The Oil & Gas Value Chain, Part 4: Oilfield Services (2026)

Data as of 15 September 2026. The framework in this guide — what oilfield services sell, how they are paid and why they move with the capex cycle — is evergreen. Rig counts, frac-crew counts, spending and company figures are dated individually and meant to be re-sourced before use. Worked margin and valuation examples are hypothetical illustrations, not measurements of any company. This report is for information only and was prepared with AI assistance — see the disclaimer at the end.

Every barrel that Part 1 of this series produces, Part 2 moves and Part 3 refines came out of a well drilled on a rig somebody else owns, lined with pipe somebody else rolled and fractured by a pump fleet somebody else runs. Oilfield services is that somebody else — the drillers, pressure pumpers, equipment makers and subsea engineers who sell rigs, crews, tools and know-how to the companies that own the barrels — and because they own no reserves, their revenue is not the oil price but their customers’ capital budget, multiplied by how hard they can price their equipment. That makes services the most geared, and most lagged, way to own the upstream cycle, and it leaves an investor one question to answer about any service company: is it riding the rig count, or building something that lasts beyond it? Every driller, service and equipment company sits in one screen on Metal Pilot’s oilfield services stock screener.

The Oil & Gas Value Chain series. Part 1: Upstream · Part 2: Midstream · Part 3: Downstream · Part 4: Oilfield Services · Companion: World Oil & Gas Basins · Supplement: Oil Sands

TL;DR & Key Takeaways

• What it is: the contractors and manufacturers behind every well — seismic, drilling, well construction, completion, production services, subsea and equipment. They sell into the whole well life but own none of the hydrocarbons.
• How it earns: on activity × price — dayrates for rigs, per-stage fees for fracturing, lump sums for subsea projects, product sales for equipment. There is no take-or-pay floor: when operators cut capex, volume and pricing fall together.
• The scale: upstream oil and gas investment runs at just under $570bn a year (2025); the US runs 591 active rigs (11 September 2026) against a 2014 average of 1,861, and the largest company, SLB, booked $35.7bn of revenue in 2025.
• The efficiency trap: longer wells and faster crews mean fewer rigs do more work. The average new Permian lateral grew 77% in a decade to 10,867 ft (3,312 m), good for technology sellers and deflation for anyone renting out commodity equipment.
• The equity behaviour: services amplify the capex cycle, with a lag. From 2014 to 2016 the US rig count fell 73% and Halliburton’s revenue 52%; from its 2020 low to its 2022 high Halliburton’s share price rose about 850%.
• The biggest swing factor: where the spending goes. Middle Eastern and Asian national oil companies now fund ~40% of upstream investment (25% in 2015), gas and offshore are growing while shale spending shrinks, and the largest companies are selling gas equipment and power alongside drilling tools.

Figure 1. Oilfield services at a glance

Figure data: Baker Hughes rig count via AOGR and the Baker Hughes international rig count, Primary Vision frac spread count, IEA World Energy Investment 2025 (pp. 50 and 53), SLB and U.S. EIA; the completion share is from the EIA/IHS upstream cost study (2014–15 well data). See Sections 2.1–2.4 and 4.1.

How to read this guide: new to the sector? Read straight through from Section 1. Here for the investment case? Jump to Section 5 — how to own it, how to screen it, and why the cheapest-looking service stock is usually the most dangerous one. Every technical term is defined in the Vocabulary (Section 8).

1. Oilfield services & the market basics

1.1 The service lines

Oilfield services (OFS) is the supply chain of the upstream industry. The operator — the exploration and production (E&P) company, major or national oil company (NOC) that holds the licence — decides where to drill and pays for the well; almost everything physical that happens on location is done by contractors. The industry’s shorthand is “picks and shovels”: the service company gets paid whether or not the well finds oil, but only if someone decides to drill it.

The work follows the life of a well, and so does the industry’s structure:

• Survey & evaluate — seismic acquisition and processing, core and fluid analysis, and the subsurface software that turns data into a drilling target.
• Drill — the rig and crew (contract drilling, onshore and offshore), plus the services that steer and support the bit: directional drilling, measurement- and logging-while-drilling (MWD/LWD), drilling fluids, bits and cementing, and the steel casing and tubing (OCTG) that line the hole.
• Complete — pressure pumping (hydraulic fracturing), wireline perforating, coiled tubing and completion tools that turn a drilled hole into a producing well.
• Produce — artificial lift, production chemicals, well intervention and, offshore, the subsea trees, flowlines and processing that carry production to a platform or floating vessel.
• Abandon — plugging wells and removing facilities at the end of field life.

How a well is physically drilled and completed is explained in Part 1: Upstream, Section 3.3; this guide covers the businesses that sell that work.

Figure 2. The oilfield services chain, survey to plug

Source: standard well-lifecycle structure as reported in the segment disclosures of SLB, Halliburton and Baker Hughes; conceptual diagram.

Each service line has its own capital intensity, its own activity metric and its own competitive structure, so a service company is best read as a portfolio of them.

Table 1. Oilfield service lines and their headline activity metric

Source: service-line taxonomy from company segment disclosures — SLB, Halliburton, TechnipFMC, NOV and Tenaris; examples are illustrative, not a recommendation.

1.2 Who buys

A service company has, in effect, one customer industry, and its revenue is that industry’s spending. Global upstream oil and gas investment — just under $570bn in 2025 (Section 2.1) — plus the operating spend on producing wells is the whole addressable market.

