Formula Rate ~~Filing~~Challenge (Applies to AEP, AEPTCo, APCo, I&M, PSO and SWEPCo)

The Registrants transitioned to stand-alone treatment of NOLCs in its PJM and SPP transmission formula rates beginning with the 2022 projected transmission revenue requirements and 2021 true-up to actual transmission revenue requirements, and provided notice of this change in informational filings made with the FERC. Stand-alone treatment of the NOLCs for transmission formula rates increased the annual revenue requirements for years 2024, 2023, 2022 and 2021 by $52 million, $60 million, $69 million and $78 million, respectively.

In January 2024, the FERC issued two orders granting formal challenges by certain unaffiliated customers related to stand-alone treatment of NOLCs in the 2021 Transmission Formula Rates of the AEP transmission owning subsidiaries within PJM and SPP. The FERC directed the AEP transmission owning subsidiaries within PJM and SPP to provide refunds with interest on all amounts collected for the 2021 rate year, and for such refunds to be reflected in the annual update for the next rate year. In February 2024, AEPSC on behalf of the AEP transmission owning subsidiaries within PJM and SPP filed requests for rehearing. In March 2024, the FERC denied AEPSC’s requests for rehearing of the January 2024 orders by operation of law and stated it may address the requests for rehearing in future orders. In March 2024, AEPSC submitted refund compliance reports to the FERC, which preserve the non-finality of the FERC’s January 2024 orders pending further proceedings on rehearing and appeal. In April ~~2017,~~2024, AEP made filings with the ~~LPSC approved~~FERC which request that the FERC: (a) reopen the record so that the FERC may take the IRS PLRs received in April 2024 regarding the treatment of stand-alone NOLCs in ratemaking into evidence and consider them in substantive orders on rehearing and (b) stay its January 2024 orders and related compliance filings and refunds to provide time for consideration of the April 2024 IRS PLRs. The Registrants have not yet been directed to make cash refunds related to the 2024, 2023 or 2022 rate years.

As a result of the January 2024 FERC orders, the Registrants’ balance sheets reflect a liability for the probable refund of all NOLC revenues included in transmission formula rates for years 2024, 2023, 2022 and 2021, with interest. The probable refunds to affiliated and nonaffiliated customers are reflected as Deferred Credits and Other Noncurrent Liabilities on the balance sheets, with the exception of amounts expected to be refunded within one year which are reflected in Other Current Liabilities. Refunds probable to be received by affiliated companies, resulting in a reduction to affiliated transmission expense, were deferred as an ~~uncontested stipulation agreement~~increase to Regulatory Liabilities or a reduction to Regulatory Assets on the balance sheets where management expects that refunds would be returned to retail customers through authorized retail jurisdiction rider mechanisms.

Request to Update SWEPCo Generation Depreciation Rates (Applies to AEP and SWEPCo)

In October 2023, SWEPCo filed an application to revise its generation wholesale customer’s contracts to reflect an increase in the annual revenue requirement of approximately $5 million for ~~its formula rate plan~~updated depreciation rates and allow for ~~test year 2015. The filing included a net annual increase not to exceed $31 million, which was effective May 2017~~the return on and ~~includes SWEPCo’s Louisiana~~of FERC customers jurisdictional share of ~~Welsh Plant~~regulatory assets associated with retired plants. In November 2023, certain intervenors filed a motion with the FERC protesting and ~~Flint Creek Plant environmental controls which were placed in service in 2016. The net annual increase is~~recommending the rejection of SWEPCo’s filings. In December 2023, the FERC issued an order approving the proposed rates effective January 1, 2024, subject to ~~refund. In October 2017,~~further review and refund and established hearing and settlement proceedings. If SWEPCo ~~filed testimony in Louisiana supporting~~is unable to recover the prudence of its environmental control investment for Welsh Plant, Units 1 and 3 and Flint Creek power plants. These environmental costs are subject to prudence review. A hearing at the LPSC is scheduled for May 2018. If any of these costs are not recoverable,remaining regulatory assets associated with retired plants, it could reduce future net income and cash flows and impact financial condition.

116

~~2018 Louisiana Formula Rate Filing~~

In April 2018, SWEPCo filed its formula rate plan for test year 2017 with the LPSC. The filing included a net $28 million annual increase, which will be effective August 2018. The filing included a reduction in the federal income tax rate due to Tax Reform. The return of excess deferred income tax benefits to customers will be addressed in a supplemental filing and will reduce the $28 million annual increase. The increase includes SWEPCo’s jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls, whose prudence review hearing is scheduled for May 2018. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

~~Welsh Plant - Environmental Impact~~

Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could total approximately $850 million, excluding AFUDC. As of March 31, 2018, SWEPCo had incurred costs of $399 million, including AFUDC, related to these projects. Management continues to evaluate the impact of environmental rules and related project cost estimates. As of March 31, 2018, the total net book value of Welsh Plant, Units 1 and 3 was $625 million, before cost of removal, including materials and supplies inventory and CWIP.

In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas filed base rate proceeding. In April 2017, the LPSC approved recovery of $131 million in investments related to its Louisiana jurisdictional share of

environmental controls installed at Welsh Plant, effective May 2017. SWEPCo’s approved Louisiana jurisdictional share of Welsh Plant deferrals: (a) are $11 million, excluding $6 million of unrecognized equity as of March 31, 2018, (b) is subject to review by the LPSC, and (c) includes a WACC return on environmental investments and the related depreciation expense and taxes. In January 2018, SWEPCo received written approval from the PUCT to recover its project costs from retail customers in its 2016 Texas base rate case and is recovering these costs from wholesale customers through SWEPCo’s FERC-approved agreements. See “2016 Texas Base Rate Case” and “2017 Louisiana Formula Rate Filing” disclosures above.

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

~~FERC Rate Matters~~

~~PJM Transmission Rates (Applies to AEP, AEPTCo, APCo, I&M and OPCo)~~

In June 2016, PJM transmission owners, including AEP’s transmission owning subsidiaries within PJM, and various state commissions filed a settlement agreement at the FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. In July 2016, certain parties filed comments at the FERC contesting the settlement agreement. Upon final FERC approval, PJM would implement a transmission enhancement charge adjustment through the PJM OATT, billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms.

~~FERC Transmission Complaint - AEP’s PJM Participants (Applies to AEP, AEPTCo, APCo, I&M and OPCo)~~

In October 2016, seven parties filed a complaint at the FERC that alleged the base return on common equity used by AEP’s transmission owning subsidiaries within PJM in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint. In November 2017, a FERC order set the matter for hearing and settlement procedures. In March 2018, AEP’s transmission owning subsidiaries within PJM and six of the complainants filed a settlement agreement with the FERC (the seventh complainant abstained). If approved by the FERC the settlement agreement (a) establishes a base ROE for AEP’s transmission owning subsidiaries within PJM of 9.85% (10.35% inclusive of the RTO incentive adder of 0.5%), effective January 1, 2018, (b) requires AEP’s transmission owning subsidiaries within PJM to provide a one-time refund of $50 million, attributable from the date of the complaint through December 31, 2017, to be credited to customer bills in the second quarter of 2018 and (c) increases the cap on the equity portion of the capital structure to 55% from 50%. As part of the settlement agreement, AEP’s transmission owning subsidiaries within PJM also filed updated transmission formula rates incorporating the reduction in the corporate federal income tax rate due to Tax Reform, effective January 1, 2018 and providing for the amortization of the portion of the excess accumulated deferred income taxes that are not subject to the normalization method of accounting, ratably over a ten year period through credits to the federal income tax expense component of the revenue requirement. In April 2018, an ALJ accepted the interim settlement rates, pending the FERC’s consideration of the settlement, and the rates are subject to refund or surcharge, with interest.

In April 2018, certain intervenors filed comments at the FERC recommending a base ROE of 8.48% and a one-time refund of $184 million. In addition, the FERC trial staff filed comments recommending a base ROE of 8.41% and one-time refund of $175 million. Also in April 2018, another intervenor recommended the refund be calculated in accordance with the base ROE that will ultimately be approved by the FERC. Management intends to file reply comments providing further support for the 9.85% base ROE agreed to in the settlement agreement.

Management believes the $50 million refund in the settlement agreement is the best estimate of the probable liability. If the FERC orders revenue reductions in excess of the terms of the settlement agreement, it could reduce future net income and cash flows and impact financial condition. A decision from the FERC is pending.

~~Modifications to AEP’s PJM Transmission Rates (Applies to AEP, AEPTCo, APCo, I&M and OPCo)~~

In November 2016, AEP’s transmission owning subsidiaries within PJM filed an application at the FERC to modify the PJM OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to projected expenses. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. The modified PJM OATT formula rates are based on projected calendar year financial activity and projected plant balances. In December 2017, AEP’s transmission owning subsidiaries within PJM filed an uncontested settlement agreement with the FERC resolving all outstanding issues. In April 2018, the FERC approved the uncontested settlement agreement and rates were implemented effective January 1, 2018.

~~FERC Transmission Complaint - AEP’s SPP Participants (Applies to AEP, AEPTCo, PSO and SWEPCo)~~

In June 2017, several parties filed a complaint at the FERC that states the base return on common equity used by AEP’s transmission owning subsidiaries within SPP in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36%, effective upon the date of the complaint. In November 2017, a FERC order set the matter for hearing and settlement procedures. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.

~~Modifications to AEP’s SPP Transmission Rates (Applies to AEP, AEPTCo, PSO and SWEPCo)~~

In October 2017, AEP’s transmission owning subsidiaries within SPP filed an application at the FERC to modify the SPP OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to projected expenses. The modified SPP OATT formula rates are based on projected 2018 calendar year financial activity and projected plant balances. In December 2017, the FERC accepted the proposed modifications effective January 1, 2018, subject to refund, and set this matter for hearing and settlement procedures. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

~~FERC SWEPCo Power Supply Agreements Complaint - East Texas Electric Cooperative, Inc. (ETEC) and Northeast Texas Electric Cooperative, Inc. (NTEC)~~

In September 2017, ETEC and NTEC filed a complaint at the FERC that states the base return on common equity used by SWEPCo in calculating their power supply formula rates is excessive and should be reduced from 11.1% to 8.41%, effective upon the date of the complaint. In November 2017, a FERC order set the matter for hearing and settlement procedures. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.

5. COMMITMENTS, GUARANTEES AND CONTINGENCIES

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

The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the ~~Registrants~~Registrants’ business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates.

For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the ~~2017~~2023 Annual Report should be read in conjunction with this report.

GUARANTEES

Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to ~~third parties~~third-parties unless specified below.

Letters of Credit (Applies to AEP, AEP Texas, APCo and ~~OPCo)~~I&M)

Standby letters of credit are entered into with ~~third parties.~~third-parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.

In March 2024, AEP ~~has a $3~~increased its $4 billion revolving credit facility to $5 billion and extended the due date from March 2027 to March 2029. Also, in ~~June 2021, under which~~March 2024, AEP extended the due date of its $1 billion revolving credit facility from March 2025 to March 2027. AEP may issue up to $1.2 billion ~~may be issued~~ as letters of credit, under these revolving credit facilities, on behalf of subsidiaries. As of March 31, ~~2018,~~2024, no letters of credit were issued under ~~the $3 billion~~either revolving credit facility.

Company

Amount

Maturity

(in millions)

AEP

247.4

April 2024 to March 2025

AEP Texas

1.8

July 2024

APCo

6.3

September 2024

I&M

2.9

September 2024

Company Amount Maturity
(in millions)
AEP $ 81.3
May 2018 to March 2019
OPCo 0.6
September 2018

~~AEP has $45 million of variable rate Pollution Control Bonds supported by $46 million of bilateral letters of credit maturing in July 2019.~~

~~Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo)~~

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $140 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. It is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $77 million. Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of March 31, 2018, SWEPCo has collected $72 million through a rider for final mine closure and reclamation costs, of which $77 million is recorded in Asset Retirement Obligations, offset by $5 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet.

~~Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause.~~

~~Guarantees of Equity Method Investees (Applies to AEP)~~

In December 2016, AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of March 31, 2018, the maximum potential amount of future payments associated with this guarantee was $75 million, which expires in December 2019.

Indemnifications and Other Guarantees

Contracts

The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of March 31, ~~2018,~~2024, there were no material liabilities recorded for any indemnifications.

AEPSC conducts power ~~purchase and sale~~purchase-and-sale activity on behalf of APCo, I&M, KPCo and WPCo, who are jointly and severally liable for activity conducted on their behalf. AEPSC also conducts power ~~purchase and sale~~purchase-and-sale activity on behalf of PSO and SWEPCo, who are jointly and severally liable for activity conducted on their behalf.

117

Master Lease Agreements (Applies to all Registrants except AEPTCo)

The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of ~~either the unamortized balance or~~ the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the ~~unamortized balance.~~amount guaranteed. As of March 31, ~~2018,~~2024, the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term iswas as follows:


Company	Maximum Potential Loss
	(in millions)
AEP	$	44.6
AEP Texas	10.7
APCo	5.8
I&M	4.1
OPCo	7.1
PSO	4.5
SWEPCo	5.1

Company
Maximum
Potential Loss
(in millions)
AEP $ 43.4
AEP Texas 10.5
APCo 8.8
I&M 3.1
OPCo 6.3
PSO 3.7
SWEPCo 3.7

~~Railcar Lease (Applies to AEP, I&M and SWEPCo)~~

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $7 million and $8 million for I&M and SWEPCo, respectively, for the remaining railcars as of March 31, 2018.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% of the projected fair value of the equipment under the current five year lease term to 77% at the end of the 20-year term. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $8 million and $9 million for I&M and SWEPCo, respectively, as of March 31, 2018, assuming the fair value of the equipment is zero at the end of the current five-year lease term. However, management believes that the fair value would produce a sufficient sales price to avoid any loss.

~~AEPRO Boat and Barge Leases (Applies to AEP)~~

In October 2015, AEP signed a Purchase and Sale Agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale closed in November 2015. Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of March 31, 2018, the maximum potential amount of future payments required under the guaranteed leases was $49 million. In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of March 31, 2018, AEP’s boat and barge lease guarantee liability was $7 million, of which $2 million was recorded in Other Current Liabilities and $5 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet.

In January 2018, S&P Global Inc. downgraded the ratings of the nonaffiliated party and set their outlook to negative. In April 2018, Moody’s Investors Service Inc. also downgraded their ratings and set their outlook to negative. It is reasonably possible that enforcement of AEP’s liability for future payments under these leases could be exercised, which could reduce future net income and cash flows and impact financial condition.

ENVIRONMENTAL CONTINGENCIES (Applies to all Registrants except AEPTCo)

Proposed Revisions to CCR Rule

In April 2024, the Federal EPA finalized revisions to the CCR Rule to expand the scope of the rule to include inactive impoundments at inactive facilities (“legacy CCR surface impoundments”) as well as to establish requirements for currently exempt solid waste management units that involve the direct placement of CCR on the land (“CCR management units”). The Federal EPA is requiring that owners and operators of legacy surface impoundments comply with all of the existing CCR Rule requirements applicable to inactive CCR surface impoundments at active facilities, except for the location restrictions and liner design criteria. The rule establishes compliance deadlines for legacy surface impoundments to meet regulatory requirements, including a requirement to initiate closure within five years after the effective date of the final rule. The rule requires evaluations to be completed at both active facilities and inactive facilities with one or more legacy surface impoundments. AEP is evaluating the applicability of the rule to current and former plant sites and is working to develop estimates of compliance costs, which are expected to be material, including costs to upgrade or close and replace legacy CCR surface impoundments and to conduct any required remedial actions including removal of coal ash.

Closure and post-closure estimated costs for facilities subject to the original CCR Rule have been included in ARO in accordance with the requirements in the Federal EPA’s original CCR rule. Material ARO revisions will be necessary to address the expanded scope of facilities subject to the revised rule. Additional material ARO revisions may occur on a site-by-site basis if groundwater monitoring activities conclude that corrective actions are required to mitigate groundwater impacts. AEP may incur significant additional costs complying with the Federal EPA’s CCR Rule, including costs to upgrade or close and replace surface impoundments and landfills used to manage CCR and to conduct any required remedial actions including removal of coal ash.

AEP would need to seek cost recovery through regulated rates, including proposing new regulatory mechanisms for cost recovery where existing mechanisms are not applicable, for which regulatory approval cannot be assured. The rule could have a material adverse impact on net income, cash flows and financial condition if AEP cannot ultimately recover any additional costs of compliance. Management is also evaluating potential legal challenges to the revised rule.

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and ~~nonhazardous~~non-hazardous materials. The Registrants currently incur costs to dispose of these substances safely. For remediation processes not specifically discussed, management does not anticipate that the liabilities, if any, arising from such remediation processes would have a material effect on the financial statements.

118

NUCLEAR CONTINGENCIES (Applies to AEP and I&M)

I&M owns and operates the ~~two-unit 2,278 MW~~ Cook Plant under licenses granted by the Nuclear Regulatory Commission. I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. Management is currently evaluating applying for license extensions for both units. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.

~~Westinghouse Electric Company Bankruptcy Filing~~

In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the U.S. Bankruptcy Code. Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication and ongoing engineering projects. The most significant of these relate to Cook Plant fuel fabrication. As part of the reorganization, the bankruptcy court approved Westinghouse’s sale of its nuclear business to Brookfield WEC Holdings, a nonaffiliated third party. Pursuant to the sale, Brookfield will assume all of I&M’s contracts with Westinghouse. The sale is subject to regulatory approvals and is expected to close in the third quarter of 2018.

OPERATIONAL CONTINGENCIES

~~Rockport Plant~~ Litigation ~~(Applies~~Related to Ohio House Bill 6 (HB 6)

In 2019, Ohio adopted and implemented HB 6 which benefits OPCo by authorizing rate recovery for certain costs including renewable energy contracts and OVEC’s coal-fired generating units. OPCo engaged in lobbying efforts and provided testimony during the legislative process in connection with HB 6. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of an Ohio legislator and associates in connection with an alleged racketeering conspiracy involving the adoption of HB 6. After AEP learned of the criminal allegations against the Ohio legislator and others relating to HB 6, AEP, with assistance from outside advisors, conducted a review of the circumstances surrounding the passage of the bill. Management does not believe that AEP was involved in any wrongful conduct in connection with the passage of HB 6.

In August 2020, an AEP shareholder filed a putative class action lawsuit in the U. S. District Court for the Southern District of Ohio against AEP and ~~I&M)~~certain of its officers for alleged violations of securities laws. In December 2021, the district court issued an opinion and order dismissing the securities litigation complaint with prejudice, determining that the complaint failed to plead any actionable misrepresentations or omissions. The plaintiffs did not appeal the ruling.

In ~~July 2013, the Wilmington Trust Company~~January 2021, an AEP shareholder filed a ~~complaint~~derivative action in the U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will 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 or retirement of the unit. The plaintiffs further allege that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations relatedOhio purporting 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. In October 2013, a motion to dismiss the case was filedassert claims on behalf of ~~AEGCo~~AEP against certain AEP officers and ~~I&M.~~

directors. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims, including the dismissal without prejudice of plaintiffs’ claims seeking compensatory damages. Several claims remained, including the claim for breach of the participation agreement andFebruary 2021, a ~~claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M~~second AEP shareholder filed a ~~motion for partial judgment on~~similar derivative action in the ~~claims seeking dismissal~~Court of ~~the breach~~Common Pleas of participation agreement claim as well as any claim for indemnification of costs associated with this case. The plaintiffs subsequently filed an amended complaint to add another claim under the lease and alsoFranklin County, Ohio. In April 2021, a third AEP shareholder filed a motion for partial summary judgment. In November 2015, AEGCo and I&M filed a motion to strike the plaintiffs’ motion for partial judgment and filed a motion to dismiss the case for failure to state a claim.

~~In March 2016, the court entered an opinion and order~~similar derivative action in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, plaintiffs filed an appeal in the U.S. Court of Appeals for the Sixth Circuit on whether AEGCo and I&M are in breach of certain contract provisions that plaintiffs allege operate to protect the plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing.

In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions which had dismissed certain of plaintiffs’ claims for breach of contract and remanding the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. In April 2017, AEGCo and I&M filed a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit, which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reverses the district court’s dismissal of certain of the owners’ claims under the lease agreements, vacates the denial of the owners’ motion for partial summary judgment and remands the case to the district court for further proceedings. The amended opinion and judgment also affirms the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims and removes the instruction to the district court in the original opinion to enter summary judgment in favor of the owners.

~~In July 2017, AEP filed a motion with~~ the U.S. District Court for the Southern District of Ohio and a fourth AEP shareholder filed a similar derivative action in the ~~original NSR litigation, seeking~~Supreme Court for the State of New York, Nassau County. These derivative complaints allege the officers and directors made misrepresentations and omissions similar to ~~modify~~those alleged in the ~~consent decree~~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 ~~eliminate~~AEP’s corporate governance and internal policies among other forms of relief. The court entered a scheduling order in the ~~obligation~~New York state court derivative action staying the case other than with respect to ~~install certain future controls at Rockport Plant, Unit 2 if~~briefing the motion to dismiss. AEP ~~does not acquire ownership~~filed substantive and forum-based motions to dismiss in April 2022. In June 2022, the Ohio state court entered an order continuing the stays of that ~~Unit, and to modify~~case until the ~~consent decree in other respects to preserve the environmental benefits~~final resolution of the ~~consent decree.~~consolidated derivative actions pending in Ohio federal district court. In ~~November 2017,~~September 2022, the ~~district~~New York state court granted the ~~owners’ unopposed~~forum-based motion to ~~stay~~dismiss with prejudice and the ~~lease litigation to afford time for resolution~~plaintiff subsequently filed a notice of ~~AEP’s~~appeal with the New York appellate court. In January 2023, the New York plaintiff filed a motion to ~~modify~~intervene in the ~~consent decree.~~

~~Management~~pending Ohio federal court action and withdrew his appeal in New York. The two derivative actions pending in federal district court in Ohio have been consolidated and the plaintiffs in the consolidated action filed an amended complaint. AEP filed a motion to dismiss the amended complaint and subsequently filed a brief in opposition to the New York plaintiffs’ motion to intervene in the consolidated action in Ohio. In March 2023, the federal district court issued an order granting the motion to dismiss with prejudice and denying the New York plaintiffs’ motion to intervene. In April 2023, one of the plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Sixth Circuit of the Ohio federal district court order dismissing the consolidated action and denying the intervention. The defendants will continue to defend against the claims. ~~Given~~Management does not believe the range of potential losses that is reasonably possible of occurring will have a material impact on results of operations, cash flows or financial condition.

In March 2021, AEP received a litigation demand letter from counsel representing a purported AEP shareholder. The litigation demand letter was directed to the Board of Directors of AEP (AEP Board) and contained factual allegations involving HB 6 that were generally consistent with those in the derivative litigation filed in state and federal court. The shareholder that sent the letter has since withdrawn the litigation demand, which is now terminated and of no further effect. In April 2023, AEP received a litigation demand from counsel representing the purported AEP shareholder who filed the dismissed derivative action in New York state court and unsuccessfully tried to intervene in the consolidated derivative actions in Ohio federal court. The litigation demand letter is directed to the AEP Board 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 ~~district court dismissed plaintiffs’~~AEP Board undertake an independent investigation into alleged legal violations by certain current and former directors and officers, and

119

that AEP commence a civil action for breaches of fiduciary duty and related claims against any individuals who allegedly harmed AEP. The AEP Board considered the 2023 litigation demand letter and formed a committee of the Board (the “Demand Review Committee”) to investigate, review, monitor and analyze the allegations in the letter and make a recommendation to the AEP Board regarding a reasonable and appropriate response to the same. The AEP Board will act in response to the letter as appropriate. Management does not believe the range of potential losses that is reasonably possible of occurring will have a material impact on results of operations, cash flows or financial condition.

In May 2021, AEP received a subpoena from the SEC’s Division of Enforcement seeking ~~compensatory relief~~various documents, including documents relating to the passage of HB 6 and documents relating to AEP’s policies and financial processes and controls. In August 2022, AEP received a second subpoena from the SEC seeking various additional documents relating to its ongoing investigation. AEP is cooperating fully with the SEC’s investigation, which has included taking testimony from certain individuals and inquiries regarding Empowering Ohio’s Economy, Inc., which is a 501(c)(4) social welfare organization, and related disclosures. The SEC staff has advanced its discussions with certain parties involved in the investigation, including AEP, concerning the staff’s intentions regarding potential claims under the securities laws. AEP and the SEC are engaged in discussions about a possible resolution of the SEC’s investigation and potential claims under the securities laws. Any resolution or filed claims, the outcome of which cannot be predicted, may subject AEP to civil penalties and other remedial measures. Discussions are continuing and management does not believe the range of potential losses that is reasonably possible of occurring as ~~premature,~~a result of this investigation, or possible resolution thereof, will have a material impact on results of operations, cash flows or financial condition.

Claims for Indemnification Made by Owners of the Gavin Power Station

In November 2022, the Federal EPA issued a final decision denying Gavin Power LLC’s requested extension to allow a CCR surface impoundment at the Gavin Power Station to continue to receive CCR and non-CCR waste streams after April 11, 2021 until May 4, 2023 (the Gavin Denial). As part of the Gavin Denial, the Federal EPA made several assertions related to the CCR Rule (see “Environmental Issues - CCR Rule” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information), including an assertion that ~~plaintiffs~~the closure of the 300 acre unlined fly ash reservoir (FAR) is noncompliant with the CCR Rule in multiple respects. The Gavin Power Station was formerly owned and operated by AEP and was sold to Gavin Power LLC and Lightstone Generation LLC in 2017. Pursuant to the PSA, AEP maintained responsibility to complete closure of the FAR in accordance with the closure plan approved by the Ohio EPA which was completed in July 2021. The PSA contains indemnification provisions, pursuant to which the owners of the Gavin Power Station have ~~yet~~notified AEP they believe they are entitled to ~~present a methodology~~indemnification for ~~determining~~any damages that may result from these claims, including any future enforcement or litigation resulting from any ~~analysis supporting~~determinations of noncompliance by the Federal EPA with various aspects of the CCR Rule consistent with the Gavin Denial. The owners of the Gavin Power Station have also sought indemnification for landowner claims for property damage allegedly caused by modifications to the FAR. Management does not believe that the owners of the Gavin Power Station have any ~~alleged damages, management~~valid claim for indemnity or otherwise against AEP under the PSA. In addition, Gavin Power LLC, several AEP subsidiaries, and other parties have filed Petitions for Review of the Gavin Denial with the U.S. Court of Appeals for the District of Columbia Circuit. Management is unable to determine a range of potential losses that ~~are~~is reasonably possible of occurring. In January 2024, Gavin Power LLC also filed a complaint with the United States District Court for the Southern District of Ohio, alleging various violations of the Administrative Procedure Act and asserting that the Federal EPA, through its prior inaction, has waived and is estopped from raising certain objections raised in the Gavin Denial. Management cannot predict the outcome of that litigation.

Litigation Regarding Justice Thermal Coal Contract

In December 2023, APCo filed a suit in the Franklin County Ohio Court of Common Pleas seeking a declaratory judgment confirming APCo’s right to terminate a long-term coal contract with Justice Thermal LLC (“Justice Thermal”) based on Justice Thermal’s failure to perform under the contract. APCo terminated that contract in January 2024, and in April 2024 APCo filed an amended complaint seeking a declaration that the termination was proper and also seeking damages for Justice Thermal’s breach of contract. Justice Thermal filed an answer and counterclaim in April 2024, contesting the validity of the contract termination and asserting counterclaims. Justice Thermal’s counterclaims allege that APCo breached the contract, assert a claim for fraud relating to APCo’s alleged fabrication of coal sample analyses, and seek damages. APCo will continue to pursue its claims and defend against the counterclaims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

120

~~Gavin Landfill Litigation (Applies to AEP and OPCo)~~

6. ACQUISITIONS AND DISPOSITIONS

In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint became the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Twelve of the family members pursued personal injury/illness claims (non-working direct claims) and the remainder pursued loss of consortium claims. The plaintiffs sought compensatory and punitive damages, as well as medical monitoring. In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants subsequently filed a motion to dismiss the twelve non-working direct claims under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. In June 2017, the West Virginia Supreme Court reversed the WVMLP decision and dismissed the claims of the twelve non-working direct claim plaintiffs. In April 2018, a settlement in principle was reached. This settlement, once finalized, will be subject to court approval. Management believes the provision recorded for this case is adequate.

6. ~~DISPOSITIONS AND IMPAIRMENTS~~

The disclosures in this note apply to AEP unless indicated otherwise.

ACQUISITIONS

Rock Falls Wind Facility (Vertically Integrated Utilities Segment) (Applies to AEP and PSO)

In November 2022, PSO entered into an agreement to acquire the Rock Falls Wind Facility. In February 2023, the FERC approved PSO’s acquisition of the Rock Falls Wind Facility under Section 203 of the Federal Power Act. In March 2023, PSO acquired an ownership interest in the entity that owned Rock Falls during its development and construction for $146 million. In accordance with the guidance for “Business Combinations,” AEP management determined that the acquisition of the Rock Falls Wind Facility represents an asset acquisition. The lease obligations related to Rock Falls were not material as at the time of acquisition.

DISPOSITIONS

~~Zimmer Plant~~Disposition of the Competitive Contracted Renewables Portfolio (Generation & Marketing Segment) (Applies to AEP)

In February ~~2017,~~2022, AEP management announced the initiation of a process to sell all or a portion of AEP Renewables’ competitive contracted renewables portfolio (the portfolio) within the Generation & Marketing segment. In late January 2023, AEP received final bids from interested parties. In February 2023, AEP’s Board of Directors approved management’s plan to sell the portfolio and AEP signed an agreement with a nonaffiliated party. AEP recorded a pretax loss of $112 million ($88 million after-tax) in the first quarter of 2023 as a result of reaching Held for Sale status and determining the carrying value of the portfolio exceeded the estimated fair value.

In August 2023, AEP completed the sale of the entire portfolio to the nonaffiliated party and received cash proceeds of approximately $1.2 billion, net of taxes and transaction costs.

