Q2 2025 Upstream Operations Roundup: Efficiency, Tech, and a Dash of M&A
Week 3 of Q2 2025 Earnings Roundup
AFE Leaks Update:
Added 131 New AFE’s this week from Wyoming and New Mexico. Added more Texas actuals with my monthly well data refresh.
Continuing to process backlog of AFE’s to add full-component breakdowns; 417 wells done in the last two weeks.
Began adding North Dakota revenue/marketing costs by API/product to the Product dataset. 2024-2025 in there for now. I have another big state in the works on that front so stay tuned.
Consulting project took up bulk of the week, so next research report will be next week sometime.
Tons of companies out there this week. I’ve parsed through the major L48 ones for you.
The second quarter of 2025 saw North American E&Ps doubling down on operational efficiency to navigate a choppy commodity environment. In earnings calls and releases, executives from EOG Resources, APA Corp, Permian Resources, Chord Energy, ConocoPhillips, Diamondback, Vital Energy, Civitas, Coterra, and Occidental touted cost-cutting wins – from cheaper drilling and lower LOE to doing more with fewer rigs – often crediting technology and disciplined execution. Several also tweaked rig counts in response to price signals and even engaged in M&A (or non-core asset sales) to high-grade their portfolios. Below is a company-by-company rundown, breaking down the key operational highlights (with a bit of color commentary) from Q2 2025. Let’s dig in.
EOG Resources: Cost Discipline and a New Utica Toy
EOG beat on volume forecasts while undershooting cost guidance. CEO Ezra Yacob bragged that oil, gas, and NGL production all exceeded guidance midpoints, with capital expenditures and cash operating costs coming in below plan. Cost discipline drove strong financials ( ~$1.0B free cash flow in Q2) and allowed a 5% dividend bump, “announced in tandem with the Encino acquisition”. The Encino acquisition closed in Q2, making the Utica Shale a new “foundational asset” for EOG’s future. They also expanded more on the $270 Mn Arrow S Eagle Ford acquisition from May. Management updated full-year guidance accordingly, still preaching capital discipline as they integrate the Utica assets.
On the ops front, EOG highlighted across-the-board per-unit cost improvements: LOE and other operating costs fell in Q2 vs Q1 (helped by lower maintenance, water handling, and workover expenses). Big picture, Yacob struck an upbeat tone that EOG has “never been better positioned,” citing operational excellence and a beefed-up portfolio spanning the Utica, Bahrain/UAE, Trinidad, and beyond.
APA Corporation (Apache): Fewer Rigs
APA Corp’s Q2 message: we’re doing more with less. CEO John Christmann noted APA is “delivering more activity with fewer rigs and frac crews”. In the Permian, APA cut its operated rig count from 8 to 6 during Q2 thanks to improved drilling efficiency, yet expects to hold production flat with that slimmer fleet. APA’s cost savings drive is in high gear too: management accelerated its $350 MM cost reduction program, now targeting that run-rate by 2026 instead of 2027. In other words, more belt-tightening on the way with big opex and overhead cuts coming (if there’s anyone left over there as it is?).
Internationally, Apache had some noteworthy operational wins as well. Egyptian production hit 144 MBOE/d in Q2, boosted by strong new gas discoveries and better infrastructure utilization. APA even secured 2 million new acres in Egypt (a presidentially approved award expanding their footprint by 35%) to keep that growth going. And in Suriname, they inched closer to development: APA upped its 2025 capex for the Block 58 project to $275 MM, with first oil expected by mid-2028. Back home, APA did sell a New Mexico asset in Q2, but so far maintained full-year oil production guidance despite that divestment. All told, Apache used Q2 to prove it can trim the fat (rigs, costs, debt) without starving production. They also paid down $850 MM of debt and returned nearly $1 Bn to investors.
