Oil & gas services benchmarks: utilization, margin, day-rate elasticity.

01 The cohort and the headline read

The cohort comprises five publicly-traded US oil & gas services companies pulled directly from SEC EDGAR XBRL filings, plus the broader 8–11 name cross-reads we maintain internally. SLB, Halliburton, and Baker Hughes anchor the integrated end. Liberty Energy represents the high-spec NAm pressure-pumping pure-play. Cactus represents the niche wellhead-and-specialty-equipment side that we use as a "production-services" proxy. Together they span $1.1B (WHD) to $35.7B (SLB) in fiscal 2025 revenue, and operating margins from 1.8% (LBRT) to 23.2% (WHD). The dispersion is the story.

The blended operating-margin median across the public cohort in fiscal 2025 ran approximately 11–13%, compressed from approximately 18–20% in fiscal 2023. The compression is concentrated in pressure pumping, completions, and the NAm short-cycle side of the integrated portfolios. Niche equipment and recurring-revenue franchises held margins materially better. Three of the five names in our cohort posted year-over-year revenue declines in fiscal 2025 — SLB at -1.6%, LBRT at -7.2%, WHD at -4.5% — with HAL and BKR essentially flat. This is not a collapse; it is a plateau-with-margin-give-back, which is exactly what the cycle math predicts after a 28% peak-to-trough WTI move.

For private services operators in the same sub-sectors, the public-cohort signal lags directly into your own renewals with a 1–3 quarter delay. Operators with younger fleet and recurring revenue track the upper end of the cohort. Operators with aging fleet, heavy equipment-finance density, and short-cycle NAm exposure track the LBRT-shaped compression. The variable that determines which side of the cohort you sit on is rarely the basin or the customer — it is the structure of the asset base and the contract book you arrived at the downturn with.

02 The WTI cycle the cohort is responding to

No oil & gas services read makes sense without naming the WTI cycle that determines what operators can charge on renewal. The Federal Reserve Bank of St. Louis FRED series for WTI (DCOILWTICO) shows the move clearly. WTI averaged $85.35 in April 2024 — the 2024 peak. From there the slide ran through 2025: $75.74 in January, $68.24 in March, a $62.17 low in May 2025, then sideways in the mid-$60s through summer, then another leg lower to a $57.97 trough in December 2025. The trailing-12 average through May 2025 was approximately $73; through December 2025 it had compressed to approximately $68. By Q1 2026 the dynamic had reversed sharply — WTI averaged $91.38 in March and $100.32 in April 2026 on a geopolitically-driven rebound — but the service-pricing book is anchored to the trailing window, not the spot print.

Henry Hub natural gas (FRED series DHHNGSP) tells a partially-decoupled story. The 2024 trough was $1.49 in March 2024 — a level that pressured all gas-leveraged service activity. The 2025 winter peaked at $4.19 in February. The 2026 January spike to $7.72 was weather-driven and corrected by April. For gas-leveraged completions and workover, the cohort sub-segments tracking gas activity (Appalachia, Haynesville) have been operating against a structurally weaker commodity backdrop than the oil-leveraged Permian, West Texas, and Eagle Ford completions cohorts. The decoupling is the second-order operating variable inside the cohort.

The Industrial Production index for Oil and Gas Extraction (FRED IPN213111N) gives the cleanest activity proxy. The index ran 122.4 at the April 2023 peak and has been on a generally-declining path since: 113.3 in March 2024, 103.5 at the November 2024 trough, a brief recovery to 105.3 in March 2025, then back down to 96.3 in July 2025. As of April 2026 it sat at 97.7. The trailing-twelve activity level is roughly 20% below the 2023 peak. That is the structural backdrop the cohort utilization is being measured against.

03 What the EDGAR cohort actually shows

The XBRL-filed fiscal 2025 financials for the cohort are where the operating shape gets explicit. We pulled annual statements directly from SEC EDGAR (10-K filings indexed via the mcp-edgar service) for SLB (filed 2026-01-23), Halliburton (2026-02-06), Baker Hughes (2026-02-05), Liberty Energy (2026-02-02), and Cactus (2026-02-26). Five different operating shapes; one cycle; meaningful dispersion.

SLB — the integrated plateau

SLB's fiscal 2025 revenue of $35.7B was down 1.6% from fiscal 2024's $36.3B — the first revenue decline in the cycle. Operating cash flow held remarkably well at $6.5B (18.2% of revenue), only fractionally below the $6.6B in fiscal 2024. Net income compressed 24% to $3.4B, reflecting cost normalization and Q4-2025 charges. The capital-return engine intensified: $2.4B in buybacks in fiscal 2025 (versus $1.7B in fiscal 2024 and $694M in fiscal 2023) and $1.6B in dividends. Long-term debt sat at $11.0B at year-end 2024 (the latest balance-sheet date in the filing). The OCF margin is the read: SLB compressed revenue and net income but converted cash at the same rate. That is what an integrated, internationally-diversified platform with offshore and digital exposure looks like in a NAm-led downcycle.