Disposition of NMRD (Generation & Marketing Segment) (Applies to AEP)

In December 2023, AEP and the joint owner signed an agreement to sell ~~its 25.4% ownership share of Zimmer Plant~~NMRD to a nonaffiliated ~~party.~~third party and the sale was completed in February 2024. AEP received cash proceeds of approximately $107 million, net of taxes and transaction costs. The transaction ~~closed in the second quarter of 2017 and~~ did not have a material impact on net income ~~cash flows~~ or financial condition. ~~The Income before Income Tax Expense and Equity Earnings of Zimmer Plant was immaterial for the three months ended March 31, 2017.~~

121

~~Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)~~

In September 2016, AEP signed a Purchase and Sale Agreement to sell AGR’s Gavin, Waterford and Darby Plants as well as AEGCo’s Lawrenceburg Plant totaling 5,329 MWs of competitive generation assets to a nonaffiliated party. The sale closed in January 2017 for $2.2 billion, which was recorded in Investing Activities on the statement of cash flows. The net proceeds from the transaction were $1.2 billion in cash after taxes, repayment of debt associated with these assets including a make whole payment related to the debt, payment of a coal contract associated with one of the plants and transaction fees. The sale resulted in a pretax gain of $227 million that was recorded in Gain on Sale of Merchant Generation Assets on AEP’s statement of income for the three months ended March 31, 2017.

~~IMPAIRMENTS~~

~~Other Assets (Corporate and Other) (Vertically Integrated Utilities Segment) (Applies to AEP and APCo)~~

In the first quarter of 2018, AEP was notified by an equity investee that it had ceased operations. AEP recorded a pretax impairment of $21 million in Other Operation on the statement of income related to the equity investment and related assets. The impairment also had an immaterial impact to APCo.

~~Merchant Generating Assets (Generation & Marketing Segment)~~

In the first quarter of 2017, AEP recorded a pretax impairment of $4 million in Other Operation on the statement of income related to the Merchant Coal-fired Generation Assets. In addition, AEP recorded a $7 million pretax impairment in Other Operation on the statement of income related to the sale of Zimmer Plant.

7. BENEFIT PLANS

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

~~AEP~~AEPSC sponsors a qualified pension plan and two unfunded ~~nonqualified~~non-qualified pension plans. Substantially all AEP subsidiary employees are covered by the qualified plan or both the qualified and a ~~nonqualified~~non-qualified pension plan. ~~AEP~~AEPSC also sponsors OPEB plans to provide health and life insurance benefits for retired employees.

Components of Net Periodic Benefit Cost (Credit)

~~The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans:~~Pension Plans

~~AEP~~


Three Months Ended March 31, 2024	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Service Cost	$	25.6	$	2.2	$	2.4	$	3.3	$	2.4	$	1.5	$	1.9
Interest Cost	51.9		4.3		6.2		6.0		4.7		2.5		3.1
Expected Return on Plan Assets	(80.2)		(6.4)		(10.7)		(10.8)		(8.2)		(4.3)		(4.4)

Amortization of Net Actuarial Loss	1.1		0.1		0.1		0.1		0.1		—		0.1
Net Periodic Benefit Cost (Credit)	$	(1.6)	$	0.2	$	(2.0)	$	(1.4)	$	(1.0)	$	(0.3)	$	0.7


Three Months Ended March 31, 2023	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Service Cost	$	23.6	$	2.0	$	2.3	$	3.0	$	2.1	$	1.4	$	1.9
Interest Cost	54.8		4.6		6.6		6.2		4.9		2.7		3.5
Expected Return on Plan Assets	(84.8)		(7.0)		(11.2)		(11.0)		(8.5)		(4.6)		(4.8)

Amortization of Net Actuarial Loss	0.3		—		—		—		—		—		—
Net Periodic Benefit Cost (Credit)	$	(6.1)	$	(0.4)	$	(2.3)	$	(1.8)	$	(1.5)	$	(0.5)	$	0.6

OPEB


Three Months Ended March 31, 2024	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Service Cost	$	1.1	$	0.1	$	0.1	$	0.1	$	0.1	$	0.1	$	0.1
Interest Cost	10.5		0.8		1.7		1.2		1.1		0.5		0.7
Expected Return on Plan Assets	(27.8)		(2.3)		(4.0)		(3.4)		(3.0)		(1.4)		(1.9)
Amortization of Prior Service Credit	(3.2)		(0.3)		(0.5)		(0.4)		(0.3)		(0.2)		(0.3)
Amortization of Net Actuarial Loss	0.8		0.1		0.1		0.1		0.1		—		0.1
Net Periodic Benefit Credit	$	(18.6)	$	(1.6)	$	(2.6)	$	(2.4)	$	(2.0)	$	(1.0)	$	(1.3)


Three Months Ended March 31, 2023	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Service Cost	$	1.1	$	0.1	$	0.1	$	0.2	$	0.1	$	0.1	$	0.1
Interest Cost	11.6		0.9		1.8		1.3		1.2		0.6		0.7
Expected Return on Plan Assets	(27.4)		(2.3)		(4.0)		(3.4)		(2.9)		(1.5)		(1.8)
Amortization of Prior Service Credit	(15.8)		(1.3)		(2.3)		(2.2)		(1.6)		(1.0)		(1.2)
Amortization of Net Actuarial Loss	3.7		0.3		0.6		0.5		0.4		0.2		0.2
Net Periodic Benefit Credit	$	(26.8)	$	(2.3)	$	(3.8)	$	(3.6)	$	(2.8)	$	(1.6)	$	(2.0)

122

Pension Plans OPEB
Three Months Ended March 31, Three Months Ended March 31,
2018 2017 2018 2017
(in millions)
Service Cost $ 24.4
$ 24.1
$ 2.9
$ 2.8
Interest Cost 46.9
50.8
11.8
14.8
Expected Return on Plan Assets (72.5 ) (71.2 ) (25.5 ) (25.3 )
Amortization of Prior Service Cost (Credit) —
0.3
(17.3 ) (17.3 )
Amortization of Net Actuarial Loss 21.3
20.7
2.6
9.2
Net Periodic Benefit Cost (Credit) $ 20.1
$ 24.7
$ (25.5 ) $ (15.8 )

~~AEP Texas~~

Pension Plans OPEB
Three Months Ended March 31, Three Months Ended March 31,
2018 2017 2018 2017
(in millions)
Service Cost $ 2.3
$ 2.1
$ 0.3
$ 0.2
Interest Cost 4.0
4.3
0.9
1.2
Expected Return on Plan Assets (6.4 ) (6.3 ) (2.1 ) (2.2 )
Amortization of Prior Service Credit —
—
(1.5 ) (1.4 )
Amortization of Net Actuarial Loss 1.8
1.8
0.2
0.8
Net Periodic Benefit Cost (Credit) $ 1.7
$ 1.9
$ (2.2 ) $ (1.4 )

~~APCo~~

Pension Plans OPEB
Three Months Ended March 31, Three Months Ended March 31,
2018
2017 2018 2017
(in millions)
Service Cost $ 2.3
$ 2.3
$ 0.3
$ 0.3
Interest Cost 5.9
6.4
2.0
2.6
Expected Return on Plan Assets (9.1 ) (8.9 ) (4.0 ) (4.1 )
Amortization of Prior Service Cost (Credit) —
0.1
(2.5 ) (2.5 )
Amortization of Net Actuarial Loss 2.6
2.6
0.5
1.6
Net Periodic Benefit Cost (Credit) $ 1.7
$ 2.5
$ (3.7 ) $ (2.1 )

~~I&M~~

Pension Plans OPEB
Three Months Ended March 31, Three Months Ended March 31,
2018 2017 2018 2017
(in millions)
Service Cost $ 3.4
$ 3.5
$ 0.4
$ 0.4
Interest Cost 5.5
6.1
1.4
1.7
Expected Return on Plan Assets (8.9 ) (8.6 ) (3.1 ) (3.1 )
Amortization of Prior Service Credit —
—
(2.4 ) (2.3 )
Amortization of Net Actuarial Loss 2.5
2.4
0.3
1.1
Net Periodic Benefit Cost (Credit) $ 2.5
$ 3.4
$ (3.4 ) $ (2.2 )

~~OPCo~~

Pension Plans OPEB
Three Months Ended March 31, Three Months Ended March 31,
2018 2017 2018 2017
(in millions)
Service Cost $ 2.0
$ 1.9
$ 0.2
$ 0.2
Interest Cost 4.4
4.8
1.3
1.7
Expected Return on Plan Assets (7.2 ) (7.0 ) (3.0 ) (3.0 )
Amortization of Prior Service Credit —
—
(1.7 ) (1.7 )
Amortization of Net Actuarial Loss 2.0
2.0
0.3
1.1
Net Periodic Benefit Cost (Credit) $ 1.2
$ 1.7
$ (2.9 ) $ (1.7 )

~~PSO~~

Pension Plans OPEB
Three Months Ended March 31, Three Months Ended March 31,
2018 2017 2018 2017
(in millions)
Service Cost $ 1.8
$ 1.6
$ 0.2
$ 0.2
Interest Cost 2.4
2.7
0.6
0.8
Expected Return on Plan Assets (4.0 ) (3.9 ) (1.4 ) (1.4 )
Amortization of Prior Service Credit —
—
(1.0 ) (1.1 )
Amortization of Net Actuarial Loss 1.1
1.1
0.1
0.5
Net Periodic Benefit Cost (Credit) $ 1.3
$ 1.5
$ (1.5 ) $ (1.0 )

~~SWEPCo~~

Pension Plans OPEB
Three Months Ended March 31, Three Months Ended March 31,
2018 2017 2018 2017
(in millions)
Service Cost $ 2.3
$ 2.2
$ 0.3
$ 0.2
Interest Cost 2.9
3.1
0.7
0.9
Expected Return on Plan Assets (4.4 ) (4.2 ) (1.6 ) (1.6 )
Amortization of Prior Service Credit —
—
(1.3 ) (1.3 )
Amortization of Net Actuarial Loss 1.3
1.2
0.1
0.6
Net Periodic Benefit Cost (Credit) $ 2.1
$ 2.3
$ (1.8 ) $ (1.2 )

8. BUSINESS SEGMENTS

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

AEP’s Reportable Segments

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 to serve ~~SSO~~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 ~~returns on equity.~~ROEs.

•Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved ~~returns on equity.~~ROEs.

Generation & Marketing

~~Competitive generation in ERCOT and PJM.~~•Contracted energy management services.

•Marketing, risk management and retail activities in ERCOT, MISO, PJM ~~SPP~~ and ~~MISO.~~SPP.

~~Contracted renewable energy investments and management services.~~•Competitive generation in PJM.

The remainder of AEP’s activities isare 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, income tax expense and other nonallocated costs.

AEP’s CODM makes operating decisions, allocates resources to and assesses performance based on these operating segments. AEP measures segment profit or loss based on net income (loss). Net income (loss) includes intercompany revenues and expenses that are eliminated on the Consolidated Financial Statements. In addition, direct interest expense and income taxes are included in net income (loss).

123

The tables below ~~present~~represent AEP’s reportable segment income statement information for the three months ended March 31, ~~2018~~2024 and ~~2017~~2023 and reportable segment balance sheet information as of March 31, ~~2018~~2024 and December 31, ~~2017.~~

Three Months Ended March 31, 2018
Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing Corporate and Other (a) Reconciling Adjustments Consolidated
(in millions)
Revenues from:

External Customers $ 2,381.5
$ 1,141.2
$ 41.1
$ 477.5
$ 7.0
$ —
$ 4,048.3
Other Operating Segments 26.5
21.2
164.4
27.6
17.0
(256.7 ) —
Total Revenues $ 2,408.0
$ 1,162.4
$ 205.5
$ 505.1
$ 24.0
$ (256.7 ) $ 4,048.3

Net Income (Loss) $ 232.8
$ 125.4
$ 104.8
$ 18.1
$ (24.4 ) $ —
$ 456.7

Three Months Ended March 31, 2017
Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing Corporate and Other (a) Reconciling Adjustments Consolidated
(in millions)
Revenues from:
��

External Customers $ 2,269.8
$ 1,066.4
$ 27.7
$ 558.8
$ 10.6
$ —
$ 3,933.3
Other Operating Segments 20.6
20.0
128.4
32.6
15.9
(217.5 ) —
Total Revenues $ 2,290.4
$ 1,086.4
$ 156.1
$ 591.4
$ 26.5
$ (217.5 ) $ 3,933.3

Net Income (Loss) $ 220.5
$ 119.1
$ 72.8
$ 186.2
$ (4.4 ) $ —
$ 594.2

March 31, 2018
Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing Corporate and Other (a) Reconciling
Adjustments Consolidated
(in millions)
Total Property, Plant and Equipment $ 43,749.8
$ 16,790.4
$ 7,446.6
$ 786.9
$ 377.7
$ (355.1 ) (b) $ 68,796.3
Accumulated Depreciation and Amortization 13,355.3
3,809.8
200.1
70.1
182.9
(187.0 ) (b) 17,431.2
Total Property Plant and Equipment - Net $ 30,394.5
$ 12,980.6
$ 7,246.5
$ 716.8
$ 194.8
$ (168.1 ) (b) $ 51,365.1

Total Assets $ 37,913.3
$ 16,272.6
$ 8,340.5
$ 2,123.7
$ 4,552.9
(c) $ (3,593.5 ) (b) (d) $ 65,609.5

Long-term Debt Due Within One Year:
Nonaffiliated $ 1,893.7
$ 670.6
$ 50.0
$ 0.1
$ 1.7
$ —
$ 2,616.1

Long-term Debt:
Affiliated 50.0
—
—
32.2
—
(82.2 ) —
Nonaffiliated 9,969.2
4,972.4
2,635.0
(0.3 ) 1,268.6
—
18,844.9

Total Long-term Debt $ 11,912.9
$ 5,643.0
$ 2,685.0
$ 32.0
$ 1,270.3
$ (82.2 ) $ 21,461.0

December 31, 2017
Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing Corporate and Other (a) Reconciling
Adjustments Consolidated
(in millions)
Total Property, Plant and Equipment $ 43,294.4
$ 16,371.2
$ 7,110.2
$ 644.6
$ 374.5
$ (366.4 ) (b) $ 67,428.5
Accumulated Depreciation and Amortization 13,153.4
3,768.3
176.6
75.0
180.6
(186.9 ) (b) 17,167.0
Total Property Plant and Equipment - Net $ 30,141.0
$ 12,602.9
$ 6,933.6
$ 569.6
$ 193.9
$ (179.5 ) (b) $ 50,261.5

Total Assets $ 37,579.7
$ 16,060.7
$ 8,141.8
$ 2,009.8
$ 3,959.1
(c) $ (3,022.0 ) (b) (d) $ 64,729.1

Long-term Debt Due Within One Year:
Nonaffiliated $ 1,038.1
$ 663.1
$ 50.0
$ —
$ 2.5
$ —
$ 1,753.7

Long-term Debt:
Affiliated 50.0
—
—
32.2
—
(82.2 ) —
Nonaffiliated 10,801.4
4,705.4
2,631.3
(0.3 ) 1,281.8
—
19,419.6

Total Long-term Debt $ 11,889.5
$ 5,368.5
$ 2,681.3
$ 31.9
$ 1,284.3
$ (82.2 ) $ 21,173.3

2023.

~~(a)~~

Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.


~~(b)~~			~~Includes eliminations due to an intercompany capital lease.~~

~~(c)~~

~~Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies.~~

~~(d)~~

~~Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable.~~


	Three Months Ended March 31, 2024
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other (a)		Reconciling Adjustments			Consolidated
	(in millions)
Revenues from:
External Customers	$	2,901.2	$	1,483.2	$	110.5	$	515.9	$	14.9	$	—		$	5,025.7
Other Operating Segments	46.7		7.0		386.8		47.6		37.9		(526.0)		(b)	—
Total Revenues	$	2,947.9	$	1,490.2	$	497.3	$	563.5	$	52.8	$	(526.0)		$	5,025.7



Net Income (Loss)	$	562.3	$	150.3	$	209.8	$	137.6	$	(54.3)	$	—		$	1,005.7

	Three Months Ended March 31, 2023
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other (a)		Reconciling Adjustments			Consolidated
	(in millions)
Revenues from:
External Customers	$	2,816.3	$	1,455.3	$	90.1	$	326.9	$	2.3	$	—		$	4,690.9
Other Operating Segments	41.5		8.9		365.4		0.1		27.8		(443.7)		(b)	—
Total Revenues	$	2,857.8	$	1,464.2	$	455.5	$	327.0	$	30.1	$	(443.7)		$	4,690.9



Net Income (Loss)	$	262.2	$	125.7	$	182.4	$	(156.4)	$	(13.5)	$	—		$	400.4


	March 31, 2024
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other (a)			Reconciling Adjustments			Consolidated
	(in millions)





Total Assets	$	52,379.2	$	25,283.4	$	17,067.4	$	2,257.5	$	5,164.3	(c)	$	(4,407.2)	(d)	$	97,744.6



	December 31, 2023
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other (a)			Reconciling Adjustments			Consolidated
	(in millions)






Total Assets	$	51,802.1	$	24,838.4	$	16,575.6	$	2,598.5	$	5,194.0	(c)	$	(4,324.6)	(d)	$	96,684.0

(a)Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and other nonallocated costs.

(b)Represents inter-segment revenues.

(c)Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies.

(d)Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable.

Registrant Subsidiaries’ Reportable Segments (Applies to all Registrant Subsidiaries except AEPTCo)

The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an integrated electricity transmission and distribution business for AEP Texas and OPCo. Other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.

124

AEPTCo’s Reportable Segments

AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric ~~utilities (State Transcos).~~utilities. The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting.” The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the RTOs in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and provide service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by the FERC and earn revenues through tariff rates charged for the use of their electric transmission systems.

AEPTCo’s ~~Chief Operating Decision Maker~~CODM makes operating decisions, allocates resources to and assesses performance based on these operating segments. The ~~seven~~ State Transcos operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities.

The tables below present AEPTCo’s reportable segment income statement information for the three months ended March 31, ~~2018~~2024 and ~~2017~~2023 and reportable segment balance sheet information as of March 31, ~~2018~~2024 and December 31, ~~2017.~~2023.


	Three Months Ended March 31, 2024
	State Transcos		AEPTCo Parent			Reconciling Adjustments		AEPTCo Consolidated
	(in millions)
Revenues from:
External Customers	$	97.0	$	—		$	—	$	97.0
Sales to AEP Affiliates	383.4		—			—		383.4
Other Revenues	2.4		—			—		2.4
Total Revenues	$	482.8	$	—		$	—	$	482.8

Net Income (Loss)	$	181.7	$	(0.5)	(a)	$	—	$	181.2

	Three Months Ended March 31, 2023
	State Transcos		AEPTCo Parent			Reconciling Adjustments		AEPTCo Consolidated
	(in millions)
Revenues from:
External Customers	$	89.0	$	—		$	—	$	89.0
Sales to AEP Affiliates	352.6		—			—		352.6
Total Revenues	$	441.6	$	—		$	—	$	441.6

Net Income	$	161.6	$	1.1	(a)	$	—	$	162.7


































	March 31, 2024
	State Transcos		AEPTCo Parent			Reconciling Adjustments			AEPTCo Consolidated
	(in millions)






Total Assets	$	15,609.4	$	5,949.9	(b)	$	(6,000.3)	(c)	$	15,559.0



	December 31, 2023
	State Transcos		AEPTCo Parent			Reconciling Adjustments			AEPTCo Consolidated
	(in millions)






Total Assets	$	15,120.6	$	5,486.6	(b)	$	(5,534.7)	(c)	$	15,072.5

(a)Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos.

(b)Primarily relates to Notes Receivable from the State Transcos.

(c)Primarily relates to the elimination of Notes Receivable from the State Transcos.

125

Three Months Ended March 31, 2018
State Transcos AEPTCo Parent Reconciling Adjustments
AEPTCo
Consolidated
(in millions)
Revenues from:
External Customers $ 31.3
$ —
$ —
$ 31.3
Sales to AEP Affiliates 162.1
—
—
162.1
Other Revenues 0.1
—
—
0.1
Total Revenues $ 193.5
$ —
$ —
$ 193.5

Interest Income $ 0.2
$ 25.0
$ (24.8 ) (a) $ 0.4
Interest Expense 19.9
24.8
(24.8 ) (a) 19.9
Income Tax Expense 22.3
0.2
—
22.5

Net Income (Loss) $ 86.0
$ (0.1 ) (b) $ —
$ 85.9

Three Months Ended March 31, 2017
State Transcos AEPTCo Parent Reconciling Adjustments
AEPTCo
Consolidated
(in millions)
Revenues from:
External Customers $ 19.2
$ —
$ —
$ 19.2
Sales to AEP Affiliates 133.4
—
—
133.4
Other Revenues 0.1
—
—
0.1
Total Revenues $ 152.7
$ —
$ —
$ 152.7

Interest Income $ 0.1
$ 19.1
$ (19.0 ) (a) $ 0.2
Interest Expense 15.8
19.2
(19.0 ) (a) 16.0
Income Tax Expense 28.4
0.1
—
28.5

Net Income $ 56.8
$ 0.2
(b) $ —
$ 57.0

March 31, 2018
State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
(in millions)
Total Transmission Property $ 7,108.0
$ —
$ —
$ 7,108.0
Accumulated Depreciation and Amortization 192.7
—
—
192.7
Total Transmission Property – Net $ 6,915.3
$ —
$ —
$ 6,915.3

Notes Receivable - Affiliated $ —
$ 2,550.7
$ (2,550.7 ) (c) $ —

Total Assets $ 7,220.0
$ 2,637.3
(d) $ (2,617.4 ) (e) $ 7,239.9

Total Long-term Debt $ 2,575.0
$ 2,550.7
$ (2,575.0 ) (c) $ 2,550.7

December 31, 2017
State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
(in millions)
Total Transmission Property $ 6,780.2
$ —
$ —
$ 6,780.2
Accumulated Depreciation and Amortization 170.4
—
—
170.4
Total Transmission Property – Net $ 6,609.8
$ —
$ —
$ 6,609.8

Notes Receivable - Affiliated $ —
$ 2,550.4
$ (2,550.4 ) (c) $ —

Total Assets $ 7,072.9
$ 2,590.1
(d) $ (2,594.9 ) (e) $ 7,068.1

Total Long-term Debt $ 2,575.0
$ 2,550.4
$ (2,575.0 ) (c) $ 2,550.4


~~(a)~~	~~Elimination of intercompany interest income/interest expense on affiliated debt arrangement.~~


~~(b)~~	~~Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos.~~


~~(c)~~	~~Elimination of intercompany debt.~~


~~(d)~~	~~Includes the elimination of AEPTCo Parent’s investments in State Transcos.~~


~~(e)~~	~~Primarily relates to the elimination of Notes Receivable from the State Transcos.~~

9. DERIVATIVES AND HEDGING

The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any ~~Derivative~~derivative and ~~Hedging~~hedging activity.

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

AEPSC is agent for and transacts on behalf of certain AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries.

The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk ~~credit risk~~ and ~~foreign currency exchange~~credit risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks.

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Risk Management Strategies

The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors.

The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts:

~~Notional Volume of Derivative Instruments~~

~~March 31, 2018~~


	Notional Volume of Derivative Instruments

	March 31, 2024														December 31, 2023
Primary Risk Exposure	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo		AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Commodity:
Power (MWhs)	233.5		—		7.0		3.4		2.2		2.2		1.6		246.8		—		16.8		5.9		2.2		4.1		2.9

Natural Gas (MMBtus)	176.8		—		43.0		—		—		49.0		19.7		151.6		—		37.3		—		—		34.9		17.9
Heating Oil and Gasoline (Gallons)	7.7		2.0		1.1		1.2		1.3		0.8		1.0		6.5		1.8		1.0		0.6		1.2		0.7		0.9
Interest Rate (USD)	$	69.6	$	—	$	—	$	—	$	—	$	—	$	—	$	80.1	$	—	$	—	$	—	$	—	$	—	$	—

Interest Rate on Long-term Debt (USD)	$	1,500.0	$	150.0	$	—	$	—	$	—	$	—	$	—	$	1,300.0	$	150.0	$	—	$	—	$	—	$	—	$	—

126

Primary Risk
Exposure

Unit of
Measure
AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Commodity:

Power MWhs 298.4
—
43.2
33.0
8.3
4.0
8.1
Coal Tons 1.2
—
—
1.2
—
—
—
Natural Gas MMBtus 78.2
—
6.2
3.7
—
—
18.0
Heating Oil and Gasoline Gallons 5.0
1.1
1.0
0.5
1.2
0.5
0.6
Interest Rate USD $ 49.8
$ —
$ —
$ —
$ —
$ —
$ —

Interest Rate and Foreign Currency USD $ 500.0
$ —
$ —
$ —
$ —
$ —
$ —

~~Notional Volume of Derivative Instruments~~

~~December 31, 2017~~

Primary Risk
Exposure

Unit of
Measure
AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Commodity:

Power MWhs 358.7
—
57.4
38.5
10.4
10.3
22.7
Coal Tons 2.0
—
—
2.0
—
—
—
Natural Gas MMBtus 53.7
—
1.1
0.7
—
—
18.3
Heating Oil and Gasoline Gallons 6.9
1.4
1.3
0.7
1.6
0.7
0.8
Interest Rate USD $ 50.7
$ —
$ —
$ —
$ —
$ —
$ —

Interest Rate and Foreign Currency USD $ 500.0
$ —
$ —
$ —
$ —
$ —
$ —

Fair Value Hedging Strategies (Applies to AEP)

Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a ~~floating rate.~~floating-rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges.

Cash Flow Hedging Strategies

The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk.

The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure.

At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure.

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes ~~supply~~ and ~~demand market data and~~other assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality.

Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts.

According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on ~~third party~~third-party contractual agreements and risk profiles. AEP netted cash collateral received from ~~third parties~~third-parties against short-term and long-term risk management assets in the amounts of $1$86 million and ~~$9.4~~$46 million as of March 31, ~~2018~~2024 and December 31, ~~2017,~~2023, respectively. ~~AEP~~There was no cash collateral received from third-parties netted against short-term and long-term risk management assets for the Registrant Subsidiaries as of March 31, 2024 and December 31, 2023. The amount of cash collateral paid to ~~third parties~~third-parties netted against short-term and long-term risk management liabilities in the amounts of $18 million and $9 million as of March 31, 2018 and December 31, 2017, respectively. The netted cash collateral from third parties against short-term and long-term risk management assets and netted cash collateral paid to third parties against short-term and long-term risk management liabilities werewas immaterial for the ~~other~~ Registrants as of March 31, ~~2018~~2024 and December 31, ~~2017.~~2023.

127

Location and Fair Value of Derivative Assets and Liabilities Recognized In the Balance Sheet

The following tables represent the gross fair value of the Registrants’ derivative activity on the balance ~~sheets:~~sheets. The derivative instruments are disclosed as gross. They are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” Unless shown as a separate line on the balance sheets due to materiality, Current Risk Management Assets are included in Prepayments and Other Current Assets, Long-term Risk Management Assets are included in Deferred Charges and Other Noncurrent Assets, Current Risk Management Liabilities are included in Other Current Liabilities and Long-term Risk Management Liabilities are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets.