What makes the pool steadier than it looks is decline. Producing fields lose output every year, and the IEA estimates that nearly 90% of upstream investment since 2019 has gone to replacing lost production rather than growing it. Without new investment, shale output would fall more than 35% within a year; Middle Eastern oil fields decline by under 2% a year after their peak. Every operator therefore has a maintenance floor of drilling it cannot cut for long without shrinking — the upstream “treadmill” described in Part 1 — and that floor is the service industry’s floor too.

Who holds the budget matters as much as its size, because the three kinds of buyer behave differently:

Table 2. Who buys oilfield services

Source: IEA World Energy Investment 2025, p. 53 for the ~40% national-oil-company share (up from 25% in 2015) and p. 50 for the 2025 investment level; decline rates and the ~90% replacement share per the IEA, The Implications of Oil and Gas Field Decline Rates, September 2025.

1.3 Units & measurement conventions

Oilfield services measures activity rather than molecules. The two most-watched numbers are counts. The rig count is the number of rigs actively drilling in a week — Baker Hughes counts a rig as active if it is on location and drilling for four of seven days — and the frac spread count is the number of hydraulic-fracturing crews at work (a frac spread is one crew and its pumping fleet; this guide also calls it a frac crew). Neither is revenue, but both move ahead of it.

Pricing is quoted by the unit of work — dayrates for rigs and vessels, per-stage or per-job prices for completions, orders, backlog (contracted but unperformed revenue) and book-to-bill (orders ÷ revenue) for equipment and subsea projects — and the physical units follow the work: feet of lateral length (metric equivalents in brackets), fracturing stages, hydraulic horsepower (HHP) for pump fleets, tonnes for pipe. Table 3 gives each with a typical magnitude. Two conventions matter when reading them: rig counts are a flow of activity at a point in time while backlog is a stock at a balance-sheet date, and currency is US dollars unless marked (€ for euro reporters).

Table 3. Units used in this report

Source: rig definitions per Baker Hughes rig count FAQs; counts per AOGR rig and frac spread data; company magnitudes per Transocean, TechnipFMC and Tenaris 2025 results; lateral length per U.S. EIA.

1.4 How oilfield services gets paid

A service company sells capacity and expertise by the unit of work, and the contract decides who carries the risk when activity or efficiency changes. Six structures cover most of the market.

Dayrate contracts pay a rig owner a fixed amount per day on location, whatever the rig achieves — the operator carries the geological and efficiency risk, the driller carries utilisation risk between contracts. Per-stage or per-job pricing pays a pressure pumper or wireline company for each fracturing stage or job, so faster crews earn more per day. Unit-price call-offs pay for tools, chemicals and rentals as they are used. Lump-sum and EPCI contracts (engineering, procurement, construction and installation) pay a subsea contractor a fixed price for a defined project, handing it the cost-overrun risk. Integrated or performance-based contracts bundle services and pay partly on outcomes such as days per well. And equipment sales plus aftermarket — rigs, blowout preventers, trees, turbines — book as orders, convert to revenue over months or years, then feed years of spare-parts and service income.

What no structure offers is midstream’s take-or-pay floor. Even a multi-year offshore contract can carry termination clauses, and short-cycle land work reprices within weeks. Pricing power therefore rests on utilisation: when most of the fleet is working, contractors lift prices; when idle equipment sits in the yard, price is the first thing given away.

Table 4. Oilfield services contract structures

Source: contract taxonomy from company disclosures, including Transocean (dayrate and backlog), TechnipFMC (inbound orders and backlog) and Baker Hughes (orders and RPO).

That completes the series’ comparison of how each link in the chain earns — and services is the only one whose revenue is someone else’s cost line.

Table 5. How the four links of the value chain earn

Source: revenue-model taxonomy across the value chain from company filings; the per-link mechanics are developed in each part of this series.

2. The activity cycle

2.1 Upstream investment

Service revenue starts as a line in an operator’s budget, so the first number to watch is what the industry plans to spend. The IEA expects upstream oil and gas investment to fall about 4% to just under $570bn in 2025, led by a sharp cut in US tight-oil (shale oil) spending (down by up to 10%), and cost-adjusted activity to fall around 8% — a gap that exists because tariffs and higher offshore dayrates raised unit costs. For 2026 the agency sees spending on oil supply falling for a third straight year, to under $500bn, while investment in natural gas projects rises more than 10% to about $330bn, a ten-year high, and upstream investment in Africa and Central and South America climbs more than 10%.

Two features of that pool shape the service industry more than its headline size. The mix is moving away from US land — toward gas, offshore and national oil companies — which favours the service companies with international and offshore reach over those tied to North American fracturing. And the maintenance floor (Section 1.2) holds over years, not quarters: operators can defer even replacement drilling for a year or two, so in a downturn service revenue falls much faster than production.

Table 6. Upstream spending signals

Source: IEA World Energy Investment 2025 (2025 level, activity, tight oil, NOC share); IEA World Energy Investment 2026, May 2026, pp. 6–7 and 26 (2026 projections); decline-replacement share per the IEA field-decline report, September 2025. 2026 figures are agency projections.

2.2 The rig count & frac spreads

The rig count is the oldest real-time gauge of service demand. It is published weekly for North America and monthly for the rest of the world, it responds to prices with a lag of months, and it leads the revenue of every company that sells into drilling.

The long record is a lesson in cyclicality. The US averaged 3,970 rigs in 1981 at the peak of the post-1970s drilling boom, and just 918 in 2000. The shale era rebuilt the count to 1,761–1,919 a year over 2011–2014, then the 2014–16 price collapse cut the average to 509 in 2016 — down 73% in two years. The pandemic took it to 433 in 2020, the lowest annual average in the series since at least 1950. The recovery peaked at 723 in 2022 and faded to 561 in 2025 as consolidated, capital-disciplined producers held output with fewer rigs (Section 2.3). On 11 September 2026 the count stood at 591 — 450 oil, 132 gas, 9 miscellaneous — up from 546 at the end of January and 539 a year earlier. Internationally, Baker Hughes counted 1,102 rigs in August 2026 (855 land, 247 offshore), a figure that excludes Russia, the Caspian, Iran, Sudan, Cuba, North Korea, Syria and onshore China.

