EXPRO GROUP HOLDINGS N.V. (XPRO)
SIC breadcrumb: Mining > SIC Major Group 13 > SIC 1389 Oil & Gas Field Services, NEC
SEC company page: https://www.sec.gov/edgar/browse/?CIK=1575828. Latest filing source: 0001437749-26-004727.
Selected Fundamentals
| Metric | Value | Unit | FY | Filed |
|---|---|---|---|---|
| Revenue | 1,607,095,000 | USD | 2025 | 2026-02-19 |
| Net income | 51,686,000 | USD | 2025 | 2026-02-19 |
| Assets | 2,259,435,000 | USD | 2025 | 2026-02-19 |
Financials
Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-19. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001575828.json. Derived margins, ratios, and free cash flow are computed from the extracted annual SEC facts.
| Metric | 2012 | 2013 | 2014 | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 |
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Revenue | 487,531,000 | 454,795,000 | 522,493,000 | 810,064,000 | 675,026,000 | 825,762,000 | 1,279,418,000 | 1,512,764,000 | 1,712,802,000 | 1,607,095,000 | ||||
| Net income | -135,338,000 | -159,457,000 | -90,733,000 | -64,761,000 | -307,045,000 | -131,891,000 | -20,145,000 | -23,360,000 | 51,918,000 | 51,686,000 | ||||
| Operating income | -163,362,000 | -214,742,000 | -92,881,000 | -72,463,000 | -322,286,000 | -127,568,000 | 2,463,000 | 10,803,000 | 94,166,000 | 81,138,000 | ||||
| Diluted EPS | 2.04 | 1.85 | 1.03 | 0.50 | -0.77 | -0.72 | -0.18 | -0.21 | 0.45 | 0.45 | ||||
| Operating cash flow | -10,831,000 | 24,774,000 | -32,644,000 | 81,209,000 | 70,391,000 | 16,144,000 | 80,169,000 | 138,309,000 | 169,479,000 | 210,172,000 | ||||
| Capital expenditures | 99,723,000 | 42,127,000 | 21,905,000 | 104,062,000 | 112,387,000 | 81,511,000 | 81,904,000 | 122,110,000 | 143,576,000 | 112,387,000 | ||||
| Share buybacks | 4,497,000 | 3,264,000 | 0.00 | 0.00 | 0.00 | 0.00 | 12,996,000 | 20,024,000 | 14,155,000 | 40,088,000 | ||||
| Assets | 1,588,061,000 | 1,261,769,000 | 1,193,929,000 | 994,165,000 | 1,039,751,000 | 1,854,638,000 | 1,937,152,000 | 2,013,007,000 | 2,333,541,000 | 2,259,435,000 | ||||
| Liabilities | 276,742,000 | 145,868,000 | 159,157,000 | 183,871,000 | 427,767,000 | 557,067,000 | 651,257,000 | 717,134,000 | 842,057,000 | 725,312,000 | ||||
| Stockholders' equity | 1,311,319,000 | 1,115,901,000 | 992,832,000 | 924,550,000 | 611,984,000 | 1,297,571,000 | 1,285,895,000 | 1,295,873,000 | 1,491,484,000 | 1,534,123,000 | ||||
| Cash and cash equivalents | 319,526,000 | 213,015,000 | 186,212,000 | 195,383,000 | 116,924,000 | 235,390,000 | 214,788,000 | 151,741,000 | 183,036,000 | 196,093,000 | ||||
| Free cash flow | -52,958,000 | 2,869,000 | -22,853,000 | -41,996,000 | -65,367,000 | -1,735,000 | 16,199,000 | 25,903,000 | 97,785,000 |
Ratios
| Metric | 2012 | 2013 | 2014 | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 |
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Net margin | -27.76% | -35.06% | -17.37% | -7.99% | -45.49% | -15.97% | -1.57% | -1.54% | 3.03% | 3.22% | ||||
| Operating margin | -33.51% | -47.22% | -17.78% | -8.95% | -47.74% | -15.45% | 0.19% | 0.71% | 5.50% | 5.05% | ||||
| Return on equity | -10.32% | -14.29% | -9.14% | -7.00% | -50.17% | -10.16% | -1.57% | -1.80% | 3.48% | 3.37% | ||||
| Return on assets | -8.52% | -12.64% | -7.60% | -6.51% | -29.53% | -7.11% | -1.04% | -1.16% | 2.22% | 2.29% | ||||
| Liabilities / equity | 0.21 | 0.13 | 0.16 | 0.20 | 0.70 | 0.43 | 0.51 | 0.55 | 0.56 | 0.47 | ||||
| Current ratio | 6.44 | 4.33 | 3.79 | 3.62 | 1.91 | 2.31 | 1.98 | 1.74 | 1.99 | 2.16 |
Financial Charts
Quarterly
Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-05. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001575828.json.
