AEP American Electric Power 10-Q 2026-09-30 section summaries

AEP Form 10-Q Cover

The combined Form 10-Q covers the quarter ended September 30, 2026. It is filed by American Electric Power Company, Inc. (AEP) and seven subsidiaries: AEP Texas, AEP Transmission Company, Appalachian Power, Indiana Michigan Power, Ohio Power, Public Service Company of Oklahoma, and Southwestern Electric Power.

AEP is a large accelerated filer. The seven subsidiaries are non-accelerated filers and use the Form 10-Q’s reduced-disclosure format. The cover reports no financial results or material business developments.

Common shares outstanding as of October 28, 2026

Glossary and business context

The glossary describes AEP as a holding company whose businesses include regulated electric utilities, transmission operations, competitive generation, wholesale and retail activities, and unregulated infrastructure-services and energy-marketing businesses. Regulated utilities generally combine generation, transmission and distribution; some subsidiaries operate transmission-only businesses regulated by FERC.

Transmission development and large-load opportunity

AEP formed two transmission-development holding companies in 2025: Grid Growth Ventures and Midcontinent Grid Solutions, each 43.25% owned by AEP. Transource Energy, a consolidated variable interest entity (VIE), is 86.5% owned by AEP and invests in transmission facilities under FERC-approved rates. The glossary also describes AEP’s transmission holding-company structure and State Transcos.

ERCOT’s Batch Zero, established in 2026, is a one-time process for evaluating qualifying large-load interconnection requests, primarily those of 75 MW or greater. It allocates available transmission capacity, identifies necessary upgrades and requires customer financial commitments. This could support transmission investment, but depends on execution and customers making the required commitments. AEP also has an equity-interest joint venture, Gigawatt AI, formed to develop an AI-centric operating system for utilities.

Financing structures

AEP Credit, a consolidated VIE, securitizes affiliate utilities’ receivables and accrued utility revenues. Other consolidated utility-level VIEs issue and service securitization bonds for specified eligible costs, including storm restoration, plant retirement, deferred storm and purchased-power costs, and certain under-recovered balances. These structures provide dedicated financing mechanisms for eligible costs; the glossary gives no balances or debt amounts. AEP also operates separate utility and nonutility money pools to meet subsidiaries’ short-term cash needs.

Generation assets and risk context

The glossary identifies Cook, a two-unit 2,296 MW nuclear plant; Mitchell, a two-unit 1,560 MW coal plant jointly owned by KPCo and WPCo; and Rockport, two 1,310 MW coal units jointly owned by AEGCo and I&M. The North Central Wind Energy Facilities project comprises three Oklahoma wind facilities totaling approximately 1,484 MW. These descriptions provide asset context but no current operating or financial performance.

AEP’s operations are exposed to utility regulation and cost-recovery processes, transmission interconnection and upgrade requirements, and environmental rules covering emissions, air quality and water discharges. The glossary defines derivatives and transmission-congestion instruments, including risk-management contracts and financial transmission rights, but reports no exposure amounts or realized impacts. It contains no current-period revenue, earnings, cash flow, balance-sheet figures or period-over-period changes.

Forward-Looking Information and Key Risks

This section provides no financial results, balance-sheet figures, or quantified guidance. AEP cautions that forward-looking expectations are subject to significant uncertainty, particularly around demand growth. The timing, scale, and realization of projected data-center demand are uncertain; forecast errors could affect load planning, capital investment, anticipated cost recovery, and financial results. Commitments made for large-load customers are also a factor.

AEP’s substantial investment program faces construction and financing risks, including delays and shortages of labor, materials, and critical equipment such as large power transformers; permitting and regulatory-approval delays; and uncertainty over the availability and cost of capital. Proceeds from expected tax-credit sales and securitizations may differ from expectations. Because regulated cost recovery can lag spending, extended delays could increase funding pressure.

Regulatory decisions are central to AEP’s ability to recover costs and earn returns. Rate cases, recovery of investments in generation, transmission, distribution, and environmental compliance, utility and RTO market rules, and cost allocation could affect profitability. Customer-affordability concerns may limit recovery through rates or influence rate design.

Physical and operating risks include wildfires, storms, hurricanes, droughts, and other catastrophic events, which could lead to liability, litigation, restoration expenses, and losses not fully covered by insurance or recoverable through rates. Generation reliability and financial performance also depend on fuel availability, plant operations, fuel and transportation costs, and recovery of fuel and energy expenses.

The energy transition and evolving environmental requirements create additional uncertainty. Changes in emissions standards, environmental rules, and tax-credit policy could affect costs and returns; changing market economics could also lead to early retirement of generation assets before their investment is recovered. The economics of natural gas and other energy commodities, along with technology changes such as distributed generation and adoption of AI by AEP, its customers, and vendors, may affect operations and demand.

Financial and market exposures include interest-rate and capital-market volatility, rating-agency actions that could increase borrowing costs, and deterioration in counterparty credit. Volatility in pension, other postretirement benefit (OPEB), nuclear-decommissioning trust, and captive-insurance investments could increase future funding needs. Geopolitical events, trade restrictions, tariffs, and sanctions may affect energy markets, fuel prices, and demand.

Other risks cited include cybersecurity threats, supply-chain disruption, government shutdowns, litigation and regulatory proceedings, workforce retention, and changing stakeholder expectations regarding sustainability. AEP states that forward-looking statements speak only as of their stated date and disclaims an obligation to update them except as required by law. It directs readers to the 2025 Form 10-K and the current report’s Risk Factors for further discussion.

AEP — Management’s Discussion and Analysis

Earnings and business performance

AEP’s Q3 2026 GAAP earnings attributable to common shareholders were $1.187B, up from $972M in Q3 2025; non-GAAP operating earnings were $1.216B, up from $963M. Growth reflected favorable weather, new data-processing and other commercial and industrial load, transmission investment and rate proceedings. Higher interest expense and credits to certain SWEPCo wholesale customers partly offset those gains.

For 9M 2026, GAAP earnings were $2.774B, down from $2.998B, while operating earnings rose to $2.849B from $2.552B. The GAAP comparison was affected by a favorable $480M June 2025 FERC order impact on NOLCs that did not recur. Other pressures included higher interest expense, customer credits and a probable partial disallowance of SWEPCo’s Pirkey Plant net book value. Management’s operating earnings are a non-GAAP measure that excludes specified items.

Q3 segment earnings attributable to AEP common shareholders (2026 vs. 2025):

• Vertically Integrated Utilities: $697M vs. $578M
• Transmission and Distribution Utilities: $284M vs. $267M
• AEP Transmission Holdco: $219M vs. $200M
• Generation & Marketing: $96M vs. $45M
• Corporate and Other: $(109)M vs. $(118)M

VIU growth benefited from higher base-rate and rider revenues, weather and commercial/industrial usage. Q3 VIU retail revenue increased $408M; total electricity sales rose to 32,465 million kWh from 29,565 million kWh. T&D retail revenue increased $210M, with higher rider revenues and purchased-power prices contributing; retail deliveries were 31.913B kWh vs. 28.084B kWh. Generation & Marketing benefited from stronger market and realized power prices, but higher purchased electricity, fuel and consumables costs offset part of the revenue gains.

Operating costs remain a significant offset to growth. VIU O&M increased $120M in Q3, and depreciation and interest expense increased $112M and $61M, respectively. T&D O&M rose $141M, substantially reflecting recoverable Ohio PJM transmission costs, vegetation management, storms and energy assistance. Higher debt balances contributed to increased interest expense across the business.

Investment, load growth and regulation

AEP forecasts approximately $15.6B of 2026 capital expenditures and a $100.4B 2027–2031 capital plan: $52.2B for VIU, $23.6B for T&D, $18.1B for Transmission Holdco, $4.4B for Generation & Marketing and $2.1B for Corporate and Other. The plan targets transmission expansion, generation for existing and forecast load, and distribution reliability. Funding is expected from operating cash flow and financing; affordability, regulatory approvals, supply chains and access to capital are important constraints.

AEP added 1,859 MW of owned generation in 2026, signed agreements to acquire another 5,099 MW, and has active RFPs for approximately 14,400 MW. Separately, approvals cover about 2,327 MW of owned generation and storage and 1,124 MW of renewable PPAs. Large-load tariffs had been filed in eight jurisdictions, with six approved; provisions may require long-term contracts, take-or-pay minimums of 80%–90% of contracted demand, credit support and customer payment for specified infrastructure costs.

In Ohio, agreements provide for three 765-kV lines serving a proposed 10.4-GW Piketon data-center campus, with an estimated $5B project budget and 2028–2030 in-service targets. The customer is responsible for transmission-related costs under 20-year arrangements, but the project remains subject to regulatory review. In Texas, AEP Texas had Letters of Agreement for about 49 GW of incremental load by 2031. ERCOT paused studies and Batch Zero classification pending verification; AEP Texas received about $2B of financial security for 45 GW of prospective Batch Zero load in July and segregated about $1.2B of cash collateral in October under new rules. The scale and timing of prospective load remain uncertain.

Rate-case outcomes also affect recovery: completed cases include annual increases of $91M for APCo/WPCo in West Virginia, $85M for SWEPCo in Arkansas, $55M for KPCo in Kentucky and $11M for OPCo in Ohio. Pending requests include $299M for PSO in Oklahoma and $95M for SWEPCo in Texas; I&M seeks a $42M decrease in Indiana. AEP Texas recorded a $23M pretax charge following an adverse UTM ruling and had deferred $89M of eligible costs and $34M related to resiliency for potential recovery, subject to prudency review.

Environmental exposure

AEP owned about 27,200 MW of generating capacity, including 10,200 MW of coal-fired capacity, at September 30, 2026. Evolving and litigated greenhouse-gas, air, coal-ash and wastewater rules create uncertainty around compliance spending, dispatch and retirement plans. AEP recorded a $674M increase in asset retirement obligations in Q2 2024 based on expanded coal-combustion-residual requirements; additional groundwater treatment or ash removal could add substantial costs. AEP expects to seek customer recovery of compliance costs, but disallowances or accelerated retirements could affect earnings and cash flow. Pirkey and other coal-plant recovery matters illustrate that risk.

Cash flow, debt and liquidity

For 9M 2026, operating cash flow was $5.767B vs. $5.131B; net income was $2.868B vs. $3.091B. Investing cash flow was $(11.171)B vs. $(7.749)B, including construction expenditures of $(9.107)B vs. $(6.001)B and generation-facility acquisitions of $(2.394)B vs. $(1.657)B. Financing cash flow was $5.643B vs. $3.479B, chiefly reflecting increased debt issuance and security deposits. Higher operating cash flow benefited from customer deposits, deferred revenue timing and regulatory liabilities, partly offset by weaker working-capital flows.

Total debt was $54.416B at September 30, 2026, versus $48.830B at December 31, 2025; debt-to-total capitalization rose to 61.5% from 60.3%. AEP reported $7.443B of net available liquidity, including $8.000B of revolving facilities, partly offset by commercial paper outstanding. Management considers liquidity adequate for the next 12 months and foreseeable future. The company issued 2 million shares for $264M net proceeds through its ATM program and had forward sale agreements covering 6 million shares for expected proceeds of $684M. Higher interest rates, refinancing conditions, ratings changes and collateral demands remain risks to financing costs and cash flow.

AEP financial results and position

Revenue and operating performance

Q3 2026 revenue was $6.832B, up from $6.011B; nine-month (9M) revenue was $18.297B, up from $16.561B.

Q3 revenue by category:

• Vertically Integrated Utilities: $3.923B from $3.511B
• Transmission and Distribution Utilities: $1.853B from $1.680B
• Generation & Marketing: $922M from $694M
• Other Revenues: $134M from $126M

Q3 total expenses increased to $5.020B from $4.489B, while operating income rose 19.1% to $1.812B from $1.522B. For 9M, expenses were $13.878B from $12.356B, and operating income increased 5.1% to $4.419B from $4.205B. Significant 9M expense increases included purchased electricity, fuel and other generation consumables of $5.808B from $5.375B; other operation of $2.592B from $2.088B; and depreciation and amortization of $2.842B from $2.566B. AEP recorded $31M of asset impairments, versus none in 2025.

Earnings, interest and shares

Q3 net income attributable to AEP common shareholders was $1.187B, up from $972M; diluted EPS was $2.16 from $1.81. For 9M, common-shareholder earnings declined to $2.774B from $2.998B, and diluted EPS fell to $5.05 from $5.59, despite higher revenue and operating income. Higher 9M interest expense—$1.743B from $1.493B—and income tax expense of $221M versus $13M contributed to the earnings decline. Comprehensive income attributable to common shareholders was $1.193B in Q3 versus $956M, and $2.789B for 9M versus $2.973B.

Q3 basic and diluted weighted-average shares were 544.432M and 550.103M, respectively, versus 534.868M and 537.989M. For 9M, basic and diluted weighted-average shares were 543.567M and 549.270M, versus 534.186M and 536.365M.