Figure 3. US active drilling rigs, annual average, 2000–2025

Figure data: Table 7. Years are selected to show the 2008–09, 2014–16 and 2020 downturns; the full annual series is in the EIA source.

Table 7. US active drilling rigs, annual average, selected years

Source: U.S. EIA — U.S. crude oil and natural gas rotary rigs in operation (Baker Hughes data), annual averages, released 31 August 2026. Weekly 2026 counts and the oil/gas split per AOGR; the international count per the Baker Hughes international rig count (August 2026 report) and its exclusions per the Baker Hughes rig count FAQs.

The completion side has its own gauge. Primary Vision’s frac spread count — crews actually pumping — ended 2025 at 154, down 47 on a year earlier as operators trimmed completions, fell to a 145 low in February 2026 and recovered to 184 by 11 September 2026. Because fracturing is the largest single item in a shale well’s cost (Section 2.4), frac crews often say more about service revenue than rigs do.

2.3 The efficiency treadmill

The rig count’s long slide since 2014 is not only a story of lower spending. It is also a story of each rig doing far more work, and that is the most important structural force in North American services.

The Permian Basin shows it best. The average new horizontal well there had a 6,149 ft (1,874 m) lateral in 2015 and 10,867 ft (3,312 m) in 2025, up 77%. Super-laterals longer than 15,000 ft (4,570 m) — nearly three miles (4.6 km) of horizontal rock — were virtually nonexistent before 2020 and made up 15% of new completions in 2025. New horizontal completions have held around 6,000 a year since 2022, yet Permian output rose from 2.9 to 11.2 million barrels of oil equivalent a day (MMboe/d) between 2015 and 2025. Faster rigs, pad drilling, simultaneous fracturing of several wells and electric-powered frac fleets all push the same way: more feet, more stages and more production from fewer machines and crews.

For the service industry this cuts both ways. Technology and consumables sellers win — longer laterals need more drill-bit and steering technology, more proppant, more casing and more completion stages per well. Owners of commodity equipment lose — each efficiency gain means fewer rigs and frac fleets are needed for the same programme, which caps utilisation and with it pricing. The efficiency gains are real, but unless the contract captures them (Table 4), they flow to the operator.

Table 8. Permian well construction, 2015 vs 2025

Source: U.S. EIA — Longer wells boost Permian crude oil and natural gas production, 19 August 2026.

Figure 4. New Permian horizontal wells by lateral length, 2025

Source: U.S. EIA, 19 August 2026.

2.4 Anatomy of a shale well’s cost

The cost of a well is the service industry’s revenue seen from the other side of the invoice, and in shale it is dominated by completion rather than drilling. The most detailed public breakdown, prepared by IHS for the U.S. EIA on 2014–15 wells, found that completion made up 55–70% of total well cost in the main onshore plays, and that total well capital costs ran $4.9–8.3 million per well. Upstream costs in 2015 were 25–30% below 2012 levels — and every dollar an operator saves on a well is a dollar of service revenue that did not happen.

The component split in Figure 5 tells you which service lines hold the biggest share of wallet. Pressure pumping and its equipment is the largest single slice; proppant and completion fluids — sand, water and chemicals often bundled by the same pumper — add a quarter more. The rig itself, the item the headline rig count tracks, is only about a sixth. The shares are dated — laterals have since grown longer and proppant loadings heavier — so treat them as the shape of the wallet, not a current price list.

Figure 5. Where a shale well’s cost goes, by component

Figure data: Table 9.

Table 9. The anatomy of a shale well’s cost

Source: U.S. EIA — Trends in U.S. Oil and Natural Gas Upstream Costs (IHS for EIA, March 2016), Figure 2 (p. 3 of EIA’s summary) for the shares, which are for 2014–15 onshore wells and sum to 99% on rounding; pages IHS-5 and IHS-7 for the 55–70% completion share and $4.9–8.3 million well cost. The pricing-behaviour column is the author’s qualitative summary, not a measured value.

2.5 Utilisation, pricing & operating leverage

Service companies own expensive fleets whose costs barely move with activity — depreciation, maintenance, yards, engineering staff — and sell them into a market where price swings with utilisation. That combination is operating leverage, and it is why service earnings move far more than service revenue.

The market’s shorthand is incremental and decremental margins: the change in operating profit divided by the change in revenue. A worked example makes the mechanism concrete. The company below is a hypothetical illustration, not any real contractor: a pressure pumper with $1,000m of revenue, variable costs of 55% of revenue and $250m of fixed costs. Profit is measured as EBITDA — earnings before interest, tax, depreciation and amortisation, the operating-cash measure the sector reports and borrows against.

Table 10. Operating leverage in a hypothetical pressure pumper

Source: Derived · hypothetical illustration built on the stated assumptions (variable costs 55% of base-case revenue and scaling with volume, not price; fixed costs $250m); not the figures of any company.

The last column is the one that matters. A 20% volume drop costs the hypothetical pumper 45% of its EBITDA; add a 10% price cut — which saves no cost at all — and it loses 85%. That is what happened in real downturns. In 2016 Halliburton reported “substantial pricing pressure across all of our product service lines” in North America and cut about 40% of its workforce from early 2015; in 2025 Liberty Energy said pricing pressure and a slowdown in activity had “driven an acceleration in equipment cannibalization and attrition” — idle fleets stripped for parts rather than maintained. The upside is the mirror image: when idle equipment has been scrapped, a recovery lifts price as well as volume, and incremental margins run hot.