| Quarter | End Date | Revenue | Net Income | Diluted EPS | Method |
|---|---|---|---|---|---|
| 2016-Q2 | 2016-06-30 | -0.20 | reported discrete quarter | ||
| 2016-Q3 | 2016-09-30 | -0.21 | reported discrete quarter | ||
| 2017-Q1 | 2017-03-31 | -0.12 | reported discrete quarter | ||
| 2017-Q3 | 2017-09-30 | 0.01 | reported discrete quarter | ||
| 2018-Q3 | 2018-09-30 | -0.03 | reported discrete quarter | ||
| 2023-Q2 | 2023-03-31 | -6,351,000 | reported discrete quarter | ||
| 2023-Q2 | 2023-06-30 | 396,917,000 | 0.08 | reported discrete quarter | |
| 2023-Q3 | 2023-06-30 | 9,295,000 | reported discrete quarter | ||
| 2023-Q3 | 2023-09-30 | 369,818,000 | reported discrete quarter | ||
| 2023-Q4 | 2023-12-31 | 406,750,000 | -12,418,000 | derived Q4 = FY annual - nine-month YTD | |
| 2024-Q1 | 2024-03-31 | 383,489,000 | -2,677,000 | reported discrete quarter | |
| 2024-Q2 | 2024-03-31 | -2,677,000 | reported discrete quarter | ||
| 2024-Q2 | 2024-06-30 | 469,642,000 | 0.13 | reported discrete quarter | |
| 2024-Q3 | 2024-06-30 | 15,286,000 | reported discrete quarter | ||
| 2024-Q3 | 2024-09-30 | 422,828,000 | 0.14 | reported discrete quarter | |
| 2024-Q4 | 2024-12-31 | 436,843,000 | 23,034,000 | derived Q4 = FY annual - nine-month YTD | |
| 2025-Q1 | 2025-03-31 | 390,872,000 | 13,948,000 | 0.12 | reported discrete quarter |
| 2025-Q2 | 2025-03-31 | 13,948,000 | reported discrete quarter | ||
| 2025-Q2 | 2025-06-30 | 422,740,000 | 0.16 | reported discrete quarter | |
| 2025-Q3 | 2025-06-30 | 18,003,000 | reported discrete quarter | ||
| 2025-Q3 | 2025-09-30 | 411,356,000 | 0.12 | reported discrete quarter | |
| 2025-Q4 | 2025-12-31 | 382,127,000 | 5,772,000 | derived Q4 = FY annual - nine-month YTD | |
| 2026-Q1 | 2026-03-31 | 367,573,000 | -1,034,000 | -0.01 | reported discrete quarter |
Quarterly Charts
Macro Cross-References
- CPIAUCSL - Consumer Price Index for All Urban Consumers: All Items in U.S. City Average
- UNRATE - Unemployment Rate
- FEDFUNDS - Federal Funds Effective Rate
- CES0500000003 - Average Hourly Earnings of All Employees, Total Private
- DFEDTARU - Federal Funds Target Range - Upper Limit
- DFEDTARL - Federal Funds Target Range - Lower Limit
- DGS3MO - Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity
- DGS2 - Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity
- DGS10 - Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity
- DGS30 - Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity
- T10Y2Y - 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity
- CPILFESL - Consumer Price Index for All Urban Consumers: All Items Less Food and Energy
- CPIUFDSL - Consumer Price Index for All Urban Consumers: Food
- CPIENGSL - Consumer Price Index for All Urban Consumers: Energy
- CUSR0000SAH1 - Consumer Price Index for All Urban Consumers: Shelter
- PCEPI - Personal Consumption Expenditures: Chain-type Price Index
- PCEPILFE - Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index
- PPIACO - Producer Price Index by Commodity: All Commodities
- T10YIE - 10-Year Breakeven Inflation Rate
- U6RATE - Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons
- PAYEMS - All Employees, Total Nonfarm
- CIVPART - Labor Force Participation Rate
- EMRATIO - Employment-Population Ratio
- UNEMPLOY - Unemployed
- CE16OV - Employment Level
- ICSA - Initial Claims
- JTSJOL - Job Openings: Total Nonfarm
- JTSQUR - Quits: Total Nonfarm
- GDPC1 - Real Gross Domestic Product
- A191RL1Q225SBEA - Real Gross Domestic Product: Percent Change from Preceding Period
- INDPRO - Industrial Production: Total Index
- TCU - Capacity Utilization: Total Index
- HOUST - New Privately-Owned Housing Units Started: Total Units
- PERMIT - New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units
- RSAFS - Advance Retail Sales: Retail Trade
- PCE - Personal Consumption Expenditures
- DSPIC96 - Real Disposable Personal Income
- PSAVERT - Personal Saving Rate
- M2SL - M2
- BOPGSTB - U.S. International Trade in Goods and Services: Balance
- MSPUS - Median Sales Price of Houses Sold for the United States
- HSN1F - New One Family Houses Sold: United States
- RHORUSQ156N - Homeownership Rate in the United States
- TTLCONS - Total Construction Spending: Total Construction in the United States
- RRVRUSQ156N - Rental Vacancy Rate in the United States
- TOTALSL - Total Consumer Credit Owned and Securitized
- REVOLSL - Revolving Consumer Credit Owned and Securitized
- DRCCLACBS - Delinquency Rate on Credit Card Loans, All Commercial Banks
- GDP - Gross Domestic Product
- GPDI - Gross Private Domestic Investment
- GCE - Government Consumption Expenditures and Gross Investment
- PCEC - Personal Consumption Expenditures
- NETEXP - Net Exports of Goods and Services