~~AEP~~

~~Fair Value of Derivative Instruments~~

~~March 31, 2018~~


	March 31, 2024
	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
Assets:	(in millions)
Current Risk Management Assets
Risk Management Contracts - Commodity	$	436.2	$	0.2	$	9.9	$	15.5	$	0.1	$	8.5	$	5.5
Hedging Contracts - Commodity	35.4		—		—		—		—		—		—
Hedging Contracts - Interest Rate	8.3		2.3		—		—		—		—		—
Total Current Risk Management Assets	479.9		2.5		9.9		15.5		0.1		8.5		5.5

Long-term Risk Management Assets
Risk Management Contracts - Commodity	525.0		—		1.2		—		—		—		—
Hedging Contracts - Commodity	81.0		—		—		—		—		—		—
Hedging Contracts - Interest Rate	—		—		—		—		—		—		—
Total Long-term Risk Management Assets	606.0		—		1.2		—		—		—		—

Total Assets	$	1,085.9	$	2.5	$	11.1	$	15.5	$	0.1	$	8.5	$	5.5

Liabilities:
Current Risk Management Liabilities
Risk Management Contracts - Commodity	$	456.9	$	—	$	21.0	$	9.0	$	6.0	$	29.1	$	9.5
Hedging Contracts - Commodity	5.1		—		—		—		—		—		—
Hedging Contracts - Interest Rate	46.1		0.1		—		—		—		—		—
Total Current Risk Management Liabilities	508.1		0.1		21.0		9.0		6.0		29.1		9.5

Long-term Risk Management Liabilities
Risk Management Contracts - Commodity	430.0		—		3.3		—		35.0		2.8		1.8
Hedging Contracts - Commodity	0.6		—		—		—		—		—		—
Hedging Contracts - Interest Rate	70.4		—		—		—		—		—		—
Total Long-term Risk Management Liabilities	501.0		—		3.3		—		35.0		2.8		1.8

Total Liabilities	$	1,009.1	$	0.1	$	24.3	$	9.0	$	41.0	$	31.9	$	11.3

Total MTM Derivative Contract Net Assets (Liabilities) Recognized	$	76.8	$	2.4	$	(13.2)	$	6.5	$	(40.9)	$	(23.4)	$	(5.8)

128


			December 31, 2023
			December 31, 2023
			December 31, 2023
			AEP
			AEP
			AEP																		AEP Texas	APCo	I&M	OPCo	PSO	SWEPCo
Assets:
Current Risk Management Assets
Current Risk Management Assets
Current Risk Management Assets
Risk Management Contracts - Commodity
Risk Management Contracts - Commodity
Risk Management Contracts - Commodity
Hedging Contracts - Commodity
Hedging Contracts - Interest Rate
Total Current Risk Management Assets
	Risk Management Contracts		Hedging Contracts						Gross Amounts of Risk Management Assets/ Liabilities Recognized				Gross Amounts Offset in the Statement of Financial Position (b)				Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c)
Balance Sheet Location	Commodity (a)		Commodity (a)			Interest Rate (a)
Long-term Risk Management Assets
Long-term Risk Management Assets
Long-term Risk Management Assets
Risk Management Contracts - Commodity
Risk Management Contracts - Commodity
Risk Management Contracts - Commodity
Hedging Contracts - Commodity
Hedging Contracts - Interest Rate
Total Long-term Risk Management Assets
	(in millions)
Current Risk Management Assets	$	257.0	$	20.1		$	1.7				$	278.8			$	(189.2	)		$	89.6
Long-term Risk Management Assets	319.6		5.1			—			324.7				(53.5		)		271.2
Total Assets
Total Assets
Total Assets	576.6		25.2			1.7			603.5				(242.7		)		360.8

Liabilities:
Liabilities:
Liabilities:
Current Risk Management Liabilities	246.8		10.1			—			256.9				(199.8		)		57.1
Current Risk Management Liabilities
Current Risk Management Liabilities
Risk Management Contracts - Commodity
Risk Management Contracts - Commodity
Risk Management Contracts - Commodity
Hedging Contracts - Commodity
Hedging Contracts - Interest Rate
Total Current Risk Management Liabilities

Long-term Risk Management Liabilities	271.6		48.5			22.3			342.4				(59.7		)		282.7
Long-term Risk Management Liabilities
Long-term Risk Management Liabilities
Risk Management Contracts - Commodity
Risk Management Contracts - Commodity
Risk Management Contracts - Commodity
Hedging Contracts - Commodity
Hedging Contracts - Interest Rate
Total Long-term Risk Management Liabilities

Total Liabilities
Total Liabilities
Total Liabilities	518.4		58.6			22.3			599.3				(259.5		)		339.8

Total MTM Derivative Contract Net Assets (Liabilities)	$	58.2	$	(33.4	)	$	(20.6	)	$	4.2			$	16.8			$	21.0
Total MTM Derivative Contract Net Assets (Liabilities) Recognized
Total MTM Derivative Contract Net Assets (Liabilities) Recognized
Total MTM Derivative Contract Net Assets (Liabilities) Recognized

~~Fair Value of Derivative Instruments~~

~~December 31, 2017~~

129

Risk
Management
Contracts
Hedging Contracts
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized

Gross
Amounts
Offset in the
Statement of
Financial
Position (b)

Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a)
(in millions)
Current Risk Management Assets $ 389.0
$ 17.5
$ 2.5
$ 409.0
$ (282.8 ) $ 126.2
Long-term Risk Management Assets 300.9
6.3
—
307.2
(25.1 ) 282.1
Total Assets 689.9
23.8
2.5
716.2
(307.9 ) 408.3

Current Risk Management Liabilities 334.6
9.0
—
343.6
(282.0 ) 61.6
Long-term Risk Management Liabilities 280.6
58.3
8.6
347.5
(25.5 ) 322.0
Total Liabilities 615.2
67.3
8.6
691.1
(307.5 ) 383.6

Total MTM Derivative Contract Net Assets (Liabilities) $ 74.7
$ (43.5 ) $ (6.1 ) $ 25.1
$ (0.4 ) $ 24.7
Offsetting Assets and Liabilities

The following tables show the net amounts of assets and liabilities presented on the balance sheets. The gross amounts offset include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with accounting guidance for “Derivatives and Hedging.” All derivative contracts subject to a master netting arrangement or similar agreement are offset on the balance sheets.


	March 31, 2024
	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
Assets:			(in millions)
Current Risk Management Assets
Gross Amounts Recognized	$	479.9	$	2.5	$	9.9	$	15.5	$	0.1	$	8.5	$	5.5
Gross Amounts Offset	(327.2)		—		(1.2)		(4.3)		—		(0.6)		(0.2)
Net Amounts Presented	152.7		2.5		8.7		11.2		0.1		7.9		5.3

Long-term Risk Management Assets
Gross Amounts Recognized	606.0		—		1.2		—		—		—		—
Gross Amounts Offset	(291.6)		—		(1.2)		—		—		—		—
Net Amounts Presented	314.4		—		—		—		—		—		—

Total Assets	$	467.1	$	2.5	$	8.7	$	11.2	$	0.1	$	7.9	$	5.3

Liabilities:
Current Risk Management Liabilities
Gross Amounts Recognized	$	508.1	$	0.1	$	21.0	$	9.0	$	6.0	$	29.1	$	9.5
Gross Amounts Offset	(323.7)		—		(2.6)		(8.3)		—		(0.6)		(0.2)
Net Amounts Presented	184.4		0.1		18.4		0.7		6.0		28.5		9.3

Long-term Risk Management Liabilities
Gross Amounts Recognized	501.0		—		3.3		—		35.0		2.8		1.8
Gross Amounts Offset	(221.5)		—		(1.2)		—		—		—		—
Net Amounts Presented	279.5		—		2.1		—		35.0		2.8		1.8

Total Liabilities	$	463.9	$	0.1	$	20.5	$	0.7	$	41.0	$	31.3	$	11.1

Total MTM Derivative Contract Net Assets (Liabilities)	$	3.2	$	2.4	$	(11.8)	$	10.5	$	(40.9)	$	(23.4)	$	(5.8)

~~AEP Texas~~

~~Fair Value of Derivative Instruments~~

~~March 31, 2018~~


	December 31, 2023
	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
Assets:			(in millions)
Current Risk Management Assets
Gross Amounts Recognized	$	611.8	$	—	$	24.6	$	30.1	$	—	$	19.7	$	12.0
Gross Amounts Offset	(394.3)		—		(2.2)		(2.3)		—		(0.7)		(0.4)
Net Amounts Presented	217.5		—		22.4		27.8		—		19.0		11.6

Long-term Risk Management Assets
Gross Amounts Recognized	555.6		—		0.3		12.0		—		—		0.5
Gross Amounts Offset	(234.4)		—		(0.3)		(0.2)		—		—		(0.5)
Net Amounts Presented	321.2		—		—		11.8		—		—		—

Total Assets	$	538.7	$	—	$	22.4	$	39.6	$	—	$	19.0	$	11.6

Liabilities:
Current Risk Management Liabilities
Gross Amounts Recognized	$	646.7	$	2.9	$	18.5	$	5.4	$	6.9	$	29.7	$	14.9
Gross Amounts Offset	(417.1)		(0.2)		(2.6)		(3.4)		(0.1)		(0.8)		(0.5)
Net Amounts Presented	229.6		2.7		15.9		2.0		6.8		28.9		14.4

Long-term Risk Management Liabilities
Gross Amounts Recognized	436.7		—		6.9		0.2		43.9		1.0		1.7
Gross Amounts Offset	(194.9)		—		(0.3)		(0.2)		—		—		(0.5)
Net Amounts Presented	241.8		—		6.6		—		43.9		1.0		1.2

Total Liabilities	$	471.4	$	2.7	$	22.5	$	2.0	$	50.7	$	29.9	$	15.6

Total MTM Derivative Contract Net Assets (Liabilities)	$	67.3	$	(2.7)	$	(0.1)	$	37.6	$	(50.7)	$	(10.9)	$	(4.0)

130

Balance Sheet Location
Risk Management
Contracts -
Commodity (a)

Gross Amounts Offset in the Statement of
Financial Position (b)

Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
(in millions)
Current Risk Management Assets $ 0.4
$ (0.1 ) $ 0.3
Long-term Risk Management Assets —
—
—
Total Assets 0.4
(0.1 ) 0.3

Current Risk Management Liabilities —
—
—
Long-term Risk Management Liabilities —
—
—
Total Liabilities —
—
—

Total MTM Derivative Contract Net Assets (Liabilities) $ 0.4
$ (0.1 ) $ 0.3

~~Fair Value of Derivative Instruments~~

~~December 31, 2017~~

Balance Sheet Location
Risk Management
Contracts -
Commodity (a)

Gross Amounts Offset in the Statement of
Financial Position (b)

Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
(in millions)
Current Risk Management Assets $ 0.5
$ —
$ 0.5
Long-term Risk Management Assets —
—
—
Total Assets 0.5
—
0.5

Current Risk Management Liabilities —
—
—
Long-term Risk Management Liabilities —
—
—
Total Liabilities —
—
—

Total MTM Derivative Contract Net Assets $ 0.5
$ —
$ 0.5

~~APCo~~

~~Fair Value of Derivative Instruments~~

~~March 31, 2018~~

Balance Sheet Location
Risk Management
Contracts -
Commodity (a)

Gross Amounts Offset in the Statement of
Financial Position (b)

Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
(in millions)
Current Risk Management Assets $ 35.8
$ (27.8 ) $ 8.0
Long-term Risk Management Assets 11.2
(8.6 ) 2.6
Total Assets 47.0
(36.4 ) 10.6

Current Risk Management Liabilities 28.4
(27.8 ) 0.6
Long-term Risk Management Liabilities 9.1
(8.7 ) 0.4
Total Liabilities 37.5
(36.5 ) 1.0

Total MTM Derivative Contract Net Assets $ 9.5
$ 0.1
$ 9.6

~~Fair Value of Derivative Instruments~~

~~December 31, 2017~~

Balance Sheet Location
Risk Management
Contracts -
Commodity (a)

Gross Amounts Offset in the Statement of
Financial Position (b)

Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
(in millions)
Current Risk Management Assets $ 75.6
$ (50.7 ) $ 24.9
Long-term Risk Management Assets 2.4
(1.3 ) 1.1
Total Assets 78.0
(52.0 ) 26.0

Current Risk Management Liabilities 50.6
(49.3 ) 1.3
Long-term Risk Management Liabilities 1.4
(1.2 ) 0.2
Total Liabilities 52.0
(50.5 ) 1.5

Total MTM Derivative Contract Net Assets (Liabilities) $ 26.0
$ (1.5 ) $ 24.5

~~I&M~~

~~Fair Value of Derivative Instruments~~

~~March 31, 2018~~

Balance Sheet Location
Risk Management
Contracts -
Commodity (a)

Gross Amounts Offset in the Statement of
Financial Position (b)

Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
(in millions)
Current Risk Management Assets $ 24.0
$ (20.7 ) $ 3.3
Long-term Risk Management Assets 8.0
(6.0 ) 2.0
Total Assets 32.0
(26.7 ) 5.3

Current Risk Management Liabilities 24.6
(20.8 ) 3.8
Long-term Risk Management Liabilities 6.1
(5.9 ) 0.2
Total Liabilities 30.7
(26.7 ) 4.0

Total MTM Derivative Contract Net Assets $ 1.3
$ —
$ 1.3

~~Fair Value of Derivative Instruments~~

~~December 31, 2017~~

Balance Sheet Location
Risk Management
Contracts -
Commodity (a)

Gross Amounts Offset in the Statement of
Financial Position (b)

Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
(in millions)
Current Risk Management Assets $ 47.2
$ (39.6 ) $ 7.6
Long-term Risk Management Assets 1.6
(0.9 ) 0.7
Total Assets 48.8
(40.5 ) 8.3

Current Risk Management Liabilities 48.5
(45.0 ) 3.5
Long-term Risk Management Liabilities 0.9
(0.8 ) 0.1
Total Liabilities 49.4
(45.8 ) 3.6

Total MTM Derivative Contract Net Assets (Liabilities) $ (0.6 ) $ 5.3
$ 4.7

~~OPCo~~

~~Fair Value of Derivative Instruments~~

~~March 31, 2018~~

Balance Sheet Location
Risk Management
Contracts -
Commodity (a)

Gross Amounts Offset in the Statement of
Financial Position (b)

Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
(in millions)
Current Risk Management Assets $ 0.5
$ (0.1 ) $ 0.4
Long-term Risk Management Assets —
—
—
Total Assets 0.5
(0.1 ) 0.4

Current Risk Management Liabilities 5.3
—
5.3
Long-term Risk Management Liabilities 93.2
—
93.2
Total Liabilities 98.5
—
98.5

Total MTM Derivative Contract Net Liabilities $ (98.0 ) $ (0.1 ) $ (98.1 )

~~Fair Value of Derivative Instruments~~

~~December 31, 2017~~

Balance Sheet Location
Risk Management
Contracts -
Commodity (a)

Gross Amounts Offset in the Statement of
Financial Position (b)

Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
(in millions)
Current Risk Management Assets $ 0.6
$ —
$ 0.6
Long-term Risk Management Assets —
—
—
Total Assets 0.6
—
0.6

Current Risk Management Liabilities 6.4
—
6.4
Long-term Risk Management Liabilities 126.0
—
126.0
Total Liabilities 132.4
—
132.4

Total MTM Derivative Contract Net Liabilities $ (131.8 ) $ —
$ (131.8 )

~~PSO~~

~~Fair Value of Derivative Instruments~~

~~March 31, 2018~~

Balance Sheet Location
Risk Management
Contracts -
Commodity (a)

Gross Amounts Offset in the Statement of
Financial Position (b)

Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
(in millions)
Current Risk Management Assets $ 2.9
$ —
$ 2.9
Long-term Risk Management Assets —
—
—
Total Assets 2.9
—
2.9

Current Risk Management Liabilities —
—
—
Long-term Risk Management Liabilities —
—
—
Total Liabilities —
—
—

Total MTM Derivative Contract Net Assets $ 2.9
$ —
$ 2.9

~~Fair Value of Derivative Instruments~~

~~December 31, 2017~~

Balance Sheet Location
Risk Management
Contracts -
Commodity (a)

Gross Amounts Offset in the Statement of
Financial Position (b)

Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
(in millions)
Current Risk Management Assets $ 6.6
$ (0.2 ) $ 6.4
Long-term Risk Management Assets —
—
—
Total Assets 6.6
(0.2 ) 6.4

Current Risk Management Liabilities 0.2
(0.2 ) —
Long-term Risk Management Liabilities —
—
—
Total Liabilities 0.2
(0.2 ) —

Total MTM Derivative Contract Net Assets $ 6.4
$ —
$ 6.4

~~SWEPCo~~

~~Fair Value of Derivative Instruments~~

~~March 31, 2018~~

Balance Sheet Location
Risk Management
Contracts -
Commodity (a)

Gross Amounts Offset in the Statement of
Financial Position (b)

Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
(in millions)
Current Risk Management Assets $ 2.8
$ (1.1 ) $ 1.7
Long-term Risk Management Assets —
—
—
Total Assets 2.8
(1.1 ) 1.7

Current Risk Management Liabilities 1.2
(1.1 ) 0.1
Long-term Risk Management Liabilities 0.5
—
0.5
Total Liabilities 1.7
(1.1 ) 0.6

Total MTM Derivative Contract Net Assets $ 1.1
$ —
$ 1.1

~~Fair Value of Derivative Instruments~~

~~December 31, 2017~~

Balance Sheet Location
Risk Management
Contracts -
Commodity (a)

Gross Amounts Offset in the Statement of
Financial Position (b)

Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
(in millions)
Current Risk Management Assets $ 7.0
$ (0.6 ) $ 6.4
Long-term Risk Management Assets —
—
—
Total Assets 7.0
(0.6 ) 6.4

Current Risk Management Liabilities 0.8
(0.6 ) 0.2
Long-term Risk Management Liabilities —
—
—
Total Liabilities 0.8
(0.6 ) 0.2

Total MTM Derivative Contract Net Assets $ 6.2
$ —
$ 6.2


~~(a)~~	Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”


~~(b)~~	~~Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”~~


~~(c)~~	~~There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.~~

The tables below present the Registrants’ ~~activity~~amount of ~~derivative~~gain (loss) recognized on risk management contracts:

Amount of Gain (Loss) Recognized on

Risk Management Contracts

~~Three Months Ended March 31, 2018~~



	Three Months Ended March 31, 2024
Location of Gain (Loss)	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Vertically Integrated Utilities Revenues	$	(25.7)	$	—	$	—	$	—	$	—	$	—	$	—

Generation & Marketing Revenues	(44.7)		—		—		—		—		—		—
Electric Generation, Transmission and Distribution Revenues	—		—		0.1		(25.8)		—		—		—


Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	1.0		—		0.9		—		—		—		—

Maintenance	0.1		—		—		—		—		—		—
Regulatory Assets (a)	13.5		0.2		(0.1)		(1.6)		8.6		(1.2)		4.9
Regulatory Liabilities (a)	52.7		0.2		13.1		2.2		—		18.3		15.0
Total Gain (Loss) on Risk Management Contracts	$	(3.1)	$	0.4	$	14.0	$	(25.2)	$	8.6	$	17.1	$	19.9


				Three Months Ended March 31, 2023
				Three Months Ended March 31, 2023
				Three Months Ended March 31, 2023
Location of Gain (Loss)	AEP			AEP Texas			APCo			I&M			OPCo		PSO		SWEPCo			Location of Gain (Loss)	AEP	AEP Texas	APCo	I&M	OPCo		PSO	SWEPCo
			(in millions)																							(in millions)
Vertically Integrated Utilities Revenues
	(in millions)
Vertically Integrated Utilities Revenues	$	(5.5	)	$	—		$	—		$	—		$	—	$	—	$	—
Generation & Marketing Revenues
Generation & Marketing Revenues
Generation & Marketing Revenues	(15.1		)	—			—			—			—		—		—
Electric Generation, Transmission and Distribution Revenues	—			—			(0.3		)	(5.1		)	—		—		—
Purchased Electricity for Resale	4.9			—			4.6			0.2			—		—		—
Other Operation	0.3			0.1			—			—			0.1		—		—

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation

Maintenance
Maintenance
Maintenance	0.4			0.1			0.1			—			0.1		—		—
Regulatory Assets (a)	37.3			—			—			6.2			31.4		—		(0.3		)
Regulatory Liabilities (a)	87.0			(0.1		)	64.1			0.2			—		12.1		(0.8		)
Total Gain (Loss) on Risk Management Contracts	$	109.3		$	0.1		$	68.5		$	1.5		$	31.6	$	12.1	$	(1.1	)

~~Amount of Gain (Loss) Recognized~~(a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

~~Risk Management Contracts~~

~~Three Months Ended March 31, 2017~~

Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Vertically Integrated Utilities Revenues $ 5.5
$ —
$ —
$ —
$ —
$ —
$ —
Generation & Marketing Revenues 10.5
—
—
—
—
—
—
Electric Generation, Transmission and Distribution Revenues —
—
0.4
5.2
—
—
0.1
Purchased Electricity for Resale 2.4
—
0.8
0.1
—
—
—
Other Operation 0.2
—
—
—
—
—
—
Maintenance 0.2
—
—
—
—
—
—
Regulatory Assets (a) (14.9 ) —
(5.8 ) (0.2 ) (8.6 ) —
(0.2 )
Regulatory Liabilities (a) 25.2
(0.2 ) 10.9
6.8
—
2.4
4.6
Total Gain (Loss) on Risk Management Contracts $ 29.1
$ (0.2 ) $ 6.3
$ 11.9
$ (8.6 ) $ 2.4
$ 4.5


~~(a)~~	~~Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.~~

Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis.

The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge.

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same ~~expense~~ line item on the statements of income as that of the associated ~~risk.~~risk being hedged. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”

131

Accounting for Fair Value Hedging Strategies (Applies to AEP)

For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts ~~Net Income~~net income during the period of change.

AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income.

The following table shows the ~~results~~impacts recognized on the balance sheets related to the hedged items in fair value hedging relationships:


	Carrying Amount of the Hedged Liabilities				Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Liabilities
	March 31, 2024		December 31, 2023		March 31, 2024		December 31, 2023
	(in millions)
Long-term Debt (a) (b)	$	(860.2)	$	(878.2)	$	86.7	$	68.4

(a)Amounts included within Noncurrent Liabilities line item Long-term Debt on the Balance Sheet.

(b)Amounts include $(28) million and $(30) million as of ~~hedging gains (losses):~~

Three Months Ended March 31,
2018 2017
(in millions)
Loss on Fair Value Hedging Instruments $ (14.5 ) $ (0.5 )
Gain on Fair Value Portion of Long-term Debt 14.2
0.5

~~During the three months ended~~ March 31, ~~2018~~2024 and ~~2017,~~December 31, 2023, respectively, for the fair value hedge ~~ineffectiveness was immaterial.~~adjustment of hedged debt obligations for which hedge accounting has been discontinued.

The pretax effects of fair value hedge accounting on income were as follows:


	Three Months Ended March 31,
	2024		2023
	(in millions)
Gain (Loss) on Interest Rate Contracts:
Fair Value Hedging Instruments (a)	$	(16.4)	$	6.9
Fair Value Portion of Long-term Debt (a)	16.4		(6.9)

(a)Gain (Loss) is included in Interest Expense on the statements of income.

Accounting for Cash Flow Hedging Strategies (Applies to AEP, AEP Texas, APCo, I&M, PSO and SWEPCo)

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the ~~effective portion of the~~ gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable.net income.

Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity, Fuel and Other Consumables Used for ~~Resale~~Electric Generation on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three months ended March 31, ~~2018~~2024 and ~~2017,~~2023, AEP applied cash flow hedging to outstanding power ~~derivatives. During the three months ended March 31, 2018~~derivatives and ~~2017,~~ the Registrant Subsidiaries did ~~not apply cash flow hedging to outstanding power derivatives.~~not.

The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three months ended March 31, ~~2018~~2024, AEP and ~~2017, the Registrants did not apply~~AEP Texas applied cash flow hedging to outstanding interest rate ~~derivatives.~~

~~The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on~~derivatives and the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships.other Registrant Subsidiaries did not. During the three months ended March 31, ~~2018~~2023, AEP, AEP Texas, I&M, PSO and ~~2017, the Registrants did not apply~~SWEPCo applied cash flow hedging to ~~any~~ outstanding ~~foreign currency derivatives.~~interest rate derivatives and the other Registrant Subsidiaries did not.

~~During the three months ended March 31, 2018 and 2017, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.~~

For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 - Comprehensive Income.

132

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were:

~~Impact of Cash Flow Hedges on AEP’s Balance Sheets~~


	Impact of Cash Flow Hedges on the Registrants’ Balance Sheets

	March 31, 2024								December 31, 2023
					Portion Expected to								Portion Expected to
	AOCI				be Reclassed to				AOCI				be Reclassed to
	Gain (Loss)				Net Income During				Gain (Loss)				Net Income During
	Net of Tax				the Next Twelve Months				Net of Tax				the Next Twelve Months
	Commodity		Interest Rate		Commodity		Interest Rate		Commodity		Interest Rate		Commodity		Interest Rate
			(in millions)
AEP	$	87.2	$	3.4	$	24.0	$	3.6	$	104.9	$	(8.1)	$	38.3	$	3.2
AEP Texas	—		4.4		—		0.5		—		0.5		—		0.2
APCo	—		5.7		—		0.8		—		5.9		—		0.8
I&M	—		(5.4)		—		(0.4)		—		(5.5)		—		(0.4)

PSO	—		(0.2)		—		—		—		(0.2)		—		—
SWEPCo	—		1.2		—		0.3		—		1.3		—		0.3

March 31, 2018 December 31, 2017
Commodity Interest Rate Commodity Interest Rate
(in millions)
Hedging Assets (a) $ 25.5
$ —
$ 22.0
$ —
Hedging Liabilities (a) 58.9
—
65.5
—
AOCI Loss Net of Tax (32.0 ) (15.5 ) (28.4 ) (13.0 )
Portion Expected to be Reclassified to Net Income During the Next Twelve Months 3.1
(1.0 ) 5.5
(0.8 )


~~(a)~~	~~Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets.~~

As of March 31, ~~2018~~2024 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is ~~117~~84 months.

~~Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets~~

March 31, 2018 December 31, 2017
Interest Rate
Company
AOCI Gain (Loss)
Net of Tax

Expected to be Reclassified to
Net Income During the Next
Twelve Months

AOCI Gain (Loss)
Net of Tax

Expected to be Reclassified to
Net Income During the Next
Twelve Months
(in millions)
AEP Texas $ (5.2 ) —
$ (1.1 ) $ (4.5 ) $ (0.9 )
APCo 2.5
0.9
2.2
0.7
I&M (12.7 ) (1.6 ) (10.7 ) (1.3 )
OPCo 2.0
1.3
1.9
1.1
PSO 2.9
1.0
2.6
0.8
SWEPCo (6.9 ) (1.7 ) (6.0 ) (1.4 )

The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.

Credit Risk

Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses ~~Moody’s Investors Service Inc., S&P Global Inc.~~credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. ~~A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold.~~ The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination

and liquidation of all positions in the event of a default including a failure or inability to post collateral when required.

Credit-Risk-Related Contingent Features

~~Collateral Triggering Events~~

Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo)

A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. The Registrants have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. The Registrants had ~~immaterial~~no derivative contracts with collateral triggering events in a net liability position as of March 31, ~~2018~~2024 and December 31, ~~2017,~~2023.

133

Cross-Acceleration Triggers

Certain interest rate derivative contracts contain cross-acceleration provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-acceleration provisions could be triggered if there was a non-performance event by the Registrants under any of their outstanding debt of at least $50 million and the lender on that debt has accelerated the entire repayment obligation. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-acceleration provisions in contracts. AEP had derivative contracts with cross-acceleration provisions in a net liability position of $116 million and $107 million and no cash collateral posted as of March 31, 2024 and December 31, 2023, respectively. If a cross-acceleration provision would have been triggered, settlement at fair value would have been required. The Registrant Subsidiaries’ derivative contracts with cross-acceleration provisions outstanding as of March 31, 2024 and December 31, 2023 were not material.

Cross-Default Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo)

In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a ~~third party~~third-party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. ~~The following table represents: (a) the fair value of these~~AEP had derivative ~~liabilities subject to~~contracts with cross-default provisions ~~prior to consideration~~in a net liability position of ~~contractual netting arrangements, (b) the amount that the exposure has been reduced by~~$235 million and $242 million and no cash collateral posted as of March 31, 2024 and ~~(c) if~~December 31, 2023, respectively, after considering contractual netting arrangements. If a cross-default provision would have been triggered, ~~the~~ settlement ~~amount that~~at fair value would ~~be required after considering contractual netting arrangements:~~

AEP

Liabilities for
Contracts with Cross
Default Provisions
Prior to Contractual
Netting Arrangements

Amount of Cash
Collateral Posted

Additional
Settlement
Liability if Cross
Default Provision
is Triggered
(in millions)
March 31, 2018 $ 272.7
$ 1.0
$ 202.4
December 31, 2017 243.6
1.3
223.1

~~Amounts for~~have been required. APCo, ~~I&M~~PSO and SWEPCo ~~are immaterial~~had derivative contracts with cross-default provisions in a net liability position of $16 million, $31 million and $10 million, respectively, and no cash collateral posted as of March 31, ~~2018~~2024. APCo, PSO and SWEPCo had derivative contracts with cross-default provisions in a net liability position of $22 million, $29 million and $15 million, respectively, and no cash collateral posted as of December 31, 2023. The other Registrant Subsidiaries had no derivative contracts with cross-default provisions outstanding as of March 31, 2024 and December 31, ~~2017, respectively.~~2023.

134

10. FAIR VALUE MEASUREMENTS

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

Fair Value Hierarchy and Valuation Techniques

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.

For commercial activities, ~~exchange traded~~exchange-traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as ~~exchange traded contracts~~exchange-traded derivatives where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require ~~nonmarket based~~nonmarket-based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility.

AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the ~~benefit plan and~~ nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. ~~The trustee uses multiple pricing vendors for the assets held in the trusts.~~

Assets in the nuclear trusts, cash and cash equivalents, other temporary investments ~~and~~ restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and ~~domestic~~ equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.

Fair Value Measurements of Long-term Debt (Applies to all Registrants)

The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The fair value of AEP’s Equity Units (Level 1) are valued based on publicly traded securities issued by AEP.

135

The book values and fair values of Long-term Debt are summarized in the following table:


	March 31, 2024				December 31, 2023
Company	Book Value		Fair Value		Book Value		Fair Value
	(in millions)
AEP	$	39,835.9	$	36,392.2	$	40,143.2	$	37,325.7
AEP Texas	5,878.7		5,289.7		5,889.8		5,400.7
AEPTCo	5,860.7		5,066.3		5,414.4		4,796.9
APCo	5,670.9		5,370.8		5,588.3		5,390.1
I&M	3,478.5		3,182.3		3,499.4		3,291.6
OPCo	3,367.4		2,912.1		3,366.8		2,992.1
PSO	2,384.9		2,130.2		2,384.6		2,154.3
SWEPCo	3,647.6		3,170.6		3,646.9		3,209.7

March 31, 2018 December 31, 2017
Company Book Value Fair Value Book Value Fair Value
(in millions)
AEP $ 21,461.0
$ 23,039.8
$ 21,173.3
$ 23,649.6
AEP Texas 3,553.3
3,818.3
3,649.3
3,964.8
AEPTCo 2,550.7
2,620.6
2,550.4
2,782.9
APCo 3,969.3
4,532.0
3,980.1
4,782.6
I&M 2,717.2
2,869.5
2,745.1
3,014.7
OPCo 2,089.7
2,367.9
1,719.3
2,064.3
PSO 1,286.7
1,400.3
1,286.5
1,457.1
SWEPCo 2,503.7
2,587.3
2,441.9
2,645.9

Fair Value Measurements of Other Temporary Investments and Restricted Cash (Applies to AEP)

Other Temporary Investments include marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS.

The following is a summary of Other Temporary ~~Investments:~~Investments and Restricted Cash:


	March 31, 2024
			Gross		Gross
			Unrealized		Unrealized		Fair
Other Temporary Investments and Restricted Cash	Cost		Gains		Losses		Value
	(in millions)
Restricted Cash (a)	$	51.1	$	—	$	—	$	51.1
Other Cash Deposits	15.4		—		—		15.4
Fixed Income Securities – Mutual Funds (b)	164.7		—		(6.8)		157.9
Equity Securities – Mutual Funds	14.7		29.0		—		43.7
Total Other Temporary Investments and Restricted Cash	$	245.9	$	29.0	$	(6.8)	$	268.1


	December 31, 2023
			Gross		Gross
			Unrealized		Unrealized		Fair
Other Temporary Investments and Restricted Cash	Cost		Gains		Losses		Value
	(in millions)
Restricted Cash (a)	$	48.9	$	—	$	—	$	48.9
Other Cash Deposits	13.9		—		—		13.9
Fixed Income Securities – Mutual Funds (b)	165.9		—		(6.2)		159.7
Equity Securities – Mutual Funds	14.8		25.9		—		40.7
Total Other Temporary Investments and Restricted Cash	$	243.5	$	25.9	$	(6.2)	$	263.2

(a)Primarily represents amounts held for the repayment of debt.