Balance sheet and capital structure

At September 30, 2026, total assets were $125.695B, up from $114.460B at December 31, 2025; total equity was $34.043B, up from $32.218B. Total liabilities were $91.576B versus $82.204B. Goodwill was $53M at both dates; no separate intangible-asset line was presented, and separately reported intangible assets other than goodwill were $0.

Total debt—short-term debt, long-term debt due within one year and noncurrent long-term debt—rose to $54.416B from $48.830B. Net PP&E increased to $100.228B from $92.374B, and construction work in progress to $10.907B from $7.635B. Securitized assets increased to $2.221B from $933M. Equity included noncontrolling interests of $1.268B, up from $1.080B; 2026 included $269M of 9M noncontrolling-interest capital contributions.

Shares issued increased from 542,048,288 at December 31, 2025 to 545,692,925 at September 30, 2026. After 1,186,815 treasury shares at each date, shares outstanding were 540,861,473 and 544,506,110, respectively.

Cash flow, investment and dividends

9M operating cash flow increased to $5.767B from $5.131B. Construction expenditures (capital investment) rose to $9.107B from $6.001B, leaving operating cash flow less construction expenditures at negative $3.340B, compared with negative $870M. Generation-facility acquisitions were $2.394B from $1.657B. Investing cash outflow widened to $11.171B from $7.749B; financing cash inflow was $5.643B versus $3.479B, including $7.026B of long-term debt issuance and $417M of common-stock issuance. Cash, cash equivalents and restricted cash ended 9M at $507M, down from $1.107B a year earlier.

Common dividends paid were $1.558B versus $1.498B; declared dividends were $0.95 per share in 2026 versus $0.93 in 2025. Overall, the statements reflect substantial utility investment and generation acquisitions, funded in part through increased debt, alongside higher construction spending and a lower ending cash balance.

AEP Texas — Q3 and first nine months ended September 30, 2026

AEP Texas’s net income increased to $172 million in Q3 2026 from $166 million in Q3 2025, and to $405 million for 9M 2026 from $389 million in 9M 2025. In Q3, a $40 million revenue increase was partly offset by $36 million of higher expenses and other costs, with a $2 million favorable income-tax effect. For 9M, an $81 million revenue increase was partly offset by $61 million of higher expenses and other costs and a $4 million unfavorable tax effect.

Demand and weather

Retail electricity deliveries rose to 14,964 million kWh in Q3 from 13,029 million kWh. By customer class, Q3 deliveries were:

• Residential: 4,608 million kWh from 4,135 million
• Commercial: 5,684 million kWh from 5,219 million
• Industrial: 4,477 million kWh from 3,489 million
• Miscellaneous: 195 million kWh from 186 million

For 9M, retail deliveries increased to 38,587 million kWh from 34,999 million:

• Residential: 10,306 million kWh from 10,326 million
• Commercial: 15,452 million kWh from 14,037 million
• Industrial: 12,348 million kWh from 10,159 million
• Miscellaneous: 481 million kWh from 477 million

Q3 actual cooling degree days increased 18% to 1,611 from 1,367. For 9M, cooling degree days were 2,735 from 2,520, while heating degree days declined to 144 from 296. Weather-related usage contributed to Q3 retail revenue growth; for 9M, weather-related usage reduced revenue compared with the prior-year first six months.

Revenue drivers

Retail revenue increased $38 million in Q3, primarily from $27 million of higher rider revenues and $14 million of higher weather-related usage. For 9M, retail revenue rose $31 million, reflecting $34 million of higher rider revenues and $13 million of higher weather-normalized residential and commercial revenues. These gains were partly offset by $7 million of Transition Funding customer refunds and $6 million from less extreme weather.

Transmission revenue increased $7 million in Q3 and $40 million in 9M, primarily reflecting continued transmission investment. Other revenue fell $5 million in Q3, mainly because of a lower PUCT-authorized cap on Texas energy-efficiency utility incentives. For 9M, other revenue rose $10 million: $16 million of higher taxable payments for large interconnection projects more than offset a $7 million incentive-related decline.

Costs, investment and financing

Operating cost pressures accompanied the revenue growth. O&M expense increased $24 million in Q3, including $14 million of higher transmission and distribution expense and $7 million of higher recoverable Transmission Cost Recovery Factor expenses. For 9M, O&M rose $46 million, driven by an $18 million partial disallowance of regulatory assets associated with UTM deferrals, $14 million of higher transmission and distribution costs, and $13 million of higher administrative and general costs, primarily employee-related.

Depreciation and amortization increased $10 million in Q3 and $19 million in 9M, mainly due to a larger depreciable asset base. The 9M increase was partly offset by lower amortization of regulatory liabilities related to Transition Funding refunds and deferral of eligible UTM costs. AFUDC increased $10 million in Q3 and $25 million in 9M as the allowance-for-equity-funds-used-during-construction base grew with ongoing investment.

Interest expense increased $13 million in Q3 and $23 million in 9M, chiefly from higher long-term debt balances, which contributed $14 million and $38 million, respectively, and $10 million of interest on customer deposits from ERCOT’s Batch Zero process in each period. Offsets included a higher debt component of AFUDC and deferral of eligible UTM costs.

Overall, the results reflect growing deliveries and returns from transmission investment, alongside higher operating and financing costs. Key pressures include debt-funded investment, UTM-related regulatory asset disallowances, and changes in customer-refund and energy-efficiency incentive mechanisms.

AEP Texas Inc. — Condensed Consolidated Financial Statements

AEP Texas, a wholly owned subsidiary of AEP, reported unaudited results for the three and nine months ended September 30, 2026. Dollar amounts are in millions unless otherwise stated.

Operating results

• Q3 2026: Revenue was $659, up from $619 in Q3 2025. Electric transmission and distribution revenue was $655 (from $616); sales to AEP affiliates were $2 (from $1); and other revenue was $2 (from $2).
• Operating expenses rose to $407 from $370, including other operation costs of $207 (from $187) and depreciation and amortization of $123 (from $113). Operating income was $252, compared with $249. Interest expense increased to $79 from $66; income before tax was $206 (from $202), income tax expense was $34 (from $36), and net income was $172 (from $166).
• 9M 2026: Revenue was $1.754B, compared with $1.673B. Transmission and distribution revenue was $1.728B (from $1.664B); affiliate sales were $5 (from $4); and other revenue was $21 (from $5). Operating expenses were $1.124B (from $1.056B), and operating income was $630 (from $617). Interest expense increased to $223 from $200; net income was $405 versus $389.

Balance sheet and financing

At September 30, 2026, total assets were $19.458B, compared with $17.075B at December 31, 2025. Total common shareholder’s equity was $6.230B, up from $5.826B. Goodwill and intangible assets other than goodwill were not separately reported on the presented balance sheet; tangible common equity based on the reported lines was therefore $6.230B.

Net property, plant and equipment increased to $17.554B from $15.864B, including construction work in progress of $2.577B (from $1.766B). Total liabilities rose to $13.228B from $11.249B. Nonaffiliated long-term debt, including current maturities, was $7.686B—$26 current and $7.660B noncurrent—compared with $7.016B at year-end.

Security deposits increased sharply to $1.151B from $87, with $1.127B of security-deposit financing inflow during 9M 2026. Advances to affiliates, an asset, increased to $389 from $7, while advances from affiliates declined to zero from $188. Regulatory assets were $470 versus $402; securitized assets were $76 versus $94, including restoration-funding balances of $76 and $94, respectively. Equity growth included retained earnings; the parent capital contribution was $1 in 9M 2026 versus $451 in 9M 2025, and AEP Texas returned $1 of capital to Parent in 2026.

Cash flow and investment

For 9M 2026, operating cash flow was $629, down from $695. Construction expenditures were $2.133B, up from $1.332B; operating cash flow less construction expenditures was consequently negative $1.504B, versus negative $637. Net investing cash outflow was $2.234B (from $1.694B), while financing cash inflow was $1.600B (from $982). Financing included $741 of nonaffiliated debt issuance (from $1.294B) and $75 of debt retirement (from $475). Cash interest paid, net of capitalized amounts, increased to $163 from $143. Cash, cash equivalents and restricted cash ended at $9, compared with $7.

Investor perspective

Earnings increased modestly, but capital spending accelerated substantially while operating cash flow declined, widening the cash funding gap. Debt increased, and the large rise in security deposits was a material balance-sheet and financing movement; the supplied statements do not explain its underlying driver. Shares outstanding at the beginning and end of the period were not provided.

AEP Transmission Company (AEPTCo)

AEPTCo’s earnings attributable to AEP’s member were $196 million in Q3 2026, up $17 million from $179 million in Q3 2025. For 9M 2026, earnings were $571 million, down $375 million from $946 million in 9M 2025. The nine-month decline was substantially affected by the June 2025 FERC order on NOLC treatment in transmission formula rates.

Investment and transmission revenue

Transmission property, net, increased to $18.704 billion at September 30, 2026, from $16.729 billion a year earlier, reflecting continued investment. Plant in service was $18.078 billion, versus $16.471 billion; construction work in progress was $2.791 billion, versus $2.098 billion; and accumulated depreciation and amortization was $2.165 billion, versus $1.840 billion.

Transmission revenue increased $36 million in Q3 2026 year over year, primarily from continued transmission investment. For 9M 2026, revenue decreased $67 million: the FERC order reduced revenue by $214 million, partly offset by $147 million of revenue from continued investment.

Costs, taxes and other drivers

The FERC order also shaped the nine-month tax comparison. Income tax expense increased $212 million, primarily because Excess ADIT declined by $254 million following the order. This was partly offset by $34 million of lower tax expense from reduced pretax book income and $5 million from lower state taxes.

Higher investment expanded the depreciable base and CWIP, increasing depreciation and amortization by $12 million in Q3 and $35 million in 9M. Allowance for equity funds used during construction increased by $5 million in Q3 and $10 million in 9M. Higher transmission investment also contributed to increased property taxes. Total taxes other than income taxes decreased $10 million in Q3, primarily due to prior-period Ohio adjustments, but increased $14 million in 9M.

O&M rose $9 million in Q3 and $37 million in 9M, reflecting higher employee costs ($7 million and $16 million, respectively), vegetation management and facility compliance costs ($2 million and $12 million), and affiliated rent and shared services ($2 million and $7 million). Interest expense increased $6 million in Q3 and $23 million in 9M, driven by higher long-term debt balances and interest rates.

Noncontrolling interests

The 9M change in noncontrolling interests was a $1 million increase overall. It included a $55 million increase related to the Midwest Transmission Holdings noncontrolling-interest transaction, which closed in June 2025, offset by $54 million from higher 2025 earnings associated with the FERC order’s impact.

AEP Transmission Company, LLC (AEPTCo)

AEPTCo, wholly owned by AEP Transmission Holdco, expanded its transmission investment during the first nine months of 2026. Higher quarterly revenue and operating income contrasted with lower year-to-date revenue and earnings, largely because 2026 included revenue-refund provisions while 2025 included reversals.

Revenue and earnings

• Q3 2026 revenue was $594M, up from $558M in Q3 2025. Transmission revenue was $115M from $108M, while sales to AEP affiliates were $501M from $450M. Revenue included a $21M affiliated refund provision and a $3M nonaffiliated provision, versus none in Q3 2025; other revenue was $2M versus none.
• 9M 2026 revenue was $1.760B, down from $1.827B in 9M 2025. Transmission revenue was $335M from $325M, and affiliated sales were $1.448B from $1.350B. The decline reflects affiliated refund provisions of $26M in 2026 versus a $120M reversal in 2025, and nonaffiliated provisions of $6M versus a $32M reversal. Other revenue was $9M versus none.
• Operating income rose to $325M from $300M in Q3, but fell to $957M from $1.110B for 9M.
• Net income was $226M from $205M in Q3 and $659M from $1.033B for 9M. Earnings attributable to AEP member were $196M from $179M in Q3 and $571M from $946M for 9M.

Costs and balance sheet

For 9M, expenses increased to $803M from $717M, including depreciation and amortization of $389M from $354M, other operation expense of $135M from $106M, and taxes other than income taxes of $250M from $236M. Interest expense rose to $196M from $173M. Income tax expense was $184M, compared with a $28M tax benefit in 9M 2025, contributing to the year-to-date net income decline.

At September 30, 2026, total assets were $19.469B, up from $17.999B at December 31, 2025. Total equity, including noncontrolling interest, was $8.619B, versus $7.643B at year-end; it comprised $7.429B of member’s equity and $1.190B of noncontrolling interest. Goodwill and intangible assets are not separately presented. Net transmission property increased to $18.704B from $17.203B, including construction work in progress of $2.791B from $2.005B. Long-term debt, including current maturities, was $6.837B, compared with $6.599B at year-end.

Cash flow, investment, and financing

For 9M 2026, operating cash flow was $984M, up from $938M, while construction expenditures—capital investment—rose to $1.740B from $1.145B, exceeding operating cash flow in both periods. Cash and cash equivalents were zero at both the beginning and end of each period.