- GFDEBTN - Federal Debt: Total Public Debt
- GFDEGDQ188S - Federal Debt: Total Public Debt as Percent of Gross Domestic Product
- FYFSD - Federal Surplus or Deficit
- FGRECPT - Federal Government Current Receipts
- FGEXPND - Federal Government: Current Expenditures
- MANEMP - All Employees, Manufacturing
- USCONS - All Employees, Construction
- USTRADE - All Employees, Retail Trade
- USFIRE - All Employees, Financial Activities
- USGOVT - All Employees, Government
- AWHAETP - Average Weekly Hours of All Employees, Total Private
- DGORDER - Manufacturers' New Orders: Durable Goods
- NEWORDER - Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft
- BUSINV - Total Business Inventories
- EXPGS - Exports of Goods and Services
- IMPGS - Imports of Goods and Services
- IR - Import Price Index (End Use): All Commodities
- PPIFIS - Producer Price Index by Commodity: Final Demand
Latest quarter (10-Q)
Latest 10-Q source: 0001437749-26-014876.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited condensed consolidated financial statements and the related notes thereto included elsewhere in this Form 10-Q and the audited consolidated financial statements and notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report. This section contains forward-looking statements that are based on management’s current expectations, estimates and projections about our business and operations, and involve risks and uncertainties. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements because of various factors, including those described in the sections titled “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” of this Form 10-Q and our Annual Report. Overview of Business Working for clients across the entire well life cycle, we are a leading provider of energy services, offering cost-effective, innovative solutions and what we consider to be best-in-class safety and service quality. With roots dating to 1938, we have approximately 7,000 employees and provide services and solutions to leading exploration and production companies in both onshore and offshore environments in over 60 countries. Our extensive portfolio of capabilities spans well construction, well flow management, subsea well access, and well intervention and integrity solutions. Well Construction • Our well construction products and services support customers’ new wellbore drilling, wellbore completion and recompletion, and wellbore plug and abandonment requirements. We offer advanced technology solutions in tubular running services, tubular products, cementing, drilling and wellbore cleanup. With a focus on innovation, we are continuing to advance the way wells are constructed by optimizing process efficiency on the rig floor, developing new methods to handle and install tubulars, and mitigating well integrity risks. We believe we are a market leader in deepwater tubular running services and solutions. In recent years, we have added a range of lower-risk, open water cementing solutions. We also offer a range of performance drilling tools designed to mitigate risk and optimize drilling efficiency, including proprietary downhole circulation tools and hydraulic pipe recovery systems. Well Management Our well management offerings consist of well flow management, subsea well access and well intervention and integrity services: • Well flow management: We gather valuable well and reservoir data, with a particular focus on well-site safety and environmental impact. We provide global, comprehensive well flow management systems for the safe production, measurement and sampling of hydrocarbons from a well, including well testing during the exploration and appraisal phase of a new field; flowback and clean-up of a new well prior to production; and in-line testing of a well during its production life. We also provide early production facilities to accelerate production; production enhancement packages to enhance reservoir recovery rates through the realization of production that was previously locked within the reservoir; flare reduction and other emissions management solutions; and metering and other well surveillance technologies to monitor and measure flow and other characteristics of wells. • Subsea well access: With nearly 50 years of experience providing a wide range of fit-for-purpose subsea well access solutions, our technology aims to provide safe well access and optimized production throughout the lifecycle of the well. We provide what we believe to be the most reliable, efficient and cost-effective subsea well access systems for exploration and appraisal, development, intervention and abandonment, including an extensive portfolio of standard and bespoke Subsea Test Tree Assemblies (“SSTA”) and a range motion-compensating and other surface handling equipment. We also provide services and solutions through a rig-deployed Intervention Riser System (“IRS”) utilizing rigs owned by a third party and have capabilities for vessel-deployed services. In addition, we provide systems integration and project management services. 