Halliburton — the sharpest NAm compression

HAL's fiscal 2025 10-K (filed 2026-02-06) shows the sharpest operating-margin compression in the cohort. Operating income fell to $2.26B from $3.82B in fiscal 2024 — a 41% drop. Reading against the cost-line revenue proxy of $19.9B, operating margin compressed from 20.0% in 2024 to 11.3% in 2025. Operating cash flow fell 24% to $2.93B. The compression is concentrated in the NAm completions side of the portfolio; international and offshore exposure cushioned but did not offset the slide. HAL's capital returns held — $1.0B in buybacks (essentially flat to fiscal 2024 at $1.0B) — but the cash-flow envelope tightened materially. This is the cohort name closest in operating shape to a leveraged NAm services pure-play, and the operating-margin print is the cleanest evidence in any 2025 10-K of the pressure-pumping margin reset.

Baker Hughes — LNG-buffered

BKR's fiscal 2025 revenue of $27.7B was flat versus $27.8B in fiscal 2024. Operating cash flow expanded 14% to $3.81B — improving cash quality despite the revenue plateau, driven by working-capital efficiency and the LNG/turbomachinery mix shift. Net income compressed 13% to $2.59B on tax and charge effects. SG&A held in absolute dollars (~$2.39B) while R&D investment continued at $600M. BKR sits structurally apart from the pure-play OFS names in the cohort because the Industrial & Energy Technology segment (turbomachinery, LNG packages, hydrogen) operates against a different demand cycle than wellsite OFS. The cohort comparable for a private services group is the OFS portion of BKR, not the consolidated print — but the consolidated print is what trades, and it is buffered.

Liberty Energy — the compression case study

LBRT's fiscal 2025 10-K shows the operating-margin compression in its purest form. Revenue: $4.01B in fiscal 2025, down 7.2% from $4.32B in fiscal 2024 and down 15.6% from the $4.75B peak in fiscal 2023. Operating income compressed from $761M in fiscal 2023 (16.0% margin) to $389M in fiscal 2024 (9.0%) to $73M in fiscal 2025 (1.8%). Net income compressed from $556M to $148M over two years. Depreciation rose to $500M (12.5% of revenue) — the equipment-finance density that does not move when revenue compresses. The balance sheet held with $191M of long-term debt at year-end 2024, and operating cash flow at 15.2% of revenue ($610M in 2025) means LBRT is still cash-generative. But the operating-margin compression from 16% to under 2% in 24 months is the cohort's case study on what NAm pressure-pumping cycle exposure looks like in a 10-K.

Cactus — the niche-margin durability

WHD's fiscal 2025 10-K shows the opposite shape. Revenue: $1.08B in fiscal 2025, down 4.5% from $1.13B in fiscal 2024. Operating income $250M (23.2% margin) versus $290M (25.6%) — a 240bp compression but still firmly in the cohort top quartile. Operating cash flow $258M (23.9% of revenue). Zero long-term debt across the period — the cohort's cleanest balance sheet. D&A at 5.9% of revenue, materially below the cohort. WHD's shape — niche equipment, low capital intensity, recurring product mix, debt-free — is the structural counter-example to LBRT. The same WTI cycle hit both names; the operating outcomes were 21 percentage points of margin apart. Asset structure and contract structure absorbed the cycle differently. That is the entire private-cohort lesson.

04 Sub-sector operating shape across Q2 2026

The cohort dispersion above maps onto a sub-sector taxonomy that the private services groups we work with need to understand precisely. The five sub-sectors operate on materially different cycle math.

Pressure pumping

The most cyclical and capex-intensive sub-sector. A new e-frac fleet runs $40–60M; a diesel replacement fleet runs $25–35M. Fleet-level EBITDA margins range from 15–25% in favorable markets and compress materially below 70% utilization. Industry-wide, approximately 150–165 frac spreads were active in early 2026, with the Permian operating roughly 70 full-time fleets (down from 90–100 a year earlier). Stage pricing has ranged from $30K to $70K+ across cycles; the mid-cycle reference is approximately $50K/stage. The Dallas Fed Energy Survey Q2 2025 showed OFS operating-margin index falling from -21.5 to -33.4, with the prices-received-for-services index turning negative (-17.7). That is the read-through to LBRT's 1.8% operating margin and HAL's NAm-pumping compression.

