APA · Q1 2026 Earnings

Cautious

APA Corporation

Reported May 6, 2026

30-second summary

US oil came in at 124 kbbl/d versus a 120–122 kbbl/d guide, prompting management to lift the FY2026 US oil outlook to a fixed 122 kbbl/d and reaffirm the $450M YE2026 cost-out target. Offsetting that, FY2026 Egypt adjusted production guidance was lowered to reflect PSC cost-recovery impacts at higher oil prices — a material negative revision that takes some shine off the US beat. The more important disclosure is in Q&A: management is explicitly pausing the buyback cadence after two months of post-conflict commodity volatility, choosing "patient" capital deployment despite $477M of Q1 FCF and a $3B net debt target now in reach near-term. Gas trading cash flow is also flagged to step down from $1.1B in 2026 to ~$400M in 2027 as basis differentials compress — a material out-year headwind that did not exist in the Q4 narrative.

Headline numbers

EPS

Q1 FY2026

$1.38

Revenue

Q1 FY2026

$2.33B

-11.8% YoY

Free cash flow

Q1 FY2026

$0.48B

Key financials

Q1 FY2026

Metric	Q1 FY2026	YoY	Q4 FY2025	QoQ
Revenue	$2.33B	-11.8%	$1.99B	+16.9%
EPS	$1.38	—	$0.91	+51.6%
Free cash flow	$0.48B	—	$0.42B	+12.2%

Guidance

Guidance is issued for the full year only, refreshed each quarter. Prior and new below are the same FY updated this quarter.

Actuals vs prior guidance

Metric	Period	Prior guide	Actual	Δ	Result
U.S. Oil Production	Q1 FY2026	120,000 to 122,000 barrels per day	124,000 barrels per day	+2,000 barrels/day above guidance high	Beat
Egypt Gross Gas Production	Q1 FY2026	13% to 15% YoY growth	518 MMCF per day	in-line with guidance	Met
Lease Operating Expense	Q1 FY2026	approximately $1.5 billion (FY2026 full-year)	below guidance	better than plan	Beat

New guidance

Metric	Period	Guide	YoY
Interest Expense Savings	FY2026	more than $60 million lower in 2026	—
Cost Reduction Savings	FY2026	$450 million cumulative run-rate savings by year-end 2026	—
U.S. Oil Production	Q2 FY2026	121,000 barrels per day	—
Egypt Gross Gas Production	Q2 FY2026	540 MMCF per day	—
Upstream Capital Investment	Q2 FY2026	approximately $575 million	—

Changes to prior guidance

Metric	Period	Prior guide	New guide	Δ	Result
U.S. Oil Production	FY2026	120,000 to 122,000 barrels per day	122,000 barrels per day	+122,000 (midpoint +1,000 bbl/day vs prior midpoint)	Raised

Reaffirmed unchanged this quarter: Egypt Gross Gas Production (540 – 550 MMCF per day), Upstream Capital Investment (approximately $2.1 billion), Lease Operating Expense (approximately $1.5 billion)

Other KPIs

Q1 FY2026

Segment	Q1 FY2026
Reported Production	442,000 BOE/day
Adjusted Production	363,000 BOE/day
U.S. Oil Production	124,000 barrels/day
Egypt Adjusted Production	71,000 BOE/day
Gross Gas Production	518 MMCF/day
Adjusted EBITDAX	$1.6 billion
Operating Cash Flow	$554 million
Lease Operating Expense	below guidance

Management tone

Q2: momentum is palpable → Q3: flexibility and hedged cash flow → Q4: production reset lower, margin story → Q1: beat-and-raise on US production, Egypt adjusted lowered, capital deployment slows.

The Permian narrative has reversed direction for the first time in a year. Three quarters ago the five-rig program was framed as a defensive moderation with explicit option to cut further; this quarter management raised the FY US oil guide above the prior range high and is touting Permian uptime as a sustainable advantage. From Q&A: "strong uptime and continued efficiency gains in the Permian Basin" is the framing for the FY2026 lift to 122 kbbl/d. What was a margin story in Q4 has quietly become a modest volume-and-margin story again — though Permian inflation (diesel, power, tubulars) was acknowledged for the first time, with most service contracts locked through 2026.