24 Table of Contents • Well intervention and integrity: We provide well intervention solutions to acquire and interpret well data, maintain and restore well bore integrity and improve production. In addition to our extensive fleet of mechanical and cased hole wireline units, we have recently introduced and acquired a number of cost-effective, innovative well intervention services, including CoilHose™, a lightweight, small-footprint solution for wellbore lifting, cleaning and chemical treatments; Octopoda™, for fluid treatments in wellbore annuli; Galea™, an autonomous well intervention solution; and expandable casing patches designed to repair damaged production casing or isolate existing perforations prior to refracturing a well (a so called “patch and perf”). We also possess several other distinct technical capabilities, including fiber optic-enabled data acquisition and interpretation services, non-intrusive metering technologies and wireless telemetry systems for reservoir monitoring. We operate a global business and have a diverse and relatively stable customer base that is comprised of national oil companies (“NOC”), international oil companies (“IOC”), independent exploration and production companies (“Independents”) and service partners. We have strong relationships with a number of the world’s largest NOCs and IOCs, some of which have been our customers for decades. We are dedicated to safely and sustainably delivering maximum value to our customers. We organize and manage our operations on a geographical basis. Our reporting structure and the key financial information used by our management team is organized around our four operating segments: (i) North and Latin America (“NLA”), (ii) Europe and Sub-Saharan Africa (“ESSA”), (iii) Middle East and North Africa (“MENA”) and (iv) Asia-Pacific (“APAC”). How We Generate Our Revenue Our revenue is derived primarily from providing services in well construction, well flow management, subsea well access and well intervention and integrity to operators globally. Our revenue includes equipment service charges, personnel charges, run charges and consumables. Some of our contracts allow us to charge for additional deliverables, such as the costs of mobilization of people and equipment and customer specific engineering costs associated with a project. We also procure products and services on behalf of our customers that are provided by third parties for which we are reimbursed with a mark-up or in connection with an integrated services contract. We also design, manufacture and sell equipment, which is typically done in connection with a related operations and maintenance arrangement with a particular customer. In addition, we also generate revenue from the sale of certain well construction products. Commodity Prices and Market Conditions Commodity Prices According to the Energy Information Administration (“EIA”), average daily oil demand declined by 1.1 million b/d in the first quarter of 2026 compared with the previous quarter. Demand was also modestly lower – by 0.4 million b/d – compared to the full-year 2025 average, although, consumption remained higher than levels recorded in the first quarter of 2025. Global liquids demand is expected to grow by 0.6 million b/d in 2026 compared with 2025, with a further increase of 1.6 million b/d anticipated in 2027. Brent crude prices rose sharply during the quarter following the onset of military action in the Middle East at the end of February. The resultant effective closure of the Strait of Hormuz, a critical petroleum export route, and the subsequent production shut-ins drove a rapid tightening of supply. Brent averaged $67/bbl in January before rising to an average of $103/bbl in March, with daily prices spiking near $128/bbl on April 2. This volatility was further evidenced following the April 7 ceasefire announcement, when Brent price dropped back below $100/bbl. The U.S. subsequently announced a blockade of Iranian ports and Brent prices have increased back to approximately $100/bbl and remain volatile. Market Conditions Prior to the outbreak of conflict in the Middle East, the global oil market in 2026 had been expected to remain oversupplied, with inventories building and prices declining steadily. The onset of hostilities has rapidly altered these dynamics. Significant volumes of production across the region have been shut-in, creating near-term market tightness and heightened