3. The three markets & the rules

3.1 Land, international & offshore

Everything in Section 2 moves at a different speed depending on where the work is: oilfield services is really three markets that share the same toolkits but not the same cycle, contracts or rules, and a company’s mix across them decides which cycle an investor is buying.

North America land is the short-cycle market: independent operators, shale wells that pay back in a year or two, rigs and frac crews contracted for weeks or months, and prices that reset quickly in both directions. International land and shallow water is dominated by national oil companies, long tenders, multi-year integrated contracts and local-content rules — slower to fall and slower to recover. Offshore and deepwater is the long-cycle market: project decisions years ahead of first oil, drillships on multi-year dayrate contracts and subsea systems booked as backlog.

International work is the least visible of the three and, for the largest companies, the most important. Its monthly count (Section 2.2) leaves out Russia, Iran, onshore China and several other markets, and because its tenders run for years, a contractor’s international revenue follows the customer’s programme rather than the latest oil price. The price of entry is local content (Section 3.3) and a few state customers’ payment terms; the reward is work that does not reset every quarter — ADNOC Drilling, working mainly for its state parent, grew revenue 22% in 2025 while the US rig count fell.

The split shows up in company exposure. In 2025 Halliburton earned 41% of its revenue in North America, while SLB and Weatherford earned about 21% and 20%. That is why Halliburton is the market’s preferred proxy for US fracturing and SLB for international and offshore spending — and why their shares behave differently in the same oil-price move (Section 5.3).

Figure 6. North America share of 2025 revenue, three diversified service companies

Source: Derived from 2025 results — Halliburton North America $9,066m of $22,184m; SLB $7,515m of $35,710m; Weatherford $983m of $4,918m.

Table 11. The three oilfield services markets

Source: market structure from company disclosures and the IEA spending mix in Table 6; revenue exposure per Figure 6. Cycle-speed bands are the author’s qualitative summary.

3.2 Offshore rigs & subsea backlog

Offshore is where the cycle is longest and the swings in rig economics are widest. At the top of the last supercycle, with oil near $100, a modern drillship could command about $600,000 a day. By 2020 the average was about $300,000, some contracts cleared below $200,000, and the count of rigs drilling in more than 400 ft (122 m) of water had fallen from 322 in 2014 to 221. The debt taken on to build that fleet broke the sector: Noble, Diamond Offshore and Valaris all filed for Chapter 11 in 2020.

The survivors emerged smaller, with less debt and scrapped older rigs, and the deepwater revival in Brazil, Guyana and West Africa did the rest. In the fourth quarter of 2025 Transocean’s fleet of 20 ultra-deepwater drillships and seven harsh-environment semisubmersibles averaged $461,300 a day of revenue per working rig, and full-year revenue efficiency was 96.5%, although contracts added in the months before its February 2026 report were priced at a weighted average of $417,000 — below that fourth-quarter average.

The equipment side of offshore books its work as backlog, which is why it looks steadier than drilling. TechnipFMC took $10.1bn of subsea orders in 2025 and ended the year with $16.6bn of backlog; Subsea7 ended with $13.8bn and Saipem with €31.5bn. The last two have agreed to merge (Section 4.2).

Table 12. Offshore market signals

Source: Energy Voice, 21 August 2020 (dayrates, rig counts, 2020 filings); Transocean 2025 results; TechnipFMC 2025 results. Dayrates are averages or reported levels, not quotes.

3.3 Regulation, local content, sanctions & trade

No regulator sets a service company’s price, but four kinds of rule shape where it can work and what it costs.

Safety and well-control regulation is the heaviest offshore. The 2010 Deepwater Horizon disaster, on a rig owned by Transocean, killed 11 workers, rewrote US offshore rules and cost Transocean $1.4bn in civil and criminal penalties agreed in 2013. Local-content rules decide who wins national oil company tenders: Saudi Aramco’s iktva programme reached 70% local content and targets 75% by 2030, which rewards service companies that manufacture and hire in-kingdom. Sanctions can close whole markets — Halliburton and Baker Hughes sold or put their Russian businesses up for sale soon after the February 2022 invasion, and SLB halted shipments of products and technology into Russia in July 2023. And trade policy moves input costs: the US doubled Section 232 tariffs on steel and aluminium to 50% in June 2025, raising the cost of imported casing and tubing that every well needs. Onshore, induced seismicity has made wastewater disposal — more than fracturing itself, per the USGS — the most regulated part of the completion chain in states such as Oklahoma and Texas.

Table 13. Who and what regulates oilfield services

Source: U.S. Department of Justice on the Transocean settlement, 3 January 2013; Aramco on iktva, 2026; company releases on Russia — Baker Hughes (1 August 2022), Halliburton (8 September 2022) and SLB (14 July 2023); White & Case on Section 232, June 2025; USGS on induced earthquakes.

4. The companies & the value chain

4.1 The largest oilfield service companies

Oilfield services has no reserves or capacity figure to rank by, so scale is read in revenue, fleet and backlog. At the top sit the “Big Three” diversified service companies — SLB, Baker Hughes and Halliburton — each present in almost every service line and every major basin. SLB is the largest at $35.7bn of 2025 revenue, with about four-fifths earned outside North America. Baker Hughes is really two businesses of similar size: oilfield services and equipment ($14.3bn) and an industrial and energy technology arm ($13.4bn) selling gas turbines, compressors and LNG equipment. Halliburton ($22.2bn) is built around North American pressure pumping, which anchors its Completion and Production division.