Capital allocation rhetoric inverted. Q4's call emphasized the framework return run-rate with net debt tracking toward $3B. This quarter, with the $3B net debt target "achievable in the near term," management is explicitly pausing rather than accelerating: "thoughtful and patient on deploying FCF remainder of year given two months of volatility post-conflict." The shift is from mechanical 60% framework return to discretionary timing. Combined with no debt maturities until December 2029, this is management buying optionality — a posture that reads as cautious about commodity prices rather than confident about the equity. The $3.2B of cumulative buybacks since end-2021 is being preserved as a track record, not extended in real time.

Gas trading now has a fully quantified out-year cliff. From Q&A: "$1.1 billion pre-tax cash flow in 2026... ~$400 million expected pre-tax cash flow in 2027 at current strip" as basis differentials compress on pipeline expansions. That's a $700M step-down in a high-margin, low-capex cash stream that has been a structural advantage of the Callon-integrated portfolio. Two quarters ago this was framed as upside; this quarter it has been framed as a fade.

Alaska exploration framing cooled. Q4 prepared the market for a two-well Sockeye appraisal program early 2027. This quarter management disclosed the reprocessed seismic showed "Sockeye was not drilled at the thickest location" — implying the prior well's results may have understated the prospect, which is technically positive but adds uncertainty about the existing resource estimate. The two-well program is still planned for winter, but the language ("re-evaluate based on new data") is more measured than Q4.

Q&A highlights

Doug Leggett · Wolf Research

What is the forward-looking run rate for gas trading cash flows beyond 2026, and what hedging tools are available? Has Alaska seismic reprocessing changed views on existing discoveries and drilling runway?

Gas trading expected at ~$400M pre-tax cash flow in 2027 at current strip for both basis and TTF, down from $1.1B in 2026 due to basis compression from pipeline expansions. Alaska seismic reprocessing showed Sockeye was not drilled at thickest location; company planning two-well program (exploration + appraisal) this winter. Basis hedges in place for 2026; monitoring 2027 hedging opportunities daily but none locked yet.

$1.1B gas trading pre-tax cash flow in 2026 ($300M from LNG, ~$800M from pipeline transport)~$400M expected pre-tax cash flow in 2027 at current stripAlaska two-well exploration and appraisal program planned for winterSockeye drilled in suboptimal location relative to reprocessed seismic

John Freeman · Raymond James

How will management allocate significant 2026 free cash flow given debt maturities not until 2029 and $3B net debt target? Will buybacks accelerate or will capital be deployed elsewhere?

Management reaffirming 60% shareholder returns framework (cumulative 71% returned since inception, 75%+ in 2025). $3B net debt target achievable in near term at current price environment. Will be 'thoughtful' and 'patient' on deploying FCF remainder of year given two months of volatility post-conflict; evaluating mix of debt paydown, dividend, and buybacks. Raised decommissioning spend guidance by $20M (planned activity increase, not cost increase). Emphasized this is deployment timing, not valuation view.

60% shareholder returns framework in place71% cumulative free cash flow returned to shareholders since framework inception$3.2B returned as buybacks since end-2021$3.6B debt reduced since end-2021

Chris Baker · Evercore ISI

What specific inflationary pressures are appearing in Permian costs? What strategic opportunities does achieving $3B net debt target unlock?

Permian inflationary pressures: diesel, power costs, and tubulars rising, but most services locked under contract through year. Teams managing well despite pressures; cost guidance unchanged. At $3B net debt target, company will balance exploration investment (Suriname, Alaska), prudent ARO/decommissioning management, and shareholder returns. Exploration spend currently ~$70M annually but will increase in 2027+ with Alaska wells and Suriname drilling.

Permian inflationary pressures: power, diesel, tubularsMost service contracts locked through 2026Current exploration spend: ~$70M/year ($20M Alaska ice roads, $50M Suriname)Exploration spend will increase in 2027+ with Alaska drilling and Suriname wells

Neil Dingman · William Blair

What exploration activities are planned in Suriname Block 58/53 near-term? How many workover rigs are running in Egypt and would higher oil prices prompt increased workover activity?

Suriname: Prior appraisal wells de-risked entire exploration play; multiple prospects identified; plan to drill exploration wells when rigs available, potentially extending plateau or finding incremental infrastructure. Egypt: Currently running mid-to-high teens workover rigs (stable level); secondary investments and waterflood projects maintaining flat production profile; no near-term plan to increase workover count despite higher prices.

Suriname appraisal wells de-risked exploration play seismicallyMultiple exploration prospects identified in Block 58Plan to drill exploration wells when rigs availableEgypt running mid-to-high teens workover rigs

Kevin McGrudy · Pickering Energy Partners

What is the outlook for international oil realizations (Egypt/North Sea) relative to Brent for Q2 and back half 2026?