price volatility. Although a two-week ceasefire was announced on April 7, disruptions to global oil markets are expected to persist through 2026. The resumption of production and the clearance of backlogs through the Strait of Hormuz will take time, and ongoing geopolitical uncertainty continues to support elevated prices. Against this backdrop, hydrocarbon demand continues to grow in the near to medium term, while energy security remains a key strategic priority for governments and operators, supporting continued investment across the industry. Over the longer term, geopolitical disruption events such as the current Middle East crisis could result in structural shifts towards greater energy independence and diversification of supply, although such transitions are expected to evolve gradually given the continued central role of hydrocarbons in the global energy system. 25 Table of Contents There are a number of market factors that have had, and may continue to have, an effect on our business, including: • The market for energy services and our business are substantially dependent on the price of oil and, to a lesser extent, the regional price of gas, which are both driven by market supply and demand. Changes in oil and gas prices impact customer willingness to spend on exploration and appraisal, development, production, and abandonment activities. The extent of the impact of a change in oil and gas prices on these activities varies extensively between geographic regions, types of customers, types of activities and the financial returns of individual projects. • Activity related to gas and liquified natural gas (“LNG”) production (and associated asset development) continues to grow as demand outpaces supply and long-term energy security remains an over-increasing priority. More broadly, the net-zero targets of many nations requires a transition to lower-carbon sources such as natural gas and LNG, resulting in increased investment in the production of the fuels. • International and offshore activity drives the majority growth throughout 2026. We also see an increased demand for services related to brownfield and production enhancement and infield development programs as operators strive to maximize their previous investments and maintain production with a lower carbon footprint. In addition, we have seen an increase in demand for production optimization technologies, especially in support of gas and LNG developments. • Expro remains selective in pursuing low-carbon opportunities that support operators’ drive for increased sustainability in their hydrocarbon production, including early-stage carbon capture and storage and flare reduction. While the broader trend toward decarbonization continues, our customers focus remains on energy security and returns driven by their core hydrocarbon businesses. Outlook The EIA states global liquids demand in 2026 is expected to average 104.6 million b/d, representing growth of 0.6 million b/d year-on-year. This is a downward revision from earlier expectations of 1.2 [Excerpt truncated for page length; source filing is linked above.]
Latest 10-K MD&A
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and the related notes thereto included in Part II, Item 8. “Financial Statements and Supplementary Data” included in this Form 10-K.
This section contains forward-looking statements that are based on management’s current expectations, estimates and projections about our business and operations, and involve risks and uncertainties. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements because of various factors, including those described in the sections titled “Cautionary Note Regarding Forward-Looking Statements,” Part I, Item 1A. “Risk Factors” and elsewhere in this Form 10-K.
This section of this Form 10-K generally discusses 2025 and 2024 items and year-to-year comparisons between 2025 and 2024. Discussions of 2023 items and year-to-year comparisons between 2024 and 2023 that are not included in this Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7. of the Company’s Annual Report on Form 10-K for the year ended December 31, 2024.
Overview of Business
Working for clients across the entire well life cycle, we are a leading provider of energy services, offering cost-effective, innovative solutions and what we consider to be best-in-class safety and service quality. With roots dating to 1938, we have approximately 8,500 employees and provide services and solutions to leading exploration and production companies in both onshore and offshore environments in over 50 countries. Our extensive portfolio of capabilities spans well construction, well flow management, subsea well access, and well intervention and integrity solutions.