Below them the industry fragments into specialists: subsea and offshore contractors (Saipem, TechnipFMC, Subsea7), the pipe and equipment manufacturers (Tenaris, NOV), land drillers and pumpers (Patterson-UTI, Liberty Energy, Helmerich & Payne), offshore drillers (Transocean) and national champions such as ADNOC Drilling.

Table 14. Major oilfield service companies and their signature businesses

Sources: 2025 results releases — SLB, Baker Hughes, Halliburton, Saipem, Tenaris, TechnipFMC, NOV, Subsea7, Weatherford, ADNOC Drilling, Patterson-UTI, Liberty Energy, Transocean and Helmerich & Payne (fiscal year to 30 September 2025). HQ is the principal executive office; several companies are incorporated elsewhere. Listing gives the primary exchange and ticker; ADNOC Drilling is majority-owned by ADNOC, and Tenaris is controlled by the Techint group. Saipem reports in euros. No market-capitalisation figures are shown by design.

Figure 7. The largest oilfield service companies by 2025 revenue

Source: data in Table 14. Saipem (€15.5bn) reports in euros and is left out of the dollar ranking rather than converted; Baker Hughes includes its industrial and energy technology segment.

4.2 The consolidation wave

The service industry has spent a decade shrinking its supplier count, in two waves. The first was defensive: after the 2014 collapse, SLB bought Cameron for $14.8bn (2016) to add pressure-control and production equipment, while Halliburton’s planned takeover of Baker Hughes collapsed in 2016 under antitrust pressure, costing Halliburton a $3.5bn termination fee. Bankruptcy did the rest — Weatherford emerged from Chapter 11 in December 2019 having eliminated $6.2bn of debt, and the offshore drillers restructured in 2020 (Section 3.2).

The second wave, since 2023, follows the customers. Upstream consolidation left fewer, larger shale operators (Part 1, Section 7.4), and service companies merged to match them and to buy into steadier revenue: production chemicals and lift, offshore backlog, gas equipment.

Table 15. The oilfield services consolidation wave

Source: SLB on Cameron — announcement (26 August 2015) and completion; Halliburton 2016 Form 10-K on the terminated merger; Weatherford, 13 December 2019; Patterson-UTI and NexTier — merger announcement (SEC Exhibit 99.1, 15 June 2023) and completion (1 September 2023); Noble on Diamond Offshore, 4 September 2024; Helmerich & Payne on KCA Deutag — announcement (SEC Exhibit 99.1, 25 July 2024) and completion; SLB on ChampionX; Baker Hughes on Chart — announcement (29 July 2025) and completion; Saipem and Subsea7 merger agreement (24 July 2025) and Offshore Magazine on the EU review. Deal values are announced transaction values, not current valuations.

4.3 Company archetypes & structures

Service companies differ along two axes that decide how they behave through the cycle: how sensitive their revenue is to short-term activity, and how much capital their business ties up in fleets that must be kept working.

Seven archetypes cover the field. Diversified service majors (SLB, Halliburton, Baker Hughes, Weatherford) spread across service lines and regions, own technology and a large installed base, and ride the cycle with the least damage. Pressure pumpers and completion specialists (Liberty, ProPetro, Patterson-UTI’s completions arm) are the most activity-sensitive businesses in energy — short contracts, fast-wearing equipment, prices that reset in weeks. Land drillers (Helmerich & Payne, Patterson-UTI, Nabors) own heavy fleets on dayrates; the best rigs command premiums but idle rigs still cost money. Offshore drillers (Transocean, Valaris, Noble) own the most expensive assets in the sector and live and die by multi-year utilisation. Subsea and offshore contractors (TechnipFMC, Subsea7, Saipem) book long projects into backlog; their risk is execution, not the weekly rig count. Equipment and tubular manufacturers (NOV, Tenaris) sell products with order lead times and aftermarket tails, so revenue trails orders. And NOC-affiliated service companies (ADNOC Drilling, China Oilfield Services) work mostly for their parent under long contracts — low activity risk, high customer concentration.

Table 16. Oilfield services archetypes and their economics

Source: archetype taxonomy from company filings and the business-model split in The Commodity Investor, Part 11: How to Value Commodity Stocks, “The archetype is the unit of analysis”; examples are illustrative, not a recommendation.

Figure 8. Oilfield services archetypes by activity sensitivity and capital intensity

Source: activity sensitivity per Table 16; capital intensity is the author’s assessment, as Table 16 carries no capital-intensity column. All positions are qualitative scores, not measured values. The shaded zone marks the high-sensitivity, high-capital-intensity quadrant where the drillers sit.

4.4 Assets on the balance sheet

A service company’s balance sheet has no reserves, no depletion and no reserve life. What sits there instead tells you how it will survive the next downturn.

Four items carry most of the information. Fleet property, plant and equipment — rigs, frac fleets, vessels — is carried at cost less depreciation, and it is where downturns show up first as impairments: when a class of equipment stops earning its cost of capital, it is written down or scrapped. Backlog and remaining performance obligations measure contracted revenue not yet earned — $35.9bn at Baker Hughes (most of it in the technology segment) and $16.6bn at TechnipFMC at the end of 2025 — and should be read with the cancellation terms behind them. Receivables matter more than in most sectors, because a handful of national oil companies can be a large share of revenue and pay on their own timetable. And goodwill from a decade of acquisitions (Section 4.2) sits on the larger balance sheets, where it is tested every time the cycle turns. The practical order for reading a service filing: segment and geographic revenue mix, then backlog and book-to-bill, then capex versus depreciation (is the fleet being renewed or harvested?), then net debt against mid-cycle EBITDA.