(b)Primarily short and intermediate maturities which may be sold and do not contain maturity dates.

136

March 31, 2018
Other Temporary Investments Cost
Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair
Value
(in millions)
Restricted Cash and Other Cash Deposits (a) $ 162.0
$ —
$ —
$ 162.0
Fixed Income Securities – Mutual Funds (b) 104.8
—
(2.2 ) 102.6
Equity Securities – Mutual Funds
17.2
19.2
—
36.4
Total Other Temporary Investments $ 284.0
$ 19.2
$ (2.2 ) $ 301.0

December 31, 2017
Other Temporary Investments Cost
Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair
Value
(in millions)
Restricted Cash and Other Cash Deposits (a) $ 220.1
$ —
$ —
$ 220.1
Fixed Income Securities – Mutual Funds (b)
104.3
—
(1.4 ) 102.9
Equity Securities – Mutual Funds
17.0
19.7
—
36.7
Total Other Temporary Investments $ 341.4
$ 19.7
$ (1.4 ) $ 359.7


~~(a)~~	~~Primarily represents amounts held for the repayment of debt.~~


~~(b)~~	~~Primarily short and intermediate maturities which may be sold and do not contain maturity dates.~~

The following table provides the activity for fixed income and equity securities within Other Temporary Investments:


	Three Months Ended March 31,
	2024		2023
	(in millions)
Proceeds from Investment Sales	$	3.0	$	—
Purchases of Investments	1.5		1.0
Gross Realized Gains on Investment Sales	0.3		—
Gross Realized Losses on Investment Sales	0.2		—

Three Months Ended March 31,
2018 2017
(in millions)
Proceeds from Investment Sales $ —
$ —
Purchases of Investments 0.6
0.5
Gross Realized Gains on Investment Sales —
—
Gross Realized Losses on Investment Sales —
—

For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three months ended March 31, 2017, see Note 3 - Comprehensive Income.

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M)

Nuclear decommissioning and ~~spent nuclear fuel~~SNF trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and ~~spent nuclear fuel~~SNF disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include:

•Acceptable investments (rated investment grade or above when purchased).

•Maximum percentage invested in a specific type of investment.

•Prohibition of investment in obligations of AEP, I&M or their affiliates.

•Withdrawals permitted only for payment of decommissioning costs and trust expenses.

I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by an external investment ~~managers who~~manager that must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.

I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies debt securities in the trust funds as available-for-sale due to their long-term purpose. Upon adoption of ASU 2016-01 in first quarter 2018, equity securities are now recorded with changes in fair value recognized in earnings. Effective January 2018 available for sale classification only applies to investment in debt securities.

Other-than-temporary impairments for investments in debt securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains, unrealized losses and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI.

The following is a summary of nuclear trust fund investments:


	March 31, 2024								December 31, 2023
			Gross		Gross		Other-Than-				Gross		Gross		Other-Than-
	Fair		Unrealized		Unrealized		Temporary		Fair		Unrealized		Unrealized		Temporary
	Value		Gains		Losses		Impairments		Value		Gains		Losses		Impairments
	(in millions)
Cash and Cash Equivalents	$	25.2	$	—	$	—	$	—	$	16.8	$	—	$	—	$	—
Fixed Income Securities:
United States Government	1,267.0		16.5		(4.2)		(25.7)		1,273.0		28.6		(3.9)		(33.2)
Corporate Debt	123.3		2.5		(6.0)		(5.1)		132.1		4.8		(5.2)		(8.6)
State and Local Government	1.7		—		—		—		1.7		—		—		—
Subtotal Fixed Income Securities	1,392.0		19.0		(10.2)		(30.8)		1,406.8		33.4		(9.1)		(41.8)
Equity Securities - Domestic	2,695.4		2,119.1		(1.1)		—		2,436.6		1,869.5		(0.9)		—
Spent Nuclear Fuel and Decommissioning Trusts	$	4,112.6	$	2,138.1	$	(11.3)	$	(30.8)	$	3,860.2	$	1,902.9	$	(10.0)	$	(41.8)

137

March 31, 2018 December 31, 2017

Fair
Value

Gross Unrealized
Gains

Other-Than-Temporary
Impairments

Fair
Value

Gross Unrealized
Gains
Other-Than-Temporary Impairments
(in millions)
Cash and Cash Equivalents $ 16.4
$ —
$ —
$ 17.2
$ —
$ —
Fixed Income Securities:

United States Government 974.6
19.0
(8.4 ) 981.2
29.7
(3.6 )
Corporate Debt 57.8
2.0
(1.7 ) 58.7
3.8
(1.2 )
State and Local Government 8.6
0.6
(0.2 ) 8.8
0.8
(0.2 )
Subtotal Fixed Income Securities 1,041.0
21.6
(10.3 ) 1,048.7
34.3
(5.0 )
Equity Securities – Domestic (a) 1,453.2
850.3
—
1,461.7
868.2
(75.5 )
Spent Nuclear Fuel and Decommissioning Trusts $ 2,510.6
$ 871.9
$ (10.3 ) $ 2,527.6
$ 902.5
$ (80.5 )


~~(a)~~	Amount reported as Gross Unrealized Gains includes unrealized gains of $855 million and unrealized losses of $4.7 million. AEP adopted ASU 2016-01 during the first quarter of 2018 by means of a modified retrospective approach. Due to the adoption of the ASU, Other-Than-Temporary Impairments are no longer applicable to Equity Securities with readily determinable fair values.

The following table provides the securities activity within the decommissioning and SNF trusts:


	Three Months Ended March 31,
	2024		2023
	(in millions)
Proceeds from Investment Sales	$	569.5	$	517.6
Purchases of Investments	588.5		536.3
Gross Realized Gains on Investment Sales	5.4		48.5
Gross Realized Losses on Investment Sales	1.2		8.6

Three Months Ended March 31,
2018 2017
(in millions)
Proceeds from Investment Sales $ 508.6
$ 487.9
Purchases of Investments 525.3
505.5
Gross Realized Gains on Investment Sales 12.0
11.3
Gross Realized Losses on Investment Sales 10.9
8.1

The base cost of fixed income securities was $1$1.4 billion and $1$1.4 billion as of March 31, ~~2018~~2024 and December 31, ~~2017,~~2023, respectively. The base cost of equity securities was ~~$603~~$577 million and ~~$594~~$568 million as of March 31, ~~2018~~2024 and December 31, ~~2017,~~2023, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of March 31, ~~2018~~2024 was as follows:


	Fair Value of Fixed
	Income Securities
	(in millions)
Within 1 year	$	338.8
After 1 year through 5 years	598.0
After 5 years through 10 years	186.6
After 10 years	268.6
Total	$	1,392.0

138

Fair Value of Fixed Income Securities
(in millions)
Within 1 year $ 355.7
After 1 year through 5 years 315.3
After 5 years through 10 years 205.8
After 10 years 164.2
Total $ 1,041.0

Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.

AEP

Assets and Liabilities Measured at Fair Value on a Recurring Basis

March 31, ~~2018~~2024


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)



Other Temporary Investments and Restricted Cash
Restricted Cash	$	51.1	$	—	$	—	$	—	$	51.1
Other Cash Deposits (a)	—		—		—		15.4		15.4
Fixed Income Securities – Mutual Funds	157.9		—		—		—		157.9
Equity Securities – Mutual Funds (b)	43.7		—		—		—		43.7
Total Other Temporary Investments and Restricted Cash	252.7		—		—		15.4		268.1

Risk Management Assets
Risk Management Commodity Contracts (c) (d)	3.6		679.7		257.5		(593.9)		346.9
Cash Flow Hedges:
Commodity Hedges (c)	—		94.5		18.7		(1.3)		111.9
Interest Rate Hedges	—		8.3		—		—		8.3

Total Risk Management Assets	3.6		782.5		276.2		(595.2)		467.1

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	13.3		—		—		11.9		25.2
Fixed Income Securities:
United States Government	—		1,267.0		—		—		1,267.0
Corporate Debt	—		123.3		—		—		123.3
State and Local Government	—		1.7		—		—		1.7
Subtotal Fixed Income Securities	—		1,392.0		—		—		1,392.0
Equity Securities – Domestic (b)	2,695.4		—		—		—		2,695.4
Total Spent Nuclear Fuel and Decommissioning Trusts	2,708.7		1,392.0		—		11.9		4,112.6



Total Assets	$	2,965.0	$	2,174.5	$	276.2	$	(567.9)	$	4,847.8

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (d)	$	21.0	$	688.4	$	157.1	$	(520.3)	$	346.2
Cash Flow Hedges:
Commodity Hedges (c)	—		2.5		—		(1.3)		1.2
Interest Rate Hedges	—		1.7		—		—		1.7
Fair Value Hedges	—		114.8		—		—		114.8
Total Risk Management Liabilities	$	21.0	$	807.4	$	157.1	$	(521.6)	$	463.9

139

Level 1 Level 2 Level 3 Other Total
Assets: (in millions)

Other Temporary Investments
Restricted Cash and Other Cash Deposits (a) $ 144.8
$ —
$ —
$ 17.2
$ 162.0
Fixed Income Securities – Mutual Funds
102.6
—
—
—
102.6
Equity Securities – Mutual Funds (b)
36.4
—
—
—
36.4
Total Other Temporary Investments
283.8
—
—
17.2
301.0

Risk Management Assets

Risk Management Commodity Contracts (c) (d) 3.0
265.0
243.3
(177.7 ) 333.6
Cash Flow Hedges:

Commodity Hedges (c) —
11.6
3.1
10.8
25.5
Fair Value Hedges —
1.7
—
—
1.7
Total Risk Management Assets 3.0
278.3
246.4
(166.9 ) 360.8

Spent Nuclear Fuel and Decommissioning Trusts

Cash and Cash Equivalents (e) 9.1
—
—
7.3
16.4
Fixed Income Securities:

United States Government —
974.6
—
—
974.6
Corporate Debt —
57.8
—
—
57.8
State and Local Government —
8.6
—
—
8.6
Subtotal Fixed Income Securities —
1,041.0
—
—
1,041.0
Equity Securities – Domestic (b)
1,453.2
—
—
—
1,453.2
Total Spent Nuclear Fuel and Decommissioning Trusts
1,462.3
1,041.0
—
7.3
2,510.6

Total Assets $ 1,749.1
$ 1,319.3
$ 246.4
$ (142.4 ) $ 3,172.4

Liabilities:

Risk Management Liabilities

Risk Management Commodity Contracts (c) (d) $ 3.6
$ 284.7
$ 164.8
$ (194.5 ) $ 258.6
Cash Flow Hedges:

Commodity Hedges (c) —
28.5
19.6
10.8
58.9
Fair Value Hedges —
22.3
—
—
22.3
Total Risk Management Liabilities $ 3.6
$ 335.5
$ 184.4
$ (183.7 ) $ 339.8

AEP

Assets and Liabilities Measured at Fair Value on a Recurring Basis

December 31, ~~2017~~2023


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)



Other Temporary Investments and Restricted Cash
Restricted Cash	$	48.9	$	—	$	—	$	—	$	48.9
Other Cash Deposits (a)	—		—		—		13.9		13.9
Fixed Income Securities – Mutual Funds	159.7		—		—		—		159.7
Equity Securities – Mutual Funds (b)	40.7		—		—		—		40.7
Total Other Temporary Investments and Restricted Cash	249.3		—		—		13.9		263.2

Risk Management Assets
Risk Management Commodity Contracts (c) (f)	9.7		736.9		274.3		(617.0)		403.9
Cash Flow Hedges:
Commodity Hedges (c)	—		123.5		19.8		(8.5)		134.8


Total Risk Management Assets	9.7		860.4		294.1		(625.5)		538.7

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	7.8		—		—		9.0		16.8
Fixed Income Securities:
United States Government	—		1,273.0		—		—		1,273.0
Corporate Debt	—		132.1		—		—		132.1
State and Local Government	—		1.7		—		—		1.7
Subtotal Fixed Income Securities	—		1,406.8		—		—		1,406.8
Equity Securities – Domestic (b)	2,436.6		—		—		—		2,436.6
Total Spent Nuclear Fuel and Decommissioning Trusts	2,444.4		1,406.8		—		9.0		3,860.2



Total Assets	$	2,703.4	$	2,267.2	$	294.1	$	(602.6)	$	4,662.1

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (f)	$	24.7	$	783.8	$	154.1	$	(600.3)	$	362.3
Cash Flow Hedges:
Commodity Hedges (c)	—		9.6		0.6		(8.5)		1.7
Interest Rate Hedges	—		9.0		—		—		9.0
Fair Value Hedges	—		98.4		—		—		98.4
Total Risk Management Liabilities	$	24.7	$	900.8	$	154.7	$	(608.8)	$	471.4

140

Level 1 Level 2 Level 3 Other Total
Assets: (in millions)

Other Temporary Investments
Restricted Cash and Other Cash Deposits (a) $ 183.2
$ —
$ —
$ 36.9
$ 220.1
Fixed Income Securities – Mutual Funds
102.9
—
—
—
102.9
Equity Securities – Mutual Funds (b)
36.7
—
—
—
36.7
Total Other Temporary Investments
322.8
—
—
36.9
359.7

Risk Management Assets

Risk Management Commodity Contracts (c) (f) 3.9
391.2
274.1
(285.4 ) 383.8
Cash Flow Hedges:

Commodity Hedges (c) —
17.3
4.7
—
22.0
Fair Value Hedges —
2.5
—
—
2.5
Total Risk Management Assets 3.9
411.0
278.8
(285.4 ) 408.3

Spent Nuclear Fuel and Decommissioning Trusts

Cash and Cash Equivalents (e) 7.5
—
—
9.7
17.2
Fixed Income Securities:

United States Government —
981.2
—
—
981.2
Corporate Debt —
58.7
—
—
58.7
State and Local Government —
8.8
—
—
8.8
Subtotal Fixed Income Securities —
1,048.7
—
—
1,048.7
Equity Securities – Domestic (b)
1,461.7
—
—
—
1,461.7
Total Spent Nuclear Fuel and Decommissioning Trusts
1,469.2
1,048.7
—
9.7
2,527.6

Total Assets $ 1,795.9
$ 1,459.7
$ 278.8
$ (238.8 ) $ 3,295.6

Liabilities:

Risk Management Liabilities

Risk Management Commodity Contracts (c) (f) $ 5.1
$ 392.5
$ 196.9
$ (285.0 ) $ 309.5
Cash Flow Hedges:

Commodity Hedges (c) —
23.9
41.6
—
65.5
Fair Value Hedges —
8.6
—
—
8.6
Total Risk Management Liabilities $ 5.1
$ 425.0
$ 238.5
$ (285.0 ) $ 383.6

~~AEP Texas~~

~~Assets and Liabilities Measured at Fair Value on a Recurring Basis~~

~~March 31, 2018~~

Level 1 Level 2 Level 3 Other Total
Assets: (in millions)

Restricted Cash for Securitized Funding $ 107.1
$ —
$ —
$ —
$ 107.1

Risk Management Assets

Risk Management Commodity Contracts (c) —
0.4
—
(0.1 ) 0.3

Total Assets $ 107.1
$ 0.4
$ —
$ (0.1 ) $ 107.4

~~AEP Texas~~

~~Assets and Liabilities Measured at Fair Value on a Recurring Basis~~

~~December 31, 2017~~

Level 1 Level 2 Level 3 Other Total
Assets: (in millions)

Restricted Cash for Securitized Funding $ 155.2
$ —
$ —
$ —
$ 155.2

Risk Management Assets

Risk Management Commodity Contracts (c) —
0.5
—
—
0.5

Total Assets $ 155.2
$ 0.5
$ —
$ —
$ 155.7

~~APCo~~

~~Assets and Liabilities Measured at Fair Value on a Recurring Basis~~

~~March 31, 2018~~

Level 1 Level 2 Level 3 Other Total
Assets: (in millions)

Restricted Cash for Securitized Funding $ 10.1
$ —
$ —
$ —
$ 10.1

Risk Management Assets

Risk Management Commodity Contracts (c) (g) 0.6
27.0
10.4
(27.4 ) 10.6

Total Assets $ 10.7
$ 27.0
$ 10.4
$ (27.4 ) $ 20.7

Liabilities:

Risk Management Liabilities

Risk Management Commodity Contracts (c) (g) $ 0.6
$ 26.6
$ 1.3
$ (27.5 ) $ 1.0

~~APCo~~

~~Assets and Liabilities Measured at Fair Value on a Recurring Basis~~

~~December 31, 2017~~

Level 1 Level 2 Level 3 Other Total
Assets: (in millions)

Restricted Cash for Securitized Funding $ 16.3
$ —
$ —
$ —
$ 16.3

Risk Management Assets

Risk Management Commodity Contracts (c) (g) —
52.5
25.1
(51.6 ) 26.0

Total Assets $ 16.3
$ 52.5
$ 25.1
$ (51.6 ) $ 42.3

Liabilities:

Risk Management Liabilities

Risk Management Commodity Contracts (c) (g) $ —
$ 51.2
$ 0.4
$ (50.1 ) $ 1.5

~~I&M~~

~~Assets and Liabilities Measured at Fair Value on a Recurring Basis~~

~~March 31, 2018~~

Level 1 Level 2 Level 3 Other Total
Assets: (in millions)

Risk Management Assets

Risk Management Commodity Contracts (c) (g) $ 0.3
$ 19.4
$ 5.1
$ (19.5 ) $ 5.3

Spent Nuclear Fuel and Decommissioning Trusts

Cash and Cash Equivalents (e) 9.1
—
—
7.3
16.4
Fixed Income Securities:

United States Government —
974.6
—
—
974.6
Corporate Debt —
57.8
—
—
57.8
State and Local Government —
8.6
—
—
8.6
Subtotal Fixed Income Securities —
1,041.0
—
—
1,041.0
Equity Securities - Domestic (b) 1,453.2
—
—
—
1,453.2
Total Spent Nuclear Fuel and Decommissioning Trusts
1,462.3
1,041.0
—
7.3
2,510.6

Total Assets $ 1,462.6
$ 1,060.4
$ 5.1
$ (12.2 ) $ 2,515.9

Liabilities:

Risk Management Liabilities

Risk Management Commodity Contracts (c) (g) $ 0.3
$ 21.0
$ 2.2
$ (19.5 ) $ 4.0

~~I&M~~

~~Assets and Liabilities Measured at Fair Value on a Recurring Basis~~

~~December 31, 2017~~

Level 1 Level 2 Level 3 Other Total
Assets: (in millions)

Risk Management Assets

Risk Management Commodity Contracts (c) (g) $ —
$ 39.4
$ 9.1
$ (40.2 ) $ 8.3

Spent Nuclear Fuel and Decommissioning Trusts

Cash and Cash Equivalents (e) 7.5
—
—
9.7
17.2
Fixed Income Securities:

United States Government —
981.2
—
—
981.2
Corporate Debt —
58.7
—
—
58.7
State and Local Government —
8.8
—
—
8.8
Subtotal Fixed Income Securities —
1,048.7
—
—
1,048.7
Equity Securities - Domestic (b) 1,461.7
—
—
—
1,461.7
Total Spent Nuclear Fuel and Decommissioning Trusts
1,469.2
1,048.7
—
9.7
2,527.6

Total Assets $ 1,469.2
$ 1,088.1
$ 9.1
$ (30.5 ) $ 2,535.9

Liabilities:

Risk Management Liabilities

Risk Management Commodity Contracts (c) (g) $ —
$ 47.6
$ 1.5
$ (45.5 ) $ 3.6

~~OPCo~~

~~Assets and Liabilities Measured at Fair Value on a Recurring Basis~~

~~March 31, 2018~~

Level 1 Level 2 Level 3 Other Total
Assets: (in millions)

Restricted Cash for Securitized Funding $ 15.9
$ —
$ —
$ —
$ 15.9

Risk Management Assets

Risk Management Commodity Contracts (c) (g) —
0.5
—
(0.1 ) 0.4

Total Assets $ 15.9
$ 0.5
$ —
$ (0.1 ) $ 16.3

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g) $ —
$ —
$ 98.5
$ —
$ 98.5

~~OPCo~~

~~Assets and Liabilities Measured at Fair Value on a Recurring Basis~~

~~December 31, 2017~~

Level 1 Level 2 Level 3 Other Total
Assets: (in millions)

Risk Management Assets

Risk Management Commodity Contracts (c) (g) $ —
$ 0.6
$ —
$ —
$ 0.6

Liabilities:

Risk Management Liabilities

Risk Management Commodity Contracts (c) (g) $ —
$ —
$ 132.4
$ —
$ 132.4

~~PSO~~

~~Assets and Liabilities Measured at Fair Value on a Recurring Basis~~

~~March 31, 2018~~

Level 1 Level 2 Level 3 Other Total
Assets: (in millions)

Risk Management Assets

Risk Management Commodity Contracts (c) (g) $ —
$ 0.1
$ 2.9
$ (0.1 ) $ 2.9

Liabilities:

Risk Management Liabilities

Risk Management Commodity Contracts (c) (g) $ —
$ —
$ 0.1
$ (0.1 ) $ —

~~PSO~~

~~Assets and Liabilities Measured at Fair Value on a Recurring Basis~~

~~December 31, 2017~~

Level 1 Level 2 Level 3 Other Total
Assets: (in millions)

Risk Management Assets

Risk Management Commodity Contracts (c) (g) $ —
$ 0.2
$ 6.4
$ (0.2 ) $ 6.4

Liabilities:

Risk Management Liabilities

Risk Management Commodity Contracts (c) (g) $ —
$ —
$ 0.2
$ (0.2 ) $ —

~~SWEPCo~~

~~Assets and Liabilities Measured at Fair Value on a Recurring Basis~~

~~March 31, 2018~~

Level 1 Level 2 Level 3 Other Total
Assets: (in millions)

Risk Management Assets

Risk Management Commodity Contracts (c) (g) $ —
$ 0.2
$ 2.6
$ (1.1 ) $ 1.7

Liabilities:

Risk Management Liabilities

Risk Management Commodity Contracts (c) (g) $ —
$ —
$ 1.7
$ (1.1 ) $ 0.6

~~SWEPCo~~

~~Assets and Liabilities Measured at Fair Value on a Recurring Basis~~

~~December 31, 2017~~

Level 1 Level 2 Level 3 Other Total
Assets: (in millions)

Risk Management Assets

Risk Management Commodity Contracts (c) (g) $ —
$ 0.3
$ 6.7
$ (0.6 ) $ 6.4

Liabilities:

Risk Management Liabilities

Risk Management Commodity Contracts (c) (g) $ —
$ —
$ 0.8
$ (0.6 ) $ 0.2


~~(a)~~	Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.


~~(b)~~	~~Amounts represent publicly traded equity securities and equity-based mutual funds.~~


~~(c)~~	Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.”

~~(d)~~

The March 31, 2018 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(19) million in 2018, $(3) million in periods 2019-2021 and $2 million in periods 2022-2023; Level 3 matures $24 million in 2018, $38 million in periods 2019-2021, $21 million in periods 2022-2023 and $(5) million in periods 2024-2032. Risk management commodity contracts are substantially comprised of power contracts.


~~(e)~~	~~Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.~~

~~(f)~~

The December 31, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(1) million in 2018; Level 2 matures $(3) million in 2018 and $2 million in periods 2022-2023; Level 3 matures $59 million in 2018, $33 million in periods 2019-2021, $14 million in periods 2022-2023 and $(29) million in periods 2024-2032. Risk management commodity contracts are substantially comprised of power contracts.


~~(g)~~	~~Substantially comprised of power contracts.~~

~~There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2018 and 2017.~~

~~The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:~~

Three Months Ended March 31, 2018 AEP APCo I&M OPCo PSO SWEPCo
(in millions)
Balance as of December 31, 2017 $ 40.3
$ 24.7
$ 7.6
$ (132.4 ) $ 6.2
$ 5.9
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 97.3
68.1
3.0
0.3
11.4
0.6
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 2.0
—
—
—
—
—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 17.9
—
—
—
—
—
Settlements (129.8 ) (85.4 ) (7.4 ) 1.1
(16.1 ) (3.9 )
Transfers into Level 3 (c) (d) 2.1
—
—
—
—
—
Transfers out of Level 3 (d) (2.0 ) —
(0.3 ) —
—
—
Changes in Fair Value Allocated to Regulated Jurisdictions (e) 34.2
1.7
—
32.5
1.3
(1.7 )
Balance as of March 31, 2018 $ 62.0
$ 9.1
$ 2.9
$ (98.5 ) $ 2.8
$ 0.9

Three Months Ended March 31, 2017 AEP APCo I&M OPCo PSO SWEPCo
(in millions)
Balance as of December 31, 2016 $ 2.5
$ 1.4
$ 2.8
$ (119.0 ) $ 0.7
$ 0.7
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 17.8
5.7
2.0
(0.5 ) 2.2
4.5
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 16.1
—
—
—
—
—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (17.2 ) —
—
—
—
—
Settlements (28.8 ) (12.2 ) (4.3 ) 2.1
(2.6 ) (4.9 )
Transfers into Level 3 (c) (d) 5.2
—
—
—
—
—
Transfers out of Level 3 (d) (8.3 ) —
—
—
—
—
Changes in Fair Value Allocated to Regulated Jurisdictions (e) (5.8 ) (0.7 ) 1.5
(7.2 ) 0.1
0.2
Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0
$ (124.6 ) $ 0.4
$ 0.5


~~(a)~~	~~Included in revenues on the statements of income.~~


~~(b)~~	~~Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.~~


~~(c)~~	~~Represents existing assets or liabilities that were previously categorized as Level 2.~~


~~(d)~~	~~Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.~~


~~(e)~~	~~Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities.~~

~~The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions:~~

~~Significant Unobservable Inputs~~

~~March 31, 2018~~

~~AEP~~

Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input Low High Average
(in millions)
Energy Contracts $ 226.0
$ 178.3
Discounted Cash Flow Forward Market Price (a) $ 8.54
$ 202.55
$ 34.74
Counterparty Credit Risk (b) 9
501
179
Natural Gas Contracts —
0.6
Discounted Cash Flow Forward Market Price (c) 2.33
2.96
2.59
FTRs 20.4
5.5
Discounted Cash Flow Forward Market Price (a) (9.68 ) 8.81
0.28
Total $ 246.4
$ 184.4

~~Significant Unobservable Inputs~~

~~December 31, 2017~~

~~AEP~~

Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input Low High Average
(in millions)
Energy Contracts $ 225.1
$ 233.7
Discounted Cash Flow Forward Market Price (a) $ (0.05 ) $ 263.00
$ 36.32
Counterparty Credit Risk (b) 8
456
180
Natural Gas Contracts —
0.2
Discounted Cash Flow Forward Market Price (c) 2.37
2.96
2.62
FTRs 53.7
4.6
Discounted Cash Flow Forward Market Price (a) (55.62 ) 54.88
0.41
Total $ 278.8
$ 238.5

~~Significant Unobservable Inputs~~

~~March 31, 2018~~

~~APCo~~

Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input (a) Low High Average
(in millions)
Energy Contracts $ 2.5
$ 0.3
Discounted Cash Flow Forward Market Price $ 20.56
$ 46.25
$ 33.30
FTRs 7.9
1.0
Discounted Cash Flow Forward Market Price (0.30 ) 6.36
1.14
Total $ 10.4
$ 1.3

~~Significant Unobservable Inputs~~

~~December 31, 2017~~

~~APCo~~

Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input (a) Low High Average
(in millions)
Energy Contracts $ 0.8
$ 0.4
Discounted Cash Flow Forward Market Price $ 20.52
$ 195.00
$ 33.80
FTRs 24.3
—
Discounted Cash Flow Forward Market Price (0.36 ) 7.15
1.62
Total $ 25.1
$ 0.4

~~Significant Unobservable Inputs~~

~~March 31, 2018~~

~~I&M~~

Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input (a) Low High Average
(in millions)
Energy Contracts $ 1.5
$ 1.3
Discounted Cash Flow Forward Market Price $ 20.56
$ 46.25
$ 33.30
FTRs 3.6
0.9
Discounted Cash Flow Forward Market Price (0.35 ) 5.74
0.77
Total $ 5.1
$ 2.2

~~Significant Unobservable Inputs~~

~~December 31, 2017~~

~~I&M~~

Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input (a) Low High Average
(in millions)
Energy Contracts $ 0.5
$ 0.3
Discounted Cash Flow Forward Market Price $ 20.52
$ 195.00
$ 33.80
FTRs 8.6
1.2
Discounted Cash Flow Forward Market Price (0.36 ) 5.75
0.86
Total $ 9.1
$ 1.5

~~Significant Unobservable Inputs~~

~~March 31, 2018~~

~~OPCo~~

Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input Low High Average
(in millions)
Energy Contracts $ —
$ 98.5
Discounted Cash Flow Forward Market Price (a) $ 27.42
$ 62.16
$ 43.76
Counterparty Credit Risk (b) 9
202
144
Total $ —
$ 98.5

~~Significant Unobservable Inputs~~

~~December 31, 2017~~

~~OPCo~~

Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input Low High Average
(in millions)
Energy Contracts $ —
$ 132.4
Discounted Cash Flow Forward Market Price (a) $ 30.52
$ 170.43
$ 44.62

Counterparty Credit Risk (b) 8
190
136
Total $ —
$ 132.4

~~Significant Unobservable Inputs~~

~~March 31, 2018~~

~~PSO~~

Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input (a) Low High Average
(in millions)
FTRs $ 2.9
$ 0.1
Discounted Cash Flow Forward Market Price $ (9.68 ) $ 1.39
$ (0.76 )

~~Significant Unobservable Inputs~~

~~December 31, 2017~~

~~PSO~~

Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input (a) Low High Average
(in millions)
FTRs $ 6.4
$ 0.2
Discounted Cash Flow Forward Market Price $ (6.62 ) $ 1.41
$ (0.76 )

~~Significant Unobservable Inputs~~

~~March 31, 2018~~

~~SWEPCo~~

Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input Low High Average
(in millions)
Natural Gas Contracts $ —
$ 0.6
Discounted Cash Flow Forward Market Price (c) $ 2.33
$ 2.96
$ 2.59
FTRs 2.6
1.1
Discounted Cash Flow Forward Market Price (a) (9.68 ) 1.39
(0.76 )
Total $ 2.6
$ 1.7

~~Significant Unobservable Inputs~~

~~December 31, 2017~~

~~SWEPCo~~

Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique Input Low High Average
(in millions)
Natural Gas Contracts $ —
$ 0.2
Discounted Cash Flow Forward Market Price (c) $ 2.37
$ 2.96
$ 2.62
FTRs 6.7
0.6
Discounted Cash Flow Forward Market Price (a) (6.62 ) 1.41
(0.76 )
Total $ 6.7
$ 0.8


~~(a)~~	~~Represents market prices in dollars per MWh.~~


~~(b)~~	~~Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points.~~


~~(c)~~	~~Represents market prices in dollars per MMBtu.~~

The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts, Natural Gas Contracts and FTRs for the Registrants as of March 31, 2018 and December 31, 2017:

~~Sensitivity of Fair Value Measurements~~



~~Significant Unobservable Input~~	~~Position~~	~~Change in Input~~	~~Impact on Fair Value~~ ~~Measurement~~
~~Forward Market Price~~	~~Buy~~	~~Increase (Decrease)~~	~~Higher (Lower)~~
~~Forward Market Price~~	~~Sell~~	~~Increase (Decrease)~~	~~Lower (Higher)~~
~~Counterparty Credit Risk~~	~~Loss~~	~~Increase (Decrease)~~	~~Higher (Lower)~~
~~Counterparty Credit Risk~~	~~Gain~~	~~Increase (Decrease)~~	~~Lower (Higher)~~

~~11.~~ ~~INCOME TAXES~~

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

~~Federal Tax Reform~~

In December 2017, legislation referred to as Tax Reform was signed into law. Tax Reform includes significant changes to the Internal Revenue Code of 1986, as amended, (the Code) and had a material impact on the Registrants’ financial statements in the reporting period of its enactment. Tax Reform lowered the corporate federal income tax rate from 35% to 21%. Tax Reform provisions related to regulated public utilities generally allow for the continued deductibility of interest expense, eliminate bonus depreciation for certain property acquired after September 27, 2017 and continue certain rate normalization requirements for accelerated depreciation benefits.