Well Construction
•
Our well construction products and services support customers’ new wellbore drilling, wellbore completion and recompletion, and wellbore plug and abandonment requirements. We offer advanced technology solutions in tubular running services, tubular products, cementing, drilling and wellbore cleanup. With a focus on innovation, we are continuing to advance the way wells are constructed by optimizing process efficiency on the rig floor, developing new methods to handle and install tubulars, and mitigating well integrity risks. We believe we are a market leader in deepwater tubular running services and solutions. In recent years, we have added a range of lower-risk, open water cementing solutions. We also offer a range of performance drilling tools designed to mitigate risk and optimize drilling efficiency, including proprietary downhole circulation tools and hydraulic pipe recovery systems.
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Table of Contents
Well Management
Our well management offerings consist of well flow management, subsea well access and well intervention and integrity services.
•
Well flow management: We gather valuable well and reservoir data, with a particular focus on well-site safety and environmental impact. We provide global, comprehensive well flow management systems for the safe production, measurement and sampling of hydrocarbons from a well, including well testing during the exploration and appraisal phase of a new field; flowback and clean-up of a new well prior to production; and in-line testing of a well during its production life. We also provide early production facilities to accelerate production; production enhancement packages to enhance reservoir recovery rates through the realization of production that was previously locked within the reservoir; flare reduction and other emissions management solutions; and metering and other well surveillance technologies to monitor and measure flow and other characteristics of wells.
•
Subsea well access: With nearly 50 years of experience providing a wide range of fit-for-purpose subsea well access solutions, our technology aims to provide safe well access and optimized production throughout the lifecycle of the well. We provide what we believe to be the most reliable, efficient and cost-effective subsea well access systems for exploration and appraisal, development, intervention and abandonment, including an extensive portfolio of standard and bespoke Subsea Test Tree Assemblies (“SSTTA”) and a range motion-compensating and other surface handling equipment. We also provide services and solutions through a rig-deployed Intervention Riser System (“IRS”) utilizing rigs owned by a third party and have capabilities for vessel-deployed services. In addition, we provide systems integration and project management services.
•
Well intervention and integrity: We provide well intervention solutions to acquire and interpret well data, maintain and restore well bore integrity and improve production. In addition to our extensive fleet of mechanical and cased hole wireline units, we have recently introduced and acquired a number of cost-effective, innovative well intervention services, including CoilHose™, a lightweight, small-footprint solution for wellbore lifting, cleaning and chemical treatments; Octopoda™, for fluid treatments in wellbore annuli; Galea™, an autonomous well intervention solution; and expandable casing patches designed to repair damaged production casing or isolate existing perforations prior to refracturing a well (a so called “patch and perf”). We also possess several other distinct technical capabilities, including fiber optic-enabled data acquisition and interpretation services, non-intrusive metering technologies and wireless telemetry systems for reservoir monitoring.
We operate a global business and have a diverse and relatively stable customer base that is comprised of national oil companies (“NOC”), international oil companies (“IOC”), independent exploration and production companies (“Independents”) and service partners. We have strong relationships with several of the world’s largest NOCs and IOCs, some of which have been our customers for decades. We are dedicated to safely and sustainably delivering maximum value to our customers.
We organize and manage our operations on a geographical basis. Our reporting structure and the key financial information used by our management team is organized around our four operating segments: (i) North and Latin America (“NLA”), (ii) Europe and Sub-Saharan Africa (“ESSA”), (iii) Middle East and North Africa (“MENA”) and (iv) Asia-Pacific (“APAC”).
How We Generate Our Revenue
Our revenue is derived primarily from providing services in well construction, well flow management, subsea well access and well intervention and integrity to operators globally. Our revenue includes equipment service charges, personnel charges, run charges and consumables. Some of our contracts allow us to charge for additional deliverables, such as the costs of mobilization of people and equipment and customer specific engineering costs associated with a project. We also procure products and services on behalf of our customers that are provided by third parties for which we are reimbursed with a mark-up or in connection with an integrated services contract. We also design, manufacture and sell equipment, which is typically done in connection with a related operations and maintenance arrangement with a particular customer. In addition, we also generate revenue from the sale of certain well construction products.