5. Investing in oilfield services

5.1 Exposure vehicles

There is no commodity to hold and no futures contract on a dayrate. Every route into oilfield services is an equity or a fund, and the choice is really a choice of where on the capex cycle you want to sit.

The spectrum runs from pressure-pumping and land-drilling shares, the purest and highest-beta bet on North American activity, to the diversified majors, the lowest-volatility way to own the whole cycle; Table 17 places offshore drillers, subsea and equipment names in between. Oil-services ETFs hold baskets of them, removing single-name risk but not cyclicality — the VanEck Oil Services ETF (OIH) concentrates its weight in the largest names, while the SPDR S&P Oil & Gas Equipment & Services ETF (XES) spreads it more evenly across smaller pumpers and drillers.

The cyclicality caveat. Every sector in this series has one structural trap. In upstream it is paying for barrels that deplete; in midstream, fund tax drag; in downstream, buying peak-cycle margins. In services it is buying the rig count at the top. Service earnings peak after the commodity price does, because activity lags price by months, so a service stock can look cheapest on trailing earnings exactly when its customers have already started cutting budgets. The disciplined approach is to value on mid-cycle margins and a normalised activity level, not on the current print (worked in Section 5.2) — and to be most interested when fleets are being scrapped, not when they are sold out.

Table 17. Ways to take oilfield services exposure

Source: vehicle structures from issuer documentation — VanEck OIH, State Street SPDR XES and company filings; structural attributes only — no fees, yields or prices are quoted.

5.2 How to value & screen oilfield services

Producers are screened on reserves and cost, refiners on complexity; service companies have neither, so the screen is built from activity, pricing, backlog and balance-sheet resilience. The method follows the valuation guide’s treatment of services: deck the thing the business actually earns on — rig and completion counts, dayrates, backlog and book-to-bill — rather than the oil price, which enters only as the driver of that activity (see The Commodity Investor, Part 11, “The commodity price deck”).

A worked example of the trap — the hypothetical pumper from Table 10, not any real company. Suppose the market values it at $1,450m of enterprise value (EV), equity plus net debt. On peak-year EBITDA of $290m it screens at 5.0×, near the bottom of the valuation guide’s mid-cycle band for services. On mid-cycle EBITDA — what it earns averaged over a normal cycle, here the $200m average of Table 10’s three volume cases — the same price is 7.3×. If the downturn then arrives with a price cut, EBITDA falls to $30m and the same EV is 48× it: the multiple that looked cheapest rested on earnings about to disappear.

The screen in Table 18 starts from the reading order in Section 4.4 and adds the tests that need a full cycle of history — decremental margins (Table 10), return on invested capital through the cycle rather than at the peak, fleet quality and utilisation, and customer concentration. You can screen the oilfield services universe on Metal Pilot and, because a service company’s revenue is its customers’ capex, cross-check the producers whose drilling budgets pay for it at the same time.

Table 18. Screening metrics for oilfield services companies

Source: metric taxonomy from service-company filings and the services archetype in The Commodity Investor, Part 11: How to Value Commodity Stocks, “The twelve archetypes and the method that fits each”; “healthy” bands are the author’s framing, not published standards.

5.3 Macro regimes, rates & correlations

Oilfield services has the most lagged macro profile in the value chain. Upstream moves with the oil price the same day; services move with what operators decide to do about it, a quarter or more later, and then amplify it.

The oil price matters through the budget, not the barrel. A price spike that operators expect to last lifts budgets and service pricing with a lag; a spike they distrust — or that investors insist be paid out as dividends rather than drilled — may barely move activity. That is why the 2022 price surge produced a much smaller rig recovery (723 rigs on average) than 2011–14 (1,761–1,919), although WTI averaged about $95 a barrel in both periods. Interest rates matter mostly through leverage: the capital-intensive drillers carry the most debt, and in 2020 it was debt, not a lack of rigs, that forced the offshore restructurings. Geography can matter as much as price. A live case, still unresolved at this guide’s 15 September 2026 data date: the 2026 Gulf disruption has so far cut regional service activity while pushing prices up and North American activity with them (Section 6).

The worked episode — services amplify the capex cycle, in both directions. Two concluded windows show it. From 2014 to 2016, the monthly average price of West Texas Intermediate (WTI), the US crude benchmark, fell 71%, from $105.79/bbl (June 2014) to $30.32 (February 2016), and the US rig count fell 73% (1,861 to 509, annual averages). Revenue fell almost as far: SLB’s by 43% ($48.6bn to $27.8bn) and Halliburton’s by 52% ($32.9bn to $15.9bn). The shares, looking ahead to recovery, fell less — SLB about 47% from its June 2014 closing high to its 2016 low, Halliburton about 61%. From 2020 to 2022 the rebound ran the other way: WTI rose from a $16.55 monthly average in April 2020 to $114.84 in June 2022, and Halliburton’s share price rose about 850% from its 2020 low to its 2022 high, against about 380% for internationally weighted SLB. The signature is clear: the more a company depends on North American short-cycle activity, the harder it swings.

Table 19. Oilfield services across macro regimes

Source: WTI monthly and annual averages per FRED (U.S. EIA data), monthly and annual; rig counts per U.S. EIA; revenue per the SLB 2016 Annual Report, Halliburton 2014 results and 2016 Form 10-K; share-price moves are percentage changes over concluded windows in the dividend-adjusted closing-price series published by Macrotrends for SLB and for Halliburton — a third-party data site, used because no free official source publishes dividend-adjusted price history; 2026 per SLB Q2 2026 results and weekly Baker Hughes counts via AOGR, still unresolved at the data date. Historical, not predictive. Cross-commodity regime behaviour is covered in the macro regime guide.