~~Provisional Amounts~~

The Registrants applied Staff Accounting Bulletin 118 (SAB 118), issued by the SEC staff in December 2017, and made reasonable estimates for the measurement and accounting of the effects of Tax Reform which are reflected in the financial statements as provisional amounts based on the best information available. SAB 118 provides for up to a one year period to complete the required analysis and accounting for Tax Reform referred to as the measurement period. While the Registrants were able to make reasonable estimates of the impact of Tax Reform in 2017, the final impact may differ from the recorded provisional amounts to the extent refinements are made to the estimated cumulative differences or as a result of additional guidance or technical corrections that may be issued by the IRS that may impact management’s interpretation and assumptions utilized. The measurement period adjustments recorded during the first quarter of 2018 to the provisional amounts were immaterial. The Registrants expect to complete the analysis of the provisional items during the second half of 2018.

~~Reduction in the Corporate Federal Income Tax Rate - Pending Rate Reductions~~

State utility commissions have issued orders or instructions requiring public utilities, including the Registrants, to record liabilities to reflect the impact of the reduction in the corporate federal income tax rate in excess of the enacted corporate federal income tax rate of 21% beginning in 2018. The following table provides a summary of the estimated provisions for revenue refund recorded by the Registrants related to the reduction in the corporate federal tax rate as of and for the three months ended March 31, 2018:

AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Decrease in Total Revenues $ (119.5 ) $ (7.6 ) $ (19.0 ) $ (35.4 ) $ (17.8 ) $ (21.3 ) $ (3.8 ) $ (11.0 )
Increase in Current Liabilities 33.9
—
16.2
7.8
3.0
6.2
—
—
Increase in Deferred Credits and Other Noncurrent Liabilities 85.6
7.6
2.8
27.6
14.8
15.1
3.8
11.0

~~Excess Accumulated Deferred Income Taxes - Pending Rate Reductions~~

As of March 31, 2018, the Registrants have approximately $4.4 billion of Excess ADIT, as well as an incremental liability of $1.2 billion to reflect the $4.4 billion Excess ADIT on a pre-tax basis, presented in Regulatory Liabilities and Deferred Investment Tax Credits on the balance sheets. The Excess ADIT is reflected on a pretax basis to appropriately contemplate future tax consequences in the periods when the regulatory liability is settled. As of March 31, 2018, approximately $3.4 billion of the Excess ADIT relates to temporary differences associated with depreciable property subject to rate normalization requirements.

As reflected in the Registrants’ respective estimated annual ETR for 2018, AEP’s regulated public utilities began amortizing the excess accumulated deferred income taxes (Excess ADIT) associated with certain depreciable property subject to rate normalization requirements using the ARAM during the first quarter of 2018. The amortization resulted in a reduction in the Excess ADIT balance recorded in Regulatory Liabilities and Deferred Investment Tax Credits and a reduction in Income Tax Expense. As a result of state utility commission orders or instructions, in the first quarter

~~of 2018 the Registrants recorded estimated provisions for revenue refund offsetting the amortization of the Excess ADIT as shown in the table below:~~

AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Decrease in Total Revenues $ (17.2 ) $ (2.1 ) $ (0.1 ) $ (4.6 ) $ (1.7 ) $ (1.4 ) $ (2.2 ) $ (3.5 )
Increase in Deferred Credits and Other Noncurrent Liabilities 17.2
2.1
0.1
4.6
1.7
1.4
2.2
3.5

In addition, with respect to the remaining $1 billion of Excess ADIT recorded in Regulatory Liabilities and Deferred Investment Tax Credits that are not subject to rate normalization requirements, the Registrants continue to work with the various state utility commissions to determine the appropriate mechanism and time period to provide these benefits of Tax Reform to customers. The corresponding reduction in Income Tax Expense will be reported in the interim period in which these benefits of Tax Reform are provided to customers.

~~Effective Tax Rates (ETR)~~

The Registrants’ interim ETR reflect the estimated annual ETR for 2018 and 2017, adjusted for tax expense associated with certain discrete items. As previously mentioned, effective January 1, 2018, Tax Reform lowered the corporate tax rate from 35% to 21%. The interim ETR differ from the federal statutory tax rate of 21% and 35% in 2018 and 2017, respectively, primarily due to state income taxes, the amortization of the excess accumulated deferred income taxes associated with certain depreciable property using the ARAM, tax credits and other book/tax differences which are accounted for on a flow-through basis.

~~The ETR for each of the Registrants are included in the following table. Significant variances in the ETR are described below.~~

Three Months Ended
March 31,
Company 2018 2017
AEP 18.3 % 36.7 %
AEP Texas 16.3 % 34.7 %
AEPTCo 20.8 % 33.3 %
APCo 18.2 % 36.5 %
I&M 16.2 % 29.9 %
OPCo 20.5 % 34.9 %
PSO 16.3 % 37.7 %
SWEPCo 18.4 % 37.3 %

~~AEP~~

~~Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017~~

The decrease in the ETR is primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and increased 2018 amortization of Excess ADIT associated with certain depreciable property using the ARAM.

AEP Texas

Assets and Liabilities Measured at Fair Value on a Recurring Basis

~~Three Months Ended~~ March 31, ~~2018 Compared to Three Months Ended~~ 2024


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)

Restricted Cash for Securitized Funding	$	42.7	$	—	$	—	$	—	$	42.7

Risk Management Assets
Risk Management Commodity Contracts (c)	—		0.2		—		2.3		2.5
Cash Flow Hedges:
Interest Rate Hedges	—		2.3		—		(2.3)		—
Total Risk Management Assets	—		2.5		—		—		2.5

Total Assets	$	42.7	$	2.5	$	—	$	—	$	45.2

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	—	$	—	$	0.1	$	0.1
Cash Flow Hedges:
Interest Rate Hedges	—		0.1		—		(0.1)		—


Total Liabilities	$	—	$	0.1	$	—	$	—	$	0.1

December 31, 2023


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)

Restricted Cash for Securitized Funding	$	34.0	$	—	$	—	$	—	$	34.0






Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	0.2	$	—	$	(0.2)	$	—
Cash Flow Hedges:
Interest Rate Hedges	—		2.7		—		—		2.7
Total Risk Management Liabilities	$	—	$	2.9	$	—	$	(0.2)	$	2.7

141

APCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

March 31, ~~2017~~2024


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)

Restricted Cash for Securitized Funding	$	8.4	$	—	$	—	$	—	$	8.4

Risk Management Assets
Risk Management Commodity Contracts (c)	—		2.1		8.6		(2.0)		8.7




Total Assets	$	8.4	$	2.1	$	8.6	$	(2.0)	$	17.1

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	19.3	$	4.6	$	(3.4)	$	20.5

December 31, 2023


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)

Restricted Cash for Securitized Funding	$	14.9	$	—	$	—	$	—	$	14.9

Risk Management Assets
Risk Management Commodity Contracts (c)	—		1.1		23.5		(2.2)		22.4




Total Assets	$	14.9	$	1.1	$	23.5	$	(2.2)	$	37.3

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	24.0	$	1.1	$	(2.6)	$	22.5

142

I&M

Assets and Liabilities Measured at Fair Value on a Recurring Basis

March 31, 2024


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)

Risk Management Assets
Risk Management Commodity Contracts (c)	$	—	$	13.1	$	1.8	$	(3.7)	$	11.2

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	13.3		—		—		11.9		25.2
Fixed Income Securities:
United States Government	—		1,267.0		—		—		1,267.0
Corporate Debt	—		123.3		—		—		123.3
State and Local Government	—		1.7		—		—		1.7
Subtotal Fixed Income Securities	—		1,392.0		—		—		1,392.0
Equity Securities - Domestic (b)	2,695.4		—		—		—		2,695.4
Total Spent Nuclear Fuel and Decommissioning Trusts	2,708.7		1,392.0		—		11.9		4,112.6

Total Assets	$	2,708.7	$	1,405.1	$	1.8	$	8.2	$	4,123.8

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	7.6	$	0.8	$	(7.7)	$	0.7

December 31, 2023


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)

Risk Management Assets
Risk Management Commodity Contracts (c)	$	—	$	37.4	$	4.5	$	(2.3)	$	39.6

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	7.8		—		—		9.0		16.8
Fixed Income Securities:
United States Government	—		1,273.0		—		—		1,273.0
Corporate Debt	—		132.1		—		—		132.1
State and Local Government	—		1.7		—		—		1.7
Subtotal Fixed Income Securities	—		1,406.8		—		—		1,406.8
Equity Securities - Domestic (b)	2,436.6		—		—		—		2,436.6
Total Spent Nuclear Fuel and Decommissioning Trusts	2,444.4		1,406.8		—		9.0		3,860.2

Total Assets	$	2,444.4	$	1,444.2	$	4.5	$	6.7	$	3,899.8

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	3.7	$	1.7	$	(3.4)	$	2.0

143

OPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

March 31, 2024


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)



Risk Management Assets
Risk Management Commodity Contracts (c)	$	—	$	0.1	$	—	$	—	$	0.1



Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	—	$	41.0	$	—	$	41.0

December 31, 2023


	Level 1		Level 2		Level 3		Other		Total









Liabilities:	(in millions)

Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	0.2	$	50.6	$	(0.1)	$	50.7

PSO

Assets and Liabilities Measured at Fair Value on a Recurring Basis

March 31, 2024


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)

Risk Management Assets
Risk Management Commodity Contracts (c)	$	—	$	0.1	$	8.4	$	(0.6)	$	7.9

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	31.2	$	0.7	$	(0.6)	$	31.3

December 31, 2023


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)

Risk Management Assets
Risk Management Commodity Contracts (c)	$	—	$	—	$	19.7	$	(0.7)	$	19.0




Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	29.6	$	1.1	$	(0.8)	$	29.9

144

SWEPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

March 31, 2024


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)



Risk Management Assets
Risk Management Commodity Contracts (c)	$	—	$	0.1	$	5.5	$	(0.3)	$	5.3



Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	11.1	$	0.2	$	(0.2)	$	11.1

December 31, 2023


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)



Risk Management Assets
Risk Management Commodity Contracts (c)	$	—	$	0.5	$	12.0	$	(0.9)	$	11.6



Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	15.7	$	0.9	$	(1.0)	$	15.6

(a)Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or third-parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.

(b)Amounts represent publicly traded equity securities and equity-based mutual funds.

(c)Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’

(d)The March 31, 2024 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $(14) million in 2024 and $(3) million in periods 2025-2027; Level 2 matures $(65) million in 2024, $51 million in periods 2025-2027 and $5 million in periods 2028-2029; Level 3 matures $34 million in 2024, $55 million in periods 2025-2027, $23 million in periods 2028-2029 and $(12) million in periods 2030-2032. Risk management commodity contracts are substantially comprised of power contracts.

(e)Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.

(f)The December 31, 2023 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $(11) million in 2024 and $(4) million in 2025-2027; Level 2 matures $(99) million in 2024, $(44) million in periods 2025-2027, $7 million in periods 2028-2029 and $2 million in periods 2030-2033; Level 3 matures $74 million in 2024, $43 million in periods 2025-2027, $18 million in periods 2028-2029 and $(16) million in periods 2030-2033. Risk management commodity contracts are substantially comprised of power contracts.

145

The ~~decrease~~following tables set forth a reconciliation of changes in the ~~ETR is primarily due to~~fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:


Three Months Ended March 31, 2024	AEP		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Balance as of December 31, 2023	$	139.4	$	22.4	$	2.8	$	(50.6)	$	18.6	$	11.1
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)	46.9		9.2		3.2		(0.4)		18.5		14.7
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)	11.3		—		—		—		—		—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)	0.6		—		—		—		—		—
Settlements	(96.6)		(26.8)		(4.8)		2.6		(31.3)		(23.6)
Transfers into Level 3 (d) (e)	4.6		—		—		—		—		—
Transfers out of Level 3 (e)	2.1		—		—		—		—		0.5
Changes in Fair Value Allocated to Regulated Jurisdictions (f)	10.8		(0.8)		(0.2)		7.4		1.9		2.6

Balance as of March 31, 2024	$	119.1	$	4.0	$	1.0	$	(41.0)	$	7.7	$	5.3


Three Months Ended March 31, 2023	AEP		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Balance as of December 31, 2022	$	160.4	$	69.1	$	4.6	$	(40.0)	$	23.7	$	14.2
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)	(7.1)		(31.9)		1.2		(1.3)		16.6		12.9
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)	14.8		—		—		—		—		—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)	(13.9)		—		—		—		—		—
Settlements	(96.6)		(27.3)		(4.2)		1.0		(34.3)		(23.0)
Transfers into Level 3 (d) (e)	(6.1)		—		—		—		—		—
Transfers out of Level 3 (e)	1.0		—		—		—		—		—
Changes in Fair Value Allocated to Regulated Jurisdictions (f)	(7.4)		(4.2)		(0.5)		(6.6)		3.3		1.7

Balance as of March 31, 2023	$	45.1	$	5.7	$	1.1	$	(46.9)	$	9.3	$	5.8

(a)Included in revenues on the statements of income.

(b)Represents the change in fair value between the ~~corporate federal income~~beginning of the reporting period and the settlement of the risk management commodity contract.

(c)Included in cash flow hedges on the statements of comprehensive income.

(d)Represents existing assets or liabilities that were previously categorized as Level 2.

(e)Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.

(f)Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These changes in fair value are recorded as regulatory liabilities for net gains and as regulatory assets for net losses or accounts payable.

146

The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions:

Significant Unobservable Inputs

March 31, 2024


							Significant	Input/Range
	Type of	Fair Value				Valuation	Unobservable					Weighted
Company	Input	Assets		Liabilities		Technique	Input	Low		High		Average (a)
		(in millions)
AEP	Energy Contracts	$	246.5	$	146.1	Discounted Cash Flow	Forward Market Price (b)	$	10.31	$	169.47	$	49.39

AEP	FTRs	29.7		11.0		Discounted Cash Flow	Forward Market Price (b)	(79.90)		23.79		(0.35)





APCo	FTRs	8.6		4.6		Discounted Cash Flow	Forward Market Price (b)	(0.38)		5.05		0.61

I&M	FTRs	1.8		0.8		Discounted Cash Flow	Forward Market Price (b)	0.03		6.82		0.84
OPCo	Energy Contracts	—		41.0		Discounted Cash Flow	Forward Market Price (b)	19.72		75.88		47.20
PSO	FTRs	8.4		0.7		Discounted Cash Flow	Forward Market Price (b)	(79.90)		3.13		(3.48)


SWEPCo	FTRs	5.5		0.2		Discounted Cash Flow	Forward Market Price (b)	(79.90)		3.13		(3.48)

December 31, 2023


							Significant	Input/Range
	Type of	Fair Value				Valuation	Unobservable					Weighted
Company	Input	Assets		Liabilities		Technique	Input	Low		High		Average (a)
		(in millions)
AEP	Energy Contracts	$	225.5	$	144.9	Discounted Cash Flow	Forward Market Price (b)	$	5.21	$	153.77	$	45.05
AEP	Natural Gas Contracts	—		0.5		Discounted Cash Flow	Forward Market Price (c)	3.11		3.11		3.11
AEP	FTRs	68.6		9.3		Discounted Cash Flow	Forward Market Price (b)	(25.45)		17.07		—



APCo	FTRs	23.5		1.1		Discounted Cash Flow	Forward Market Price (b)	(1.04)		6.45		1.36
I&M	FTRs	4.5		1.7		Discounted Cash Flow	Forward Market Price (b)	(1.48)		8.40		(0.85)
OPCo	Energy Contracts	—		50.6		Discounted Cash Flow	Forward Market Price (b)	22.92		67.53		42.85
PSO	FTRs	19.7		1.1		Discounted Cash Flow	Forward Market Price (b)	(25.45)		4.80		(4.33)
SWEPCo	Natural Gas Contracts	—		0.5		Discounted Cash Flow	Forward Market Price (c)	3.11		3.11		3.11
SWEPCo	FTRs	12.0		0.4		Discounted Cash Flow	Forward Market Price (b)	(25.45)		4.80		(4.33)

(a)The weighted average is the product of the forward market price of the underlying commodity and volume weighted by term.

(b)Represents market prices in dollars per MWh.

(c)Represents market prices in dollars per MMBtu.

The following table provides the measurement uncertainty of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of March 31, 2024 and December 31, 2023:

Significant Unobservable Input

Position

Change in Input

Impact on Fair Value
Measurement

Forward Market Price

Buy

Increase (Decrease)

Higher (Lower)

Forward Market Price

Sell

Increase (Decrease)

Lower (Higher)

147

11. INCOME TAXES

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

Effective Tax Rates (ETR)

The Registrants’ interim ETR reflect the estimated annual ETR for 2024 and 2023, adjusted for tax ~~rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and increased 2018 amortization of Excess ADIT~~expense associated with certain ~~depreciable property using~~discrete items. In the ~~ARAM.~~first quarter of 2024, I&M, PSO, and SWEPCo recorded tax benefits of $61 million, $49 million, and $114 million, respectively, related to the reduction of a regulatory liability associated with the IRS PLRs received, driving a reduction to the interim ETR resulting in AEP’s tax rate of (16.5)% as shown below.

~~AEPTCo~~

~~Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017~~

The ~~decrease~~ETR for each of the Registrants are included in the ~~ETR is primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform.~~following tables:

~~APCo~~


	Three Months Ended March 31, 2024
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
U.S. Federal Statutory Rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) due to:
State Income Tax, net of Federal Benefit	2.1	%	0.2	%	2.6	%	2.4	%	3.9	%	1.0	%	3.7	%	1.7	%
Tax Reform Excess ADIT Reversal	(2.3)	%	(1.3)	%	0.2	%	(13.4)	%	(0.5)	%	(6.0)	%	(2.0)	%	4.6	%
Remeasurement of Excess ADIT	(29.7)	%	—	%	—	%	—	%	(58.2)	%	—	%	(263.3)	%	(224.7)	%
Production and Investment Tax Credits	(6.8)	%	(0.2)	%	—	%	(0.1)	%	(1.1)	%	—	%	(49.6)	%	(23.8)	%
Flow Through	—	%	0.1	%	0.3	%	(0.3)	%	(2.8)	%	0.6	%	0.2	%	0.6	%
AFUDC Equity	(1.2)	%	(1.5)	%	(1.8)	%	(0.4)	%	(0.7)	%	(1.0)	%	(1.3)	%	(1.3)	%

Discrete Tax Adjustments	0.2	%	—	%	—	%	—	%	—	%	—	%	0.9	%	1.3	%
Other	0.2	%	0.5	%	—	%	0.1	%	—	%	0.2	%	1.2	%	(0.8)	%
Effective Income Tax Rate	(16.5)	%	18.8	%	22.3	%	9.3	%	(38.4)	%	15.8	%	(289.2)	%	(221.4)	%

~~Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017~~


	Three Months Ended March 31, 2023
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
U.S. Federal Statutory Rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) due to:
State Income Tax, net of Federal Benefit	1.9	%	0.3	%	2.6	%	2.4	%	3.6	%	1.0	%	3.2	%	(0.4)	%
Tax Reform Excess ADIT Reversal	(6.2)	%	(1.5)	%	0.3	%	(4.6)	%	(7.9)	%	(6.8)	%	(18.7)	%	(3.8)	%

Production and Investment Tax Credits	(9.7)	%	(0.2)	%	—	%	—	%	(1.1)	%	—	%	(55.7)	%	(26.4)	%
Flow Through	0.1	%	0.2	%	0.3	%	0.6	%	(1.8)	%	0.5	%	0.3	%	0.5	%
AFUDC Equity	(1.4)	%	(1.5)	%	(1.6)	%	(0.7)	%	(0.5)	%	(0.8)	%	(1.4)	%	(0.8)	%

Discrete Tax Adjustments	(3.2)	%	—	%	—	%	3.2	%	1.8	%	—	%	—	%	—	%
Other	0.1	%	0.1	%	0.1	%	—	%	—	%	—	%	(2.0)	%	(0.8)	%
Effective Income Tax Rate	2.6	%	18.4	%	22.7	%	21.9	%	15.1	%	14.9	%	(53.3)	%	(10.7)	%

~~I&M~~

~~Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017~~

The decrease in the ETR is primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, increased 2018 amortization of excess accumulated deferred income taxes associated with certain depreciable property using the ARAM, and decreased state income taxes resulting from elimination of bonus depreciation for certain property acquired after September 27, 2017. These decreases were partially offset by an increase in book/tax differences which are accounted for on a flow-through basis resulting from a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028.

~~OPCo~~

~~Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017~~

~~The decrease in the ETR is primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform.~~

~~PSO~~

~~Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017~~

~~SWEPCo~~

~~Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017~~

Federal and State Income Tax Audit Status

The statute of limitations for the IRS to examine AEP and subsidiaries ~~are no longer subject~~originally filed federal return has expired for tax years 2016 and earlier. AEP has agreed to ~~U.S. federal examination~~extend the statute of limitations on the 2017-2020 tax returns to May 31, 2025, to allow time for ~~years before 2011.~~the current IRS audit to be completed including a refund claim approval by the Congressional Joint Committee on Taxation.

The current IRS audit and associated refund claim evolved from a net operating loss carryback to 2015 that originated in the 2017 return. AEP has received and agreed to immaterial IRS proposed adjustments on the 2017 tax return. The IRS ~~examination of years 2011 through 2013 started in April 2014.~~exam is complete, and AEP ~~and subsidiaries received a Revenue Agents Report in April 2016, completing~~is currently waiting on the ~~2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted~~IRS to submit the refund claim to the Congressional Joint Committee on Taxation for ~~approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. To resolve the issue under consideration, AEP~~resolution and subsidiaries and the IRS exam team agreed to utilize the Fast Track Settlement Program in December 2017. The program was completed in March 2018 and tax years 2014 and 2015 were added to the IRS examination to reflect the impact of the Fast Track changes that were carried forward to 2014 and 2015.final approval.

Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income.

148

AEP and subsidiaries file income tax returns in various state and local ~~or foreign~~ jurisdictions. These taxing authorities routinely examine the tax ~~returns.~~returns, and AEP and subsidiaries are currently under examination in several state and local jurisdictions. ~~However, it~~Generally, the statutes of limitations have expired for tax years prior to 2017. In addition, management is ~~possible that previously filed~~monitoring and continues to evaluate the potential impact of federal legislation and corresponding state conformity.

Federal Legislation

In August 2022, President Biden signed H.R. 5376 into law, commonly known as the Inflation Reduction Act of 2022, or IRA. Most notably this budget reconciliation legislation creates a 15% minimum tax ~~returns have positions that may~~on adjusted financial statement income (Corporate Alternative Minimum Tax or CAMT), extends and increases the value of PTCs and ITCs, adds a nuclear and clean hydrogen PTC, an energy storage ITC and allows the sale or transfer of tax credits to third parties for cash. As further significant guidance from Treasury and the IRS is expected on the tax provisions in the IRA, AEP will continue to monitor any issued guidance and evaluate the impact on future net income, cash flows and financial condition.

AEP and subsidiaries are applicable corporations for purposes of the CAMT in 2024. CAMT cash taxes are expected to be ~~challenged~~partially offset by ~~these~~regulatory recovery, the utilization of tax ~~authorities. Management believes that adequate provisions for income~~credits and additionally the cash inflow generated by the sale of tax credits. The sale of tax credits are presented in the operating section of the statements of cash flows consistent with the presentation of cash taxes ~~have been made for potential liabilities resulting from such challenges and that~~paid. AEP presents the ~~ultimate resolution~~loss on sale of ~~these audits will not materially impact net income. The Registrants are no longer subject to state, local or non-U.S.~~tax credits through income tax ~~examinations by tax authorities for years before 2009.~~expense.

~~State Tax Legislation (Applies to AEP, AEPTCo, I&M and OPCo)~~

In June 2023, the IRS issued temporary regulations related to the transfer of tax credits. In 2023, AEP, on behalf of PSO, SWEPCo and AEP Energy Supply, LLC, entered into transferability agreements with nonaffiliated parties to sell 2023 generated PTCs resulting in cash proceeds of approximately $174 million with $102 million received in 2023, $62 million received in the first quarter of 2024 and the remaining $10 million was received in April ~~2018,~~2024. AEP expects to continue to explore the ~~Kentucky legislature enacted House Bill 366 (HB 366) adopting significant changes~~ability to ~~Kentucky's corporate income~~efficiently monetize its tax ~~code. HB 366 amended and reduced~~credits through third party transferability agreements.

I&M’s Cook Plant qualifies for the corporate tax rate from a graduated rate with a maximum 6% rate to a single 5% corporate tax rate. HB 366 also modified the apportionment formula from a traditional three-factor formula of property, payroll, and double weighted sales to a single sales factor apportionment. The corporate income tax changes under HB 366 are effectivetransferable Nuclear PTC, which is available for tax years beginning in 2024 through 2032. The Nuclear PTC is calculated based on ~~or after January 1, 2018. The legislation~~electricity generated and sold to third-parties and is subject to a “reduction amount” as the facility’s gross receipts increase above a certain threshold. Due to lack of guidance and uncertainty surrounding the computation of gross receipts, AEP and I&M are unable to estimate the amount of the Nuclear PTCs earned as of March 31, 2024 and have not ~~expected to materially impact net income, cash flows or financial condition.~~included any Nuclear PTCs in the annualized effective tax rate for the first quarter of 2024.

149

12. FINANCING ACTIVITIES

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

Common Stock (Applies to AEP)

At-the-Market (ATM) Program

In 2023, AEP filed a prospectus supplement and executed an Equity Distribution Agreement, pursuant to which AEP may sell, from time to time, up to an aggregate of $1.7 billion of its common stock through an ATM offering program, including an equity forward sales component. The compensation paid to the selling agents by AEP may be up to 2% of the gross offering proceeds of the shares. There were no issuances under the ATM program for the three months ended March 31, 2024.

Long-term Debt Outstanding (Applies to AEP)

The following table details long-term debt ~~outstanding:~~outstanding, net of issuance costs and premiums or discounts:


Type of Debt	March 31, 2024		December 31, 2023
	(in millions)
Senior Unsecured Notes	$	34,606.1	$	33,779.4
Pollution Control Bonds	1,771.0		1,771.6
Notes Payable	163.5		193.3
Securitization Bonds	343.8		368.9
Spent Nuclear Fuel Obligation (a)	304.4		300.4
Junior Subordinated Notes	1,588.2		2,388.1
Other Long-term Debt	1,058.9		1,341.5
Total Long-term Debt Outstanding	39,835.9		40,143.2
Long-term Debt Due Within One Year	1,198.6		2,490.5
Long-term Debt	$	38,637.3	$	37,652.7

Type of Debt March 31, 2018 December 31, 2017
(in millions)
Senior Unsecured Notes $ 17,004.6
$ 16,478.3
Pollution Control Bonds 1,540.4
1,621.7
Notes Payable 230.2
260.8
Securitization Bonds 1,285.9
1,416.5
Spent Nuclear Fuel Obligation (a) 269.5
268.6
Other Long-term Debt 1,130.4
1,127.4
Total Long-term Debt Outstanding 21,461.0
21,173.3
Long-term Debt Due Within One Year 2,616.1
1,753.7
Long-term Debt $ 18,844.9
$ 19,419.6

(a)Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for SNF disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $355 million and $348 million as of March 31, 2024 and December 31, 2023, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.

