AEP — Q2 2026 Financial Report Analysis

Data-center load reached the revenue line; the 42% earnings drop is a 2025 comparison artifact

American Electric Power's second quarter of 2026 looks bad on the surface and reasonably good underneath, and the gap between the two is almost entirely explained by one item in last year's quarter. Revenue rose 7.0% to $5.45 billion, but GAAP earnings attributable to common shareholders fell 41.8% to $713 million ($1.30 diluted per share) from $1.23 billion ($2.29) a year earlier. "Operating earnings" — AEP's own non-GAAP measure, which strips out items management considers unrelated to running the utilities — fell only 3.1%, to $742 million, or $1.36 per share against $1.43.

The reason the two measures diverge so violently is that in June 2025 AEP received a favorable order from the Federal Energy Regulatory Commission (FERC) on how net operating loss carryforwards are treated in transmission formula rates. The 10-Q quantifies that single order at $480 million of earnings in the second quarter of 2025, of which $270 million landed in transmission revenue ($214 million at the AEP Transmission Holdco segment, $56 million at the Vertically Integrated Utilities segment) and the rest came through a reduction in excess accumulated deferred income taxes. Nothing comparable recurred in 2026. Strip that $270 million of revenue out of the 2025 base and the underlying revenue comparison is roughly +13%, not +7%.

Headline results

"Operating margin" here is operating income as a share of revenue — what's left after running the utilities but before interest and tax. The effective tax rate is income tax expense over pre-tax income; both years are far below the 21% federal statutory rate, in 2026 because of production tax credits from renewables and in 2025 because of the excess-ADIT reduction from the FERC order, which produced a net tax benefit on positive pre-tax income.

A note on the EPS lines: AEP calculates its operating EPS on basic weighted-average shares (544.2 million in Q2 2026, up from 534.3 million), while GAAP diluted EPS uses 550.6 million against 536.4 million a year ago. The widening gap between basic and diluted counts — 6.5 million shares versus 2.1 million — is the dilution from unsettled forward equity sale agreements, discussed below.

Takeaway: Transmission investment is compounding, but AEP now keeps less of it. The AEP Transmission Holdco segment added $67 million of revenue in the quarter "due to continued transmission investment," yet its operating earnings were flat at $225 million against $224 million, because the June 2025 sale of a minority stake in Midwest Transmission Holdings routed $25 million more of the quarter's transmission earnings to the minority partner. The 2025 stake sale raised $2.8 billion of cash for the capital plan without issuing shares — but it permanently diverts a slice of the growth from the segment that has been AEP's most reliable earnings engine. That is the structural cost of the funding, and it will keep showing up in every quarterly comparison.

Segment detail

Operating earnings by segment, in millions:

Two things stand out. First, Corporate and Other — parent-company interest, taxes and unallocated costs — deteriorated by $44 million in the quarter and $123 million year to date, which is where the cost of financing a rapidly growing capital program collects before it is pushed into rates. Second, the Transmission & Distribution segment (AEP Ohio and AEP Texas) is the only one growing operating earnings at a double-digit rate off a meaningful base, up 6.7% in the quarter and 14.4% year to date.

Load: the growth is commercial, and it is not weather

This is the quarter where AEP's data-center pipeline became visible in delivered volumes rather than in slide decks. Retail kilowatt-hours by customer class:

The MD&A attributes the increase specifically to "new data processing load added in the commercial and industrial customer classes." The pattern is internally consistent: commercial volumes up 15–17% in both segments, industrial up 15% in Texas and Ohio (where the interconnection queue is concentrated) but flat in the vertically integrated states, and residential flat to down.

Crucially, this is not a weather effect — if anything weather worked against AEP. Cooling degree days fell 9% in Texas and 6% in Ohio, costing the T&D segment $7 million of revenue in the quarter, and the vertically integrated utilities lost $27 million of year-to-date revenue from a 15% drop in heating degree days in the western region. The revenue that did grow was weather-normalized (adjusted to remove temperature swings so the underlying customer trend is visible): $60 million of weather-normalized retail revenue growth at the vertically integrated utilities, primarily commercial and industrial, plus $11 million in the Texas commercial class. Residential volumes fell partly because 2025 had favorable weather — a comp distortion, not demand destruction.

The contracted pipeline behind those volumes grew again. AEP signed an incremental 6 GW of load agreements in the quarter, mostly in Texas, taking total contracted load additions through 2030 to 69 GW — against roughly 33,000 MW of currently owned and contracted generating capacity, which is the scale of the problem. AEP Texas alone has executed letters of agreement for about 45 GW of incremental load by 2030, of which roughly 40 GW is seeking consideration under ERCOT's one-time "Batch Zero" transitional interconnection process for loads of 75 MW or greater. In July 2026 AEP Texas collected about $2 billion of financial security — cash collateral, parental guarantees and letters of credit — against that 40 GW. That is the single most useful data point for assessing how real the pipeline is: customers have posted money. ERCOT is expected to give eligible Batch Zero projects load-ramp information in April 2027, at which point those customers decide whether to proceed. Until then the timing and the ultimate cost allocation remain, in the filing's own words, "subject to ongoing ERCOT and PUCT actions."