Financing included $859M of nonaffiliated long-term debt issuance and $623M of repayments. AEPTCo received capital contributions of $386M from AEP member and $240M from noncontrolling interests, and paid dividends of $141M to AEP member and $168M to noncontrolling interests. Cash interest paid, net of capitalized amounts, was $154M, versus $140M.

Equity growth during 2026 reflected contributions and earnings. In 2025, the Midwest Transmission Holdings noncontrolling-interest transaction had added $2.783B net of transaction costs; there were no comparable transaction proceeds in 9M 2026. No share count is reported for this LLC.

APCo operating results and drivers

Earnings and revenue

• Net income rose $43 million to $124 million in Q3 2026 from $81 million in Q3 2025. For 9M 2026, net income increased $16 million to $369 million from $353 million.
• Revenue increased $76 million in Q3 and $39 million in 9M. Q3’s increase comprised retail +$53 million, off-system sales +$7 million, transmission +$10 million, and other revenue +$6 million. For 9M, retail was −$3 million, off-system sales +$9 million, transmission +$32 million, and other revenue +$1 million.

Retail sales, weather and revenue

• Q3 retail electricity sales increased to 6,524 million kWh from 6,365 million; 9M sales decreased to 19,645 million kWh from 19,715 million.
  • Q3 residential sales were 2,613 million kWh from 2,516 million, commercial sales were 1,595 million from 1,530 million, and industrial sales were 2,105 million from 2,117 million.
  • For 9M, residential sales were 8,210 million kWh from 8,202 million, commercial sales were 4,536 million from 4,495 million, and industrial sales were 6,278 million from 6,397 million.
• Cooling degree days increased 25% in Q3 (932 from 748) and 18% in 9M (1,386 from 1,176). Q3 retail revenue benefited from $53 million of higher base-rate and rider revenue and $21 million from weather-related usage, partly offset by $13 million of lower fuel revenue. For 9M, higher base-rate and rider revenue (+$110 million) and weather-related usage (+$15 million) were offset by lower fuel revenue (−$114 million) and lower weather-normalized revenue (−$21 million), mainly residential.

Wholesale and transmission

• Wholesale sales were 1,133 million kWh in Q3 from 966 million, but 2,118 million kWh in 9M from 2,269 million.
• Off-system sales revenue increased $7 million in Q3 and $9 million in 9M, primarily from July 2026 margins amid higher PJM prices and APCo generation performance during high-price periods.
• Transmission revenue rose $10 million in Q3 and $32 million in 9M, mainly reflecting continued investment. The 9M increase was partly offset by a $6 million effect from a June 2025 FERC order concerning NOLCs in transmission formula rates.

Expenses, regulatory recovery and taxes

• Purchased electricity, fuel and consumables expense decreased $24 million in Q3 and $81 million in 9M. Lower fuel revenues increased Virginia FAC and West Virginia ENEC under-recoveries by $40 million in Q3 and $152 million in 9M. WVPSC-ordered final recovery of MRBC, Broadband and vegetation-management under-recoveries added $39 million in both periods; partly offsetting these amounts were lower under-recoveries associated with higher PJM revenues ($34 million in Q3; $57 million in 9M). Other offsets and costs included previously deferred Virginia consumables now recovered through E-RAC rates, nonrecoverable Virginia purchased-power costs and renewable-compliance expense.
• O&M expense increased $32 million in Q3, driven by employee costs (+$8 million), distribution/vegetation management and storm restoration (+$7 million), transmission (+$6 million), steam-generation maintenance (+$5 million), and ARO/Legacy CCR accretion (+$4 million). 9M O&M rose $60 million, including distribution (+$33 million), employee costs (+$17 million), steam-generation maintenance (+$15 million), and accretion (+$8 million), partly offset by a $23 million gain on sale of a non-utility land investment.
• Depreciation and amortization increased $28 million in Q3, mainly from a July 2026 order’s final true-up for past West Virginia MRBC costs, and $26 million in 9M, primarily from a CAMT regulatory-deferral true-up. Interest expense rose $21 million in Q3 and $38 million in 9M, reflecting higher long-term debt balances.
• Income-tax expense decreased $25 million in Q3, mainly due to increased flow-through benefits, lower flow-through CAMT expense and higher PTCs. The $40 million 9M decrease reflected a $25 million CAMT true-up related to IRS Notice 2026-07, higher PTCs, lower state taxes, increased Excess ADIT amortization and lower pretax book income; these benefits were partly offset by a $23 million increase associated with reduced Excess ADIT, primarily tied to the June 2025 FERC NOLC order. Taxes other than income taxes increased $14 million in 9M, mainly from higher business and occupation and property taxes.

Appalachian Power Company (APCo) — condensed financial statements

Unaudited; figures in U.S. dollars. Q3 and 9M refer to the periods ended September 30, 2026, with comparable 2025 periods.

Results of operations

• Q3 revenue was $1.133B, up from $1.057B:
  • Electric generation, transmission and distribution: $1.047B from $981M
  • Sales to AEP affiliates: $81M from $71M
  • Other revenue: $5M from $5M
• 9M revenue was $3.216B, compared with $3.177B:
  • Electric generation, transmission and distribution: $2.951B from $2.955B
  • Sales to AEP affiliates: $254M from $209M
  • Other revenue: $11M from $13M
• Q3 operating income increased to $213M from $174M, and net income rose to $124M from $81M. For 9M, operating income was $608M from $588M and net income was $369M from $353M.
• Interest expense rose to $91M from $70M in Q3 and $246M from $208M in 9M. Lower income tax expense partly offset the higher interest burden: $7M from $32M in Q3 and $19M from $59M in 9M.
• Total operating expenses were $920M from $883M in Q3 and $2.608B from $2.589B in 9M. Depreciation and amortization increased to $180M from $152M in Q3 and $512M from $486M in 9M; maintenance rose to $117M from $105M and $320M from $267M, respectively. These increases were partly offset by lower purchased electricity, fuel and other generation consumables: $350M from $374M in Q3 and $991M from $1.072B in 9M.

Balance sheet and financing

At September 30, 2026, total assets were $18.832B, compared with $17.792B at December 31, 2025; total common shareholder’s equity was $5.929B, down from $6.180B. Goodwill and intangible assets other than goodwill were not separately presented in the summarized balance-sheet information. Common shares outstanding were 13,499,500 at September 30, 2026; beginning-period shares were not provided.

Nonaffiliate long-term debt, including current maturities, increased to $7.422B from $6.259B. Included in the September balance was $1.427B of Appalachian consumer rate relief and recovery funding debt ($66M current and $1.361B noncurrent), compared with $92M at year-end ($30M current and $62M noncurrent). Securitized assets related to the funding programs rose to $1.406B from $78M, a substantial change in the balance sheet’s securitization-related assets and debt.

Net PP&E declined to $14.184B from $14.713B. Reported generation PP&E fell to $5.724B from $7.886B, while transmission PP&E increased to $5.431B from $5.277B and distribution PP&E to $6.119B from $5.938B; the reported information does not explain the large generation-asset decline. Risk management assets rose to $188M from $81M, and the regulatory asset for under-recovered fuel costs increased to $160M from $83M.

Cash flows and equity

For 9M, operating cash flow was $812M from $809M, and construction expenditures (capital expenditures) were $761M from $749M. Acquisitions of assets used $352M, versus none in 9M 2025, contributing to investing cash outflow of $1.099B from $768M.

Financing cash flow was $328M, compared with an outflow of $46M. APCo issued $1.364B of long-term debt from $593M and retired $206M from $498M; common dividends were $700M from $50M, while parent capital contributions were $81M from $8M. Cash, cash equivalents and restricted cash for securitized funding ended 9M at $64M from $15M.

Equity declined by $251M from year-end, principally reflecting $700M of common dividends, partly offset by $369M of 9M net income and the $81M parent contribution. Other comprehensive loss was $1M in each 9M period.

Overall, APCo reported higher operating income, net income and operating cash flow, while increased debt and interest expense raise financing-cost considerations. Fuel-cost recovery is reflected in regulatory assets and cash-flow adjustments; risk-management marks were a $91M 9M 2026 cash-flow reconciliation adjustment, versus $57M in 9M 2025. APCo is wholly owned by its parent.

Indiana Michigan Power

Earnings and demand

Indiana Michigan Power’s net income declined in Q3 2026 to $113 million from $150 million in Q3 2025, but increased for 9M 2026 to $358 million from $332 million. In Q3, an $82 million revenue increase was more than offset by $102 million of adverse expense and other changes and $17 million of higher income tax expense. For 9M, $355 million of higher revenue exceeded $253 million of adverse expense and other changes and $76 million of higher income tax expense.

Electricity sales rose substantially overall, led by commercial demand:

Residential and industrial sales declined year over year in 9M. Actual 9M cooling degree days fell 5% and heating degree days fell 4%, contributing to an $8 million reduction in weather-related usage.

Revenue drivers

Retail revenue increased $78 million in Q3 and $327 million in 9M. Q3 growth included $69 million of higher weather-normalized revenue, primarily commercial, and $26 million of higher fuel revenue, partly offset by $24 million of lower rider revenue. For 9M, higher weather-normalized revenue ($193 million), fuel revenue ($91 million) and rider revenue ($31 million), along with $19 million from lower regulatory provisions for refund, drove the increase.

Off-system sales revenue declined $2 million in Q3 but increased $42 million in 9M. The 9M increase primarily reflected Rockport Unit 2 merchant sales during Winter Storm Fern in January 2026, partly offset by lower merchant sales and economic hedging activity. 9M transmission revenue decreased $12 million, primarily due to a June 2025 FERC order affecting NOLCs in transmission formula rates.

Costs, investment and regulatory factors

Operating cost pressures constrained earnings. O&M expense rose $60 million in Q3 and $110 million in 9M, reflecting storm restoration and vegetation management, higher recoverable PJM transmission expenses, employee-related costs and costs associated with acquired generation facilities. 9M generation fuel and purchased-power costs increased $80 million, primarily from recoverable costs, partly offset by lower Rockport Unit 2 merchant-generation fuel costs.

Depreciation and amortization increased $9 million in Q3 and $25 million in 9M, mainly because of a higher depreciable base and acquired generation. The 9M increase also included $8 million related to NOLC Excess ADIT deferrals and amortization, partly offset by $11 million of lower expense from Michigan PTC deferral activity. Other income increased $9 million in 9M, primarily from higher AFUDC associated with a larger equity base and increased equity return rates. Interest expense rose $8 million in Q3 and $26 million in 9M as long-term debt balances increased.

9M income tax expense increased $76 million, including $32 million from reduced Excess ADIT following the FERC order, $22 million from higher pretax book income and $18 million from lower PTCs.

Investor considerations

Commercial sales and weather-normalized retail revenue supported growth, while higher O&M, fuel and purchased-power costs, depreciation, interest and taxes limited earnings. Results remain exposed to storm and vegetation-management costs, PJM and FERC-related regulatory changes, PTC availability and the economics of merchant generation.

Indiana Michigan Power Company (I&M) — Q3 and nine months ended September 30, 2026

I&M, a wholly owned subsidiary of AEP, reported unaudited results for Q3 and the first nine months of 2026. Revenue grew in both periods, but Q3 earnings declined as expenses rose; year-to-date operating income increased while net income grew more modestly.

Earnings and revenue

• Q3 2026: Revenue was $894M, up from $812M; operating income was $154M, down from $166M; and net income was $113M, down from $150M.
• 9M 2026: Revenue was $2.627B, up from $2.272B; operating income was $503M, up from $379M; and net income was $358M, up from $332M.

Revenue was driven primarily by electric generation, transmission and distribution. Refund provisions reduced reported revenue in both periods.

Expenses and earnings drivers

Total expenses were $740M in Q3 2026, compared with $646M, and $2.124B in 9M 2026, compared with $1.893B. Notable expense comparisons:

Income tax expense was $6M in Q3 2026, versus an $11M benefit in Q3 2025; for 9M, tax expense was $41M, versus a $35M benefit.

Balance sheet and funding

At September 30, 2026, total assets were $16.408B, compared with $14.625B at December 31, 2025. Total common shareholder’s equity increased to $4.120B from $3.784B, while total liabilities rose to $12.288B from $10.841B. Goodwill and intangible assets other than goodwill were not separately presented.

Net property, plant and equipment increased to $9.498B from $7.944B, including construction work in progress of $701M, up from $403M. Spent nuclear fuel and decommissioning trusts were $5.256B, versus $4.916B.

Long-term debt, including current maturities, was $4.118B at September 30, 2026: $75M current and $4.043B noncurrent nonaffiliated debt. At year-end 2025, it was $3.561B: $117M current and $3.444B noncurrent. Advances from affiliates were $284M, compared with none at year-end. The current regulatory liability for over-recovered fuel costs increased to $155M from $19M.

Cash flow and equity

For 9M 2026, operating cash flow was $1.068B, compared with $942M in 9M 2025; net income was $358M versus $332M. Construction expenditures (capital expenditures) were $648M, up from $478M. Investing cash outflow increased to $1.874B from $748M, including $1.275B for acquisitions of generation facilities, with no such acquisition amount in 2025.