~~(a)~~

Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $313 million and $312 million as of March 31, 2018 and December 31, 2017, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.

Long-term Debt Activity

Long-term debt and other securities issued, retired and principal payments made during the first three months of ~~2018~~2024 are shown in the ~~tables below:~~following tables:


		Principal		Interest
Company	Type of Debt	Amount (a)		Rate	Due Date
Issuances:		(in millions)		(%)
AEPTCo	Senior Unsecured Notes	$	450.0	5.15	2034
APCo	Senior Unsecured Notes	400.0		5.65	2034












Non-Registrant:






Transource Energy	Other Long-term Debt	18.0		Variable	2025


Total Issuances		$	868.0

(a)Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.

150

Company Type of Debt Principal Amount (a) Interest Rate Due Date
Issuances: (in millions) (%)
OPCo Senior Unsecured Notes $ 400.0
4.15 2048
SWEPCo Senior Unsecured Notes 450.0
3.85 2048

Non-Registrant:
Transource Energy Other Long-term Debt 3.4
Variable 2020
Total Issuances $ 853.4


		Principal		Interest
Company	Type of Debt	Amount Paid		Rate	Due Date
Retirements and Principal Payments:		(in millions)		(%)
AEP	Junior Subordinated Notes	$	805.0	2.03	2024


AEP Texas	Securitization Bonds	11.9		2.06	2025
APCo	Other Long-term Debt	300.0		Variable	2024

APCo	Securitization Bonds	13.4		3.77	2028
I&M	Notes Payable	1.2		Variable	2024
I&M	Notes Payable	0.9		Variable	2025
I&M	Notes Payable	4.0		0.93	2025
I&M	Notes Payable	5.0		3.44	2026
I&M	Notes Payable	6.8		5.93	2027
I&M	Notes Payable	6.8		6.01	2028
I&M	Other Long-term Debt	0.7		6.00	2025
PSO	Other Long-term Debt	0.1		3.00	2027












Non-Registrant:
AEGCo	Notes Payable	5.0		2.43	2028
Transource Energy	Senior Unsecured Notes	1.4		2.75	2050



Total Retirements and Principal Payments		$	1,162.2


~~(a)~~	~~Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.~~

Long-term Debt Subsequent Events

Company Type of Debt Principal Amount Paid Interest Rate Due Date
Retirements and Principal Payments: (in millions) (%)
AEP Texas Securitization Bonds $ 70.0
5.17 2018
AEP Texas Securitization Bonds 26.5
5.306 2020
APCo Securitization Bonds 11.7
2.008 2023
I&M Notes Payable 0.8
Variable 2019
I&M Notes Payable 7.9
Variable 2019
I&M Notes Payable 4.8
Variable 2020
I&M Notes Payable 8.5
Variable 2021
I&M Notes Payable 7.0
Variable 2022
I&M Other Long-term Debt 0.4
6.00 2025
OPCo Securitization Bonds 22.9
2.049 2019
PSO Other Long-term Debt 0.1
3.00 2027
SWEPCo Pollution Control Bonds 81.7
4.95 2018
SWEPCo Senior Unsecured Notes 300.0
5.875 2018
SWEPCo Other Long-term Debt 0.1
3.50 2023
SWEPCo Notes Payable 1.6
4.58 2032
Total Retirements and Principal Payments $ 544.0

~~As of March 31, 2018, trustees held, on behalf of AEP, $678 million of their reacquired Pollution Control Bonds. Of this total, $104 million and $345 million related to APCo and OPCo, respectively.~~

In April ~~2018, AEP Texas retired $30~~2024, APCo remarketed $86 million of ~~5.89% Senior Unsecured Notes due in 2018.~~Pollution Control Bonds.

In April ~~2018,~~2024, I&M issued $80 million of 6.41% Notes Payable due in 2028.

In April 2024, I&M retired $2$8 million of Notes Payable related to DCC Fuel.

In April 2024, WPCo issued $450 million of 6.89% Notes Payable due in 2034.

In April 2024, WPCo retired $265 million of Other Long-term Debt.

Debt Covenants (Applies to AEP and AEPTCo)

Covenants in AEPTCo’s note purchase agreements and indenture limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. AEPTCo’s contractually-defined priority debt was ~~4.5%~~0.2% of consolidated tangible net assets as of March 31, ~~2018.~~2024. The method for calculating the consolidated tangible net assets is ~~contractually defined~~contractually-defined in the note purchase agreements.

Dividend Restrictions

Utility Subsidiaries’ Restrictions

Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. 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.

All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act ~~restriction~~requirement that prohibits the payment of dividends out of capital accounts ~~without regulatory approval;~~in certain circumstances; payment of dividends is generally allowed out of retained ~~earnings only. Additionally, the~~earnings. The Federal Power Act also creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to ~~AGR,~~ APCo and I&M.

Certain AEP subsidiaries have credit agreements that contain covenants that limit their debt to capitalization ratio to 67.5%. The method for calculating outstanding debt and capitalization is ~~contractually defined~~contractually-defined in the credit agreements.

151

The Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings.

Parent Restrictions (Applies to AEP)

The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries.

Pursuant to the leverage restrictions in credit agreements, AEP must 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~~contractually-defined in the credit agreements.

Corporate Borrowing Program ~~- AEP System~~ (Applies to all Registrant Subsidiaries)

~~The~~ AEP ~~System uses~~subsidiaries use a corporate borrowing program to meet ~~the~~their short-term borrowing ~~needs of AEP’s subsidiaries.~~needs. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility ~~subsidiaries,~~subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility ~~subsidiaries,~~subsidiaries; and direct borrowing from AEP. The AEP ~~System~~ Utility Money Pool operates in accordance with the terms and conditions of ~~the AEP System Utility Money Pool~~its agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of March 31, ~~2018~~2024 and December 31, ~~2017~~2023 are included in Advances to Affiliates and Advances from Affiliates, respectively, on ~~each of~~ the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and corresponding authorized borrowing limits for the three months ended March 31, ~~2018~~2024 are described in the following table:


	Maximum				Average				Net Loans to
	Borrowings		Maximum		Borrowings		Average		(Borrowings from)		Authorized
	from the		Loans to the		from the		Loans to the		the Utility Money		Short-term
	Utility		Utility		Utility		Utility		Pool as of		Borrowing
Company	Money Pool		Money Pool		Money Pool		Money Pool		March 31, 2024		Limit
	(in millions)
AEP Texas	$	267.9	$	—	$	191.2	$	—	$	(267.9)	$	600.0
AEPTCo	313.3		298.0		178.5		75.3		272.9		820.0		(a)
APCo	399.5		51.1		205.5		20.3		37.4		750.0
I&M	125.5		—		60.2		—		(73.2)		500.0
OPCo	295.2		—		143.4		—		(295.2)		500.0
PSO	264.6		—		128.8		—		(264.6)		750.0
SWEPCo	254.5		—		161.1		—		(254.5)		750.0

Company
Maximum
Borrowings
from the
Utility
Money Pool

Maximum
Loans to the
Utility
Money Pool

Average
Borrowings
from the
Utility
Money Pool

Average
Loans to the
Utility
Money Pool

Net Loans to
(Borrowings from)
the Utility Money
Pool as of
March 31, 2018

Authorized
Short-term
Borrowing
Limit

(in millions)
AEP Texas $ 307.2
$ 103.6
$ 219.2
$ 50.4
$ (232.7 ) $ 500.0

AEPTCo 337.3
123.9
188.2
26.3
(272.8 ) 795.0
(a)
APCo 285.6
23.7
223.6
23.5
(222.4 ) 600.0

I&M 314.1
12.5
240.6
12.5
(301.6 ) 500.0

OPCo 229.1
216.4
104.9
179.5
200.4
400.0

PSO 179.1
—
143.3
—
(179.1 ) 300.0

SWEPCo 169.1
296.5
143.7
273.2
(148.6 ) 350.0

(a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.


~~(a)~~	~~Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.~~

The activity in the above table does not include short-term lending activity of certain AEP nonutility subsidiaries. AEP Texas’ wholly-owned subsidiary, AEP Texas North Generation Company, LLC and SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, ~~LP are participants~~LLC participate in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of March 31, ~~2018~~2024 and December 31, ~~2017~~2023 are included in Advances to Affiliates on ~~each~~the subsidiaries’ balance sheets. The Nonutility Money Pool participants’ ~~money pool~~ activity for the three months ended March 31, ~~2018~~2024 is described in the following table:


		Maximum Loans		Average Loans		Loans to the Nonutility
		to the Nonutility		to the Nonutility		Money Pool as of
Company		Money Pool		Money Pool		March 31, 2024
	(in millions)
AEP Texas		$	7.1	$	7.0	$	7.0
SWEPCo		2.3		2.2		2.3

152

Maximum Maximum Average Average Loans to the
Borrowings from Loans to the Borrowings from Loans to the Nonutility
the Nonutility Nonutility the Nonutility Nonutility Money Pool as of
Company Money Pool Money Pool Money Pool Money Pool March 31, 2018
(in millions)
AEP Texas $ —
$ 8.4
$ —
$ 8.2
$ 8.1
SWEPCo —
2.0
—
2.0
2.0

AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of ~~outstanding loans to (borrowings from)~~borrowings from AEP as of March 31, ~~2018~~2024 and December 31, ~~2017~~2023 are included in Advances ~~to Affiliates and Advances~~ from Affiliates ~~respectively,~~ on AEPTCo’s balance sheets. AEPTCo’s direct ~~borrowing and lending activity~~financing activities with AEP and corresponding authorized borrowing limit for the three months ended March 31, ~~2018 is~~2024 are described in the following table:


												Authorized
Maximum	Maximum	Maximum		Average		Average		Borrowings from		Loans to		Short-term
Borrowings	Borrowings	Loans		Borrowings		Loans		AEP as of		AEP as of		Borrowing
Borrowings
Borrowings
from AEP
from AEP
from AEP	from AEP	to AEP		from AEP		to AEP		March 31, 2018		March 31, 2018		Limit
(in millions)
(in millions)
(in millions)
$	1.1	$	104.7	$	1.1	$	51.1	$	1.1	$	23.9	$	75.0	(a)	44.4	$	$	148.5	$	$	4.4	$	$	72.9	$	$	3.7	$	$	—	$	$	50.0	(a)	(a)


~~(a)~~	~~Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.~~

(a) Amount represents the authorized short-term borrowing limit from FERC or state regulatory agencies not otherwise included in the utility money pool above.

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool ~~were as follows:~~are summarized in the following table:


	Three Months Ended March 31,
	2024		2023
Maximum Interest Rate	5.79	%	5.42	%
Minimum Interest Rate	5.66	%	4.66	%

Three Months Ended March 31,
2018 2017
Maximum Interest Rate 2.42 % 1.27 %
Minimum Interest Rate 1.83 % 0.92 %

The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized ~~for all Registrant Subsidiaries~~ in the following table:


	Average Interest Rate for Funds				Average Interest Rate for Funds
	Borrowed from the Utility Money Pool				Loaned to the Utility Money Pool
	for Three Months Ended March 31,				for Three Months Ended March 31,
Company	2024		2023		2024		2023
AEP Texas	5.71	%	5.18	%	—	%	—	%
AEPTCo	5.72	%	5.09	%	5.70	%	5.29	%
APCo	5.74	%	5.14	%	5.72	%	5.12	%
I&M	5.73	%	5.12	%	—	%	5.16	%
OPCo	5.71	%	5.17	%	—	%	—	%
PSO	5.71	%	4.84	%	—	%	5.11	%
SWEPCo	5.71	%	5.12	%	—	%	—	%

Average Interest Rate Average Interest Rate
for Funds Borrowed for Funds Loaned
from the Utility Money Pool for to the Utility Money Pool for
Three Months Ended March 31, Three Months Ended March 31,
Company 2018 2017 2018 2017
AEP Texas 2.07 % 1.02 % 1.90 % — %
AEPTCo 2.06 % 1.08 % 1.92 % 0.99 %
APCo 2.00 % 1.04 % 2.00 % 1.03 %
I&M 2.02 % 1.04 % 2.00 % 1.03 %
OPCo 2.00 % 1.10 % 2.40 % 0.98 %
PSO 2.01 % 1.06 % — % — %
SWEPCo 2.10 % 1.06 % 1.88 % 0.98 %

Maximum, minimum and average interest rates for funds ~~either borrowed from or~~ loaned to the Nonutility Money Pool are summarized in the following ~~tables:~~table:

Three Months Ended March 31, 2024

Three Months Ended March 31, 2023

Maximum

Minimum

Average

Maximum

Minimum

Average

Interest Rate

for Funds

Loaned to

the Nonutility

Company

Money Pool

AEP Texas

5.79

5.66

5.72

5.42

4.66

5.12

SWEPCo

5.79

5.66

5.72

5.42

4.66

5.13

~~Three Months Ended March 31, 2018:~~

153

Maximum Minimum Maximum Minimum Average Average
Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate
for Funds for Funds for Funds for Funds for Funds for Funds
Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to
the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility
Company Money Pool Money Pool Money Pool Money Pool Money Pool Money Pool
AEP Texas — % — % 2.42 % 1.83 % — % 2.00 %
SWEPCo — % — % 2.42 % 1.83 % — % 2.00 %

~~Three Months Ended March 31, 2017:~~

Maximum Minimum Maximum Minimum Average Average
Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate
for Funds for Funds for Funds for Funds for Funds for Funds
Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to
the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility
Company Money Pool Money Pool Money Pool Money Pool Money Pool Money Pool
AEP Texas — % — % 1.27 % 0.92 % — % 1.03 %
SWEPCo — % — % 1.27 % . 0.92 % — % 1.03 %

AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table:


	Maximum		Minimum		Maximum		Minimum		Average		Average				Maximum			Minimum		Maximum			Minimum					Average
	Interest Rate		Interest Rate		Interest Rate		Interest Rate		Interest Rate		Interest Rate				Interest Rate										Interest Rate
Three Months	for Funds		for Funds		for Funds		for Funds		for Funds		for Funds		Three Months	for Funds										for Funds
Ended	Borrowed		Borrowed		Loaned		Loaned		Borrowed		Loaned		Ended	Borrowed			Borrowed		Loaned			Loaned				Borrowed			Loaned
March 31,	from AEP		from AEP		to AEP		to AEP		from AEP		to AEP		March 31,	from AEP		from AEP	to AEP				to AEP	from AEP		to AEP
2018	2.42	%	1.83	%	2.42	%	1.83	%	2.00	%	2.02	%
2017	1.27	%	0.92	%	1.27	%	0.92	%	1.03	%	1.04	%
2024													2024	5.79	%		5.66	%	5.79	%		5.66	%			5.74	%		5.71	%
2023													2023	5.38	%		4.53	%	5.38	%		4.53	%			5.03	%		5.15	%

Short-term Debt (Applies to AEP and SWEPCo)

Outstanding short-term debt was as follows:


		March 31, 2024				December 31, 2023
		Outstanding		Interest		Outstanding		Interest
Company	Type of Debt	Amount		Rate (a)		Amount		Rate (a)
		(dollars in millions)
AEP	Securitized Debt for Receivables (b)	$	900.0	5.54	%	$	888.0	5.65	%
AEP	Commercial Paper	2,832.2		5.61	%	1,937.9		5.69	%






SWEPCo	Notes Payable	5.4		7.68	%	4.3		7.71	%
	Total Short-term Debt	$	3,737.6			$	2,830.2

March 31, 2018 December 31, 2017
Company Type of Debt
Outstanding
Amount

Interest
Rate (a)
Outstanding
Amount Interest
Rate (a)
(in millions)
(in millions)
AEP Securitized Debt for Receivables (b) $ 750.0
1.74 % $ 718.0
1.22 %
AEP Commercial Paper 1,886.2
2.41 % 898.6
1.85 %
SWEPCo Notes Payable 22.6
3.20 % 22.0
2.92 %
Total Short-term Debt $ 2,658.8

$ 1,638.6

(a)Weighted-average rate as of March 31, 2024 and December 31, 2023, respectively.


~~(a)~~	~~Weighted average rate.~~


~~(b)~~	~~Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.~~

(b)Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 5.

Securitized Accounts ~~Receivable~~Receivables – AEP Credit (Applies to AEP)

AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections.

AEP Credit’s receivables securitization agreement provides a commitment of ~~$750~~$900 million from bank conduits to purchase receivables and expires in ~~June 2019.~~September 2025. As of March 31, 2024, the affiliated utility subsidiaries were in compliance with all requirements under the agreement.

Accounts receivable information for AEP Credit iswas as follows:


	Three Months Ended March 31,
	2024			2023
	(dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable	5.61		%	4.86		%
Net Uncollectible Accounts Receivable Written-Off	$	8.1		$	6.9

Three Months Ended March 31,
2018 2017
(dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable 1.74 % 1.00 %
Net Uncollectible Accounts Receivable Written Off $ 4.2
$ 5.9


	March 31, 2024		December 31, 2023
	(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts	$	1,164.2	$	1,207.4
Short-term – Securitized Debt of Receivables	900.0		888.0
Delinquent Securitized Accounts Receivable	58.2		52.2
Bad Debt Reserves Related to Securitization	42.6		42.0
Unbilled Receivables Related to Securitization	336.9		409.8

March 31, 2018 December 31, 2017
(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 944.5
$ 925.5
Short-term – Securitized Debt of Receivables 750.0
718.0
Delinquent Securitized Accounts Receivable 55.1
41.1
Bad Debt Reserves Related to Securitization 30.8
28.7
Unbilled Receivables Related to Securitization 249.9
303.2

AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due.

154

Securitized Accounts Receivables – AEP Credit (Applies to all Registrant Subsidiaries except AEP Texas and AEPTCo)

Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreements were:


Company	March 31, 2024		December 31, 2023
	(in millions)
APCo	$	196.5	$	184.6
I&M	167.0		156.4
OPCo	536.0		541.7
PSO	96.3		134.6
SWEPCo	144.2		168.3

Company March 31, 2018 December 31, 2017
(in millions)
APCo $ 139.2
$ 136.2
I&M 147.8
136.5
OPCo 386.2
367.4
PSO 109.2
115.1
SWEPCo 130.6
138.2

The fees paid to AEP Credit for customer accounts receivable sold were:


	Three Months Ended March 31,					Three Months Ended March 31,
Company	2018		2017		Company			2024	2023
	(in millions)						(in millions)
APCo	$	1.7	$	1.4
I&M	2.1		1.5
OPCo	5.6		5.7
PSO	1.8		1.5
SWEPCo	1.9		1.6

The proceeds on the sale of receivables to AEP Credit were:


	Three Months Ended March 31,
Company			2024		2023
		(in millions)
APCo			$	536.0	$	506.2
I&M			529.7		525.4
OPCo			845.7		884.4
PSO			361.6		416.3
SWEPCo			425.4		437.6

155

Three Months Ended March 31,
Company 2018 2017
(in millions)
APCo $ 400.2
$ 369.7
I&M 459.1
418.2
OPCo 680.0
632.3
PSO 332.6
286.8
SWEPCo 397.6
341.2

13. VARIABLE INTEREST ENTITIES

The disclosures in this note apply to AEP ~~only.~~unless indicated otherwise.

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a variable interest in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently.

~~Desert Sky Wind Farm LLC (Desert Sky)~~AEP holds ownership interests in businesses with varying ownership structures. Partnership interests and ~~Trent Wind Farm LLC (Trent) (collectively “the LLCs”) were established for~~other variable interests are evaluated to determine if each entity is a VIE, and if so, whether or not the ~~purpose~~VIE should be consolidated into AEP’s financial statements. AEP has not provided material financial or other support that was not previously contractually required to any of repowering, owning and operating approximately 310.5 MW of wind-powered electric energy generation facilities in Texas. In January 2018, AEP admitted a non-affiliate as a member of the LLCs to own and repower Desert Sky and Trent, whichits consolidated VIEs. If an entity is ~~expected~~determined not to be ~~completed in 2018. The non-affiliate contributed full turbine sets~~a VIE, or if the entity is determined to ~~each project in exchange for~~be a ~~20.1% interest in the LLCs. The non-affiliates’ contribution of $84 million was recorded as Net Property, Plant~~VIE and Equipment on the balance sheets, which was the fair value as of the contribution date determined based on key input assumptions of the original cost of the full turbine sets and the discounted cash flow benefit associated with the production tax credits available from repowering Desert Sky and Trent based on their expected net capacity, capacity factor and the operational availability. AEP owns 79.9% of the LLCs. As a result, management has concluded that Desert Sky and Trent, collectively, are VIE’s and that AEP is not deemed to be the primary beneficiary, ~~based~~the entity is accounted for under the equity method of accounting.

Consolidated Variable Interests Entities

The Annual Report on ~~its power~~Form 10-K for the year ended December 31, 2023 includes a detailed discussion of the Registrants’ consolidated VIEs.

The balances below represent the assets and liabilities of consolidated VIEs. These balances include intercompany transactions that are eliminated upon consolidation.




March 31, 2024

	Consolidated VIEs
	SWEPCo Sabine		I&M DCC Fuel		AEP Texas Transition Funding			AEP Texas Restoration Funding			APCo Appalachian Consumer Rate Relief Funding			AEP Credit		Protected Cell of EIS		Transource Energy
	(in millions)
ASSETS
Current Assets	$	5.1	$	75.3	$	40.1		$	20.4		$	6.3		$	1,165.3	$	211.6	$	31.7
Net Property, Plant and Equipment	—		129.5		—			—			—			—		—		536.9
Other Noncurrent Assets	140.1		63.5		55.3		(a)	139.7		(b)	130.3		(c)	10.2		—		9.3
Total Assets	$	145.2	$	268.3	$	95.4		$	160.1		$	136.6		$	1,175.5	$	211.6	$	577.9

LIABILITIES AND EQUITY
Current Liabilities	$	22.8	$	75.1	$	76.3		$	36.4		$	29.0		$	1,113.7	$	52.3	$	22.5
Noncurrent Liabilities	122.1		193.2		14.7			122.4			105.7			1.0		90.8		258.8
Equity	0.3		—		4.4			1.3			1.9			60.8		68.5		296.6
Total Liabilities and Equity	$	145.2	$	268.3	$	95.4		$	160.1		$	136.6		$	1,175.5	$	211.6	$	577.9

(a)Includes an intercompany item eliminated in consolidation of $6 million.

(b)Includes an intercompany item eliminated in consolidation of $6 million.

(c)Includes an intercompany item eliminated in consolidation of $2 million.

156




December 31, 2023

	Consolidated VIEs
	SWEPCo Sabine		I&M DCC Fuel		AEP Texas Transition Funding			AEP Texas Restoration Funding			APCo Appalachian Consumer Rate Relief Funding			AEP Credit		Protected Cell of EIS		Transource Energy
	(in millions)
ASSETS
Current Assets	$	4.2	$	81.9	$	25.5		$	27.5		$	13.3		$	1,208.8	$	205.3	$	36.9
Net Property, Plant and Equipment	—		153.8		—			—			—			—		—		533.4
Other Noncurrent Assets	150.7		81.7		71.4		(a)	145.6		(b)	138.2		(c)	9.6		—		5.1
Total Assets	$	154.9	$	317.4	$	96.9		$	173.1		$	151.5		$	1,218.4	$	205.3	$	575.4

LIABILITIES AND EQUITY
Current Liabilities	$	19.9	$	81.7	$	75.5		$	36.8		$	29.9		$	1,155.0	$	49.2	$	45.3
Noncurrent Liabilities	134.8		235.7		17.0			135.1			119.7			0.9		91.7		241.5
Equity	0.2		—		4.4			1.2			1.9			62.5		64.4		288.6
Total Liabilities and Equity	$	154.9	$	317.4	$	96.9		$	173.1		$	151.5		$	1,218.4	$	205.3	$	575.4

(a)Includes an intercompany item eliminated in consolidation of $8 million.

(b)Includes an intercompany item eliminated in consolidation of $6 million.

(c)Includes an intercompany item eliminated in consolidation of $2 million.

Significant Variable Interests in Non-Consolidated VIEs and Significant Equity Method Investments

The Annual Report on Form 10-K for the year ended December 31, 2023 includes a detailed discussion of significant variable interests in non-consolidated VIEs and other significant equity method investments. As of December 31, 2023, AEP no longer owns interests in four joint ventures due to ~~direct the activities that most significantly impact Desert Sky and Trent’s economic performance. Also in January 2018, Desert Sky and Trent entered into a forward PPA for~~ the sale of ~~power to AEPEP related to deliveries of electricity beginning January 1, 2021~~the Competitive Contracted Renewables Portfolio. Previously held by AEP Wind Holdings, LLC, the interests were accounted for ~~a 12 year period. Prior to~~under the ~~effective date~~equity method. See the “Disposition of the ~~PPA, Desert Sky and Trent will sell power at market rates into ERCOT. AEP and the non-affiliate will share tax attributes including production tax credits and cash distributions from the operation~~Competitive Contracted Renewables Portfolio” section of ~~the LLCs generally consistent with the ownership percentages. See the table below~~Note 6 for ~~the classification of Desert Sky and Trent’s assets and liabilities on the balance sheets:~~additional information.

157

American Electric Power Company, Inc.
Variable Interest Entities
March 31, 2018

Desert Sky and Trent
(in millions)
ASSETS
Current Assets $ 41.1
Net Property, Plant and Equipment 255.4
Other Noncurrent Assets 0.7
Total Assets $ 297.2

LIABILITIES AND EQUITY
Current Liabilities $ 41.4
Noncurrent Liabilities 8.3
Equity 247.5
Total Liabilities and Equity $ 297.2

AEP has a call right, which if exercised, would require the non-affiliate to sell its noncontrolling interest in the LLCs to AEP. The exercise period is for ninety days, beginning two years after the repowering completion. The non-affiliates’ interest in the LLCs is presented as redeemable noncontrolling interest on the balance sheets. The non-affiliate holds redemption rights, which if exercised, would require AEP to purchase the non-affiliates’ noncontrolling interest in the LLCs. The exercise price for both the call and redemption right are determined using a discounted cash flow model with agreed input assumptions as well as potential updates to certain assumptions reasonably expected based on the actual results of the LLCs. As of March 31, 2018, AEP recorded $71 million of Redeemable Noncontrolling Interest in Mezzanine Equity on the balance sheets.

14. REVENUE FROM CONTRACTS WITH CUSTOMERS

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

Disaggregated Revenues from Contracts with Customers

The ~~table~~tables below ~~represents~~represent AEP’s reportable segment revenues from contracts with customers, net of respective provisions for refund, by type of revenue:


	Three Months Ended March 31, 2024
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other		Reconciling Adjustments		AEP Consolidated
	(in millions)
Retail Revenues:
Residential Revenues	$	1,212.3	$	703.8	$	—	$	—	$	—	$	—	$	1,916.1
Commercial Revenues	645.1		397.0		—		—		—		—		1,042.1
Industrial Revenues (a)	647.1		136.1		—		—		—		(0.2)		783.0
Other Retail Revenues	55.3		13.9		—		—		—		—		69.2
Total Retail Revenues	2,559.8		1,250.8		—		—		—		(0.2)		3,810.4

Wholesale and Competitive Retail Revenues:
Generation Revenues	235.9		—		—		27.4		—		0.1		263.4
Transmission Revenues (b)	118.9		179.8		488.7		—		—		(418.6)		368.8
Renewable Generation Revenues (a)	—		—		—		6.3		—		(1.4)		4.9
Retail, Trading and Marketing Revenues (c)	—		—		—		571.4		0.5		(46.2)		525.7
Total Wholesale and Competitive Retail Revenues	354.8		179.8		488.7		605.1		0.5		(466.1)		1,162.8

Other Revenues from Contracts with Customers (d)	59.7		51.0		8.1		1.3		60.4		(68.7)		111.8

Total Revenues from Contracts with Customers	2,974.3		1,481.6		496.8		606.4		60.9		(535.0)		5,085.0

Other Revenues:
Alternative Revenue Programs (e)	(0.7)		0.7		0.5		—		—		1.0		1.5
Other Revenues (a) (f)	(25.7)		7.9		—		(42.9)		(8.1)		8.0		(60.8)
Total Other Revenues	(26.4)		8.6		0.5		(42.9)		(8.1)		9.0		(59.3)

Total Revenues	$	2,947.9	$	1,490.2	$	497.3	$	563.5	$	52.8	$	(526.0)	$	5,025.7

Three Months Ended March 31, 2018
Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other Reconciling Adjustments AEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues $ 1,001.2
$ 567.9
$ —
$ —
$ —
$ —
$ 1,569.1
Commercial Revenues 515.8
300.3
—
—
—
—
816.1
Industrial Revenues 518.9
113.2
—
—
—
—
632.1
Other Retail Revenues 43.8
9.5
—
—
—
—
53.3
Total Retail Revenues 2,079.7
990.9
—
—
—
—
3,070.6

Wholesale and Competitive Retail Revenues:
Generation Revenues 214.0
—
—
145.1
—
—
359.1
Generation Revenues – Affiliated 3.0
—
—
27.1
—
(30.1 ) —
Transmission Revenues 57.9
94.1
56.8
—
—
—
208.8
Transmission Revenues – Affiliated 17.1
—
162.7
—
—
(179.8 ) —
Marketing, Competitive Retail and Renewable Revenues —
—
—
309.7
—
—
309.7
Total Wholesale and Competitive Retail Revenues 292.0
94.1
219.5
481.9
—
(209.9 ) 877.6

Other Revenues from Contracts with Customers 34.7
49.0
0.3
1.7
5.0
—
90.7
Other Revenues from Contracts with Customers - Affiliated 5.2
0.7
1.7
0.5
17.0
(25.1 ) —

Total Revenues from Contracts with Customers 2,411.6
1,134.7
221.5
484.1
22.0
(235.0 ) 4,038.9

Other Revenues:
Alternative Revenues (9.1 ) 6.0
(16.0 ) —
—
—
(19.1 )
Other Revenues 5.5
—
—
21.0
2.0
—
28.5
Other Revenues - Affiliated —
21.7
—
—
—
(21.7 ) —
Total Other Revenues (3.6 ) 27.7
(16.0 ) 21.0
2.0
(21.7 ) 9.4

Total Revenues $ 2,408.0
$ 1,162.4
$ 205.5
$ 505.1
$ 24.0
$ (256.7 ) $ 4,048.3

(a)Amounts include affiliated and nonaffiliated revenues.