Completions services (broader)

Completions services beyond pure pumping — completion tools, plug-and-perf, perforating, cementing, flowback support, sand handling and related equipment — sit one structural step away from the pure-fleet economics. Tools-and-consumables mix raises margin durability; capex intensity is lower than a fleet rebuild. The 2025–2026 read is meaningfully better than pure pumping but still cyclical. Private operators with a mix of fleet and tools/services should expect tools/services to act as the margin floor when pumping pricing compresses.

Wireline

Wireline tracks completions activity with materially less capex burden than pumping. Equipment turns are better; pricing is tied to log/intervention depth and high-spec tool demand. Margins are more durable through the cycle, and cash conversion is better. In our work with private wireline operators, the 2025–2026 utilization read sits roughly 5–10 percentage points above pressure-pumping peers and EBITDA margins approximately 4–6 percentage points higher.

Drilling services

Drilling services — directional, MWD/LWD, drilling tools and optimization — depend on rig count and well complexity rather than completion intensity directly. The cycle is less sharp than pumping because drilling programs are planned. Contracts run well-to-well or 6–12 months, so day-rate lag to WTI is 1–2 quarters. Margins attractive when tool utilization tight; soften when oversupply or pricing competition returns. The 2026 environment is stable-to-mixed: less stressed than pumping, but not a supercycle.

Workover and well servicing

The most defensive of the five sub-sectors. Workover is tied to maintenance, repairs, interventions, artificial lift, and mature-field optimization — production-side activity that runs counter-cyclically to drilling capex when operators emphasize base-production maintenance. Capex intensity is materially lower than drilling and dramatically lower than pumping. Rates are steadier and more local-market driven. In a capital-discipline regime like 2025–2026, workover and well servicing are the cohort's most-defensive pocket, and the private operators in this corner have been the cleanest performers in our practice through the down-leg.

05 Day-rate elasticity to WTI on the renewal cycle

The elasticity of service pricing to WTI is positive, lagged, and asymmetric. Service pricing follows WTI; it does not lead it. The lag varies by sub-sector and contract structure, and the asymmetry — downside faster than upside — is the cycle math that determines whether a private operator can survive a down-leg in their current capital structure.

Rig day-rates run a 1–2 quarter lag at renewal, with short-run elasticity to WTI roughly 0.2x–0.5x. Contracts are well-to-well or 6–12 months, so pricing resets only on renewal. Pressure-pumping and completions pricing runs the shortest lag, often 0–2 quarters, with elasticity 0.5x–1.0x in stressed markets. Completion-adjacent services (wireline, cementing, logistics) run typically one budget cycle of lag, with elasticity 0.3x–0.8x. The practical modeling convention we use in our work: a 15% WTI move down translates to roughly 10%–14% day-rate compression in 2–3 quarters for completions and pumping; a 15% WTI move up recovers approximately 7%–10% over 4–6 quarters. The asymmetry compounds across the cycle and is the structural reason mid-market services operators leveraged on the up-leg get into trouble on the down-leg even when revenue is "only" 15% off peak.

The mechanism is straightforward. When WTI falls, E&P operators cut capex budgets within a quarter. Completions are the first lever pulled because the work is highly discretionary on the activity calendar. Service providers compete harder to keep fleets busy and crews retained. Pricing falls at the next renewal and sometimes sooner in spot-heavy work. When WTI rises, service prices do not jump immediately. Operators absorb the higher commodity price as margin expansion first. Service contractors only regain pricing power once utilization tightens enough that fleets become scarce and contracting windows roll. The price-up window is structurally narrower than the price-down window.

For 2026 specifically, the WTI rebound to $91+ in March and $100+ in April is the favorable signal — but the cohort's pricing book is anchored to the trailing-12 average, which still includes the $58–$65 prints from late 2025. The day-rate recovery, if WTI holds, will land on Q4 2026 and Q1 2027 renewals. The Q2 and Q3 2026 quarters are likely to print at compressed pricing levels for most of the cohort. That is the working assumption we are using with our private services clients on cash-flow planning.

06 The private-to-public gap in operating shape and multiples

For mid-market private operators, the structural gap to the public cohort is the most important valuation variable. Three gaps matter: operating-margin, leverage, and multiple. Each is wider than most private operators realize.

Operating-margin gap

Public OFS / integrated names run 18–25% EBITDA margins at the better segments and 15–22% at niche publics. Private mid-market OFS typically runs 10–18% — a 3–7 percentage point structural gap. The gap is wider than the asset mix suggests because public companies have scale advantages in SG&A, central procurement, asset utilization across basins, and pricing discipline across regions. Best-in-class private chemicals and tools players can match public margins; pressure-pumping, coil, and well-servicing private operators typically run 8–15% EBITDA margins versus 15–22% for comparable public segments. The first lever in any sponsor-backed value creation plan is closing 100–300bp of this gap via SG&A rationalization, asset utilization tightening, pricing discipline, and working-capital optimization.