5.4 Value drivers & cycles

Seven forces move service economics, and the oil price is not one of them — it works through the first, upstream capex.

Upstream capex sets the size of the pool. Utilisation decides pricing — every idle fleet scrapped in a downturn is future pricing power. Efficiency is two-way: it expands the work per well that technology sellers can bill but shrinks the number of rigs and crews needed (Section 2.3). Customer consolidation reduces the number of buyers and increases their bargaining power, as the shale mergers catalogued in Part 1 did. The spending mix — gas over oil, offshore and NOCs over US land — moves share between archetypes. Adjacent markets — gas turbines, LNG equipment, carbon storage, geothermal and data-centre power — are now large enough to change what some service companies are: Baker Hughes booked a record $14.9bn of industrial and energy technology orders in 2025. And cost inflation and tariffs cut both ways: they lift list prices but squeeze anyone on a fixed-price contract.

The last cycle is instructive. The 2014–16 bust forced a decade of scrapping, bankruptcy and mergers; the survivors met the 2021–23 recovery with fewer fleets and regained pricing, then watched a disciplined, consolidated customer base hold activity flat as efficiency kept improving. The service cycle is still real, but its peaks are now capped by customer discipline — which is exactly why the largest companies are looking for revenue beyond the wellhead (Section 6).

Table 20. Oilfield services value drivers

Source: drivers derived from the episodes and data cited in Sections 2–3 and 5.3; the adjacent-market figure per Baker Hughes 2025 results.

5.5 Risks, controversies & ESG

Oilfield services carries all of upstream’s cycle risk with less of its upside, plus risks of its own.

The downturn is the defining risk. Activity and pricing fall together, operating leverage turns decremental, and leveraged fleet owners can go from sold out to restructuring within two years — as Weatherford (2019) and the offshore drillers (2020) did.

Efficiency deflation is the structural threat. Every gain in feet per day or stages per crew reduces the equipment the market needs. Unless a service company owns the technology that delivers the gain, it pays for it in utilisation and price.

Customer power and discipline cap the upside. A consolidated, dividend-focused shale industry is a tougher customer than the growth-at-any-price operators of 2011–14, and national oil companies can reprice or pause programmes by decree.

Geopolitics, sanctions and concentration are now first-order risks. Sanctions have already closed one market to the Big Three (Section 3.3), the 2026 Gulf disruption, unresolved at the data date, has halted programmes across a region (Section 6), and heavy exposure to a few national customers brings receivable and contract risk with it.

Safety and the energy-transition controversy complete the list. A well-control failure can be catastrophic for the contractor involved — Deepwater Horizon (Section 3.3) is the reference case. And the long-run question is two-sided: the bear case is that peak oil demand shrinks drilling for good; the bull case is that shale’s decline — output would fall more than 35% within a year without new investment — and the ~90% replacement share of upstream spend (Section 1.2) keep wells being drilled for decades, while the same subsurface and equipment skills sell into gas, carbon storage, geothermal and power. Both positions rest on assumptions about demand that no one can verify.

Table 21. Oilfield services risk register

Source: risks derived from the concluded episodes cited above — the 2014–16 bust, the Weatherford and offshore-driller restructurings, the 2022 Russia exits and Deepwater Horizon; the 2026 Gulf disruption, still unresolved at the data date, is not used as evidence. Likelihood and impact are the author’s qualitative assessment, not a modelled probability.

Figure 9. Oilfield services risk map

Source: data in Table 21. Each point prints its likelihood × impact score; the shaded region is the high-likelihood, high-impact quadrant. Ratings are the author’s assessment, not disclosed figures.

6. Future outlook & catalysts

Four forces will decide the next oilfield services cycle, and they no longer all point the same way.

The spending mix is shifting away from US oil. The IEA expects oil supply investment to fall for a third year in 2026 while gas investment reaches a ten-year high and upstream spending in Africa and Latin America rises more than 10%. That favours offshore contractors, gas-equipment makers and internationally weighted service majors over North American land specialists — although US activity has shown in 2026 that it can still turn quickly when prices move (Section 2.2).

The Middle East after 2026 is the largest open question. The region’s national oil companies are the service industry’s biggest single customer group, and the 2026 Gulf disruption — disrupted crude and product flows through the Strait of Hormuz and shut-in regional output through the second quarter, per the U.S. EIA — cut activity there in the first half of the year. SLB expected Middle East rig activity to rise at the start of the year; by the second quarter its Middle East revenue was down 13% on the first. How quickly programmes restart — and whether producers outside the Gulf drill more to diversify supply — will set international service revenue for 2027.

Diversification beyond the wellhead is now strategy, not a sideline. The adjacent markets in Section 5.4 now carry forward targets: SLB expects its data-centre business to pass a $1bn annualised run rate by the end of 2026, and Liberty Energy plans 3 GW of distributed power by 2029. Investors will increasingly have to value some “oilfield service” companies as industrial equipment businesses.

Consolidation will keep going. Saipem–Subsea7 is still pending: the companies target completion in the second half of 2026, but the European Commission suspended its in-depth review on 25 August 2026. The logic that drove SLB–ChampionX — buying steady production-linked revenue — applies across the mid-sized service tier.

Table 22. What to watch

Source: IEA World Energy Investment 2026, pp. 6–7 and 26; SLB Q4 2025 and Q2 2026 results; Liberty Energy; Saipem and Offshore Magazine on Saipem7. Timings are company and agency expectations and slip routinely.

7. Summary

Oilfield services is the contractor and equipment layer behind every well — seismic, drilling, completion, production services, subsea and equipment — and it earns neither a commodity price nor a fee, but a share of its customers’ capital budgets, priced by how tightly its fleets are used. That single fact explains the sector’s behaviour: revenue follows upstream capex with a lag, and earnings amplify it through operating leverage in both directions.