(b)Amounts include affiliated and nonaffiliated revenues. The ~~table below represents revenues from contracts with customers, net of respective provisions for refund, by type of~~affiliated revenue for ~~the Registrant Subsidiaries:~~AEP Transmission Holdco was $387 million. The remaining affiliated amounts were immaterial.

Three Months Ended March 31, 2018
AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCO
(in millions)
Retail Revenues:
Residential Revenues $ 131.6
$ —
$ 414.0
$ 189.0
$ 436.8
$ 141.1
$ 140.1
Commercial Revenues 105.4
—
147.1
110.8
194.7
88.0
110.1
Industrial Revenues 25.8
—
146.8
130.8
87.7
65.4
75.4
Other Retail Revenues 6.2
—
19.6
2.2
3.2
18.3
2.1
Total Retail Revenues 269.0
—
727.5
432.8
722.4
312.8
327.7

Wholesale Revenues:
Generation Revenues —
—
22.3
111.1
—
5.9
59.9
Generation Revenues – Affiliated —
—
40.5
2.9
—
—
—
Transmission Revenues 78.0
48.3
16.9
6.8
16.0
10.6
20.2
Transmission Revenues – Affiliated —
160.1
7.9
—
—
—
5.8
Total Wholesale Revenues 78.0
208.4
87.6
120.8
16.0
16.5
85.9

Other Revenues from Contracts with Customers 6.7
0.1
10.2
7.7
42.3
3.1
5.8
Other Revenues from Contracts with Customers - Affiliated 0.4
2.0
1.0
15.0
—
1.1
0.3

Total Revenues from Contracts with Customers 354.1
210.5
826.3
576.3
780.7
333.5
419.7

Other Revenues:
Alternative Revenues (0.3 ) (17.0 ) (5.9 ) (5.0 ) 6.3
3.3
(0.3 )
Other Revenues —
—
—
5.5
0.8
—
—
Other Revenues - Affiliated 17.8
—
—
—
3.1
—
—
Total Other Revenues 17.5
(17.0 ) (5.9 ) 0.5
10.2
3.3
(0.3 )

Total Revenues $ 371.6
$ 193.5
$ 820.4
$ 576.8
$ 790.9
$ 336.8
$ 419.4

~~Performance Obligations~~

AEP has performance obligations as part of its normal course of business. A performance obligation is a promise to transfer a distinct good or service, or a series of distinct goods or services that are substantially the same(c)Amounts include affiliated and ~~have the same pattern of transfer to a customer.~~nonaffiliated revenues. The invoice practical expedient within the accounting guidance for “Revenue from Contracts with Customers” allows for the recognition of revenue from performance obligations in the amount of consideration to which there is a right to invoice the customer and when the amount for which there is a right to invoice corresponds directly to the value transferred to the customer.

The purpose of the invoice practical expedient is to depict an entity’s measure of progress toward completion of the performance obligation within a contract and can only be applied to performance obligations that are satisfied over time and when the invoice is representative of services provided to date. AEP subsidiaries elected to apply the invoice practical expedient to recognizeaffiliated revenue for performance obligations satisfied over time as the invoices from the respective revenue streams are representative of services or goods provided to date to the customer. Performance obligations for AEP’s subsidiaries are summarized as follows:

~~Retail Revenues~~

AEP’s subsidiaries within the Vertically Integrated Utilities and Transmission and Distribution Utilities segments have performance obligations to generate, transmit and distribute electricity for sale to rate-regulated retail customers. The performance obligation to deliver electricity is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Revenues are variable as they are subject to the customer’s usage requirements.

Rate-regulated retail customers typically have the right to discontinue receiving service at will, therefore these contracts between AEP’s subsidiaries and their customers for rate-regulated services are generally limited to the services requested and received to date for such arrangements. Retail customers are generally billed on a monthly basis, and payment is typically due within 15 to 20 days after the issuance of the invoice. Payments from Retail Electric Providers are due to AEP Texas within 35 days.

~~Wholesale Revenues - Generation~~

~~AEP’s subsidiaries within the Vertically Integrated Utilities and~~ Generation & Marketing ~~segments have performance obligations to sell electricity to wholesale customers from generation assets~~was $46 million. The remaining affiliated amounts were immaterial.

(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Corporate and Other was $48 million. The remaining affiliated amounts were immaterial.

(e)Alternative revenue programs in PJM, SPP and ERCOT. The performance obligation to deliver electricity from generation assets is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Wholesale generation revenues are variable as they are subject to the customer’s usage requirements.certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.

~~AEP’s subsidiaries within the Vertically Integrated Utilities and~~ (f)Generation & Marketing segments also have performance obligations to stand ready in order to promote grid reliability. Stand ready services are sold into PJM’s Reliability Pricing Model (RPM) capacity market. RPM entails a base auctionincludes economic hedge activity.

158


	Three Months Ended March 31, 2023
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other		Reconciling Adjustments		AEP Consolidated
	(in millions)
Retail Revenues:
Residential Revenues	$	1,170.4	$	656.8	$	—	$	—	$	—	$	—	$	1,827.2
Commercial Revenues	633.4		375.9		—		—		—		—		1,009.3
Industrial Revenues	670.3		212.9		—		—		—		(0.2)		883.0
Other Retail Revenues	56.8		12.1		—		—		—		—		68.9
Total Retail Revenues	2,530.9		1,257.7		—		—		—		(0.2)		3,788.4

Wholesale and Competitive Retail Revenues:
Generation Revenues	182.8		—		—		32.4		—		—		215.2
Transmission Revenues (a)	114.7		164.2		450.1		—		—		(401.8)		327.2
Renewable Generation Revenues (b)	—		—		—		21.3		—		(0.1)		21.2
Retail, Trading and Marketing Revenues (b)	—		—		—		413.7		(0.3)		0.1		413.5
Total Wholesale and Competitive Retail Revenues	297.5		164.2		450.1		467.4		(0.3)		(401.8)		977.1

Other Revenues from Contracts with Customers (c)	32.6		42.8		3.6		0.6		29.4		(43.7)		65.3

Total Revenues from Contracts with Customers	2,861.0		1,464.7		453.7		468.0		29.1		(445.7)		4,830.8

Other Revenues:
Alternative Revenue Programs (d)	(3.1)		(11.6)		1.8		—		—		2.9		(10.0)
Other Revenues (b) (e)	(0.1)		11.1		—		(141.0)		1.0		(0.9)		(129.9)
Total Other Revenues	(3.2)		(0.5)		1.8		(141.0)		1.0		2.0		(139.9)

Total Revenues	$	2,857.8	$	1,464.2	$	455.5	$	327.0	$	30.1	$	(443.7)	$	4,690.9

(a)Amounts include affiliated and ~~at least three incremental auctions~~nonaffiliated revenues. The affiliated revenue for a specific PJM delivery year, with the incremental auctions spanning three years. The performance obligation to stand ready is satisfied over time and the consideration for which is variable until the occurrence of the third incremental auction, at which point the performance obligation becomes fixed.

Payments from the RTO for stand ready services are typically received within one week from the issuance of the invoice, which is typically issued weekly. Gross margin resulting from generation sales within the Vertically Integrated Utilities segment are primarily subject to margin sharing agreements with customers and vary by state, where the revenues are reflected gross in the disaggregated revenue tables above.

~~Wholesale Revenues - Generation Affiliated~~

APCo has a performance obligation to supply wholesale electricity to KGPCo through a purchased power agreement. The FERC regulates the cost-based wholesale power transactions between APCo and KGPCo. The purchased power agreement includes a component for the recovery of transmission costs under the FERC OATT. The transmission cost component of purchased power is cost-based and regulated by the TRA. APCo’s performance obligation under the purchased power agreement is satisfied over time as KGPCo simultaneously receives and consumes the wholesale electricity. APCo’s revenues from the purchased power agreement are presented within the Generation Revenues - Affiliated line in the disaggregated revenue tables above.

~~Wholesale Revenues - Transmission~~

~~AEP’s subsidiaries within the Vertically Integrated Utilities, Transmission and Distribution Utilities and~~ AEP Transmission Holdco ~~segments have performance obligations to transmit electricity to wholesale customers through assets owned~~was $357 million. The remaining affiliated amounts were immaterial.

(b)Amounts include affiliated and ~~operated by AEP subsidiaries.~~nonaffiliated revenues.

(c)Amounts include affiliated and nonaffiliated revenues. The ~~performance obligation to provide transmission services~~affiliated revenue for Corporate and Other was $29 million. The remaining affiliated amounts were immaterial.

(d)Alternative revenue programs in ~~PJM, SPP and ERCOT encompass a time frame greater than a year, where the performance obligation within each RTO is partially fixed~~certain jurisdictions include regulatory mechanisms that periodically adjust for ~~a period~~over/under collection of ~~one year or less. Payments from the RTO for transmission services are typically received within one week from the issuance of the invoice, which is issued monthly for SPP and ERCOT and weekly for PJM.~~related revenues.

AEP subsidiaries within the PJM and SPP regions collect revenues through Transmission Formula Rates. The FERC-approved rates establish the annual transmission revenue requirement (ATRR) and transmission service rates for transmission owners. The formula rates establish rates for a one year period and also include a true-up calculation for the prior year’s billings, allowing for over/under-recovery of the transmission owner’s ATRR. The annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for “Regulated Operations,” and are therefore presented as such in the disaggregated revenue tables above. AEP subsidiaries within the ERCOT region collect revenues through a combination of base rates and interim Transmission Costs of Services filings that are approved by the PUCT.

~~Wholesale Revenues - Transmission Affiliated~~

APCo, I&M, KGPCo, KPCo, OPCo and WPCo (AEP East Companies) are parties to the Transmission Agreement (TA), which defines how transmission costs are allocated among the AEP East Companies on a 12-month average coincident peak basis. PSO, SWEPCO and AEPSC are parties to the Transmission Coordination Agreement (TCA) by and among PSO, SWEPCO and AEPSC, in connection with the operation of the transmission assets of the two AEP utility subsidiaries. AEPTCo is a load serving entity within the PJM and SPP regions providing transmission services to affiliates in accordance with the OATT, TA and TCA. Affiliate revenues as a result of the respective TA and the TCA are reflected as Transmission Revenues - Affiliated in the disaggregated revenue tables above.

~~Marketing, Competitive Retail and Renewable Revenues~~

~~AEP’s subsidiaries within the~~ (e)Generation & Marketing ~~segment have performance obligations~~includes economic hedge activity.

159


	Three Months Ended March 31, 2024
	AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Retail Revenues:
Residential Revenues	$	147.3	$	—	$	526.3	$	224.8	$	556.5	$	158.2	$	182.4
Commercial Revenues	110.9		—		188.3		144.8		286.1		103.0		140.0
Industrial Revenues (a)	35.6		—		196.4		147.9		100.5		80.3		95.0
Other Retail Revenues	9.7		—		28.1		1.3		4.2		21.5		2.6
Total Retail Revenues	303.5		—		939.1		518.8		947.3		363.0		420.0

Wholesale Revenues:
Generation Revenues (b)	—		—		85.1		137.3		—		2.2		47.1
Transmission Revenues (c)	155.9		475.4		47.1		10.1		23.8		10.8		39.6
Total Wholesale Revenues	155.9		475.4		132.2		147.4		23.8		13.0		86.7

Other Revenues from Contracts with Customers (d)	8.8		8.1		21.7		27.6		42.2		12.0		9.6

Total Revenues from Contracts with Customers	468.2		483.5		1,093.0		693.8		1,013.3		388.0		516.3

Other Revenues:
Alternative Revenue Programs (e)	(1.8)		(0.7)		(0.1)		(0.5)		2.6		(0.2)		(0.1)
Other Revenues (a)	—		—		0.1		(25.9)		7.9		—		—
Total Other Revenues	(1.8)		(0.7)		—		(26.4)		10.5		(0.2)		(0.1)

Total Revenues	$	466.4	$	482.8	$	1,093.0	$	667.4	$	1,023.8	$	387.8	$	516.2

(a)Amounts include affiliated and nonaffiliated revenues.

(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $41 million primarily related to ~~deliver electricity~~the PPA with KGPCo.

(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $384 million, APCo was $21 million and SWEPCo was $14 million. The remaining affiliated amounts were immaterial.

(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $18 million primarily related to ~~competitive retail~~barging, urea transloading and ~~wholesale customers. Performance obligations~~other transportation services. The remaining affiliated amounts were immaterial.

(e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for ~~marketing, competitive retail~~over/under collection of related revenues.

160


	Three Months Ended March 31, 2023
	AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Retail Revenues:
Residential Revenues	$	130.7	$	—	$	470.5	$	239.6	$	526.0	$	170.9	$	175.9
Commercial Revenues	97.3		—		171.3		138.9		278.5		109.1		143.5
Industrial Revenues	39.3		—		185.8		152.6		173.6		98.3		104.2
Other Retail Revenues	8.3		—		26.2		1.3		3.8		24.2		2.6
Total Retail Revenues	275.6		—		853.8		532.4		981.9		402.5		426.2

Wholesale Revenues:
Generation Revenues (a)	—		—		80.2		104.0		—		0.9		39.6
Transmission Revenues (b)	146.3		438.7		41.4		8.1		17.9		11.3		42.9
Total Wholesale Revenues	146.3		438.7		121.6		112.1		17.9		12.2		82.5

Other Revenues from Contracts with Customers (c)	9.7		3.7		13.0		21.4		33.2		2.3		7.9

Total Revenues from Contracts with Customers	431.6		442.4		988.4		665.9		1,033.0		417.0		516.6

Other Revenues:
Alternative Revenue Programs (d)	(2.1)		(0.8)		(0.7)		(2.9)		(9.5)		—		(0.7)
Other Revenues (e)	—		—		—		—		11.1		—		—
Total Other Revenues	(2.1)		(0.8)		(0.7)		(2.9)		1.6		—		(0.7)

Total Revenues	$	429.5	$	441.6	$	987.7	$	663.0	$	1,034.6	$	417.0	$	515.9

(a)Amounts include affiliated and ~~renewable offtake sales are satisfied over time as~~nonaffiliated revenues. The affiliated revenue for APCo was $47 million primarily related to the ~~customer simultaneously receives~~PPA with KGPCo.

(b)Amounts include affiliated and ~~consumes the benefits provided. Revenues are~~nonaffiliated revenues. The affiliated revenue for AEPTCo was $349 million. The remaining affiliated amounts were immaterial.

(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $18 million primarily ~~variable as they are subject~~related to ~~customer’s usage requirements; however,~~barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.

(d)Alternative revenue programs in certain ~~contracts mandate a delivery~~jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of ~~a set quantity of electricity at a predetermined price, resulting in a fixed performance obligation.~~related revenues.

(e)Amounts include affiliated and nonaffiliated revenues.

Payment terms under marketing arrangements typically follow standard Edison Electric Institute and International Swaps and Derivatives Association terms, which call for payment in 20 days. Payments for competitive retail and offtake arrangements for renewable assets range from 15 to 60 days and are dependent on the product sold, location and the creditworthiness of customer. Invoices for marketing arrangements, competitive retail and offtake arrangements for renewable assets are issued monthly.

Fixed Performance Obligations (Applies to AEP, APCo and I&M)

The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of March 31, ~~2018.~~2024. Fixed performance obligations primarily include ~~wholesale transmission services,~~ electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market.

Company (a) Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total
(in millions)
AEP $ 748.7
$ 256.1
$ 164.1
$ 348.7
$ 1,517.6
AEP Texas 233.4
—
—
—
233.4
AEPTCo 536.2
—
—
—
536.2
APCo 92.0
31.8
22.7
11.4
157.9
I&M 20.6
8.7
8.7
4.3
42.3
OPCo 42.1
—
—
—
42.1
PSO 11.9
—
—
—
11.9
SWEPCo 24.9
—
—
—
24.9

~~(a)Amounts~~ The Registrants elected to apply the exemption to not disclose the value of unsatisfied performance obligations for contracts with an original expected term of one year or less. Due to the annual establishment of revenue requirements, transmission revenues are excluded from the table below. The Registrant Subsidiaries amounts shown in the table below include affiliated and nonaffiliated ~~revenues except for AEP.~~revenues.


Company	2024		2025-2026		2027-2028		After 2028		Total
	(in millions)
AEP	$	62.3	$	166.8	$	84.1	$	24.7	$	337.9


APCo	12.1		32.2		24.3		11.7		80.3
I&M	3.3		8.8		8.8		4.5		25.4

161

Contract Assets and Liabilities

Contract assets are recognized when the Registrants have a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. The Registrants dodid not have ~~any~~ material contract assets as of March 31, ~~2018.~~2024 and December 31, 2023.

When the Registrants receive consideration, or such consideration is unconditionally due from a customer prior to transferring goods or services to the customer under the terms of a sales contract, they recognize a contract liability on the balance ~~sheet~~sheets in the amount of that consideration. Revenue for such consideration is subsequently recognized in the period or periods in which the remaining performance obligations in the contract are satisfied. The Registrants’ contract liabilities typically arise from services provided under joint use agreements for utility poles. The Registrants dodid not have ~~any~~ material contract liabilities as of March 31, ~~2018.~~2024 and December 31, 2023.

Accounts Receivable from Contracts with Customers

Accounts receivable from contracts with customers are presented on the ~~Registrants’~~Registrant Subsidiaries’ balance sheets within the Accounts Receivable - Customers line item. The ~~Registrants’~~Registrant Subsidiaries’ balances for receivables from contracts that are not recognized in accordance with the accounting guidance for “Revenue from Contracts with Customers” included in Accounts Receivable - Customers ~~are~~were not material as of March 31, ~~2018.~~2024 and December 31, 2023. See “Securitized Accounts Receivable - AEP Credit” section of Note 12 for additional ~~information related to AEP Credit’s securitized accounts receivable.~~information.

The following table represents the amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable - Affiliated Companies on the Registrant Subsidiaries’ balance sheets:


	AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
March 31, 2024	$	—	$	129.2	$	77.8	$	55.8	$	72.3	$	10.8	$	16.1
December 31, 2023	—		123.2		71.7		44.0		70.1		12.4		27.4

162

Company March 31, 2018 January 1, 2018
(in millions)
AEP Texas $ —
$ —
AEPTCo 60.6
47.1
APCo 36.3
35.6
I&M 14.8
15.1
OPCo 27.1
26.1
PSO 6.2
6.1
SWEPCo 11.4
11.0

~~Contract Costs~~

Contract costs to obtain or fulfill a contract for AEP subsidiaries within the Generation & Marketing segment are accounted for under the guidance for “Other Assets and Deferred Costs” and presented as a single asset and neither bifurcated nor reclassified between current and noncurrent assets on the Registrants’ balance sheets. Contract costs to acquire a contract are amortized in a manner consistent with the transfer of goods or services to the customer in Other Operation on the Registrants’ income statements. The Registrants do not have material contract costs as of March 31, 2018.

CONTROLS AND PROCEDURES

During the first quarter of ~~2018~~,2024, management, including the principal executive officer and principal financial officer of each of the Registrants, evaluated the Registrants’ disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. As of March 31, ~~2018,~~2024, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives.

There was no change in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the first quarter of ~~2018~~2024 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

163

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For a discussion of material legal proceedings, see ~~Note 5~~ - ~~Commitments,~~“Commitments, Guarantees and Contingencies,” of Note 5incorporated herein by reference.

Item 1A. Risk Factors

The Annual Report on Form 10-K for the year ended December 31, ~~2017~~2023 includes a detailed discussion of risk factors. As of March 31, ~~2018,~~2024, the risk ~~factor~~factors appearing in ~~the 2017~~AEP’s 2023 Annual Report ~~on Form 10-K under the heading set forth below is~~are supplemented and updated as follows:

~~Certain elements~~The occurrence of ~~AEP’s transmission formula rates~~one or more wildfires could cause tremendous loss, impact the market value and credit ratings of our securities and have ~~been challenged, which could result in lowered rates and/or refunds of amounts previously collected and thus have an~~a material adverse effect on ~~AEP’s business,~~our financial ~~condition, results of operations and cash flows.~~condition. (Applies to all ~~Registrants~~Registrants)

More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other ~~than AEP Texas)~~

~~AEP provides transmission service under rates regulated by~~factors have increased the ~~FERC. The FERC has approved~~duration of the ~~cost-based formula rate templates used by~~wildfire season and the potential impact of an event. AEP’s infrastructure is aging and poses risks to safety and system reliability and wildfire mitigation initiatives may not be successful or effective in preventing or reducing wildfire-related events. Wildfires can occur even when effective mitigation procedures are followed. Despite AEP’s wildfire mitigation initiatives, a wildfire could be ignited, spread and cause damages, which would subject AEP to ~~calculate its respective annual revenue requirements, but it has not expressly approved~~significant liability. Other potential risks associated with wildfires include the ~~amount~~inability to secure sufficient insurance coverage, or increased costs of actual capital and operating expenditures to be used in the formula rates. All aspects of AEP’s rates accepted or approved by the FERC, including the formula rate templates, the rates of return on the actual equity portion of its respective capital structuresinsurance, regulatory recovery risk, litigation risk, and the approved targeted capital structures, are subject to challenge by interested parties at the FERC, or by the FERC on its own initiative. In addition, interested parties may challenge the annual implementationpotential for a credit downgrade and calculation by AEP of its projected rates and formula rate true up pursuant to its approved formula rate templates under AEP’s formula rate implementation protocols. If a challenger can establish that any of these aspects are unjust, unreasonable, unduly discriminatory or preferential, then the FERC will make appropriate prospective adjustments to them and/or disallow any of AEP’s inclusion of those aspects in the rate setting formula.

In April 2018, certain intervenors filed comments at the FERC recommending a base ROE of 8.48% and a one-time refund of $184 million. In addition, the FERC trial staff filed comments recommending a base ROE of 8.41% and one-time refund of $175 million. Also in April 2018, another intervenor recommended the refund be calculated in accordance with the approved base ROE. Management believes its financial statements adequately address the impact of the settlement agreement. If the FERC orders revenue reductions in excess of the terms of the settlement agreement, it could reduce future net income and cash flows and impact financial condition. A decision from the FERC is pending.

In June 2017, a similar complaint was filed with the FERC claiming that the base ROE used by certain AEP subsidiaries that operate in SPP, including the West Transcos, in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36%, effective upon the date of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.

End-use consumers and entities supplying electricity to end-use consumers may also attempt to influence government and/or regulators to change the rate setting methodologies that apply to AEP, particularly if rates for delivered electricity increase substantially.

~~OVEC may require~~subsequent additional ~~liquidity and other capital support. (Applies to AEP, APCo, I&M and OPCo)~~

AEP and several nonaffiliated utility companies own OVEC. The Inter-Company Power Agreement (ICPA) defines the rights and obligations and sets the power participation ratio of the parties to it. Under the ICPA, parties are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,400 MWs) in proportion to their respective power participation ratios. The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%. If a party fails to make payments owed by it under the ICPA, OVEC may not have sufficient funds to honor its payment obligations, including its ongoing operating expenses as well as its indebtedness. OVEC has outstanding indebtedness of approximately $1.4 billion, of which APCo, I&M, and OPCo are collectively responsible for $622 million through the ICPA. Although they are not an obligor or guarantor, APCo, I&M, and OPCo are responsible for their respective ratio of OVEC’s outstanding debt through the ICPA.

A nonaffiliated party, whose aggregate power participation ratio is 4.85% under the ICPA, has filed a petition seeking protection under bankruptcy law. Bankruptcy filings typically trigger review of the petitioner’s contractual obligations, including, in this instance, the ICPA. Because the ICPA is subject to FERC approval and jurisdiction, prior to the bankruptcy petition OVEC made a filing at FERC seeking, among other objectives, to confirm FERC’s jurisdiction. Litigation related to these filings continues. In addition, as a result of these and prior related developments, OVEC’s credit ratings have been impacted.

If OVEC does not have sufficient funds to honor its payment obligations, there is risk that APCo, I&M and/or OPCo may need to make payments in addition to their power participation ratio payments. Further, if OVEC’s indebtedness is accelerated for any reason, there is risk that APCo, I&M and/or OPCo may be required to pay some or all of such accelerated indebtedness in amounts equal to their aggregate power participation ratio of 43.47%. Also, as a result of the credit rating agencies’ actions, OVEC’s abilitycosts to access capital ~~markets on terms as favorable as previously may diminish and its financing costs will increase.~~markets.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

~~None~~None.

Item 3. Defaults Upon Senior Securities

~~None~~None.

Item 4. Mine Safety Disclosures

~~The Federal Mine Safety~~Not applicable.

Item 5. Other Information

On March 1, 2024, Greg B. Hall, the Executive Vice President and ~~Health~~Chief Commercial Officer of the Company, entered into a Rule 10b5-1 trading agreement (“Rule 10b5-1 Trading Plan”) intended to satisfy the affirmative defense conditions of Rule 10b5‑1(c) of the Securities Exchange Act of ~~1977 (Mine Act) imposes stringent health~~1934. Mr. Hall’s Rule 10b5-1 Trading Plan provides for an aggregate sale of up to 3,297 shares of common stock on or after May 31, 2024 and ~~safety standards on various mining operations. The Mine Act~~until such shares are sold and ~~its related regulations affect numerous aspects~~2,703 shares of ~~mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans~~common stock between May 31, 2024 and ~~other matters. SWEPCo, through its ownership of DHLC, a wholly-owned lignite mining subsidiary of SWEPCo, is subject to~~December 31, 2024.

On March 1, 2024, Therace M. Risch, the ~~provisions~~Executive Vice President and Chief Information and Technology Officer of the ~~Mine Act.~~Company, entered into a Rule 10b5-1 Trading Plan intended to satisfy the affirmative defense conditions of Rule 10b5‑1(c) of the Securities Exchange Act of 1934. Ms. Risch’s Rule 10b5-1 Trading Plan provides for an aggregate sale of up to 5,539 shares of common stock between May 31, 2024 and April 30, 2025.

~~The Dodd-Frank Wall Street Reform~~On March 5, 2024, Antonio P. Smyth, Executive Vice President – Grid Solutions and ~~Consumer Protection~~Government Affairs of the Company, entered into a Rule 10b5-1 Trading Plan intended to satisfy the affirmative defense conditions of Rule 10b5‑1(c) of the Securities Exchange Act ~~(Dodd-Frank Act) requires companies that operate mines~~of 1934. Mr. Smyth’s Rule 10b5-1 Trading Plan provides for an aggregate sale of up to ~~include in their periodic reports filed with~~2,623 shares of common stock on or after June 5, 2024 and until such shares are sold and 2,624 shares of common stock between June 5, 2024 and January 31, 2025.

During the SEC, certain mine safety information covered by the Mine Act. Exhibit 95 “Mine Safety Disclosure Exhibit” contains the notices of violation and proposed assessments received by DHLC under the Mine Act for the quarterthree months ended March 31, ~~2018.~~2024, none of the Company’s other directors or officers (as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934) adopted, terminated or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K of the Securities Act of 1933).

164

~~Item 5.~~ ~~Other Information~~

~~None.~~

Item 6. Exhibits

The documents designated with an (*) below have previously been filed on behalf of the Registrants shown and are incorporated herein by reference to the documents indicated and made a part hereof.

Exhibit

Description

Previously Filed as Exhibit to:

AEPTCo‡ File No. 333-217143

4(a)

Company Order and Officer’s Certificate between AEPTCo and The Bank of New York Mellon Trust Company, N.A. as Trustee dated March 13, 2024 establishing terms of the 5.15% Senior Notes, Series Q due 2034.

Form 8-K dated March 13, 2024 , Exhibit 4(a)

APCo‡ File No. 1-3457

4(b)

Company Order and Officer’s Certificate between APCo and The Bank of New York Mellon Trust Company, N.A. as Trustee dated March 20, 2024 establishing terms of the 5.65% Senior Notes, Series CC due 2034.

Form 8-K dated March 20, 2024 , Exhibit 4(a )

The exhibits designated with an (X) in the table below are being filed on behalf of the Registrants.

Exhibit

Description

AEP

AEP
Texas

AEPTCo

APCo

I&M

OPCo

PSO

SWEPCo

4(c)

March 28, 2024 Amendment and extension to $1,000,000,000 Credit Agreement dated March 31, 2021 among the Company, Initial Lenders and Wells Fargo Bank National Association as Administrative Agent.

~~Exhibit~~4(d)

~~Description~~

~~AEP~~

~~Texas~~

~~AEPTCo~~

~~APCo~~

~~I&M~~

~~OPCo~~

~~PSO~~

~~SWEPCo~~

~~10(a)~~

~~Performance Share Award Agreement furnished~~March 28, 2024 Amendment and extension to ~~participants~~$5,000,000,000 of the ~~AEP~~$4,000,000,000 Credit Agreement dated March 31, 2021 among the Company, Initial Lenders and Wells Fargo Bank National Association as Administrative Agent.

10(a)

Executive Severance, Release of All Claims and Noncompetition Agreement between the Company and Julia A. Sloat.

10(b)

Aircraft Time Sharing Agreement between AEPSC and Benjamin G.S. Fowke, III.

10(c)

American Electric Power System ~~AEP~~2024 Long-Term Incentive ~~Plan, as amended~~Plan.

~~10(b)~~31(a)

~~Restricted Stock Unit Agreement furnished to participants of the AEP System AEP-Long Term Incentive Plan, as Amended and Restated~~

~~Computation of Consolidated Ratio of Earnings to Fixed Charges~~

~~31(a)~~

Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31(b)

Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32(a)

Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

32(b)

Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

95101.INS

~~Mine Safety Disclosures~~

~~101.INS~~

XBRL Instance Document

XThe instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.