Financing activities provided $806M, versus $194M used in 9M 2025. I&M issued $640M of nonaffiliated long-term debt, compared with $249M, and received $28M in parent contributions, compared with $8M. Common dividends were $50M in each period. Period-end cash was $2M. Cash interest paid, net of capitalized amounts, was $129M, versus $111M.

Common shareholder’s equity rose from $3.784B at December 31, 2025 to $4.120B at September 30, 2026. The balance sheet reported 1.400 million shares outstanding at September 30; an opening-period share count was not provided. No other comprehensive income was reported in Q3 or 9M 2026 or 2025, so comprehensive income equaled net income.

Ohio Power Company (OPCo)

OPCo, an AEP subsidiary, reported higher net income in both Q3 and the first nine months of 2026. Increased retail and transmission revenues supported results, partly offset by higher operating and maintenance costs.

Earnings and electricity sales

• Net income: Q3 2026 was $112M, up from $101M in Q3 2025; 9M 2026 was $338M, up from $267M in 9M 2025. Revenue increases of $138M in Q3 and $312M in 9M were partly offset by expense and other changes of $131M and $257M, respectively.
• Retail electricity sales: Q3 volume increased to 16,949 million kWh from 15,055 million kWh; 9M volume rose to 47,028 million kWh from 41,173 million kWh. Commercial sales accounted for much of the growth, reaching 9,201 million kWh from 7,391 million kWh in Q3 and 25,171 million kWh from 19,203 million kWh in 9M. Residential sales were nearly flat in Q3 and declined year to date.
• Total electricity sales, including wholesale: 16,951 million kWh from 15,607 million kWh in Q3 and 47,929 million kWh from 42,856 million kWh in 9M.

Revenue drivers

Retail revenue increased $172M in Q3 and $314M in 9M. Q3 drivers included $114M of higher rider revenues, $40M from higher purchased-power prices for standard service offer (SSO) customers, $10M from weather-normalized commercial and industrial revenues, and $5M from weather-related usage. For 9M, rider revenues added $198M, higher SSO purchased-power prices added $99M, and weather-normalized residential and commercial revenues added $20M; lower weather-related usage reduced revenue by $14M.

Transmission revenue increased $6M in Q3 and $26M in 9M, primarily reflecting continued investment. Off-system sales declined $32M in Q3 and $14M in 9M. The main factor was OPCo’s June 2026 transfer of its OVEC power participation entitlement to AGR. The 9M decline was partly offset by $18M of higher first-half OVEC power sales amid higher market prices and volumes. Other revenue declined $8M in Q3 and $14M in 9M, primarily because Ohio legislation ended retail recovery of OVEC purchased-power costs, reducing third-party Legacy Generation Resource Rider revenue.

Costs and regulatory factors

Other operation and maintenance expense increased $117M in Q3 and $215M in 9M, largely from higher transmission costs—including recoverable PJM expenses—distribution storm restoration and vegetation management, and energy assistance. The 9M increase included $151M in transmission expense ($134M PJM-related), $28M in distribution expense, and $22M in energy assistance; these increases were substantially associated with recoverable costs.

Depreciation and amortization increased $12M in Q3 and $25M in 9M due to a higher depreciable base. Other taxes increased $8M and $33M, respectively, mainly because of property taxes.

Purchased electricity for resale expense decreased $14M in Q3 and $27M in 9M. Lower OVEC costs following the entitlement transfer and legislative changes were partly offset by higher recoverable SSO auction purchases, which increased $36M in Q3 and $86M in 9M. Purchased electricity from AEP affiliates increased $8M in Q3 and $13M in 9M, primarily for SSO customers. Income tax expense decreased $5M in Q3 and $18M in 9M, mainly due to customer refunds of Excess ADIT credits under the 2025 base-rate case.

Weather

Q3 actual cooling degree days were 794 versus 734. For 9M, actual heating degree days were 1,996 versus 2,077, while cooling degree days were 1,115 versus 1,076.

Ohio Power Company — nine months ended September 30, 2026

Ohio Power Company, wholly owned by AEP, reported higher revenue and earnings, while sharply increased construction spending left cash flow after construction outlays negative and increased reliance on parent and affiliate funding.

Revenue and profitability

• Q3 2026 revenue was $1.208B, up from $1.070B in Q3 2025 (+12.9%). By category:
  • Electricity, transmission and distribution: $1.190B from $1.059B
  • Sales to AEP affiliates: $13M from $8M
  • Other revenue: $5M from $3M
• 9M 2026 revenue was $3.305B, up from $2.993B (+10.4%). By category:
  • Electricity, transmission and distribution: $3.253B from $2.959B
  • Sales to AEP affiliates: $40M from $24M
  • Other revenue: $12M from $10M
• Operating income was $160M in Q3, from $153M (+4.6%), and $462M for 9M, from $409M (+13.0%). Q3 growth was constrained by expenses: total expenses increased to $1.048B from $917M, led by other operation expense of $449M from $341M. For 9M, total expenses were $2.843B from $2.584B.
• Net income was $112M in Q3, from $101M (+10.9%), and $338M for 9M, from $267M (+26.6%). Interest expense was $40M in both Q3 periods and $117M for 9M, from $118M. 9M income tax expense declined to $41M from $59M.

Balance sheet and equity

At September 30, 2026, total assets were $12.716B, compared with $12.210B at December 31, 2025; common shareholder equity was $4.446B, compared with $4.151B. Goodwill and intangible assets other than goodwill were not separately presented in the summarized balance sheet information.

Net property, plant and equipment increased to $11.398B from $10.684B, including construction work in progress of $863M from $811M. Nonaffiliated long-term debt was $3.721B from $3.718B; current liabilities were $1.905B from $1.890B. Cash was $7M from $5M. Common shares outstanding at September 30, 2026 were 27,952,473; the beginning-period share count was not provided.

Equity growth reflected $338M of 9M net income and $109M of parent capital contributions, partly offset by $150M of common dividends and a $2M noncash distribution to Parent.

Cash flow and funding

For 9M 2026, operating cash flow was $719M, up from $646M in 9M 2025. Construction expenditures rose 28.9% to $963M from $747M. Net investing cash outflow was $907M from $587M, and operating cash flow less construction expenditures was negative $244M, compared with negative $101M.

Financing included $109M of parent capital contributions, compared with $2M, and a $161M net increase in advances from affiliates, compared with $13M. Common dividends paid were $150M, compared with $71M. Cash interest paid, net of capitalized amounts, was $90M, compared with $91M.

The combination of rising construction outlays and negative cash flow after construction spending makes parent contributions and affiliate advances important sources of funding.

Public Service Company of Oklahoma (PSO)

Earnings and revenue

PSO’s Q3 2026 net income was $234 million, up $104 million from $130 million in Q3 2025. The increase reflected $174 million of higher revenue, partly offset by a $17 million adverse net impact from expenses and other items and a $53 million decrease in income tax benefit.

For 9M 2026, net income was $303 million, up $82 million from $221 million in 9M 2025. A $271 million revenue increase was partly offset by a $176 million adverse net impact from expenses and other items and a $13 million decrease in income tax benefit.

Retail revenue increased $173 million in Q3 and $276 million in 9M. Rider revenue accounted for increases of $148 million and $274 million, respectively, including $75 million of 2026 interim rate rider revenue. Weather-related usage added $56 million in Q3 and $62 million in 9M. Offsets included lower fuel revenue—down $36 million in Q3 and $48 million in 9M—reflecting lower authorized fuel rates. Weather-normalized revenue rose $6 million in Q3, mainly from industrial customers, but fell $11 million in 9M, mainly from residential customers. Other revenue declined $6 million in Q3 and $8 million in 9M, primarily due to lower associated business development revenue and environmental-credit sale gains. Transmission revenue increased $7 million in Q3 and $3 million in 9M, reflecting continued investment.

Electricity sales and weather

Retail electricity sales were 6,290 million kWh in Q3 2026, versus 5,660 million kWh in Q3 2025, and 15,446 million kWh in 9M 2026, versus 14,841 million kWh in 9M 2025. Total sales, including wholesale, were 6,386 million kWh versus 5,828 million kWh in Q3, and 15,596 million kWh versus 15,094 million kWh in 9M.

Weather materially supported usage: Q3 cooling degree days were 1,913 versus 1,353, and 9M cooling degree days were 2,763 versus 1,982. By contrast, 9M heating degree days were 761 versus 1,193. Residential retail sales rose to 2,459 million kWh from 2,027 million kWh in Q3 and to 5,229 million kWh from 4,938 million kWh in 9M.

Expenses and taxes

In Q3, purchased electricity, fuel and other generation consumables expense decreased $64 million, including a $37 million decrease from deferred-fuel effects associated with lower fuel revenue and a $25 million decrease in recoverable production tax credits (PTCs). Depreciation and amortization increased $69 million because of a higher depreciable base, while interest expense increased $8 million, reflecting higher long-term debt.

For 9M, purchased electricity, fuel and other generation consumables expense decreased $21 million: a $47 million decrease related to deferred-fuel effects was partly offset by a $28 million increase in recoverable PTCs. Other O&M expense increased $67 million, including $30 million of higher generation costs from acquired generation facilities, $13 million of higher employee costs, $11 million of higher distribution costs (including overhead-line maintenance), and $7 million of higher transmission expense. SPP expenses rose $33 million, partly offset by a $19 million reduction following the June 2025 FERC order on NOLC treatment in transmission formula rates and a $12 million SPP upgrade-cost refund. Depreciation and amortization rose $80 million on a higher depreciable base; property taxes increased $10 million, partly due to acquired generation facilities; and interest expense increased $35 million due to higher long-term debt.

The income tax benefit decreased $53 million in Q3, mainly due to $33 million of higher pretax book income and $17 million of fewer PTCs. The $13 million 9M decrease reflected $20 million from higher pretax book income and $13 million from lower Excess ADIT, primarily related to the June 2025 FERC order on NOLCs, partly offset by $21 million from increased PTCs.

PSO condensed financial statements

PSO is wholly owned by AEP’s parent. For the three and nine months ended September 30, 2026, revenue and earnings increased year over year, while higher depreciation, debt and construction spending were notable alongside lower purchased power and fuel costs.

Revenue

Earnings and expenses

Q3 operating income rose to $297M from $135M, and net income increased to $234M from $130M. Total expenses were $571M, versus $559M. Purchased electricity, fuel and consumables fell to $231M from $295M, more than offsetting increases in depreciation and amortization ($136M from $67M) and other operation costs ($145M from $139M). Interest expense increased to $48M from $40M. Income tax expense was $21M, compared with a $32M tax benefit in Q3 2025.

For 9M 2026, operating income increased to $376M from $241M, and net income to $303M from $221M. Total expenses were $1.452B, versus $1.316B. Depreciation and amortization rose to $283M from $203M, and other operation expense to $410M from $363M; purchased electricity, fuel and consumables declined to $575M from $596M. Interest expense increased to $134M from $99M. PSO recorded a $51M income tax benefit, versus a $64M benefit in 9M 2025.

Balance sheet and shares

At September 30, 2026, total assets were $12.006B, compared with $10.218B at December 31, 2025; total equity was $4.029B, compared with $3.613B. Goodwill and intangible assets other than goodwill were not separately reported in the presented balance sheet.

Net property, plant and equipment increased to $10.436B from $8.964B, including construction work in progress of $1.168B from $635M. Long-term debt, nonaffiliated, was $4.462B, up from $3.475B; no debt was due within one year at September 30, versus $51M at year-end 2025. Customer deposits increased to $355M from $115M. Common shares outstanding were 9.013M at September 30, 2026; beginning-period shares were not stated in the chunk summary.

Cash flow, investment and financing

For 9M 2026, operating cash flow increased to $892M from $571M, while net income was $303M from $221M. Construction expenditures, a measure of capital investment, rose to $1.089B from $534M. Generation-facility acquisitions were $608M, versus $1.657B in 9M 2025; investing cash outflow was $1.766B from $1.952B.

Operating cash flow benefited from a $238M increase in customer deposits, compared with $42M in 9M 2025, and a $156M increase in other noncurrent liabilities, compared with $14M. Financing included $986M of nonaffiliated long-term debt issuance and $113M of parent capital contributions, versus $793M and $675M, respectively, in 9M 2025. Cash interest paid, net of capitalized amounts, rose to $152M from $96M; ending cash was $4M, versus $3M a year earlier.

Overall, earnings growth reflected higher revenue and lower purchased electricity, fuel and consumables, despite rising depreciation, operating and interest costs. The sharp increase in construction spending, higher debt and greater cash interest paid are important counterpoints to stronger operating cash flow.

SWEPCo

SWEPCo’s earnings attributable to its common shareholder were nearly flat in Q3 2026 at $188M, compared with $189M in Q3 2025. For 9M 2026, earnings declined to $330M from $353M in 9M 2025.