Leverage gap

Public OFS runs 0.5–2.0x net leverage on the major names — disciplined capital structures coming out of the 2015–2020 restructuring cycle. WHD runs at zero long-term debt. SLB at roughly 1.5x. HAL at approximately 1.0–1.3x. Private sponsor-backed mid-market OFS typically runs 3.0–4.0x net leverage, with recurring/contracted models sometimes underwritten as high as 4.5x. Cyclical pure-frac assets are more conservatively underwritten at 2.0–3.0x. The leverage gap is 1.5–3.0 turns higher on the private side, which means private operators pay full price for cycle compression that public operators absorb without distress. This is the single most consequential structural variable for cycle-survival math.

Multiple gap

Public OFS / equipment trades at approximately 6–9x EV/EBITDA at the sector base rate, with premium tech-adjacent / recurring deals (SLB-ChampionX, BKR-Chart) clearing low-teens pro-forma synergies. Private mid-market OFS clears 5–7.5x typical, with cyclical pumping and well services at 3–5x and recurring chemicals or specialty tools at 8–10x. The gap to public trading multiples is 3–5 turns, or roughly 50–70% of public valuations. The arbitrage is the single largest structural opportunity in the cohort: PE buyers acquire mid-market platforms at 5–8x and exit to strategics or public markets at 8–11x after building scale, improving margins, adding recurring revenue lines, and de-risking customer/basin concentration. That is the structural playbook our M&A advisory work is built around.

07 The operating playbook the cohort signals

The public cohort's 2025 disclosures point to a consistent operating playbook for services operators navigating the down-leg. The same playbook applies to the private operators we work with — most of it earlier and more aggressively than the public cohort because leverage and customer concentration force the timing.

1. 01
   Fleet stack-and-store discipline. Aging-fleet utilization is the single largest variance driver in the cohort. Operators with fleet over 8 years average are running 4–6 utilization points below cohort median; operators under 5 years are running 4–6 points above. The discipline of stacking marginal equipment instead of running it at zero contribution is the cleanest single decision the cohort has signalled through 2024 and 2025. For our private clients with mixed-vintage fleet, the stack-decision math is the most consequential operating decision in the calendar.
2. 02
   Bench-retention engineering. Crew retention through compression is what determines who is ready to ramp on the next up-leg. The cohort's investor-day language consistently emphasizes crew retention as a strategic priority through the down-leg. Bench-retention costs are real and they have to be funded out of OCF; the alternative is losing 6-12 months on the recovery curve when WTI re-rates. Our practice work with private operators has emphasized this trade explicitly — pay to retain through Q2-Q4 2026, deploy on Q4 2026 / Q1 2027 renewals when WTI elasticity catches up.
3. 03
   Equipment-finance refinancing. D&A as a percentage of revenue is the equipment-finance density read. LBRT's 12.5% D&A/revenue is the cohort's steepest fixed-cost burden; WHD's 5.9% is the lightest. For private operators with cyclical equipment finance booked in 2022-2023, the refinancing exercise — extending term, decoupling from utilization triggers, restructuring rate floors — is the second-highest-leverage finance initiative in the calendar after working-capital tightening. The window to refinance closes if utilization compresses through covenant triggers; the work has to be done while the relationship is still constructive.

The companion read for the operating playbook is the 13-week cash flow template we publish for oil & gas services, and the interim CFO commodity-downturn post that lays out the financial-management posture across the cycle. Those documents lay out the operating cadence; this cohort read lays out the benchmark numbers that should anchor the operating decisions.

08 Four questions for the private services operator

The cohort read above translates into four questions every private services operator should be able to answer at the desk on Monday morning. We use these explicitly in our scoping work.

1. How does your fleet utilization compare to the sub-sector median, and is your fleet-vintage profile a structural advantage or a structural disadvantage versus the public-cohort signal?
2. How does your trailing-12 day-rate trend compare to the cohort's -8% to -12% completions-and-pumping median, and is your renewal-cycle calendar visible 12 months forward with named customers and date-anchored milestones?
3. Is your EBITDA margin within the cohort's 11–14% blended range, and is your equipment-finance density (D&A / revenue) inside the 6–13% cohort band — or outside it, in either direction?
4. Is your net leverage inside the sponsor-backed 3.0–4.0x range, and do your covenants give you headroom to ride a further 2-quarter compression at current utilization before triggering the lender conversation?