Q3 2025 Earnings Preview: Setting Expectations

Earnings season is still six weeks away, but the data is already coming in. With WTI crude averaging in the low-to-mid $70s through the summer months and Henry Hub natural gas holding around $2.80–$3.10/MMBtu for most of Q3, the commodity environment for the quarter was neither a disaster nor a bonanza. For upstream operators, that means the results will be defined by cost discipline, operational execution, and capital allocation — not price upside.

Here's what CIR is watching as the Q3 2025 earnings cycle approaches.

Oil: Volumes Will Matter More Than Price

With WTI averaging roughly $72/bbl in Q3 — down slightly from Q2 and well below the $80+ highs of late 2023 — revenue-per-barrel will not be the headline for oil-focused operators. Investors and analysts will focus on production volumes, unit costs, and free cash flow conversion.

Diamondback Energy (FANG) is expected to post another quarter of strong Permian execution. Following its acquisition of Endeavor Energy Resources — one of the largest private E&P deals in history at ~$26 billion — FANG's integration milestones will be in focus. Is the combined entity drilling to synergy targets? Are unit costs trending down as operations are consolidated? Management's commentary on 2026 capital plans will be the most closely parsed portion of the call.

Devon Energy (DVN) faces a different set of questions. Production guidance for 2025 has been modestly reset, and the company's multi-basin portfolio — Permian, Eagle Ford, Anadarko, Williston — adds complexity. Market participants will look for clarity on portfolio prioritization: is Devon drilling its best Permian inventory or spreading capital too thinly across too many basins?

ConocoPhillips (COP), now operating with the Marathon Oil assets acquired in late 2024, will be presenting its first full quarter as a combined entity. The integration of Marathon's Eagle Ford and Bakken positions adds meaningful volume. COP's discipline on per-unit cost targets will be a focal point — they've committed to not letting the acquired assets dilute their cost structure.

Gas: The Recovery Trade Holds (Barely)

Natural gas prices have been the biggest positive surprise of 2025 for producers who stuck with gas-weighted portfolios through the 2024 carnage. Henry Hub averaging near $3.00 is well above the sub-$2 lows of early 2024, and LNG feedgas demand has provided a structural demand floor that simply didn't exist three years ago.

EQT Corporation (EQT), the largest U.S. natural gas producer, has been vindicated in its decision to maintain Appalachian production capacity and hedge selectively rather than cut activity aggressively. CEO Toby Rice has articulated a "patient capital" thesis: keep the infrastructure in place, wait for the LNG-driven demand recovery, and avoid the costly restart costs that come from letting rigs go. Q3 results will show whether that thesis is generating cash.

Expand Energy (formerly Chesapeake Energy) will be reporting its first full year of post-merger quarters as the combined Chesapeake/Southwestern entity. The Haynesville and Marcellus positions together make it the most LNG-correlated E&P in the public markets. Management will almost certainly spend time on the LNG volume growth runway.

Coterra Energy (CTRA), with meaningful Marcellus and Permian exposure, sits at an interesting intersection. Crude revenue has been stable if unexciting; Marcellus gas volumes have benefited from tighter regional spreads as takeaway has improved. Watch for Coterra's capital allocation commentary — the company has been among the most shareholder-friendly operators in terms of variable dividends and buybacks.

The Macro Overhang: Demand Concerns and OPEC+

The Q3 earnings narrative will be colored by broader macro uncertainty. China's economic recovery has been uneven, with refinery throughput disappointing expectations through much of Q3. OPEC+ production policy remains a key variable — the group's ability to enforce cuts among members like Iraq and Kazakhstan has been inconsistent.

For upstream operators, the key communication task in Q3 earnings will be articulating resilience: "Here is our free cash flow generation at $65 WTI, $70 WTI, and $75 WTI. Here is why our 2026 plan is durable across those scenarios." Companies that have invested in low-cost Tier 1 inventory over the past three years will have the most credible story to tell.

What Consensus Expects

Street estimates for the major E&Ps embed modest revenue declines quarter-over-quarter (reflecting lower realized prices) with stable-to-lower unit costs. Free cash flow estimates have been trimmed modestly from the start-of-year forecast but remain healthy for operators with strong balance sheets. Dividend sustainability is not in question for the investment-grade E&Ps. The debate is entirely around growth capital and buyback pace for 2026.

Companies most at risk of negative surprises: smaller, higher-cost operators with Haynesville exposure and limited hedging, who may find Q3 realized prices disappointing versus strip. Companies most likely to positively surprise: highly efficient Permian operators where well productivity data suggests per-unit costs continue to compress.

Q3 earnings season kicks off in earnest in mid-October. CIR will be covering every major report.

Crude Intelligence Report is an independent upstream oil and gas intelligence publication. Content 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. The author and publisher hold no positions in any companies mentioned in this article. © 2026 Crude Intelligence Report. All rights reserved.