Sales and weather

Q3 electricity sales rose 8.5% to 7,238M kWh from 6,668M kWh. Retail sales increased to 5,443M kWh from 5,106M kWh, and wholesale sales to 1,795M kWh from 1,562M kWh. Q3 cooling degree days were 1,771, versus 1,545 a year earlier, supporting weather-related retail revenue growth.

For 9M, total sales increased to 17,783M kWh from 17,581M kWh: retail sales rose to 13,609M kWh from 13,276M kWh, while wholesale sales declined to 4,174M kWh from 4,305M kWh. Cooling degree days were 2,809 versus 2,589; heating degree days fell to 496 from 726.

Q3 earnings drivers

Revenue increased $46M overall. Retail revenue rose $63M, partly offset by a $16M decline in transmission revenue and a $1M decline in other revenue. Retail growth reflected the Arkansas base rate case (+$31M), Louisiana rider revenues (+$29M) and weather-related usage (+$20M). Offsets included an $18M credit to certain existing wholesale generation customers and $7M of lower weather-normalized revenue.

Transmission revenue declined primarily because $12M of SPP upgrade credits were repaid; that decrease was offset by an equal amount of incremental O&M expense. Higher generation fuel costs reduced earnings by $13M. Interest expense rose $25M, including $19M from higher long-term debt and $4M of interest on credits owed to wholesale customers. Lower production tax credits reduced the income tax benefit by $6M.

9M earnings drivers

Revenue increased $104M, led by $105M of retail revenue growth, with transmission revenue down $6M and off-system sales up $1M. Retail gains included Louisiana rider revenue (+$82M), the Arkansas rate case (+$64M) and higher weather-normalized revenue (+$39M). These were partly offset by a $53M reduction in fuel revenue—including a $43M Texas over-recovered fuel refund and $10M from lower authorized rates—and $41M of credits to certain wholesale generation customers.

Transmission revenue reflected a $27M decrease following the June 2025 FERC order on NOLCs in transmission formula rates and $12M of SPP upgrade-credit repayments, partly offset by $34M from continued transmission investment.

Lower purchased electricity, fuel and consumables improved earnings by $43M, largely reflecting the Texas fuel refund, lower authorized rates and prior-year fuel disallowances; the benefit was partly offset by higher recoverable PTCs and non-recoverable fuel costs. O&M increased $60M: generation costs rose $28M, including $16M related to the Wagon Wheel Wind Facility acquisition; distribution line maintenance rose $17M; employee costs rose $9M; and a $6M partial write-off followed a FERC audit of capitalized vegetation-management costs.

Depreciation and amortization increased $40M, primarily due to a higher depreciable base, including Wagon Wheel. Asset impairment charges rose $31M because of a probable partial disallowance of Pirkey Plant net book value in the 2025 Texas Base Rate Case. Interest expense increased $61M, principally from higher long-term debt (+$46M), Texas tax-normalization rider amortization (+$7M) and interest on wholesale-customer credits (+$4M).

The income tax benefit increased $23M, mainly from higher PTCs (+$48M), lower pretax book income (+$10M) and lower state taxes (+$7M), partly offset by a $42M reduction in Excess ADIT associated primarily with the FERC NOLC order.

SWEPCo — Q3 and 9M 2026 results and financial position

Revenue and earnings

• Q3 2026 revenue was $770M, up from $724M; 9M revenue was $1.929B, up from $1.825B. Generation, transmission and distribution revenue was $769M vs. $694M in Q3 and $1.906B vs. $1.761B in 9M. Affiliate sales were $24M vs. $28M in Q3 and $71M vs. $63M in 9M. Other revenue was $2M vs. $6M in Q3 and $5M vs. $10M in 9M.
• Refund provisions against nonaffiliate revenue increased materially, to $25M from $4M in Q3 and $53M from $9M in 9M, offsetting some of the revenue growth.
• Q3 operating income rose to $221M from $191M, while 9M operating income was $359M vs. $349M. Q3 net income was $189M vs. $190M; 9M net income declined to $332M from $356M. Earnings attributable to SWEPCo’s common shareholder were $188M vs. $189M in Q3 and $330M vs. $353M in 9M.

Expenses and earnings pressures

• Total expenses were $549M vs. $533M in Q3 and $1.570B vs. $1.476B in 9M. Interest expense rose to $62M from $37M in Q3 and $171M from $110M in 9M, weighing on earnings despite higher operating income.
• 9M depreciation and amortization increased to $374M from $334M. SWEPCo recorded $31M of asset impairment and related charges in 9M 2026, versus none in 9M 2025.

Cash flow, investment and liquidity

• 9M operating cash flow fell to $606M from $753M, while construction expenditures increased to $1.022B from $654M. Operating cash flow therefore did not cover construction expenditures. Investing cash outflow was $1.470B vs. $910M.
• Cash, cash equivalents and restricted cash were $9M at period-end, down from $17M at the start of the period and $11M at September 30, 2025. Cash interest paid, net of capitalized amounts, was $139M vs. $119M.

Funding and balance sheet

• At September 30, 2026, total assets were $14.830B, compared with $13.524B at December 31, 2025; total equity was $5.480B vs. $4.899B. Goodwill and other intangible assets are not separately presented in the excerpt, so tangible common equity cannot be determined from the disclosed lines.
• Nonaffiliate long-term debt totaled $5.591B, including $417M due within one year. At year-end 2025, nonaffiliate debt totaled $3.974B, including $917M due within one year, alongside $1.000B of affiliate long-term debt. During 9M 2026, SWEPCo issued $2.134B of nonaffiliate long-term debt and retired $1.000B of affiliate debt.
• Financing cash flow included $246M of parent contributions, down from $450M in 9M 2025. Advances to affiliates rose to $494M from $23M at year-end, with a $471M net cash outflow from changes in affiliate advances.
• Parent contributions of $246M, 9M net income of $332M, and $5M of other comprehensive income contributed to the increase in equity; dividends paid to nonaffiliated shareholders were $2M. SWEPCo is wholly owned by its parent. The balance sheet reports 3,680 common shares outstanding at September 30, 2026; an opening-period share count is not provided.

Regulatory exposure and investor considerations

Refund provisions remain a notable regulatory exposure: provision-for-refund liabilities were $90M current and $8M noncurrent at September 30, 2026, compared with $81M current and $47M noncurrent at year-end 2025. Higher capital spending and increased external borrowing, alongside lower 9M operating cash flow and elevated interest expense, constrain internally generated funding.

Earnings and share dilution

AEP’s Q3 2026 earnings attributable to common shareholders increased 22.1% year over year to $1.187 billion from $972 million. Basic EPS rose to $2.18 from $1.82, and diluted EPS to $2.16 from $1.81. Weighted-average basic shares were 544.4 million versus 534.9 million; diluted shares were 550.1 million versus 538.0 million, reflecting a dilutive effect of 5.7 million shares versus 3.1 million.

For the first nine months of 2026, earnings attributable to common shareholders declined 7.5% to $2.774 billion from $2.998 billion. Basic EPS was $5.10 versus $5.61, and diluted EPS was $5.05 versus $5.59. Weighted-average basic shares increased to 543.6 million from 534.2 million, while diluted shares increased to 549.3 million from 536.4 million; the dilutive effect was 5.7 million shares versus 2.2 million.

AEP expects to issue 3.0 million common shares when its ATM Forward matures and settles in December 2026. The shares were excluded from Q3 2026 diluted EPS because the forward price exceeded the average market price, making their inclusion antidilutive. No antidilutive shares were outstanding at September 30, 2025.

Cash and other interim-period disclosures

At September 30, 2026, cash, cash equivalents and restricted cash were $507 million for AEP, $9 million for AEP Texas, $64 million for APCo, and $9 million for SWEPCo, compared with $268 million, $14 million, $23 million, and $17 million, respectively, at December 31, 2025. AEP’s cash and cash equivalents, excluding restricted cash, were $418 million, up from $197 million at year-end 2025.

Restricted cash—primarily funds held by trustees for securitization bond payments—was $89 million for AEP, $9 million for AEP Texas, $60 million for APCo, and $6 million for SWEPCo at September 30, 2026, versus $71 million, $14 million, $18 million, and $15 million, respectively, at December 31, 2025.

For the first nine months of 2026, cash paid for interest, net of capitalized amounts, increased 17.7% to $1.548 billion from $1.315 billion. Construction expenditures included in current liabilities at September 30 were $1.813 billion, compared with $1.169 billion a year earlier. Contribution-in-aid-of-construction advances included in current assets were $69 million, versus none in 2025.

The interim financial statements are unaudited and include normal and recurring adjustments. Management cautions that interim results are not necessarily indicative of full-year 2026 results. A 2025 change to rounding presentation had no material impact on previously reported figures.

New accounting standards and regulatory developments

• ASU 2025-06 — internal-use software: AEP and the other Registrants early adopted the standard prospectively on January 1, 2026. Adoption had no material impact on results of operations, financial position, or cash flows. The standard updates the capitalization model by replacing project-stage references with a threshold based on whether a software project is probable of completion.

• ASU 2024-03 — expense disaggregation: The standard will require disclosure of specified expenses included in income-statement captions, including employee compensation, depreciation, and intangible-asset amortization. It also requires disclosure of total selling expenses and, annually, the company’s definition of selling expenses. It applies to annual periods beginning after December 15, 2026, and interim periods beginning after December 15, 2027; early adoption is permitted. Management is evaluating the timing and method of adoption.

• ASU 2026-02 — environmental credits: The standard establishes accounting and disclosure guidance for environmental credits and related obligations, relevant to entities that generate, purchase, or receive credits or have obligations that may be settled using them. It applies to annual periods beginning after December 15, 2027, including interim periods within those years; retrospective early adoption is permitted. Management is evaluating the impact.

• SEC climate-disclosure rule: The rule remains legally and regulatorily unsettled. After the SEC ended its defense of the rule, the Eighth Circuit held the case in abeyance in September 2025 pending SEC action. In May 2026, the SEC proposed rescinding the rules; rescission is not final and remains subject to notice-and-comment rulemaking.

AOCI and other comprehensive income

AEP reported positive other comprehensive income (OCI) in 2026, reversing the losses recorded in the comparable 2025 periods. The filing says AOCI’s impact was not material to Registrant Subsidiaries.

• Q3 2026: OCI was $6 million, compared with a $16 million loss in Q3 2025. Q3 2026 included $21 million of after-tax fair-value gains recognized in AOCI and $15 million of net-of-tax reclassifications out of AOCI. Q3 2025 included a $17 million after-tax fair-value loss and $1 million of net-of-tax reclassifications into AOCI.
• Nine months ended September 30, 2026: OCI was $15 million, compared with a $25 million loss in the 2025 period. The 2026 period included $66 million of after-tax fair-value gains and $51 million of net-of-tax reclassifications out of AOCI. The 2025 period included a $16 million after-tax fair-value loss and $9 million of net-of-tax reclassifications out of AOCI.

Total AOCI was $51 million at September 30, 2026, up from $45 million at June 30, 2026 and $36 million at December 31, 2025; it was negative $28 million at September 30, 2025. At September 30, 2026, AOCI comprised $85 million from commodity cash-flow hedges, $4 million from interest-rate hedges, and negative $38 million from pension and other postretirement benefit (OPEB) items. The comparable September 30, 2025 balances were $77 million, negative $1 million, and negative $104 million, respectively.

Commodity-hedge gains reclassified from AOCI reduced purchased electricity, fuel and other consumables used for generation by $20 million in Q3 2026 and $68 million in the nine-month period. The comparable prior-year periods had a $3 million loss reclassified in Q3 and a $9 million gain reclassified year to date. These reclassifications affect reported generation-related expense. Pension/OPEB AOCI amortization was $1 million in Q3 2026 and $4 million for the nine months, included in periodic benefit costs.

Regulatory recovery and generation transition

At September 30, 2026, AEP reported $1.534 billion of regulatory assets pending final approval, up from $1.307 billion at December 31, 2025. Notable balances included $264 million for Welsh accelerated depreciation, $89 million for UTM deferred costs, $73 million for Texas system-resiliency costs and $61 million for Pirkey unrecovered plant costs. Of the total, $376 million of storm costs and $289 million of asset-retirement-obligation costs were not currently earning a return. Subsidiary balances were AEP Texas $264 million, AEPTCo $9 million, APCo $396 million, I&M $153 million, PSO $123 million and SWEPCo $517 million; parent and subsidiary balances overlap and should not be added together. Disallowances could reduce future earnings and cash flows.

Retirements and environmental requirements leave material costs dependent on regulatory recovery. SWEPCo’s retired Pirkey Plant had $167 million of net investment, including materials and supplies and net of cost of removal, at September 30, 2026. Arkansas approved 10-year recovery with a 3% return; Louisiana permits recovery with a return through 2032. A Texas settlement proposed recovery of part of the $47 million jurisdictional net book value over 19 years without a return on the unamortized balance. SWEPCo recorded a $31 million probable partial disallowance in Q1 2026; Texas PUCT approval remained pending.