For the year ended December 31, 2025, approximately 81% of our revenue was generated outside of the United States and approximately 63% of our revenue was generated by activities related to offshore oil and gas operations. Approximately 65% of our revenue was generated by services tied to drilling and completions-related activities, which are generally funded by customers’ capital expenditures, and approximately 35% of our revenue was generated by production optimization related activities, which are generally funded by customers’ operating expenditures.
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Table of Contents
Commodity Prices and Market Conditions
Commodity Prices
Average daily oil demand declined slightly in the fourth quarter of 2025, down by 0.1 million b/d compared to levels recorded in the prior quarter; however, there remained an increase compared to the fourth quarter of 2024, and the full year average for 2024. Global liquids demand grew by 1.2 million b/d year-on-year in 2025 and is expected to grow a further 1.1 million b/d in 2026. Brent crude prices softened modestly over the fourth quarter of 2025, declining from a monthly average of approximately $65 per barrel (“/bbl”) in October to around $63/bbl in December. The easing in prices reflected a gradual weakening in market fundamentals as global supply growth outpaced demand and increasing oil in storage outweighed the effect of potential disruptions driven by tensions in Russia-Ukraine and Venezuela. Price declines were marginally offset by Chinese inventory builds and the OPEC+ decision to pause the unwinding of production cuts, underscoring the group’s continued focus on market stability.
Market Conditions
Entering 2026, global oil inventories are expected to continue rising, as supply growth outpaces demand, placing downward pressure on prices. Despite softer fundamentals, geopolitical risks, evolving sanctions regimes and policy uncertainty continue to create potential supply disruptions, placing a higher degree of volatility on crude markets. On balance, oil prices are expected to remain subdued throughout 2026. Nevertheless, global oil and gas demand continues to grow, reinforcing the need for sustained investment to maintain and expand supply.
There are several market factors that have had, and may continue to have, an effect on our business, including:
•
The market for energy services and our business are substantially dependent on the price of oil and, to a lesser extent, the regional price of gas, which are both driven by market supply and demand. Changes in oil and gas prices impact customer willingness to spend on exploration and appraisal, development, production, and abandonment activities. The extent of the impact of a change in oil and gas prices on these activities varies extensively between geographic regions, types of customers, types of activities and the financial returns of individual projects.
•
Activity related to gas and liquified natural gas (“LNG”) production (and associated asset development) continues to grow as demand still outpaces supply and long-term energy security remains a priority. More broadly, the net-zero targets of many nations require a transition to lower-carbon sources such as natural gas and LNG, resulting in increased investment in the production of the fuels.
•
International and offshore activity continues to be a source of growth throughout 2026. We also see an increased demand for services related to brownfield and production enhancement and infield development programs as operators strive to maximize their previous investments and maintain production with a lower carbon footprint. In addition, we have seen an increase in demand for production optimization technologies, especially in support of gas and LNG developments.
•
Expro remains selective in pursuing low-carbon opportunities that support operators’ drive for increased sustainability in their hydrocarbon production, including early-stage carbon capture and storage and flare reduction. While the broader trend toward decarbonization continues, our customers focus remains on energy security and returns driven by their core hydrocarbon businesses.
Outlook
According to the U.S. Energy Information Administration (“EIA”), global liquids consumption is forecasted to average approximately 104.8 million barrels per day in 2026, an increase of around 1.1 million barrels per day compared to 2025. Demand growth is expected to be driven almost entirely by non-OECD countries, with Asia (led by China and India) accounting for the majority of incremental consumption, alongside growth in Africa and the Middle East.
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Although consumption and production are forecast to grow at similar rates, total supply is expected to exceed demand, resulting in continued inventory builds in 2026. OPEC+ is expected to manage production levels to mitigate downside price pressure, with output likely remaining below targeted capacity levels. Strategic stockpiling, particularly in China, is expected to continue and may help limit price declines.
Based on these assumptions, the EIA forecasts Brent crude oil prices to average approximately $56 per barrel for 2026. This outlook remains subject to elevated uncertainty given ongoing geopolitical tensions, evolving sanctions, and political instability in key producing regions including Venezuela, Iran and Russia-Ukraine.