Permian Resources: Record-Breaking Efficiency
The co-CEOs practically high-fived each other on the call in regards to efficiency, noting the “11th consecutive quarter of solid operational execution”. Q2 included company-best metrics like the fastest well ever drilled, the most footage drilled per day, and the lowest completion cost per foot in PR’s history. In short, their drilling and frac crews are breaking speed limits and driving costs down to new lows. This outperformance let Permian raise its full-year guidance and do more with less capital. In fact, management bumped 2025 total production guidance up by +3% while lowering the capex budget ~2% – thanks to efficiency gains that add ~$50 MM to 2026 free cash flow. They even credited new tech and techniques: e.g. simul-fracs pushing >170,000 barrels of water per day on Delaware completions and savvy marketing agreements that boosted gas netbacks by $0.10/Mcf and oil by $0.50/bbl.
Permian Resources also made a splash with M&A this quarter – scooping up assets right in their backyard. In May, they closed a $608 MM acquisition from APA Corp, adding a big swath of Delaware Basin acreage that neatly overlaps with PR’s existing position. Management loves these “exact type of deal[s]” that bring immediate free cash flow and inventory that competes for capital on day one. The deal (a North Delaware Basin package) closed in late June, and PR’s leverage remains low (~1×) even after the purchase. In fact, Fitch just awarded Permian Resources its first investment-grade credit rating in July – a nice validation of their financial and operational discipline. The company isn’t shy about more deals either; with ~$3 B liquidity, management says they can pursue further “countercyclical investments” (and still pay down debt and do buybacks all at once). To punctuate the quarter, PR bought back $43 MM of stock and added 1,300 net acres via small “grassroots” deals.
Chord Energy: Long Laterals, Low Costs in the Williston
Chord Energy quietly keeps executing in the Williston Basin, and Q2 was no exception. The company beat its cash flow forecasts, with net operating cash and free cash flow above expectations due to “efficient execution and strong asset performance”. CEO Danny Brown credited better uptime and greater efficiency – less downtime and solid well results – which enabled Chord to raise its full-year oil production guidance slightly (+500 Bbl/d) while trimming capex by $20 MM at guidance midpoint. That’s a nice little upgrade: more output for less spend. Notably, Chord is pushing the envelope on well length in the Bakken/Three Forks. They drilled four 4-mile laterals so far with costs below budget, and are now accelerating this extended-reach program. They plan to turn in-line seven 4-mile laterals in 2025, proving out the productivity of extra-long wells. Chord even mentioned the early adoption of new technologies as key to its success – it will be interesting what exactly these are when they get around to adding color.
Operationally, Chord’s Q2 production was ~282 MBOE/d, a hair above the top end of guidance. LOE came in around $10/Boe, in line with guidance. Cash G&A was well below guidance (only ~$22 MM vs $26–28 MM planned), reflecting cost discipline and presumably some synergy benefits from past mergers. Chord is also returning barrels of cash to shareholders – over 90% of Q2 free cash flow was returned via dividends ($1.30/sh base) and buybacks. Since its 2022 merger, Chord has repurchased 10% of its outstanding shares (fully diluted), a substantial shrink.
ConocoPhillips: Steady Growth with a Static Rig Count
ConocoPhillips delivered a solid if unspectacular quarter, focusing on efficiency and portfolio high-grading. One eye-catching point: Management noted they have not added a single rig in the Lower 48 in 3–4 years, yet have managed to grow production in that time. That’s a testament to how much more productive their drilling has become post-mergers – integrating assets like Concho’s Permian acreage and leveraging tech to do more with the same rigs. They signaled confidence that they can maintain capital-efficient growth in the U.S. shale assets “without increasing rig count for three to four years” going forward. In any case, Conoco is clearly prioritizing returns over sheer growth: they actually trimmed 2025 capex guidance by a few hundred million earlier in the year, yet are sticking to production targets.