The demand signal is large but shifting. Upstream investment runs at just under $570bn (2025), nearly 90% of it simply replacing declining output, and Middle Eastern and Asian national oil companies now fund ~40% of it. The rig count tells the cyclical story best — 1,861 US rigs in 2014, 509 in 2016, 433 in 2020 and 591 in September 2026 — while the efficiency treadmill, with Permian laterals up 77% in a decade, means each rig and frac crew does far more work than before. Completion, not drilling, takes the largest share of a shale well’s cost. It is really three markets — short-cycle North American land, tender-driven international work and long-cycle offshore — each with its own contracts and rules, from local content to sanctions and steel tariffs.

The industry is led by SLB, Baker Hughes and Halliburton, surrounded by specialists whose economics differ sharply: pressure pumpers and land drillers live on the short cycle, offshore drillers on long-cycle utilisation, subsea and equipment companies on backlog. A decade of consolidation — from Cameron to ChampionX and Chart, with Saipem–Subsea7 still pending — has produced fewer, bigger suppliers facing fewer, bigger customers.

For investors, the concluded record is unambiguous: from 2014 to 2016 US rigs fell 73% and Halliburton’s revenue 52%, and from the 2020 low to the 2022 high Halliburton’s shares rose about 850%. The disciplined approach is to value service companies on mid-cycle margins, backlog and returns through the cycle, to be wary when trailing earnings look cheapest, and to watch where the spending goes — gas, offshore, the Middle East and markets beyond the wellhead. To see every driller, service and equipment company in one screen, explore Metal Pilot’s oilfield services stock screener.

Next in the series → Part 4 completes the value chain. Start again from the wellhead with Part 1: Upstream, or see where the rigs actually work in the companion guide to world oil & gas basins.

8. Vocabulary

Table 23. Oilfield services terminology

Source: definitions compiled from Baker Hughes rig count FAQs, the U.S. EIA glossary, company filings cited in this report and standard industry usage.

9. Sources, methodology & disclaimer

9.1 Sources, methodology & data vintage

Agencies and data providers. IEA World Energy Investment 2025 and executive summary; IEA World Energy Investment 2026; IEA, The Implications of Oil and Gas Field Decline Rates (September 2025); U.S. EIA rotary rigs in operation; U.S. EIA — Longer wells boost Permian production; U.S. EIA — Trends in U.S. Oil and Natural Gas Upstream Costs; U.S. EIA on Middle East disruptions, 2Q 2026; FRED WTI monthly and annual series; U.S. Department of Justice on the Transocean settlement; Baker Hughes rig count via AOGR and the Baker Hughes international rig count; Primary Vision frac spread count via AOGR and its 2025 series; USGS on induced earthquakes.

Company sources. 2025 results and filings of SLB, Baker Hughes, Halliburton, Saipem, Tenaris, TechnipFMC, NOV, Subsea7, Weatherford, ADNOC Drilling, Patterson-UTI, Liberty Energy, Transocean and Helmerich & Payne, linked beneath Table 14; SLB’s second-quarter 2026 results; the SLB 2016 Annual Report; Halliburton’s 2014 results and 2016 Form 10-K; the Baker Hughes, Halliburton and SLB Russia releases linked beneath Table 13; deal announcements and completions as linked beneath Table 15.

Industry and press. Energy Voice on the 2020 offshore restructurings; Offshore Magazine on the EU review of Saipem7; Aramco on iktva; White & Case on Section 232; Macrotrends, a third-party data site, for dividend-adjusted share-price history, which no free official source publishes; the VanEck OIH and State Street SPDR XES issuer pages for ETF structure.

Methodology. Rig counts are Baker Hughes data: annual averages from the EIA series, weekly and monthly readings as published, with the international count excluding Russia, the Caspian, Iran, Sudan, Cuba, North Korea, Syria and onshore China. Company revenue is as reported for fiscal 2025 in each company’s reporting currency (Helmerich & Payne’s fiscal year ends in September); revenue is used to indicate scale, not to rank businesses of different mix like for like, and Baker Hughes includes its non-oilfield technology segment. The shale well-cost breakdown is from 2014–15 well data and is shown as a dated shape of spend, not a current cost. Equity moves are percentage changes in dividend-adjusted closing prices over concluded windows and are settled history; oil-price comparisons use monthly WTI averages, so they do not match intraday extremes. Investment figures for 2026 are IEA projections and are labelled as such. The operating-leverage example (Table 10) and its mid-cycle valuation extension (Section 5.2) are hypothetical illustrations. Archetype positions and risk ratings are qualitative author assessments. No market capitalisations, share prices or enterprise values appear anywhere in this report, by design; deal values in Table 15 are announced transaction values.

Data as of 15 September 2026. Intended update cadence: annually, after fourth-quarter results and the IEA World Energy Investment report.

9.2 Disclaimer & disclosure

This report is for informational purposes only and is not investment advice, a recommendation, or an offer to buy or sell any security. Oilfield service companies carry cyclical, operating-leverage, balance-sheet, contract, geopolitical and safety risks, and activity, revenue and backlog figures are estimates as of the stated dates that change with each reporting cycle. Historical activity and equity behaviour is presented as settled history; past performance is not indicative of future results, and the regime patterns described here are sample-dependent and can break down. Readers should do their own research and consider consulting a licensed financial adviser before acting. This report was prepared with the assistance of AI, consistent with the ai = true flag in its front matter; figures were sourced from the references above and reviewed, but readers should verify any figure they intend to rely on. The author holds no position in any company named in this report.