XOM and CVX Q1 2026: Record Guyana, Golden Pass LNG, and the $99 WTI Question

XOM | NYSE  |  CVX | NYSE  |  Source data: Q1 2026 earnings releases (8-K filed May 1, 2026), per ExxonMobil and Chevron Corp SEC filings

ExxonMobil and Chevron reported Q1 2026 earnings this morning against a backdrop that didn't fully exist yet. The numbers cover January through March, when Brent averaged roughly $81/bbl. The market they're walking into today — WTI at $99, Brent above $113, UAE out of OPEC — is a different animal entirely. Q2 will be the real test of what this cash machine actually earns at $100 crude.

ExxonMobil: The Underlying Business Is Stronger Than the Headline Suggests

Reported Q1 earnings of $4.2 billion ($1.00/share) significantly understate how the business actually performed. Strip out $3.9 billion in unfavorable estimated timing effects — mark-to-market derivatives where the physical deliveries hadn't yet cleared due to Middle East supply disruptions — and ExxonMobil earned $8.8 billion ($2.09/share) in the quarter, up $1.2 billion year-over-year.

CIR Analysis: The timing effects aren't accounting games. They're structural artifacts of a company running one of the world's largest physical commodity trading operations. When prices spike quickly (as they did in March following the UAE OPEC announcement), unsettled derivatives get marked at end-of-period prices while the physical barrels sit in transit. Those effects unwind in subsequent quarters. With $100+ WTI heading into Q2, the unwinding should be favorable.

Production: 4.594 million boe/d in Q1 2026, essentially flat with Q1 2025 (4.551 Mboe/d). The headline flatness masks the real story: Guyana set a new quarterly production record at more than 900,000 gross barrels of oil per day, an operational achievement that ExxonMobil described as industry-leading in FPSO availability per Solomon Associates benchmarking. The Permian contributed to advantaged volume growth alongside Guyana — both are the explicit "advantaged assets" XOM references in its segment disclosures.

Upstream capex ran $4.8 billion in the quarter, split $3.4 billion US / $1.4 billion international, on pace with full-year guidance of $27-$29 billion. Structural cost savings hit $15.6 billion cumulative since 2019, with $0.6 billion added this quarter alone.

Shareholder returns: $9.2 billion in Q1, including $4.9 billion of buybacks — on pace with ExxonMobil's announced $20 billion repurchase plan for 2026. Dividend declared at $1.03/share for Q2, payable June 10.

The Golden Pass LNG Train 1 milestone is worth noting separately. ExxonMobil and QatarEnergy achieved first LNG production at Sabine Pass in late March, and the first export cargo loaded in April. Golden Pass adds approximately 5% to total US LNG export capacity. With European storage still running below target and Asian spot demand elevated, this timing is near-optimal for the project's economics.

Chevron: Hess Integration Driving Production, Timing Effects Masking Strength

Chevron reported Q1 earnings of $2.2 billion ($1.11/share), with adjusted earnings of $2.8 billion ($1.41/share) once legal reserves and foreign currency effects are stripped. Year-over-year, reported earnings fell from $3.5 billion — but as with ExxonMobil, the comparison is complicated by approximately $2.9 billion in unfavorable timing effects, the same derivative/LIFO mismatch driven by March's sharp price spike.

Production was the standout: 3.858 Mboe/d total, up 15% year-over-year worldwide and 24% in the US. The Hess acquisition is doing exactly what Chevron said it would do. US production exceeded 2.0 million boe/d for the third consecutive quarter — a number that didn't exist in Chevron's portfolio two years ago. The Gulf of America and Permian Basin are cited explicitly as growth contributors alongside Hess integration volumes.

CIR Analysis: The Hess acquisition closed at roughly $60 Brent. Chevron is now operating those assets into $80-100+ Brent. The incremental free cash flow on the production uplift at current prices is substantial — and it's not yet visible in Q1 numbers that reflect a $81/bbl average quarter.

Cash returns totaled $6.0 billion in Q1 — the 16th consecutive quarter above $5 billion. Dividends of $1.78/share were declared for Q2, payable June 10. Free cash flow turned negative at -$1.5 billion on a reported basis, driven by $4.6 billion in working capital outflows from the March price surge (the same mechanism that hit ExxonMobil). Adjusted FCF was $4.1 billion, consistent with Q4 2025 and Q1 2025.

Capex ran $4.1 billion, up from $3.9 billion in Q1 2025, largely reflecting legacy Hess asset spending partially offset by lower Permian outflows. The company noted US upstream capex declined year-over-year despite production growth — a cost discipline signal the Permian service community should read as frac demand neutral-to-softer in the near term.

The $99 WTI Question: What Q2 Actually Looks Like

Both companies are entering Q2 with significantly different market conditions than Q1. WTI closed April at $99.89. Brent is above $113. The UAE's exit from OPEC, effective today, removes a structural ceiling from cartel supply discipline. The geopolitical floor is holding precisely because the geopolitical risk hasn't resolved — it's shifted.

CIR Analysis: At $99 WTI for a full quarter, ExxonMobil's underlying earnings run-rate likely exceeds $10 billion (excluding timing effects). Chevron's adjusted free cash flow at $99 WTI should comfortably exceed $5 billion in Q2 based on its production base and cost structure. Both companies remain on track for 2026 to be a record year for shareholder distributions — if prices hold.

The Permian read-through for frac demand is nuanced. ExxonMobil cited advantaged volume growth in the Permian as a contributor but disclosed US upstream capex of $3.4 billion for the quarter, which is below run-rate for a company targeting Permian production expansion. Chevron noted lower Permian capex despite higher production — a sign that efficiency gains are compressing the activity-to-barrels relationship. Neither company signals a near-term Permian rig count surge. The incremental barrels are coming from longer laterals, tighter spacing, and operational optimization, not from adding rigs.

For service companies watching these results, the demand signal is mixed: production is growing, returns-to-shareholders are prioritized over capex expansion, and unit cost improvements are reducing the per-barrel activity content. The frac sector's recovery thesis still rests more on pricing than on volume acceleration.

What To Watch

• ExxonMobil Q2 timing effect reversal — the $3.9B that compressed Q1 should partially unwind in Q2 if prices stay elevated
• Golden Pass LNG commercial operations timeline — Train 1 is producing, but full ramp to commercial rates and Train 2/3 scheduling matters for Haynesville/Appalachian gas producers pricing into LNG markets
• Chevron's TCO (Tengizchevroil) Kazakhstan production recovery — downtime cited as a Q1 headwind; watch for restoration of ~100k boe/d in Q2
• Permian capex guidance confirmation — both companies guided to flat-to-down US upstream capex YoY despite higher production, which signals continued service sector margin pressure
• Devon-Coterra merger vote (May 4) — the largest pending Permian consolidation event; outcome will further define who the basin's dominant operators are heading into H2 2026

Crude Intelligence Report is an independent upstream oil and gas intelligence publication. The content in this article is for informational purposes only and does not constitute investment advice, financial advice, or a recommendation to buy or sell any security. Always conduct your own due diligence before making investment decisions. CIR and its contributors may hold positions in companies mentioned; any such positions will be disclosed when known. © 2026 Crude Intelligence Report. All rights reserved.