Operationally, COP’s Q2 total output was ~1.51 MMBOE/d (Lower 48 about 1.508 MMBOE/d), roughly 17% higher year-over-year as major projects ramped up, with the Permian Basin leading the charge. Conoco is also pruning its portfolio to keep the focus on high-margin assets: year-to-date 2025, they’ve executed ~$1.3 B in non-core asset sales in the Lower 48 (ie MRO’s Anadarko asset), with a goal of $2 B by 2026. This includes packages in the Permian and elsewhere that don’t move the needle. One could say ConocoPhillips is behaving like a lean shale machine these days – a far cry from its old “big oil” persona. Even Alaska (Willow) and LNG investments got less airtime this quarter than good old shale efficiency. All told, COP emphasized discipline and efficiency: keeping rigs flat, high-grading the asset base, and riding improved well performance. They generated ~$1.8 B adjusted earnings in Q2 and beat Street estimates.
Diamondback Energy: Doing More with Less
Midland-based Diamondback lives and breathes cost leadership, and Q2 reaffirmed that reputation. The company further cut its 2025 capital budget by $100 MM (now $3.4–3.6 B, about 13% below the original plan) while narrowing annual oil production guidance upward to 485–492 MBO/d. In plain terms: spend down, production up. One metric Diamondback loves to tout is oil production per dollar of capex, and for 2025 it’s now tracking ~50.9 barrels per $1 MM – ~14% better capital productivity than initially expected. Key to this efficiency, Diamondback has aggressively streamlined operations: they’re dropping their operated rig count from 17 to 13 as 2025 progresses, yet still hitting volume targets. Not many can pull that off, but FANG’s “record-low drilling times and completion efficiency” in Q2 made it possible. Wells are being drilled faster than ever in both the Midland and Delaware assets, and cycle times keep improving.
On the cost side, cash operating costs averaged just $10.10/Boe in Q2. Within that, LOE was a rock-bottom $5.26/Boe – among the lowest in the industry – thanks to scale and relentless field optimization. (For context, Diamondback’s LOE is roughly half of some peers’, an enormous advantage.) The company turned 116 operated wells to sales in Q2 (108 in Midland Basin, 8 in Delaware) with an average lateral ~13,400 feet, continuing its focus on long laterals to dilute fixed costs. And those long laterals are diverse: FANG is developing multiple zones (Spraberry, Wolfcamp, etc.) concurrently – the Q2 completions even included co-developing 11 two-mile laterals across four different reservoirs in Martin County with strong 30-day IPs (~823 bopd per well). Diamondback is clearly squeezing every dollar: even non-op and infrastructure spend is carefully managed (they spent only ~$67 MM on infrastructure in Q2, despite their scale).
On the strategic front, Diamondback isn’t just cutting costs – it’s pruning assets too. They executed $268 MM of non-core asset sales in Q2, inching toward a $1.5 B divestiture target. That, along with $1.2 B of Q2 free cash flow, is helping fund big shareholder returns: Diamondback repurchased ~$398 MM of stock in Q2 and boosted its share buyback authorization to a hefty $8 B total. In short, Diamondback is the poster child of “efficient shales” – fewer rigs, faster wells, razor-thin LOE, and opportunistic asset management. They make it look easy.
Vital Energy: Cutting Costs and Turning Backwards
Vital Energy (VTLE) had a mixed quarter financially (a large net loss on paper due to impairments), but operationally they’re focused on turning the ship around. CEO Jason Pigott emphasized “ongoing efforts to lower costs and optimize our assets, with the ultimate goal of enhancing returns.”. That came through in some places in the Q2 results: LOE was $107.8 MM, beating guidance (which was $112–118 MM). In fact, per-unit LOE improvements were driven by efficiencies in their new acquisitions – the recently acquired Point Energy assets in the Delaware Basin are operating cheaper than expected – plus cost-cutting in things like field power generation and chemicals. They’ve also trimmed the fat at HQ: G&A came in ~7% below guidance in Q2, and in June Vital cut headcount ~10% (employees and contractors) to ensure overhead stays down going forward. Those moves should yield a ~12% drop in G&A expense by Q4. Essentially, Vital is in belt-tightening mode to dig out of the red and generate consistent free cash flow.