101.SCH

XBRL Taxonomy Extension Schema

101.CAL

XBRL Taxonomy Extension Calculation Linkbase

101.DEF

XBRL Taxonomy Extension Definition Linkbase

165

Exhibit

Description

AEP

AEP
Texas

AEPTCo

APCo

I&M

OPCo

PSO

SWEPCo

101.LAB

XBRL Taxonomy Extension Label Linkbase

101.PRE

XBRL Taxonomy Extension Presentation Linkbase

104

Cover Page Interactive Data File

XFormatted as Inline XBRL and contained in Exhibit 101.

166

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

AMERICAN ELECTRIC POWER COMPANY, INC.

By: /s/ ~~Joseph M. Buonaiuto~~Kate Sturgess

~~Joseph M. Buonaiuto~~Kate Sturgess

Controller and Chief Accounting Officer

AEP TEXAS INC.

AEP TRANSMISSION COMPANY, LLC

APPALACHIAN POWER COMPANY

INDIANA MICHIGAN POWER COMPANY

OHIO POWER COMPANY

PUBLIC SERVICE COMPANY OF OKLAHOMA

SOUTHWESTERN ELECTRIC POWER COMPANY

By: /s/ ~~Joseph M. Buonaiuto~~Kate Sturgess

~~Joseph M. Buonaiuto~~Kate Sturgess

Controller and Chief Accounting Officer

Date: April ~~26, 2018~~

30, 2024

~~206~~

167


Term		Meaning

~~Term~~AEGCo		~~Meaning~~

~~AEGCo~~	AEP Generating Company, an AEP electric utility subsidiary.
AEP		American Electric Power Company, Inc., an investor-owned electric public utility holding company which includes American Electric Power Company, Inc. (Parent) and majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit		AEP Credit, Inc., a consolidated ~~variable interest entity~~VIE of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP ~~System~~Energy Supply LLC		~~American Electric Power System, an electric system, owned~~A nonregulated holding company for AEP’s competitive generation, wholesale and ~~operated by AEP subsidiaries.~~retail businesses, and a wholly-owned subsidiary of AEP.
AEP Renewables		A division of AEP Energy Supply LLC that develops and/or acquires large scale renewable projects that are backed with long-term contracts with creditworthy counterparties.

AEP Texas		AEP Texas Inc., an AEP electric utility subsidiary.
AEP Transmission Holdco		AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP.

AEPEP		AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in ~~the~~ deregulated ~~Ohio and Texas~~ markets.
~~AEPRO~~AEPSC		~~AEP River Operations, LLC, a commercial barge operation sold in November 2015.~~
~~AEPSC~~	American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEPTCo		AEP Transmission Company, LLC, a wholly-owned subsidiary of AEP Transmission Holdco, is an intermediate holding company that owns ~~seven wholly-owned transmission companies.~~the State Transcos.
AEPTCo Parent		AEP Transmission Company, LLC, the holding company of the State Transcos within the AEPTCo consolidation.
AFUDC		Allowance for Equity Funds Used During Construction.
~~AGR~~	~~AEP Generation Resources Inc., a competitive AEP subsidiary in the Generation & Marketing segment.~~
ALJ		Administrative Law Judge.


AOCI		Accumulated Other Comprehensive Income.
APCo		Appalachian Power Company, an AEP electric utility subsidiary.
Appalachian Consumer Rate Relief Funding		Appalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo and a consolidated ~~variable interest entity~~VIE formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ~~ENEC~~Expanded Net Energy Cost deferral balance.

APSC		Arkansas Public Service Commission.
~~ARAM~~
ARO		~~Average Rate Assumption Method, an IRS approved method used to calculate the reversal of Excess Accumulated Deferred Income Taxes for ratemaking purposes.~~Asset Retirement Obligations.
~~ASC~~		~~Accounting Standard Codification.~~
ASU		Accounting Standards Update.
~~CAA~~ATM		At-the-Market.

CAA		Clean Air Act.
~~CAIR~~

CCR		~~Clean Air Interstate Rule.~~Coal Combustion Residual.
CO₂		Carbon dioxide and other greenhouse gases.


CODM		Chief Operating Decision Maker.
Cook Plant		Donald C. Cook Nuclear Plant, a two-unit, ~~2,278~~2,296 MW nuclear plant owned by I&M.
~~CWIP~~COVID-19		Coronavirus 2019, a highly infectious respiratory disease. In March 2020, the World Health Organization declared COVID-19 a worldwide pandemic.
CSAPR		Cross-State Air Pollution Rule.
CWIP		Construction Work in Progress.
DCC Fuel		DCC Fuel ~~VI LLC,~~XIV, DCC Fuel ~~VII,~~XV, DCC Fuel ~~VIII,~~XVI, DCC Fuel ~~IX,~~XVII, DCC Fuel XXVIII, DCC Fuel XIX and DCC Fuel XIXX consolidated ~~variable interest entities~~VIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
~~Desert Sky~~DHLC		~~Desert Sky Wind Farm, a 160.5 MW wind electricity generation facility located on Indian Mesa in Pecos County, Texas.~~
~~DHLC~~	Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo. DHLC is a non-consolidated VIE of SWEPCo.
DIR		Distribution Investment Rider.


Term		Meaning

~~Term~~EIS		~~Meaning~~

~~DIR~~	~~Distribution Investment Rider.~~
~~EIS~~	Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated ~~variable interest entity~~VIE of AEP.
~~ENEC~~ELG		Effluent Limitation Guidelines.
ENEC		Expanded Net Energy Cost.
Energy Supply		AEP Energy Supply LLC, a nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.
~~ERCOT~~Equity Units		AEP’s Equity Units issued in August 2020.
ERCOT		Electric Reliability Council of Texas regional transmission organization.
ESP		Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.
~~ETR~~ETT		~~Effective tax rates.~~
~~ETT~~	Electric Transmission Texas, LLC, an equity interest joint venture between AEP Transmission Holdco and Berkshire Hathaway Energy Company formed to own and operate electric transmission facilities in ERCOT.
~~FASB~~Excess ADIT		Excess accumulated deferred income taxes.
FAC		Fuel Adjustment Clause.
FASB		Financial Accounting Standards Board.
Federal EPA		United States Environmental Protection Agency.
FERC		Federal Energy Regulatory Commission.
FGD		Flue Gas Desulfurization or scrubbers.
~~FTR~~FIP		Federal Implementation Plan.
FTR		Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP		Accounting Principles Generally Accepted in the United States of America.
~~Global Settlement~~GHG		In February 2017, the PUCO approved a settlement agreement filed by OPCo in December 2016 which resolved all remaining open issues on remand from the Supreme Court of Ohio in OPCo’s 2009 - 2011 and June 2012 - May 2015 ESP filings. It also resolved all open issues in OPCo’s 2009, 2014 and 2015 SEET filings and 2009, 2012 and 2013 Fuel Adjustment Clause Audits.Greenhouse gas.
I&M		Indiana Michigan Power Company, an AEP electric utility subsidiary.
~~IRS~~IRA		On August 16, 2022 President Biden signed into law legislation commonly referred to as the “Inflation Reduction Act” (IRA).
IRP		Integrated Resource Plan.
IRS		Internal Revenue Service.
~~IURC~~ITC		Investment Tax Credit.
IURC		Indiana Utility Regulatory Commission.
KGPCo		Kingsport Power Company, an AEP electric utility subsidiary.
KPCo		Kentucky Power Company, an AEP electric utility subsidiary.

KPSC		Kentucky Public Service Commission.
kV
KWh		~~Kilovolt.~~Kilowatt-hour.
~~KWh~~LPSC		~~Kilowatthour.~~
~~LPSC~~	Louisiana Public Service Commission.
~~Market Based Mechanism~~MATS		An order from the LPSC established to evaluate proposals to construct or acquire generating capacity. The LPSC directs that the market based mechanism shall be a request for proposal competitive solicitation process.Mercury and Air Toxic Standards.

MISO		Midcontinent Independent System Operator.
~~MMBtu~~Mitchell Plant		A two unit, 1,560 MW coal-fired power plant located in Moundsville, West Virginia. The plant is jointly owned by KPCo and WPCo.
MMBtu		Million British Thermal Units.
MPSC		Michigan Public Service Commission.
MTM		Mark-to-Market.
MW		Megawatt.
MWh		~~Megawatthour.~~Megawatt-hour.
NAAQS		National Ambient Air Quality Standards.


Term		Meaning

NCWF		North Central Wind Energy Facilities, a joint PSO and SWEPCo project, which includes three Oklahoma wind facilities totaling approximately 1,484 MWs of wind generation.
NMRD		New Mexico Renewable Development, LLC.
Nonutility Money Pool		Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
NO₂
NOLC		~~Nitrogen dioxide.~~Net Operating Loss Carryforward.
NO_x		Nitrogen oxide.
~~NSR~~		~~New Source Review.~~
~~OATT~~OCC		~~Open Access Transmission Tariff.~~
~~OCC~~	Corporation Commission of the State of Oklahoma.



~~Term~~		~~Meaning~~

~~Ohio Phase-in-Recovery Funding~~OPCo		Ohio Phase-in-Recovery Funding LLC, a wholly-owned subsidiary of OPCo and a consolidated variable interest entity formed for the purpose of issuing and servicing securitization bonds related to phase-in recovery property.
~~OPCo~~	Ohio Power Company, an AEP electric utility subsidiary.
OPEB		Other Postretirement ~~Benefit Plans.~~Benefits.

OTC		~~Over the counter.~~Over-the-counter.
OVEC		Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
Parent		American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.

PJM		Pennsylvania – New Jersey – Maryland regional transmission organization.
PMPLR		~~Particulate Matter.~~Private Letter Ruling.
~~PPA~~PM		Particulate Matter.
PPA		Purchase Power and Sale Agreement.
~~PSO~~PSA		Purchase and Sale Agreement.
PSO		Public Service Company of Oklahoma, an AEP electric utility subsidiary.
~~PUCO~~PTC		Production Tax Credit.
PUCO		Public Utilities Commission of Ohio.
PUCT		Public Utility Commission of Texas.


Registrant Subsidiaries		AEP subsidiaries which are SEC registrants: AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Registrants		SEC registrants: AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Restoration Funding		AEP Texas Restoration Funding LLC, a wholly-owned subsidiary of AEP Texas and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to storm restoration in Texas primarily caused by Hurricane Harvey.
Risk Management Contracts		Trading and ~~nontrading~~non-trading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant		A generation plant, jointly owned by AEGCo and I&M, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana. ~~AEGCo and I&M jointly-own Unit 1. In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.~~
~~RPM~~ROE		Return on Equity.
RPM		Reliability Pricing Model.
~~RSR~~RTO		~~Retail Stability Rider.~~
~~RTO~~	Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine		Sabine Mining Company, a lignite mining company that is a consolidated ~~variable interest entity~~VIE for AEP and SWEPCo.
~~SCR~~		~~Selective Catalytic Reduction, NO~~_x~~reduction technology at Rockport Plant.~~
SEC		U.S. Securities and Exchange Commission.
~~SEET~~SIP		~~Significantly Excessive Earnings Test.~~State Implementation Plan.
SNF		Spent Nuclear Fuel.
SO₂		Sulfur dioxide.
SPP		Southwest Power Pool regional transmission organization.
SSO		Standard service offer.
State Transcos		AEPTCo’s seven wholly-owned, FERC regulated, transmission only electric utilities, ~~each of~~ which isare geographically aligned with ~~AEP~~AEP’s existing utility operating companies.

SWEPCo		Southwestern Electric Power Company, an AEP electric utility subsidiary.


Term			Meaning

Tax Reform			On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018.
~~TCC~~			~~Formerly AEP Texas Central Company, now a division of AEP Texas.~~
~~Texas Restructuring Legislation~~			~~Legislation enacted in 1999 to restructure the electric utility industry in Texas.~~
~~TNC~~		~~Formerly Texas North Company, now a division of AEP Texas.~~
~~TRA~~	~~Tennessee Regulatory Authority.~~
Transition Funding		~~AEP Texas Central Transition Funding II LLC and~~ AEP Texas Central Transition Funding III LLC, a wholly-owned ~~subsidiaries~~subsidiary of ~~TCC~~AEP Texas and consolidated ~~variable interest entities~~VIE formed for the purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation.



	Number of ~~Shares~~ shares of ~~Common Stock~~ ~~Outstanding~~common stock outstanding of the Registrants as of
		April ~~26, 2018~~30, 2024

American Electric Power Company, Inc.		~~492,523,470~~527,121,759
		($6.50 par value)
AEP Texas Inc.		100
		($0.01 par value)
AEP Transmission Company, LLC (a)		NA

Appalachian Power Company		13,499,500
		(no par value)
Indiana Michigan Power Company		1,400,000
		(no par value)
Ohio Power Company		27,952,473
		(no par value)
Public Service Company of Oklahoma		9,013,000
		($15 par value)
Southwestern Electric Power Company		~~7,536,640~~3,680
		($18 par value)


~~(a)~~	~~100% interest is held by AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of American Electric Power Company, Inc.~~


•
Ÿ	~~Economic growth or contraction within and changes~~Changes in economic conditions, electric market demand and demographic patterns in AEP service territories.
Ÿ•		The economic impact of increased global trade tensions including the conflicts in Ukraine and the Middle East, and the adoption or expansion of economic sanctions or trade restrictions.
•		Inflationary or deflationary interest rate trends.
Ÿ•		Volatility and disruptions in financial markets precipitated by any cause, including failure to make progress on federal budget or debt ceiling matters or instability in the ~~financial markets,~~banking industry; particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt.
Ÿ•		The availability and cost of funds to finance working capital and capital needs, particularly (a) if expected sources of capital such as proceeds from the sale of assets, subsidiaries and tax credits and anticipated securitizations do not materialize or do not materialize at the level anticipated, and (b) during periods when the time lag between incurring costs and recovery is long and the costs are material.
Ÿ•		~~Electric load and customer growth.~~Decreased demand for electricity.
Ÿ•		Weather conditions, including storms and drought conditions, and the ability to recover significant storm restoration costs.
Ÿ•		Limitations or restrictions on the amounts and types of insurance available to cover losses that might arise in connection with natural disasters or operations.
•		The cost of fuel and its transportation, the creditworthiness and performance of fuel suppliers and transporters and the cost of storing and disposing of used fuel, including coal ash and ~~spent nuclear fuel.~~SNF.
Ÿ•		~~Availability~~The availability of fuel and necessary generation capacity and the performance of generation ~~plants and the availability of fuel, including processed nuclear fuel, parts and service from reliable vendors.~~plants.
Ÿ•		The ability to recover fuel and other energy costs through regulated or competitive electric rates.
Ÿ•		The ability to transition from fossil generation and the ability to build or acquire renewable generation, transmission lines and facilities (including the ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms, including favorable tax treatment, cost caps imposed by regulators and other operational commitments to regulatory commissions and customers for renewable generation projects, and to recover ~~those~~all related costs.
Ÿ•		The impact of pandemics and any associated disruption of AEP’s business operations due to impacts on economic or market conditions, costs of compliance with potential government regulations, electricity usage, supply chain issues, customers, service providers, vendors and suppliers.
•		New legislation, litigation ~~and~~or government regulation, including changes to tax laws and regulations, oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or ~~particulate matter~~PM and other substances that could impact the continued operation, cost recovery and/or profitability of generation plants and related assets.
Ÿ•		~~Evolving public perception~~The impact of ~~the~~federal tax legislation on results of operations, financial condition, cash flows or credit ratings.
•		The risks ~~associated with fuels used~~ before, during and after ~~the~~ generation of electricity associated with the fuels used or the by-products and wastes of such fuels, including ~~nuclear fuel.~~coal ash and SNF.
Ÿ•		Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental ~~compliance and excess accumulated deferred income taxes.~~compliance.
Ÿ•		Resolution of ~~litigation.~~litigation or regulatory proceedings or investigations.
Ÿ•		The ability to ~~constrain~~efficiently manage operation and maintenance costs.
Ÿ•		Prices and demand for power generated and sold at wholesale.
Ÿ•		Changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation.
Ÿ•		The ability to recover through rates any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives.
Ÿ•		Volatility and changes in markets for ~~capacity and electricity,~~ coal and other energy-related commodities, particularly changes in the price of natural gas.


•			The impact of changing expectations and demands of customers, regulators, investors and stakeholders, including focus on environmental, social and governance concerns.
Ÿ•			Changes in utility regulation and the allocation of costs within ~~regional transmission organizations,~~RTOs including ERCOT, PJM and SPP.
Ÿ•			Changes in the creditworthiness of the counterparties with contractual arrangements, including participants in the energy trading market.
Ÿ•			Actions of rating agencies, including changes in the ratings of debt.
Ÿ•			The impact of volatility in the capital markets on the value of the investments held by the pension, ~~other postretirement benefit plans,~~OPEB, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements.


•
Ÿ	Accounting ~~pronouncements~~standards periodically issued by accounting standard-setting bodies.
Ÿ•		~~Impact of federal tax reform on customer rates, income tax expense and cash flows.~~
Ÿ	Other risks and unforeseen events, including wars and military conflicts, the effects of terrorism (including increased security costs), embargoes, ~~cyber security~~wildfires, cybersecurity threats and other catastrophic events.
•		The ability to attract and retain the requisite work force and key personnel.


Registrant	Increase in Pretax Income from the Recognition of Regulatory Assets		Reduction in Income Tax Expense (a)		Increase in Net Income
	(in millions)
I&M	$	20.2	$	49.5	$	69.7
PSO	12.1		44.7		56.8
SWEPCo	35.4		101.1		136.5
AEP Total	$	67.7	$	195.3	$	263.0


		Expected/Authorized	As of			As of		Increase/
Company	Jurisdiction	Recovery Period	March 31, 2024			December 31, 2023		(Decrease)
			(in millions)
APCo	Virginia	2025	$	221.1	(a)	$	254.4	$	(33.3)
APCo	West Virginia	2034	164.1		(b)	162.2		1.9


PSO	Oklahoma	2024	155.8		(c)	118.3		37.5


SWEPCo	Texas	2035	81.0		(d)	80.9		0.1

WPCo	West Virginia	2034	206.2		(b)	181.3		24.9
		Total	$	828.2		$	797.1	$	31.1



		Generating	Amounts Pending
Company	Plant Name and Unit	Capacity	Regulatory Approval
		(in MWs)	(in millions)
APCo	Kanawha River Plant	400	$	44.8
APCo	Clinch River Plant, Unit 3	235	32.6
APCo (a)	Clinch River Plant, Units 1 and 2	470	31.8
APCo	Sporn Plant, Units 1 and 3	300	17.2
APCo	Glen Lyn Plant	335	13.4
I&M (b)	Tanners Creek Plant	995	27.7
SWEPCo	Welsh Plant, Unit 2	528	50.6
Total		3,263	$	218.1


~~(a)~~	APCo obtained permits following the Virginia SCC’s and WVPSC’s approval to convert its 470 MW Clinch River Plant, Units 1 and 2 to natural gas. In 2015, APCo retired the coal-related assets of Clinch River Plant, Units 1 and 2. Clinch River Plant, Unit 1 and Unit 2 began operations as natural gas units in February 2016 and April 2016, respectively.



First Quarter of 2017	$	71.8

Changes in Transmission Revenues:
Transmission Revenues	49.4
Total Change in Transmission Revenues	49.4

Changes in Expenses and Other:
Other Operation and Maintenance	(7.8		)
Depreciation and Amortization	(7.2		)
Taxes Other Than Income Taxes	(4.7		)
Interest and Investment Income	0.1
Allowance for Equity Funds Used During Construction	4.5
Non-Service Cost Components of Net Periodic Pension Cost	0.6
Interest Expense	(3.8		)
Total Change in Expenses and Other	(18.3		)

Income Tax Expense	8.9
Equity Earnings of Unconsolidated Subsidiaries	(8.0		)
Net Income Attributable to Noncontrolling Interests	0.2

First Quarter of 2018	$	104.0


NA	~~Not applicable.~~



	March 31, 2018				December 31, 2017
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	21,461.0	50.3	%	$	21,173.3	51.5	%
Short-term Debt	2,658.8		6.2		1,638.6		4.0
Total Debt	24,119.8		56.5		22,811.9		55.5
AEP Common Equity	18,483.3		43.4		18,287.0		44.4
Noncontrolling Interests	28.3		0.1		26.6		0.1
Total Debt and Equity Capitalization	$	42,631.4	100.0	%	$	41,125.5	100.0	%



	March 31, 2018		December 31, 2017
	(in millions)
Rockport Plant, Unit 2 Future Minimum Lease Payments	$	738.4	$	738.4
Railcars Maximum Potential Loss from Lease Agreement	15.4		17.9



MTM Risk Management Contract Net Assets (Liabilities)
Three Months Ended March 31, 2018

	Vertically Integrated Utilities			Transmission and Distribution Utilities			Generation & Marketing			Total
	(in millions)
Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2017	$	42.1		$	(131.3	)	$	163.9		$	74.7
Gain from Contracts Realized/Settled During the Period and Entered in a Prior Period	(30.5		)	(1.1		)	(9.2		)	(40.8		)
Fair Value of New Contracts at Inception When Entered During the Period (a)	—			—			6.1			6.1
Changes in Fair Value Due to Market Fluctuations During the Period (b)	—			—			(22.4		)	(22.4		)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)	5.8			34.8			—			40.6
Total MTM Risk Management Contract Net Assets (Liabilities) as of March 31, 2018	$	17.4		$	(97.6	)	$	138.4		58.2
Commodity Cash Flow Hedge Contracts										(33.4		)
Fair Value Hedge Contracts										(20.6		)
Collateral Deposits										16.8
Total MTM Derivative Contract Net Assets as of March 31, 2018										$	21.0




		Cash Flow Hedge - Interest Rate			Pension and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2017		$	(4.5	)	$	(8.1	)	$	(12.6	)
Change in Fair Value Recognized in AOCI		—			—			—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense		0.3			—			0.3
Amortization of Prior Service Cost (Credit)		—			—			—
Amortization of Actuarial (Gains)/Losses		—			0.1			0.1
Reclassifications from AOCI, before Income Tax (Expense) Credit		0.3			0.1			0.4
Income Tax (Expense) Credit		0.1			—			0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0.2			0.1			0.3
Net Current Period Other Comprehensive Income (Loss)		0.2			0.1			0.3
ASU 2018-02 Adoption (a)		(0.9		)	(1.8		)	(2.7		)
Balance in AOCI as of March 31, 2018		$	(5.2	)	$	(9.8	)	$	(15.0	)




		Cash Flow Hedge - Interest Rate
	(in millions)
Balance in AOCI as of December 31, 2016		$	3.0
Change in Fair Value Recognized in AOCI		—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense		(0.4		)
Reclassifications from AOCI, before Income Tax (Expense) Credit		(0.4		)
Income Tax (Expense) Credit		(0.2		)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(0.2		)
Net Current Period Other Comprehensive Income (Loss)		(0.2		)
Balance in AOCI as of March 31, 2017		$	2.8



	Pension Plans						OPEB
	Three Months Ended March 31,						Three Months Ended March 31,
	2018			2017			2018			2017
	(in millions)
Service Cost	$	24.4		$	24.1		$	2.9		$	2.8
Interest Cost	46.9			50.8			11.8			14.8
Expected Return on Plan Assets	(72.5		)	(71.2		)	(25.5		)	(25.3		)
Amortization of Prior Service Cost (Credit)	—			0.3			(17.3		)	(17.3		)
Amortization of Net Actuarial Loss	21.3			20.7			2.6			9.2
Net Periodic Benefit Cost (Credit)	$	20.1		$	24.7		$	(25.5	)	$	(15.8	)



	Three Months Ended March 31, 2017
	State Transcos		AEPTCo Parent			Reconciling Adjustments				AEPTCo Consolidated
	(in millions)
Revenues from:
External Customers	$	19.2	$	—		$	—			$	19.2
Sales to AEP Affiliates	133.4		—			—				133.4
Other Revenues	0.1		—			—				0.1
Total Revenues	$	152.7	$	—		$	—			$	152.7

Interest Income	$	0.1	$	19.1		$	(19.0	)	(a)	$	0.2
Interest Expense	15.8		19.2			(19.0		)	(a)	16.0
Income Tax Expense	28.4		0.1			—				28.5

Net Income	$	56.8	$	0.2	(b)	$	—			$	57.0



Primary Risk Exposure	Unit of Measure	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
		(in millions)
Commodity:
Power	MWhs	298.4		—		43.2		33.0		8.3		4.0		8.1
Coal	Tons	1.2		—		—		1.2		—		—		—
Natural Gas	MMBtus	78.2		—		6.2		3.7		—		—		18.0
Heating Oil and Gasoline	Gallons	5.0		1.1		1.0		0.5		1.2		0.5		0.6
Interest Rate	USD	$	49.8	$	—	$	—	$	—	$	—	$	—	$	—

Interest Rate and Foreign Currency	USD	$	500.0	$	—	$	—	$	—	$	—	$	—	$	—



Balance Sheet Location	Risk Management Contracts - Commodity (a)		Gross Amounts Offset in the Statement of Financial Position (b)			Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c)
	(in millions)
Current Risk Management Assets	$	0.4	$	(0.1	)	$	0.3
Long-term Risk Management Assets	—		—			—
Total Assets	0.4		(0.1		)	0.3

Current Risk Management Liabilities	—		—			—
Long-term Risk Management Liabilities	—		—			—
Total Liabilities	—		—			—

Total MTM Derivative Contract Net Assets (Liabilities)	$	0.4	$	(0.1	)	$	0.3



	AEP
	Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		Amount of Cash Collateral Posted		Additional Settlement Liability if Cross Default Provision is Triggered
	(in millions)
March 31, 2018	$	272.7	$	1.0	$	202.4
December 31, 2017	243.6		1.3		223.1



	March 31, 2018
Other Temporary Investments	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(in millions)
Restricted Cash and Other Cash Deposits (a)	$	162.0	$	—	$	—		$	162.0
Fixed Income Securities – Mutual Funds (b)	104.8		—		(2.2		)	102.6
Equity Securities – Mutual Funds	17.2		19.2		—			36.4
Total Other Temporary Investments	$	284.0	$	19.2	$	(2.2	)	$	301.0



	Fair Value of Fixed Income Securities
	(in millions)
Within 1 year	$	355.7
After 1 year through 5 years	315.3
After 5 years through 10 years	205.8
After 10 years	164.2
Total	$	1,041.0



Company	Type of Debt	Principal Amount (a)		Interest Rate	Due Date
Issuances:		(in millions)		(%)
OPCo	Senior Unsecured Notes	$	400.0	4.15	2048
SWEPCo	Senior Unsecured Notes	450.0		3.85	2048

Non-Registrant:
Transource Energy	Other Long-term Debt	3.4		Variable	2020
Total Issuances		$	853.4



Company	Type of Debt	Principal Amount Paid		Interest Rate	Due Date
Retirements and Principal Payments:		(in millions)		(%)
AEP Texas	Securitization Bonds	$	70.0	5.17	2018
AEP Texas	Securitization Bonds	26.5		5.306	2020
APCo	Securitization Bonds	11.7		2.008	2023
I&M	Notes Payable	0.8		Variable	2019
I&M	Notes Payable	7.9		Variable	2019
I&M	Notes Payable	4.8		Variable	2020
I&M	Notes Payable	8.5		Variable	2021
I&M	Notes Payable	7.0		Variable	2022
I&M	Other Long-term Debt	0.4		6.00	2025
OPCo	Securitization Bonds	22.9		2.049	2019
PSO	Other Long-term Debt	0.1		3.00	2027
SWEPCo	Pollution Control Bonds	81.7		4.95	2018
SWEPCo	Senior Unsecured Notes	300.0		5.875	2018
SWEPCo	Other Long-term Debt	0.1		3.50	2023
SWEPCo	Notes Payable	1.6		4.58	2032
Total Retirements and Principal Payments		$	544.0



Company	Maximum Borrowings from the Utility Money Pool		Maximum Loans to the Utility Money Pool		Average Borrowings from the Utility Money Pool		Average Loans to the Utility Money Pool		Net Loans to (Borrowings from) the Utility Money Pool as of March 31, 2018			Authorized Short-term Borrowing Limit
	(in millions)
AEP Texas	$	307.2	$	103.6	$	219.2	$	50.4	$	(232.7	)	$	500.0
AEPTCo	337.3		123.9		188.2		26.3		(272.8		)	795.0		(a)
APCo	285.6		23.7		223.6		23.5		(222.4		)	600.0
I&M	314.1		12.5		240.6		12.5		(301.6		)	500.0
OPCo	229.1		216.4		104.9		179.5		200.4			400.0
PSO	179.1		—		143.3		—		(179.1		)	300.0
SWEPCo	169.1		296.5		143.7		273.2		(148.6		)	350.0



	Average Interest Rate				Average Interest Rate
	for Funds Borrowed				for Funds Loaned
	from the Utility Money Pool for				to the Utility Money Pool for
	Three Months Ended March 31,				Three Months Ended March 31,
Company	2018		2017		2018		2017
AEP Texas	2.07	%	1.02	%	1.90	%	—	%
AEPTCo	2.06	%	1.08	%	1.92	%	0.99	%
APCo	2.00	%	1.04	%	2.00	%	1.03	%
I&M	2.02	%	1.04	%	2.00	%	1.03	%
OPCo	2.00	%	1.10	%	2.40	%	0.98	%
PSO	2.01	%	1.06	%	—	%	—	%
SWEPCo	2.10	%	1.06	%	1.88	%	0.98	%



Company (a)	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
AEP	$	748.7	$	256.1	$	164.1	$	348.7	$	1,517.6
AEP Texas	233.4		—		—		—		233.4
AEPTCo	536.2		—		—		—		536.2
APCo	92.0		31.8		22.7		11.4		157.9
I&M	20.6		8.7		8.7		4.3		42.3
OPCo	42.1		—		—		—		42.1
PSO	11.9		—		—		—		11.9
SWEPCo	24.9		—		—		—		24.9



Company	March 31, 2018		January 1, 2018
	(in millions)
AEP Texas	$	—	$	—
AEPTCo	60.6		47.1
APCo	36.3		35.6
I&M	14.8		15.1
OPCo	27.1		26.1
PSO	6.2		6.1
SWEPCo	11.4		11.0