Northeastern Unit 3 had $50 million net book value, a $259 million accelerated-depreciation regulatory asset and a $22 million cost-of-removal regulatory liability; it was projected to retire in 2026, with recovery continuing through 2040. Welsh Units 1 and 3 had $220 million net book value, a $264 million accelerated-depreciation regulatory asset and a $56 million cost-of-removal regulatory liability; coal retirement was projected for 2028, with recovery periods extending as late as 2042. PSO retired $325 million of coal-related assets at Northeastern Unit 3 in Q1 2026; $152 million, including ARO costs, remained unrecovered at September 30 and was being collected in rates. The unit began operating on natural gas in January 2026, but continued operation through May 2041 depends on EPA approval.

West Virginia and Virginia recovery and rates

West Virginia’s July 2026 ENEC order approved a projected $593 million under-recovery for securitization ($274 million APCo), including $34 million of remaining MRBC under-recovery ($28 million APCo). The final financing order approved $2.708 billion of securitization costs ($1.672 billion APCo; $1.036 billion WPCo), comprising undepreciated plant ($1.704 billion), ENEC under-recovery ($593 million), forecast CCR/ELG investments ($237 million), deferred storm O&M regulatory assets ($158 million) and estimated upfront financing costs ($16 million). Bond issuance was planned for Q4 2026, subject to market conditions and final review. The prior ENEC cases included $232 million of disallowed under-recovered costs ($136 million APCo); remand proceedings continue, with the companies seeking a reduction of at least $179 million. Potential disallowances or refunds remain an earnings and cash-flow risk.

The WVPSC also approved annual inflation adjustments of 4% for residential/commercial and 2.5% for industrial customers. Revised tariffs effective July 1, 2026, provide a combined $40 million annual increase, but customer appeals could require refunds. Reconsideration of the 2024 base-rate case increased the approved annual increase to $91 million ($79 million APCo) and the ROE to 9.75%. In Virginia, APCo issued 20-year securitization bonds in May 2026 to finance approximately $1.4 billion of costs, including $1.2 billion of plant balances and $141 million of deferred storm O&M.

State rate cases and cost recovery

AEP Texas’s cumulative interim transmission and distribution base-rate increases generated an estimated $287 million of revenue through September 30, 2026, subject to review. It recorded a $12 million provision for refund related to its 2025 UTM filing and a $23 million unfavorable pretax impact in May 2026 after the PUCT chairman supported partial disallowance. Its $89 million of deferred eligible UTM costs and $34 million of deferred resiliency costs remain subject to prudency review.

In Virginia, APCo’s October 2026 base-rate settlement estimated a $4 million first-year base-revenue decrease and no second-year change, using a 9.80% ROE; final approval was pending. ETT’s settlement reduced its requested $42 million annual increase to approximately $8 million, using a 9.6% ROE.

I&M’s Indiana multi-year plan filing proposed a $42 million overall decrease for 2027–2029, with a 10.1% ROE, rate freezes and a mechanism to record earnings above authorized thresholds as a regulatory liability. I&M’s large-load-related regulatory liability for potential customer refunds was $97 million at September 30, 2026. It also proposed a further $66 million customer credit for over-earnings through May 2026. In Michigan, the PSCR order disallowed $1 million of OVEC costs and none of Rockport UPA costs.

KPCo’s approved 2026 rate increase was $55 million annually, comprising $36 million in base rates and a $19 million generation rider, at a 9.75% base-rate ROE. Its Mitchell Plant share had $514 million net book value at September 30, before cost of removal. KPCo is pursuing securitization; meanwhile, the KPSC required $47 million of past vegetation costs to be reclassified as a regulatory asset and recovered over 30 years without carrying costs. KPCo obtained authority to defer another $18 million pending a final decision.

In Ohio, OPCo’s 2025 settlement’s $11 million annual net increase is more than offset by amortization of deferred-tax regulatory liabilities, producing an overall annual revenue impact of a $59 million decrease. OPCo deferred approximately $27 million and $30 million of March and August 2026 storm restoration costs for recovery. PSO’s Oklahoma settlement proposed a $73 million annual increase at a 9.375% ROE, well below its $299 million request; interim rates began July 2026 subject to refund. SWEPCo’s Texas settlement proposed a $48 million annual increase at a 9.53% ROE and partial Pirkey recovery, pending PUCT approval.

Transmission disputes and other exposures

FERC’s 2025 NOLC decision produced a material, nonrecurring Q2 2025 benefit. Stand-alone NOLC treatment had increased annual transmission revenue requirements by $78 million (2021), $68 million (2022), $61 million (2023), $52 million (2024) and $49 million (2025), totaling $308 million. AEP recorded Q2 2025 revenue and interest and reduced Excess ADIT liabilities; the resulting AEP net income impact was $554 million, including $499 million attributable to common shareholders. Corresponding subsidiary common earnings impacts were AEPTCo $362 million, APCo $29 million, I&M $45 million, PSO $3 million and SWEPCo $56 million; OPCo reported no impact. Refunds for the 2021 rate year were provided primarily through 2025 transmission requirements; no cash refunds had been ordered for 2022–2025. Appeals remained pending, with oral argument scheduled for Q4 2026.

Other risks include unresolved challenges to transmission-cost allocation and SWEPCo vegetation-cost treatment; AEP stopped capitalizing identified vegetation costs prospectively in Q1 2026. PSO and SWEPCo also face possible customer refunds if North Central Wind facilities fail their capacity-factor guarantees. A July 2026 SPP refund generated a $12 million net favorable Q3 impact for PSO and no net impact for SWEPCo; further SPP cost review could result in losses. AEP’s share of the continuing modified-scope Independence Energy Connection project included $73 million in PP&E and $20 million in regulatory assets for costs outside the scope, whose recovery remains uncertain.

Commitments, Guarantees and Contingencies — AEP, Q3 2026

Generation commitments

In June 2026, OPCo transferred its 4.3% ownership interest in OVEC to Parent and its 19.93% power participation entitlement to AGR. Parent remains responsible for AGR’s obligations under the intercompany power agreement. OPCo’s remaining energy and capacity purchase commitments are immaterial.

In Q3 2026, management determined that two turbine purchase agreements are unconditional purchase obligations:

• I&M: $782M agreement; remaining scheduled spending is $31M through 2026, $497M in 2027, $145M in 2028 and $31M in 2030.
• PSO: $349M agreement; remaining scheduled spending is $54M through 2026, $129M in 2027, and $9M in each of 2028 and 2029.

Credit support and lease guarantees

In April 2026, AEP increased one revolving credit facility from $5B to $6.5B and extended its maturity from March 2029 to April 2031. It increased another from $1B to $1.5B and extended maturity from March 2027 to April 2029. Up to $1.2B may be issued as subsidiary letters of credit under these facilities; none were outstanding at September 30, 2026.

AEP also had seven uncommitted facilities totaling $850M. Maximum future payments for letters of credit issued under them were $525M, with maturities from October 2026 through September 2027. AEP issued an additional $131M under these facilities in Q2 2026.

At September 30, 2026, maximum potential loss on lease guarantees—assuming leased equipment had no fair value at lease end—was $34M for AEP. Disclosed subsidiary amounts were AEP Texas $7M, APCo $5M, I&M $3M, OPCo $6M, PSO $3M and SWEPCo $4M. Historically, equipment fair value at lease end has exceeded guaranteed residual values. No material indemnification liabilities were recorded.

Environmental and nuclear exposures

The EPA’s 2024 Legacy CCR Rule extends requirements to inactive impoundments and certain coal-combustion-residual management units, with closure initiation required by May 2028. AEP recorded a $674M increase in asset retirement obligations (ARO) in Q2 2024, initially based primarily on closure-in-place and monitoring estimates. Further site analysis, regulatory developments, or changes in closure methods or CCR quantities could materially increase the ARO and reduce future net income and cash flows.

Recovery of these costs is not assured in all jurisdictions. In January 2026, the Virginia SCC approved APCo’s recovery of $80M in Legacy CCR Rule regulatory assets through 2041, including ongoing depreciation and accretion; AEP is pursuing recovery elsewhere.

I&M’s Cook Plant operating licenses expire in 2034 and 2037, and the company has begun seeking extensions to 2054 and 2057. Spent nuclear fuel disposal and plant decommissioning represent significant future commitments. A nuclear incident could expose AEP to substantial shared industry liability.

Insurance and litigation

Insurance may be insufficient or unavailable for cybersecurity events, extreme weather, wildfire liabilities, Cook Plant damage and replacement power. Transmission and distribution lines, poles and towers are generally excluded from property coverage; uninsured losses not recovered through rates could reduce earnings and cash flow.

Buyers of the Gavin Power Station seek indemnification for alleged CCR Rule noncompliance and landowner property-damage claims. A related case against the EPA was dismissed in December 2025 and did not name AEP. Management considers the indemnification claim invalid, does not believe a loss is probable, and cannot estimate a reasonably possible loss range.

Wholesale contracts

SWEPCo recorded an additional $22M revenue credit in Q3 2026, bringing its 2026 year-to-date accrual for wholesale customer agreements to $45M. All amounts were paid during 2026.

Acquisitions and portfolio changes

AEP expanded and reshaped its generation portfolio through acquisitions in 2025 and 2026, adding gas-fired, wind, and solar capacity. The transactions were treated as asset acquisitions, with costs allocated to acquired assets and assumed liabilities based on relative fair values.

2026 acquisitions

• I&M — Oregon: Acquired the 870-MW combined-cycle gas plant in March. The acquisition included $918M of net PP&E, $35M of prepayments and other current assets, $5M of materials and supplies, $16M of receivables, and $9M of accounts payable.
• I&M — Big Sandy: Acquired the 318-MW gas peaker in August, recording $300M of net PP&E, $3M of materials and supplies, $11M of receivables, and $4M of accounts payable.
• PSO — Lazbuddie: Acquired the 265-MW wind facility in August, recording $637M of net PP&E, $20M of operating lease assets, and an $8M asset retirement obligation (ARO).
• AGR — Wolf Hills: Acquired the 263-MW gas peaker in August, recording $85M of net PP&E, $2M of materials and supplies, $7M of receivables, and $3M of accounts payable.
• APCo — Grover Hill: Acquired the 143-MW wind facility in May, recording $361M of net PP&E, $8M of operating lease assets, and a $1M ARO.

2025 PSO acquisitions

PSO acquired four generation facilities for an aggregate purchase price of $1.7B, with total net PP&E of $1.842B:

• Green Country, a 904-MW gas facility: $819M of PP&E.
• Pixley, a 189-MW solar facility: $380M of PP&E.
• Flat Ridge IV, a 135-MW wind facility: $305M of PP&E.
• Flat Ridge V, a 153-MW wind facility: $338M of PP&E.

The acquisitions also included $25M of operating lease assets, $19M of AROs, and $91M of other liabilities. The other liabilities comprised $50M in regulatory liabilities and deferred investment tax credits, $21M in other current liabilities, and $20M in deferred credits and other noncurrent liabilities.

Regulatory recovery and related exposures

The acquisitions add renewable generation and dispatchable gas capacity, but recovery depends in part on regulatory mechanisms and proceedings. Oregon and Big Sandy support I&M’s Indiana and FERC-jurisdictional customers. Their costs are eligible for existing riders or included in I&M’s Indiana earnings-test evaluation before incorporation into base rates. Lazbuddie and Grover Hill revenue requirements, net of production tax credit benefits, are recoverable through existing riders pending base-rate inclusion. PSO’s 2025 renewable acquisitions have similar rider-based recovery.

Pixley’s retail-rate approval includes capital-cost, performance, and other guarantees that could give rise to future regulatory liabilities. Wolf Hills is a competitive PJM asset and is not currently subject to regulated rate recovery. Rider recovery is transitional, so ultimate recovery remains exposed to regulatory proceedings.

Green Country’s acquired capacity sales agreement requires PSO to sell part of the facility’s capacity to SWEPCo through May 2027. Acquisition-related capacity-contract liabilities reduce PSO’s recoverable revenue requirement; associated intangible and regulatory liabilities were valued using discounted cash flows based on forward market prices.

Transmission monetization and impairment

In June 2025, an investor acquired a 19.9% noncontrolling interest in Midwest Transmission Holdings for $2.82B, providing AEP with a substantial capital inflow while AEP retained the remaining interest.

In Q1 2026, SWEPCo recorded a $31M pretax impairment charge for a probable partial disallowance of recovery of Pirkey Plant’s net book value in the 2025 Texas Base Rate Case. This highlights the risk that regulators may limit recovery of generation-asset costs. Several wind acquisitions also involved land-access operating lease assets and AROs, adding associated obligations to the acquired portfolios.

Benefit plans

These disclosures apply to all Registrants except AEPTCo. AEPSC sponsors a qualified pension plan and two unfunded non-qualified pension plans covering substantially all AEP subsidiary employees, as well as retiree health and life other postretirement benefit (OPEB) plans. Amounts below are in millions.

Pension plans

AEP’s net periodic pension cost increased to $22M in Q3 2026 from $11M in Q3 2025, and to $62M in 9M 2026 from $32M in 9M 2025. The year-to-date increase primarily reflected higher amortization of net actuarial losses ($32M from $12M) and a smaller expected-return credit (−$191M from −$211M), partly offset by lower interest cost ($154M from $159M). Settlements are described as deferrals of regulatory activity.