But it’s not all about slashing costs – Vital is also experimenting with new well designs to boost productivity. In Q2 they brought on their first two “J-Hook” wells, and they’ve started drilling a 12-well project using “horseshoe” shaped laterals. Pigott highlighted that Vital “continues to lead the industry in the application of optimized well designs” like these J-Hooks. It’s early, but if successful, such designs could meaningfully improve EURs on their acreage; particularly somewhat stranded units. On the development pace, Vital is front-loading activity: they plan to turn-in-line all 38 wells scheduled for 2H 2025 by early October, which should surge production in Q4. Q2 production was ~137.9 MBOE/d (62.1 MBO/d oil) – within guidance – albeit with a small hit from some weather and facility downtime. Expect that to jump after those 38 wells come online.
Vital did have a hiccup with capital in Q2: they spent $257 MM, a tad above the $215–245 MM guidance due to some drilling cost overruns ($13 MM) and pulling some activity forward ($11 MM). They adjusted future plans to compensate, trimming Q3 capex guidance by $25 MM (now $235–265 MM) while keeping full-year capex at $850–900 MM. On the portfolio front, Vital executed a small divestiture of 3,800 net acres (Crane & Upton counties) for $6.5 MM in July, with proceeds going to debt reduction. Every little bit helps when deleveraging. Overall, Vital’s Q2 narrative is “restructure and innovate”: cut costs hard, streamline the org, and try novel drilling techniques.
Civitas Resources: Permian Up, Costs Down
Colorado/Niobrara stalwart Civitas had a busy Q2 as it digested last year’s Permian acquisitions. Oil volumes jumped 6% sequentially, almost entirely thanks to the Permian assets now hitting their stride. By Q2, over half of Civitas’s production came from the Permian Basin, with the rest from its legacy DJ Basin operations (a big shift for a company that was all-DJ a year ago). Even with the Permian growth, the team kept spending in check: capital expenditures came in at the low end of expectations due to well cost optimization, efficiency gains, and timing tweaks. Civitas proudly reported that its average drill-complete-tie-in costs per lateral foot have dropped meaningfully since January – down ~7% in Delaware, 5% in Midland, and 3% in the DJ. That’s cross-basin efficiency improvement, showing they are squeezing costs out of both the new Texas assets and the familiar Colorado ones.
Operational highlights were plenty. In the Permian, Civitas had 42 net wells turned to sales in Q2 (mix of Delaware and Midland). They’re utilizing cutting-edge techniques, e.g. simul-frac operations in the Delaware averaging 170,000 barrels of water pumped per day on initial pads. They also brought online their first operated Delaware wells in Lea County, NM, with performance right on expectations. Meanwhile in the Midland Basin, Civitas drilled and completed 11 two-mile laterals in Martin County, co-developing multiple zones (Middle & Lower Spraberry, Jo Mill, Wolfcamp A) – those wells averaged 823 bopd over 30 days each. Over in the DJ Basin, the legacy business is still moving along: Q2 saw 46 net DJ wells turned online, including an 8-well pad in the Watkins area featuring record-long laterals. They drilled some of the longest wells in Colorado history – four-mile reach, with ~3-mile laterals completed – and got 1,100 bopd 30-day average per well. They even drilled a pad of four-mile laterals in just 4.4 days from spud to TD on average, showcasing top-tier drilling efficiency. The takeaway: Civitas isn’t letting Colorado’s regulatory maze slow its technical progress.
Crucially, cash operating costs came down nicely as Civitas integrated its new assets. Q2 cash operating expense (LOE + GP&T + cash G&A) was $10.19/Boe more ~10% lower than Q1. In particular, Permian LOE per Boe dropped over 15% from Q1 as they eliminated duplicate maintenance, optimized water disposal, and reduced fuel/power costs on those assets (management noted much lower workover and water-handling costs).
On the flip side, Civitas decided to streamline the DJ portfolio: they announced agreements to divest $435 MM of non-core DJ Basin assets (set to close in 2H 2025). Those packages total ~10 MBOE/d of production (roughly 50% oil) that were outside Civitas’s core development areas. The sales will bring in cash (to pay down debt from the Permian acquisitions) and effectively focus Civitas on its highest-return acreage in both basins. Notably, along with the asset sales, Civitas is also undergoing leadership change – CEO Chris Doyle is departing – marking a pivot as the company fully transitions from a pure-play DJ to a multi-basin operator.