Dated Brent differential to Brent futures currently $8-10 premium in Q2, compressing to $5-10 through year. WTI realization premiums $2-5 over futures. Current market showing spot premiums for both commodities.

Dated Brent premium to futures: $8-10 in Q2, $5-10 through yearWTI producer realization premium: $2-5 over futuresSpot market premiums currently elevated

Answers to last quarter's watch list

US oil tracking 120–122 kbbl/d FY2026 guide or further sequential decline from Q4 132 kbbl/d exit — Q1 came in at 124 kbbl/d, above the guide range high, and the FY guide was lifted to 122 kbbl/d fixed. The 3,000 bpd Q1 weather drag flagged in Q4 Q&A did not prevent the beat. Q2 guide of 121 kbbl/d implies modest back-half loading to deliver the FY number. Status: Resolved positively

YE2026 $450M cost-out target raised again — The $450M target was reaffirmed, not raised. After three consecutive beat-and-raises (Q2, Q3, Q4 FY2025), the program took a pause this quarter. Q1 LOE came in below guidance, supporting the trajectory, but management did not extend the target. The fourth consecutive beat-and-raise that would force a structural margin re-rate did not arrive. Status: Resolved negatively

Cadence of net debt paydown toward $3B target / Q4 FCF return rate — Mixed. The $3B net debt target is now characterized as achievable "in the near term," but management explicitly paused the buyback cadence pending commodity-tape clarity. Cumulative shareholder returns held at 71% since inception, but Q1 specifically did not maintain the Q4 pace. The slowdown is deliberate, not forced. Status: Resolved negatively (on cadence, not on target)

Egypt gas production trajectory vs. +13–15% FY2026 guide — Q1 gross gas of 518 MMCF/d reported in-line with guidance, and Q2 guided to 540 MMCF/d (low end of the 540–550 FY range). Trajectory consistent with the full-year framework — gas pivot on schedule but with the bulk of the YoY lift coming in 2H. Status: Continue monitoring

Suriname Block 58 exploration well outcomes and Uruguay farm-down — Management said appraisal wells have de-risked the exploration play with multiple prospects identified, but exploration drilling depends on rig availability — no specific timing committed. Uruguay was not discussed in the available Q&A. Status: Continue monitoring

Shallow Delaware Bone Springs four-well spacing test validating 1,700-location technical upside inventory — No specific Bone Springs spacing test results disclosed this quarter. Status: Continue monitoring

What to watch into next quarter

Whether US oil production sustains above 121 kbbl/d in Q2 — the FY2026 122 kbbl/d fixed guide requires a 2H step-up if Q2 lands at the guide point.

Whether buyback cadence resumes at the 60% framework level or stays subdued — the Q2 print is the first opportunity to confirm whether the "patient" deployment posture was a one-quarter pause or a structural shift toward debt-prioritized capital allocation.

Gas trading cash flow disclosure refinement: any change to the $400M FY2027 framework given how material the $700M step-down is to consolidated FCF.

Net debt trajectory from the Q1 ending balance of $4.12B (up from $3.98B at YE2025 on working-capital build) — the path to the $3B "near-term" target requires drawdown from $4.12B, not $3.98B, so Q2 needs to show the working-capital reversal plus underlying paydown. April's $555M bond repayment is a start.

Alaska Sockeye appraisal well permitting and confirmed winter spud date, plus any incremental seismic reprocessing color on the broader play.

Whether the YE2026 $450M cost-out target gets extended at the Q2 print — five consecutive prints without a raise after three in a row would suggest the program has matured.

Magnitude of the lowered FY2026 Egypt adjusted production guide once quantified — management acknowledged the cut but did not put a number on it, leaving the consolidated adjusted production outlook directionally weaker than the prior 371 kBOE/d framework.

Sources

APA Corporation Q1 FY2026 Earnings Release, SEC Form 8-K Exhibit 99.1 — https://www.sec.gov/Archives/edgar/data/1841666/000184166626000027/exhibit9911q26earningsrele.htm
APA Corporation Q1 FY2026 Earnings Call Q&A (Leggett, Freeman, Baker, Dingman, McGrudy exchanges)
APA Corporation Q4 FY2025 and Q3 FY2025 Earnings briefs (Tapebrief prior coverage)

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