Other postretirement benefits

AEP’s net periodic OPEB benefit credit increased to $22M in Q3 2026 from $20M in Q3 2025, and to $66M in 9M 2026 from $59M in 9M 2025. For 9M, the expected-return credit was −$88M from −$85M, while interest cost declined to $23M from $26M.

Pension contributions

AEP made a $95M discretionary qualified pension contribution in Q2 2025. Disclosed Registrant contributions were AEP Texas $12M, I&M $2M, PSO $1M and SWEPCo $9M; APCo made no contribution. The disclosure applies to all Registrants except AEPTCo and OPCo. AEP may make discretionary contributions to maintain plan funded status.

AEP business segments

AEP’s third-quarter results improved across all four reportable segments, with higher revenue and earnings. For the first nine months of 2026, revenue increased but earnings attributable to AEP common shareholders declined, largely reflecting weaker AEP Transmission Holdco results and a less favorable income-tax comparison.

Consolidated results

• Q3 2026: Revenue was $6.832B, from $6.011B in Q3 2025; earnings attributable to AEP common shareholders were $1.187B, from $972M.
• 9M 2026: Revenue was $18.297B, from $16.561B; earnings attributable to common shareholders were $2.774B, down from $2.998B.

Reportable segment results

Segment revenue includes intersegment amounts; consolidated revenue reflects eliminations. Earnings below are attributable to each segment’s common shareholders.

The nine-month earnings decline was concentrated in AEP Transmission Holdco, whose earnings fell $360M year over year. Its 9M 2026 income tax expense was $199M, compared with an $11M tax benefit in 2025. Consolidated income tax expense also rose, to $221M from $13M. The other three reportable segments improved nine-month earnings, while Corporate and Other’s loss widened to $333M from $215M.

Capital investment and transmission subsidiary

AEP gross property additions increased to $4.580B in Q3 2026 from $2.279B in Q3 2025, and to $11.501B for 9M 2026 from $7.658B. The nine-month increase was broad-based, particularly in Vertically Integrated Utilities ($6.050B, from $4.356B), Transmission and Distribution Utilities ($3.094B, from $2.079B) and AEP Transmission Holdco ($1.782B, from $1.182B).

AEPTCo, a transmission-only subsidiary, reported Q3 State Transco revenue of $594M, from $558M, and earnings attributable to AEPTCo common shareholders of $196M, from $179M. Q3 gross property additions were $875M, from $358M. For 9M, revenue was $1.760B, from $1.827B, and earnings were $571M, from $946M; gross property additions rose to $1.740B from $1.145B. Most 9M revenue—$1.422B—was from affiliate sales. The State Transcos earn tariff revenue from FERC-regulated transmission systems. AEPTCo is a subsidiary-level disclosure and should not be added to AEP’s consolidated segment results.

Business and assets

AEP’s businesses include regulated vertically integrated utilities, transmission and distribution, FERC-regulated transmission investments, and competitive generation and marketing across ERCOT, MISO, PJM and SPP. Regulation and cost-based rates shape utility operations; transmission investment is supported by approved or pending regulatory returns on equity. AEP total assets were $125.695B at September 30, 2026, versus $114.460B at December 31, 2025. AEPTCo consolidated total assets were $19.469B, versus $17.999B. The disclosure does not provide total equity, goodwill or other intangible asset balances, and identifies no specific new risk event.

Derivatives and hedging

AEP uses physical and financial forwards, and smaller amounts of swaps and options, to manage commodity-price exposure in power, capacity, natural gas, coal and emissions markets, as well as interest-rate exposure. It also uses derivatives to pursue market opportunities, but does not hedge all commodity-price or interest-rate risk. AEPTCo reported no derivative or hedging activity during the periods presented.

Positions, fair values and collateral

At September 30, 2026, AEP’s commodity-derivative notionals were 336 million MWh of power (327 million at December 31, 2025), 204 million MMBtu of natural gas (166 million) and 12 million gallons of heating oil and gasoline (8 million). Interest-rate derivative notional was $38 million ($40 million), while interest-rate contracts on long-term debt were $500 million at both dates. Subsidiary positions also shifted: APCo’s power notional increased to 34 million MWh from 23 million, while SWEPCo’s natural-gas notional declined to 18 million MMBtu from 26 million.

Before balance-sheet netting, AEP’s derivative assets were $2.233 billion and liabilities $1.693 billion at September 30, 2026, yielding $540 million of net derivative assets recognized. At December 31, 2025, the corresponding amounts were $1.357 billion, $970 million and $387 million. After netting under master agreements and collateral, balance-sheet derivative assets were $854 million and liabilities $423 million, for $431 million of net assets presented; at year-end 2025, they were $617 million, $310 million and $307 million.

At September 30, 2026, net derivative assets recognized by subsidiary were AEP Texas $2 million, APCo $171 million, I&M $18 million, PSO $8 million and SWEPCo $32 million; OPCo had a $21 million net liability. At December 31, 2025, balances were AEP Texas $0, APCo $78 million, I&M $10 million, OPCo a $33 million net liability, PSO $14 million and SWEPCo $24 million. AEP netted $116 million of third-party cash collateral received against risk-management assets, up from $83 million at year-end; subsidiary collateral received and collateral paid were not material.

Risk-management gains and hedge accounting

AEP recognized risk-management contract gains of $227 million in Q3 2026, versus $73 million in Q3 2025, and $675 million in 9M 2026, versus $336 million in 9M 2025. Regulatory liabilities accounted for $155 million of Q3 2026 gains and $503 million of 9M gains, compared with $59 million and $283 million in the prior-year periods. Regulatory accounting defers certain realized and unrealized gains and losses rather than recognizing them immediately in earnings.

AEP designates some interest-rate derivatives as fair-value hedges of debt. The hedged long-term debt carrying amount was $479 million at September 30, 2026, including $21 million of fair-value hedge adjustments; at December 31, 2025, these amounts were $484 million and $15 million. Q3 fair-value hedge instrument losses and offsetting debt gains were each $3 million; 9M 2026 effects were zero.

Cash-flow hedge effects are recorded in AOCI until the hedged item affects income. At September 30, 2026, after-tax AOCI gains were $85 million for commodity hedges and $4 million for interest-rate hedges; $49 million and $1 million, respectively, were expected to be reclassified to income within 12 months. AEP hedged forecast transactions for up to approximately nine years. AEP applied cash-flow hedge accounting to power derivatives in Q3 and 9M 2026; SWEPCo applied it to interest-rate derivatives, while other subsidiaries did not.

Valuation, counterparty and settlement risks

Derivative valuations use exchange prices and broker quotes where available, and models and assumptions otherwise, with adjustments for discounting, liquidity and credit quality. Volatile or imperfect energy markets and long-dated contracts create estimation risk; actual prices may diverge from assumed curves, affecting future earnings and cash flows. Market conditions, margin requirements and settlement timing can also drive cash-flow variability. AEP manages counterparty exposure through credit monitoring, master-agreement netting, collateral, letters of credit, guarantees, margin requirements and contractual rights to terminate and liquidate positions after default or failure to post collateral.

Only a limited number of contracts have rating-based collateral triggers. AEP had not been downgraded below a threshold requiring additional collateral, and net-liability exposure on triggered contracts was immaterial at both reporting dates; subsidiaries had none in a net-liability position. Certain AEP interest-rate derivatives have cross-acceleration provisions tied to accelerated repayment of debt of at least $50 million. AEP’s net liability under these contracts was $30 million at both dates, with no cash collateral posted; subsidiaries had no such contracts.

A majority of non-exchange-traded commodity contracts at AEP, APCo, I&M, PSO and SWEPCo have cross-default provisions that may require settlement at fair value following qualifying defaults involving Parent, an obligor or a third-party obligation of $50 million or more. AEP’s net liability after contractual netting increased to $207 million at September 30, 2026 from $183 million at December 31, 2025, with no cash collateral posted at either date. Subsidiary net liabilities at September 30 were APCo $15 million, I&M $1 million, PSO $31 million and SWEPCo $10 million, also with no collateral posted. At year-end, disclosed balances were APCo $2 million, PSO $27 million and SWEPCo $10 million; other subsidiary exposures were immaterial. These broad provisions could create settlement exposure if triggered.

Fair-value measurements

Debt fair value remains below carrying value

At September 30, 2026, AEP’s long-term debt had a book value of $52.541B and fair value of $47.152B, compared with $47.322B and $44.930B, respectively, at December 31, 2025. Subsidiary book value / fair value at September 30, 2026, versus December 31, 2025, was:

Debt is not marked to market. These Level 2 fair values are estimates based on comparable-debt market prices and current interest rates, and may not represent values realizable in an exchange.

Nuclear trusts and temporary investments

I&M’s decommissioning and spent nuclear fuel trusts increased to $5.256B at September 30, 2026, from $4.916B at year-end 2025. Domestic equities were $3.398B (including $2.880B of gross unrealized gains), versus $3.160B (including $2.621B); fixed income was $1.823B, versus $1.727B. Fixed-income gross unrealized losses were $54M, compared with $8M, and other-than-temporary impairments were $54M, compared with $21M. Fair-value changes and impairments flow through regulatory accounts under rate treatment, so they do not affect earnings or AOCI. Trust withdrawals are restricted to decommissioning costs and trust expenses. During the nine months ended September 30, 2026, trust purchases were $2.493B and sales $2.435B; realized gains were $134M and realized losses $30M.

AEP’s other temporary investments and restricted cash totaled $341M, up from $291M. This included restricted cash of $89M (from $71M), fixed-income mutual funds of $191M (from $165M) and equity mutual funds of $46M (from $42M). Restricted cash primarily supports debt repayment. In the 2026 nine-month period, AEP purchased $37M and received $8M from investment sales, compared with purchases of $20M and sales proceeds of $17M in the comparable 2025 period.

Commodity derivatives and Level 3 valuation exposure

AEP’s recurring fair-value risk-management assets were $854M at September 30, 2026, versus $617M at year-end 2025; liabilities were $423M, versus $310M. AEP reported $575M of Level 3 assets and $202M of Level 3 liabilities at September 30, 2026. The Level 3 net position was $373M, up from $327M at September 30, 2025. September 2026 net positions by registrant were AEP $373M, APCo $183M, I&M $23M, OPCo a $22M net liability, PSO $41M and SWEPCo $43M; the 2025 comparatives were $327M, $91M, $11M, a $44M net liability, $65M and $57M, respectively.

Level 3 positions rely on discounted cash flows and unobservable forward market prices, exposing valuations to changes in assumptions. At September 30, 2026, AEP Energy Contracts had $230M of assets and $181M of liabilities, compared with $224M and $144M at year-end; AEP FTRs had $345M of assets and $21M of liabilities, compared with $187M and $8M. Subsidiary positions included APCo FTRs with $183M of assets and no liabilities (from $81M and none); I&M FTRs with $28M of assets and $5M of liabilities (from $9M and none); OPCo Energy Contracts with no assets and $22M of liabilities (from none and $33M); PSO FTRs with $41M of assets and no liabilities (from $43M and $2M); and SWEPCo FTRs with $43M of assets and no liabilities (from $37M and $2M).

Unobservable forward-price inputs were particularly wide: $0.70–$235.15/MWh for AEP Energy Contracts, with a $56.21/MWh weighted average, and negative $78.84–$104.78/MWh for AEP FTRs, with a $2.08/MWh weighted average. At year-end 2025, the respective ranges and weighted averages were $5.65–$141.75/MWh and $50.61/MWh, and negative $32.49–$21.68/MWh and $0.49/MWh. Higher forward prices increase fair value for buy positions and decrease it for sell positions, with the reverse effect when prices fall. Illiquid and structured contracts, as well as counterparty credit risk, can require internally developed or extrapolated inputs. Some Level 3 contracts are economically hedged, and some valuation changes are assigned to regulated jurisdictions.

For the nine months ended September 30, 2026, the Level 3 rollforward included $245M of realized gains recognized in revenues, a $24M unrealized loss on positions still held (also in revenues), $14M of OCI gains, $463M of settlements, and $341M of fair-value gains allocated to regulated jurisdictions. The comparable 2025 amounts were $155M of realized gains, $31M of unrealized gains on positions still held, $14M of OCI gains, $277M of settlements and $240M allocated to regulated jurisdictions. APCo accounted for $162M of 2026 realized gains; I&M, OPCo, PSO and SWEPCo reported $12M, $1M, $47M and $18M, respectively. Settlements included $243M at APCo, $21M at I&M, a $3M inflow at OPCo, $88M at PSO and $52M at SWEPCo. Regulated-jurisdiction net gains are recorded as regulatory liabilities; net losses are recorded as regulatory assets or accounts payable.

During the third quarter, AEP’s Level 3 net trading derivative balance moved from $380M at June 30, 2026, to $373M at September 30, 2026. The reported movements included $123M of realized gains, $28M of unrealized losses on positions still held, $192M of settlements and an $81M increase from fair-value changes allocated to regulated jurisdictions.