Going forward, Civitas expects Permian volumes to stay strong into Q4 (they’ve got a healthy DUC inventory there), while the DJ will shrink a bit due to the asset sales. They guided a slight reduction in Q3 volumes from the divestitures but highlighted that corporate margins will improve after shedding higher-cost assets. In fact, Civitas launched a formal efficiency initiative targeting $40 MM of annual margin improvements, “led by well cost and cycle time reductions in each basin, improved oil differentials from new transportation agreements,” etc.
Coterra Energy: Gas Prices Rebound, Output Rises
Coterra, the oil-and-gas combo of Cimarex + Cabot, enjoyed a favorable turn in Q2 as natural gas prices rebounded from their winter lows. The company’s production jumped 17% year-over-year to 783,900 BOE/d, with significant gains in the Permian and Anadarko (Mid-Continent) oil assets fueling the growth. After a tough start to 2025 for gas, Henry Hub prices recovered enough in Q2 to “cushion” the impact of weaker oil prices. Coterra’s realized gas price was $2.20/Mcf in Q2 – still not high, but 74% higher than a year ago when the gas market was in the doldrums. That uplift, combined with record volumes, helped Coterra beat profit expectations despite oil averaging 20% lower than last year. In fact, the company’s adjusted EPS of $0.48 slightly topped estimates, and cash flow was robust. Essentially, their diversified production (roughly half gas, half liquids) worked as intended: gas came to the rescue when oil faltered.
On the operations side, Coterra is holding output roughly flat in the Marcellus – they dialed back activity when prices were ultra-low, avoiding unneeded growth. Now, with prices up a bit, they can methodically complete DUCs or modestly increase activity to maintain volume. Meanwhile, the Permian (Delaware) assets acquired in the 2021 merger are the focus; Coterra’s Permian + Anadarko liquids production grew enough to set company records. They haven’t given specific rig counts publicly for each region, but it’s clear they are allocating capital to these higher-return projects. Coterra hasn’t needed to add drilling rigs to drive this growth – similar to Conoco, they’re benefiting from productivity gains on rigs they already had in the field.
A notable strategic move: Coterra signed a 7-year gas supply deal to deliver 50 MMcf/d to a new 1,350 MW power plant (the CPV Basin Ranch Energy Center) being built in the Permian region. This is their first long-term gas contract in West Texas, and it locks in a chunk of demand starting in 2028. Essentially, Coterra is finding new markets for Permian gas (which is wise, considering Permian gas has faced pricing and takeaway challenges). This kind of deal should secure a steady offtake at presumably decent pricing, leveraging growing local demand for gas-fired power in the oil patch. It’s a forward-looking way to ensure their associated gas isn’t stranded or sold at deep discount in the future.
Financially, Coterra remains very shareholder-friendly: they noted 58% of Q2 free cash flow was returned to shareholders via dividends and buybacks. They also maintained their full-year production outlook of ~1.4 MMBOE/d and operating cost guidance, indicating prior cost inflation is under control. In Q3, volumes are expected roughly flat or slightly up from Q2, with a similar mix (Permian oil steady, Marcellus gas stable).
Occidental Petroleum: Pruning and Optimizing
Oxy’s Q2 was more of the same; doing what they can to work off the Anadarko/Crownrock debt-load. On one hand, lower oil and gas prices slashed their profit by ~60% year-on-year, but on the other, the company generated a hefty $2.6 B of operating cash flow – actually more cash in the first half of 2025 than the first half of 2024, thanks to working capital and efficiency gains. Oxy has been extremely aggressive in using that cash to pay down debt and cut costs, reinforcing its balance sheet. They outlined $500 MM of cost reductions for 2025 and by August had repaid $7.5 B of debt since mid-2024. A lot of those savings are coming from streamlining operations and overhead. CEO Vicki Hollub highlighted that Oxy is “strategically strengthening [the] portfolio” – which in practice meant selling off non-core stuff and using the proceeds to delever.