To serve it, AEP has now secured roughly 13 GW of gas-fired turbine capacity for potential deployment through 2031, with up to 10 GW more under evaluation through 2035. Turbine slots have been the binding constraint across the US utility sector; securing them early is an option on growth, but it is also a commitment made before the load is contractually locked at every site.

Rate cases: the allowed return keeps getting negotiated down

A regulated utility earns a return on its "rate base" — the depreciated capital it has invested and that regulators have approved for recovery — at an "allowed return on equity" (ROE) set by the commission. The gap between what a utility requests and what it gets is where a large capital plan either works or doesn't. This quarter's outcomes were consistently settled well below ask:

• Ohio (OPCo). Requested a net $97 million distribution increase at a 10.9% ROE. The PUCO approved a settlement in April 2026 at a 9.84% ROE, and after amortizing $82 million of deferred tax regulatory liabilities over 18 months the overall effect is a net $59 million annual revenue decrease for customers. AEP presented this publicly as a customer rate decrease, which it is — it is also a materially lower allowed return than requested.
• Oklahoma (PSO). Requested $299 million at a 10.5% ROE in January 2026; staff and intervenors countered with $10–109 million at 8.3–9.38%. A non-unanimous June 2026 settlement lands at $73 million at a 9.375% ROE, roughly a quarter of the ask. Interim rates took effect July 1, 2026; a final order was expected in Q3 2026, and the large-load tariff provisions remain contested at hearing.
• Virginia (APCo). Filed in May 2026 for a headline $105 million decrease, which nets to a $61 million increase at a requested 10.5% ROE once the expiring securitization-related rider credit is accounted for. Hearing October 2026, order due by January 2027, new rates March 2027. AEP described this as its smallest Virginia base-rate increase request in nearly 30 years — enabled by a $1.4 billion securitization that moved costs off base rates.
• Texas (SWEPCo). The 2025 Texas base rate case reached a unanimous settlement in principle in April 2026, which included a probable partial disallowance of $31 million of the retired Pirkey Plant's net book value, recognized in Q1 2026. The remaining Texas jurisdictional share of Pirkey is $46 million.
• AEP Texas Unified Tracker Mechanism. A Texas ALJ recommended partial disallowance of costs in AEP Texas's first UTM filing, based on a narrower reading of when deferrals became eligible; the PUCT Chairman agreed in a May 2026 memorandum. AEP Texas booked a $23 million unfavorable pretax charge, with the final calculation and order expected in Q3 2026. $72 million of eligible costs remain deferred as a regulatory asset, $65 million of which goes into the next UTM application.

Three of these — the Pirkey disallowance ($0.06), the UTM disallowance ($0.04) and a West Virginia commission order ($0.07 unfavorable) — plus a $23 million probable liability for credits to certain SWEPCo wholesale generation customers ($0.04) are the items AEP excludes from operating earnings. Investors should be careful here: partial disallowances of prudently-incurred-but-rejected costs are a recurring feature of a utility running a $78 billion capital plan across 11 state jurisdictions, not one-time noise. Four separate regulatory disallowance or credit items in two quarters is a pattern. Year to date, AEP's adjustments net to adding $0.09 to GAAP EPS of $2.89 (diluted) to reach $3.01 of operating EPS — the non-GAAP figure is the flattering one, which is the opposite of last year, when adjustments removed $0.82.

Separately, a "regulatory lag" issue sits behind all of this: AEP spends capital continuously but only earns on it once a commission approves recovery. Interest expense rose 19.6% in the quarter on higher long-term debt balances, while the rate relief that pays for that debt arrives on a commission's timetable. The Ohio and Oklahoma outcomes above show the relief arriving smaller than requested.

Paying for $78 billion

The capital plan is now $12.8 billion in 2026 and $65.1 billion across 2027–2030 — $77.9 billion over five years. The first half of 2026 shows what that looks like in cash terms:

Operating cash flow grew 28%, but more than half of that improvement ($540 million) came from an increase in customer security deposits and timing differences in rider refunds — working capital, not earnings. Against $5.6 billion of construction spending and $1.0 billion of dividends, AEP ran a roughly $3.2 billion cash shortfall in six months, funded with $4.0 billion of net debt. Debt-to-total-capital moved from 60.3% to 61.4%; the credit-agreement covenant measure (which excludes securitization bonds and AEP Credit debt) sat at 52.4% against a 67.5% limit, so there is covenant headroom, but the trend direction matters for the credit ratings that set AEP's borrowing cost.

One genuinely favorable item: $425 million of contributions in aid of construction in six months, up from $106 million — customers, largely large-load customers, paying cash up front for interconnection work. That is capital AEP doesn't have to finance or earn a return on, and it grew fourfold.