Exchange-traded futures generally use observable Level 1 prices; corroborated broker quotes and market inputs are generally Level 2. Less-liquid commodity contracts may be Level 3. Nuclear-trust securities use external pricing and investment-manager review, supplemented by management valuation testing. Management reported no significant changes in valuation techniques.

Income taxes

Effective tax rates (ETRs) differed substantially across AEP and its registrants, reflecting production and investment tax credits, excess accumulated deferred income tax (ADIT) reversals and other tax items.

Production and investment tax credits reduced rates for several entities, particularly PSO and SWEPCo in 9M 2026; AEP’s 9M rate also reflected credits and excess ADIT reversals. Q3 2026 included reversals of origination flow-through for several registrants. The 9M 2025 comparisons were affected by excess ADIT remeasurement, which reduced AEP’s ETR by 12.4 percentage points.

Cash income taxes

For 9M 2026, total cash income taxes paid/(received), including transfer credits, were:

Transfer credits reduced AEP’s cash taxes by $63M in 9M 2026, compared with $102M in 9M 2025. The 2026 credits included $50M for I&M, $6M for PSO and $3M for SWEPCo; AEP’s reported total cash tax receipt was $37M after transfer credits.

Audits and tax developments

The IRS notified AEP in July 2026 that it would end its examination of AEP’s 2023 federal return, except for potential items arising in later-year examinations. AEP’s 2024 federal return was selected for examination in Q2 2026, and the examination began in July. No state or local income tax examinations were ongoing; statutes of limitation generally have expired for years before 2023.

The 2025 One Big Beautiful Bill Act accelerates the phaseout of technology-neutral wind and solar production and investment tax credits, adds restrictions concerning certain foreign ownership, influence or assistance, and makes 100% bonus depreciation permanent for certain non-regulated entities. AEP does not expect a material effect on registrants apart from bonus depreciation. A June 2026 court ruling vacated IRS guidance that had eliminated the 5% cost safe harbor for qualifying wind and solar projects beginning construction after September 1, 2025, restoring the safe harbor. An appeal remains possible, but AEP expects no material impact.

February 2026 CAMT guidance permits deductions for certain tax-deductible repairs in adjusted financial statement income and is expected to reduce applicable registrants’ prior and future CAMT liabilities. AEP is monitoring further federal tax guidance and its potential effects on future net income, cash flows and financial condition.

Financing, debt and equity

AEP’s financing mix shifted further toward long-term debt and equity. At September 30, 2026, long-term debt outstanding, net of issuance costs and premiums or discounts, was $52.541 billion, up from $47.322 billion at December 31, 2025. It comprised $41.626 billion of senior unsecured notes (from $37.190 billion), $2.262 billion of securitization bonds (from $984 million), $4.683 billion of junior subordinated notes (from $4.681 billion), $1.637 billion of pollution-control bonds (unchanged), $574 million of notes payable (from $683 million), $339 million of spent nuclear fuel obligations (from $330 million), and $1.420 billion of other long-term debt (from $1.817 billion). Debt due within one year was $2.677 billion, down from $3.194 billion; long-term debt excluding current maturities was $49.864 billion, up from $44.128 billion.

During 9M 2026, AEP and subsidiaries issued $7.092 billion of principal in debt and securities and reported $1.834 billion of retirements and principal payments. Major issuance included $750 million of AEP Texas 5.20% senior notes due 2036; $650 million of AEPTCo 5.25% notes due 2036; $1.376 billion of APCo securitization bonds at 4.96%–5.84%, due 2035–2046; $650 million of I&M 5.60% notes due 2056; $1.0 billion of PSO senior notes at 5.40%–6.30%; and $2.15 billion of SWEPCo senior notes at 5.20%–6.00%, due 2033–2056. Listed repayments included $623 million of AEPTCo variable-rate debt and $500 million of SWEPCo 1.65% notes. Separately, SWEPCo retired $1.0 billion of 4.24% affiliated notes payable due 2028 in March 2026.

A common-stock ATM program authorized for up to $3.5 billion in November 2025 issued 2 million shares for $264 million net proceeds in Q1 2026. At September 30, forward equity agreements covered 48 million shares and $5.358 billion of expected proceeds, subject to settlement timing, funding rates, spreads and expected dividends: 18 million shares/$1.729 billion under the March 2025 forward, 6 million/$684 million under ATM forwards, and 24 million/$2.945 billion under the May 2026 forward. Five million shares under the March 2025 forward were settled in 2025 for $500 million.

Short-term funding and receivables

Short-term debt rose to $1.875 billion from $1.508 billion at year-end: $975 million of commercial paper at a 4.21% weighted-average rate (from $605 million at 3.92%) and $900 million of securitized receivables debt at 4.03% (unchanged at $900 million, previously 4.00%). The receivables facility can provide up to $900 million through bank conduits and expires in September 2028.

AEP Credit’s retained interest in receivables pledged as collateral, less uncollectible accounts, increased to $1.559 billion from $1.230 billion. Delinquent securitized receivables were $41 million versus $66 million; bad-debt reserves were $41 million versus $42 million; and unbilled receivables were $338 million versus $368 million. Net uncollectible receivables written off increased to $14 million in Q3 from $11 million and $30 million in 9M from $25 million. Securitization effective rates fell to 3.97% in Q3 from 4.52%, and 3.94% in 9M from 4.56%.

Subsidiaries sell receivables and accrued unbilled revenue to AEP Credit without recourse, with fees partly reflecting financing costs and uncollectible-account experience; APCo cannot sell West Virginia receivables. Q3 / 9M sale proceeds were: APCo $452 million/$1.411 billion (prior-year $495 million/$1.530 billion); I&M $723 million/$2.068 billion ($683 million/$1.813 billion); OPCo $1.070 billion/$2.799 billion ($927 million/$2.523 billion); PSO $809 million/$1.722 billion ($659 million/$1.466 billion); and SWEPCo $644 million/$1.539 billion ($550 million/$1.434 billion). September 30 receivables and accrued unbilled revenue balances, compared with year-end, were $600 million at OPCo (from $501 million), $281 million at PSO (from $140 million), $232 million at SWEPCo (from $169 million), $210 million at APCo (from $203 million), and $191 million at I&M (from $175 million).

Intercompany funding and restrictions

Subsidiary borrowing relies on utility and nonutility money pools as well as parent financing. At September 30, net utility-pool loans were $494 million for SWEPCo, $382 million for AEP Texas, $70 million for PSO and $45 million for APCo; net borrowings were $284 million for I&M, $240 million for OPCo and $196 million for AEPTCo. Authorized utility short-term borrowing limits ranged from $750 million to $1.070 billion. Average utility-pool borrowing rates in 9M 2026 were about 3.92%–4.03%, below 4.61%–4.69% in 9M 2025. In October, AEP contributed $450 million to AEP Texas and $210 million to OPCo; AEPTCo issued $270 million of variable-rate debt due 2028, and I&M issued $110 million of 5.51% notes due 2031.

AEP’s debt-to-total-capitalization covenant limit is 67.5%, also applicable to certain subsidiaries. AEPTCo priority debt was 1.4% of contractually defined tangible net assets against a 10% ceiling, including a $50 million secured-debt sublimit. Subsidiary dividends are generally payable from retained earnings but may be restricted by financing terms and regulation. The Federal Power Act restricts dividends from capital accounts and establishes a hydroelectric-earnings reserve applicable to APCo and I&M.

Variable-interest entities, investments, and retirement obligations

Appalachian Recovery Funding

AEP consolidated Appalachian Recovery Funding, a VIE formed in May 2026 to securitize specified Virginia-jurisdictional Amos and Mountaineer plant balances and deferred storm costs. At September 30, 2026, the securitized asset was $1.3 billion and securitization bonds totaled $1.335 billion, including $35 million due within one year and $1.3 billion long-term.

The bonds are payable solely from, and secured by, recovery charges collected from APCo’s Virginia customers; bondholders have no recourse to APCo or other AEP entities. APCo services the asset and remits collections for debt service and related costs. AEP reported no material financial or other support to consolidated VIEs beyond previously contracted obligations.

OVEC transfer

In June 2026, after PUCO and FERC approvals, OPCo transferred its 4.3% OVEC ownership interest to Parent and its 19.93% OVEC power participation entitlement to AGR. Parent remains responsible for AGR’s financial and other obligations under the intercompany power agreement.

Gigawatt AI investment

AEP’s equity-method investment in privately held Gigawatt AI (GWAI) reached $200 million at September 30, 2026. AEP held 20 million voting shares, representing 21% of GWAI’s outstanding voting common stock, with a $200 million carrying value. The investment consists of an initial $100 million and four $25 million performance-milestone investments.

AEP can designate one of GWAI’s three directors; that seat is held by an AEP officer, making the investment a related-party transaction. GWAI’s founders retain the remaining equity and board representation. AEP also acquired a perpetual software license and a $50 million stock warrant; both had immaterial fair values at September 30, 2026, and the warrant is measured at recurring fair value. AEP’s share of GWAI losses was immaterial in both Q3 and 9M 2026. The investment gives AEP governance influence and exposure to utility-focused AI development, while involving private-company and related-party risks.

Asset retirement obligations

AEP’s asset retirement obligations (AROs), including obligations for ash facilities, asbestos, renewables and other sites, rose to $3.825 billion at September 30, 2026, from $3.712 billion at December 31, 2025. The 9M 2026 rollforward included $131 million of accretion expense, $11 million of liabilities incurred, $72 million settled, and $43 million of upward cash-flow estimate revisions. PSO AROs increased to $172 million from $143 million, while SWEPCo AROs declined to $264 million from $290 million. Estimate revisions primarily reflected changes in closure areas, volumes and/or unit costs, highlighting estimation exposure in long-dated retirement obligations.

Revenue and customer contracts

AEP’s Q3 2026 consolidated revenue was $6.832 billion, up from $6.011 billion in Q3 2025. Revenue from customer contracts was $6.793 billion, compared with $5.963 billion; other revenue was $39 million, versus $48 million. Growth was driven primarily by retail and wholesale/competitive retail activity. The filing provides revenue disaggregation, not segment profit measures.

Retail growth reflected stronger residential and commercial revenues; industrial revenue also increased. Wholesale growth included higher transmission, retail/trading/marketing, and generation revenue.

Reportable segments and reconciling category

Subsidiary total revenues were: AEP Texas $659M vs. $619M; AEPTCo $594M vs. $558M; APCo $1.133B vs. $1.057B; I&M $894M vs. $812M; OPCo $1.208B vs. $1.070B; PSO $868M vs. $694M; and SWEPCo $770M vs. $724M.

Affiliated transmission activity included $480 million of AEPTHCo revenue and $68 million of VIU revenue in Q3; intercompany amounts are eliminated through reconciling adjustments. AEP also reports affiliated generation, trading/marketing, and other customer-contract revenue.

Contract balances and obligations

AEP T&D Services’ contract liabilities rose to $197 million at September 30, 2026, from $37 million at December 31, 2025, mainly due to customer advances for long-lead transmission and distribution equipment and related construction services. Revenue is recognized as the performance obligations are fulfilled. Subsidiary contract liabilities and contract assets were not material.

Remaining fixed performance obligations totaled $86 million at September 30, 2026: $18 million in 2026, $54 million in 2027–2028, $12 million in 2029–2030, and $2 million thereafter. They primarily relate to fixed-amount electricity sales and PJM capacity-market stand-ready services; transmission revenue is excluded. Beginning in Q1 2026, PSO and SWEPCo included fuel-related amounts in unbilled revenue to reflect earned but uninvoiced consideration; the change was not material.

Other disclosures

AEP reported no material changes to the risk factors disclosed in its FY2025 Form 10-K. On October 23, 2026, AEP entered into a settlement and noncompetition agreement with former President of Nuclear Development Alicia Knapp, superseding arrangements described in a September 30 Form 8-K. Subject to her release and compliance with the agreement, she will receive $4.342662 million, less withholding; she waived benefits under the company’s executive or general severance plans. No directors or officers adopted, terminated, or modified trading arrangements under Rule 10b5-1 or otherwise during Q3 2026.

Exhibits and financing documents

AEP Texas entered into a U.S. Department of Energy financing arrangement dated July 7, 2026. It comprises a Note Purchase Agreement with the DOE and Federal Financing Bank, a Future Advance Promissory Note, and a DOE Loan Guarantee Agreement. The filing does not state financing amounts or whether funds have been drawn.

The exhibits also establish terms for:

• PSO’s 5.40% Series O senior notes due 2034 and 6.30% Series P senior notes due 2056, under an August 1, 2026 supplemental indenture.
• SWEPCo’s 6.00% Series S senior notes due 2037, under a September 16, 2026 supplemental indenture.

These financing documents had been disclosed in prior Form 8-K filings and are incorporated by reference. The remaining exhibits consist of officer certifications, XBRL materials, and signatures. The report was signed October 28, 2026.