Indeed, Occidental announced four separate divestitures of Permian Basin assets in Q2. Between April and July, they sold ~$370 MM of non-core and non-operated Permian acreage in small deals.
Honestly, if I was a small team, this is the type of stuff that makes sense; a large company that has a bunch of non-core acreage they need to monetize to help pay down debt. There are probably some gems in there if you know the asset-base.
In July, they inked a big $580 MM sale of a Midland Basin gas gathering system (to Enterprise Products). Combined, that’s ~$950 MM of asset sales, all earmarked for debt reduction. These sales are essentially Oxy shedding peripheral acreage and midstream that weren’t in near-term plans, to focus on what Hollub calls “the best assets in our history”. Notably, since they announced the CrownRock Permian acquisition in late 2023, Oxy has now done about $4 B of divestitures to help fund it and slim down elsewhere.
Operationally, Oxy’s total production was ~1.40 MMBOE/d in Q2 (flat with Q1), and they maintained full-year guidance of 1.40–1.43 MMBOE/d. The Permian Resources segment (their unconventional Permian operations) is the engine, averaging roughly 0.77 MMBOE/d during Q2 and expected to tick up slightly to 0.79 MMBOE/d in Q3. Oxy’s Permian shale output is at record levels. Oxy hinted at deferring some activity to live within a modest capital budget. And across the company, they’re focused on efficiency. They mentioned targeting $100–200 MM per quarter in cost savings through 2025 via supply chain improvements, productivity gains, and streamlining operations.
Beyond traditional E&P, Occidental continues to push its carbon management initiatives (through Oxy Low Carbon Ventures), though that’s more future-facing. For the upstream reader, the key takeaway is that Oxy is tightening its operational screws: they are very conscious of costs (both opex and capex), they’re not chasing growth for growth’s sake, and they’ll sell assets that don’t fit the plan. As Hollub put it, it’s rewarding to see portfolio efforts “drive debt reduction and create value for shareholders”. Oxy even kept its dividend steady and is opportunistically buying back stock as debt comes down. It’s a more cautious, cash-flow-geared Oxy than the gung-ho acquirer of 2019 – essentially, Occidental is in full optimization mode.
Wrap-Up
Q2 2025 makes one thing clear: upstream companies have entered a new chapter of austerity and innovation. Across the board, E&Ps are finding ways to shave costs – be it fewer rigs for the same output (APA, COP), cheaper wells per foot (Civitas, Chord), industry-low LOEs (Diamondback, EOG), or, sadly, people. In many cases, AI and digital optimization lurk behind the scenes (though not always called out by name) in drilling faster, predicting maintenance, or optimizing completions. We saw hints of it with simul-fracs, extended laterals, “J-hook” wells, and improved cycle times noted this quarter. Companies are clearly focused on getting more barrels out of each dollar invested, which is exactly what investors have demanded.
We also saw an interesting mix of offense and defense on strategy. Some went on offense: Permian Resources buying assets mid-cycle, EOG expanding into a new play, Civitas pushing technical limits in new acreage. Others played defense: Occidental and Conoco pruned portfolios and hoarded cash to fortify balance sheets, Vital slashed costs to ride out pricing pain. Yet the common thread is operational focus – the era of growth-at-any-cost is long gone. Today it’s about profitable barrels, not just barrels. That meant rig counts coming down in several cases (APA -25%, FANG -24% in the Permian) in response to price signals or prior overcapacity. It also meant prioritizing projects with the best returns.
Many of these companies are keeping production flat-to-growing in 2025 while spending less capital than last year – a sharp reversal from the inflationary struggles of 2022–23. The takeaway this quarter is cautious optimism. Companies are hitting operational records and finding new ways to save money, which bodes well for margins if prices cooperate. And unlike past cycles, they’re not rushing to ramp up drilling at the first hint of higher prices – the rig reductions and asset sales show restraint. Of course, volatility remains (one quarter does not a trend make), and some moves – like ultra-long laterals or aggressive cost cuts – will need to prove out over time. But for now, Q2 2025 gave us a welcome narrative of smart execution.