On equity, AEP is pre-funding rather than issuing into the market all at once. It has issued $405 million of stock year to date, mostly under a $3.5 billion at-the-market program, and holds three unsettled forward sale agreements: 18 million shares from the March 2025 forward ($1.73 billion expected proceeds, maturing December 2026), 3 million ATM forward shares ($374 million, December 2026) and 24 million shares from a May 2026 forward (~$2.93 billion, maturing May 2028). That is roughly $5.0 billion of equity contracted but not yet settled, and about 45 million shares — 8% of the current basic count — that will land on the share base over the next two years. The dilution is already partly in diluted EPS; the cash is not yet in the balance sheet.

The affordability argument AEP is making is the counterweight, and it is specific rather than rhetorical. Management identified up to $16 billion of expected cost offsets for residential customers in the vertically integrated utilities, supported by fully executed take-or-pay service agreements — contracts with terms up to 20 years that can require a large customer to pay for 80–90% of contracted demand whether or not it is used. Large-load tariffs of this kind are now approved in five states, with three filings pending (Michigan, Oklahoma and SWEPCo-Texas); Virginia approved APCo's in the second quarter, covering new loads of 150 MW aggregated or 100 MW individually. On top of that, AEP has secured about $5 billion of Department of Energy loans — including up to $3.3 billion at AEP Texas for nearly 100 transmission projects, expected to save customers $685 million of interest — plus nearly $400 million of grants, for roughly $1.4 billion of estimated customer benefit. Whether take-or-pay minimums hold up if a hyperscaler cancels a campus is the untested part of the structure.

Guidance and trajectory

AEP raised full-year 2026 operating EPS guidance to $6.25–$6.55 from $6.15–$6.45, and reconciles that to estimated GAAP EPS of $6.16–$6.46. It reaffirmed a 7–9% long-term annual operating earnings growth rate through 2030 and said it expects a compound annual growth rate above 9% measured from the 2025 guidance midpoint — a growth rate that is arithmetically easier to hit because 2025's reported base was depressed relative to its guidance. Management also flagged more than $10 billion of potential incremental capital beyond the $78 billion plan: a Wyoming fuel cell project, the Piketon transmission opportunity in Ohio, and additional in-footprint generation.

Raising guidance while first-half operating EPS is up only 1.0% ($3.01 versus $2.98) implies a second half carrying most of the year's growth. The first-half arithmetic supports it: at the $6.40 midpoint, AEP needs $3.39 in the second half against $3.01 delivered, roughly 13% higher than the first half. The drivers are identifiable rather than speculative — PSO interim rates effective July 1, the Ohio settlement rates in effect since April, and a full quarter of the new data-center volumes rather than a partial ramp. It is achievable, but it depends on a Q3 Oklahoma order that doesn't reopen the settlement and on no further disallowance surprises.

Our read on trajectory. The demand story is the most credible one in the US utility sector right now, and unusually, it is showing up in delivered kilowatt-hours and posted collateral rather than only in forecasts: 8.2% retail volume growth, $2 billion of customer security in Texas, a fourfold increase in customer-funded construction contributions. That is the bull case, and it is supported by the filing.

The constraint is the funding-and-recovery arithmetic, and it has three parts. First, AEP is spending well ahead of its cash generation — a $3.2 billion six-month shortfall funded almost entirely with debt, at a debt-to-cap ratio that climbed another 1.1 points in six months. Second, the equity needed to hold that ratio is coming, roughly $5 billion of it, contracted but unsettled. Third, and most important, the allowed returns that pay for the capital are being negotiated down: 9.84% in Ohio against a 10.9% request, 9.375% in Oklahoma against 10.5%, and four separate regulatory disallowances or customer-credit items in two quarters. A capital plan of this size only produces 7–9% earnings growth if commissions let AEP earn close to its requested return on it, and the 2026 evidence is that they are letting it earn somewhat less. Load growth genuinely does spread fixed costs across more customers — that mechanism is real and is why AEP can show a rate decrease in Ohio — but it also gives commissions room to compress the allowed return while still delivering lower bills.

The most likely path is that AEP hits its 2026 guidance and the lower end of the 7–9% range thereafter, with the variance driven less by whether data-center load arrives than by what the commissions allow AEP to earn on the infrastructure built to serve it.

What to watch

• Q3 2026 Oklahoma order on the non-unanimous PSO settlement — interim rates are already collecting at 9.375%, and contested provisions plus the open large-load tariff issue could move the number.
• Final PUCT order on the AEP Texas UTM calculation, expected in Q3 2026, which sizes the disallowance beyond the $23 million already booked.
• The $65 million of UTM costs going into the next application — a second adverse ruling would establish the Texas deferral mechanism as structurally leaky rather than a one-time timing dispute.
• ERCOT Batch Zero eligibility determinations and the April 2027 load-ramp information, which converts 40 GW of letters of agreement into interconnection agreements or doesn't.
• Settlement of the March 2025 and ATM forwards in December 2026 — about 21 million shares and $2.1 billion — and whether AEP needs to add to the $5 billion of contracted equity to hold its debt ratio.
• West Virginia securitization, expected in Q4 2026 against $2.7 billion of WVPSC-approved eligible costs, plus the intervenor appeal of the Inflation-Based Rate Adjustment now at the West Virginia Supreme Court.