In this environment, Expro maintains cautious optimism regarding demand for products and services. While overall market conditions are softer, the continued need for hydrocarbons supports investment in strategic offshore developments and the optimization of existing assets — areas where Expro is well positioned.
Turning to the natural gas outlook, in the United States, the EIA forecasts Henry Hub natural gas prices to average approximately $3.46 per million British thermal units (“MMBtu”) in 2026, largely flat from 2025 levels, as production continues to increase and a milder-than-average winter has reduced demand over what is typically the annual peak. Internationally, Rystad Energy in December modestly revised down its 2026 price forecasts for European Title Transfer Facility (“TTF”) and Northeast Asia spot markets, reflecting lower oil prices and a weaker macroeconomic backdrop. European TTF prices are expected to average approximately $9.70/MMBtu, with Asian spot prices averaging around $10.20/MMBtu in 2026. Nevertheless, natural gas demand remains resilient and continues to play a central role in global energy transition pathways, supporting a long-term opportunity pipeline for Expro.
Upstream investment is expected to recover modestly in 2026 compared to 2025, despite lower oil prices, as project sanctioning activity increases. International and offshore spending is expected to be the primary source of growth, while U.S. land activity moderates — a market where Expro has limited exposure. Investment growth is concentrated in offshore developments, particularly deepwater projects in Brazil and Guyana, and in regions including the Middle East, Europe, Sub-Saharan Africa, and Latin America. These positive trends the international and offshore segments support demand across Expro’s well construction, well flow management, and subsea product lines.
Brownfield activity is expected to gain further momentum in 2026 as operators focus on efficiency, cost reduction, and production optimization. This environment supports continued demand for Expro’s well intervention, production optimization, and digital solutions, aligned with customer priorities around efficiency, safety, automation, and emissions reduction.
While near-term market conditions remain subdued and uncertainty persists, resilient global demand for hydrocarbons continues to support investment in international and offshore markets. Expro’s diversified service portfolio, strong international footprint, technology differentiation, and focus on margin discipline underpin a cautiously constructive outlook for 2026 and beyond, as we continue to support customers across the full life cycle of their assets.
The following provides an outlook for 2026 by our reporting segments based on data from Spears and Associates Inc:
NLA: North American drilling activity is expected to slip by 2% in 2026 to an average of 549 active rigs, accounting for a total of around 15,300 wells completed (down 1% from 2025). North American completion activity is projected to slow by 1% overall in 2026 to a total of about 11,700 frac jobs for the year. The expected slowdown in activity reflects the more volatile, short-cycle nature of shale production and is driven largely by North American commodity prices. Henry Hub spot gas prices are projected to increase over the fourth quarter 2025 to fourth quarter 2026 timeframe, driving an increase of approximately 10% in the gas focused rig count on an exit-to-exit basis. In contrast, spot West Texas Intermediate prices are expected to be little changed over the course of 2026, driving a decline of 1% in the oil-centric rig count over 2026. In Central and South America, drilling activity is projected to increase by 3% in 2026 to an average of 139 active rigs, accounting for a total of about 1,850 new wells. Onshore drilling in the region is forecast to increase 1% in 2026 to an average of 100 active land rigs drilling almost 1,625 new wells, driven by Ecuador and Mexico. Offshore activity is expected to grow by 11% in 2026, averaging 39 rigs totaling some 225 new wells, driven by large-scale deepwater plays in Brazil, Guyana and Suriname, as well as continued recovery in Pemex-funded activity. Drilling activity in Central and South America is mixed in 2026, with Argentina and Brazil remaining the main growth engines despite cost pressures, lower prices and regulatory hurdles, as shale and deepwater projects continue to advance. Guyana and Suriname also continue to expand their offshore developments. In contrast, Colombia, Mexico and Venezuela face policy, fiscal and sanction-related constraints that limit new exploration, keeping regional growth uneven and highly concentrated in a few basins.
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ESSA: The outlook calls for European drilling activity to increase 1% in 2026 to an average of 99 active rigs accounting for a total of around 780 new wells. Onshore drilling in Europe is forecast to average 72 active rigs in 2026, up by 1% accounting for about 480 new wells drilled. Offshore drilling in the region is projected to increase 4% in 2026, averaging 28 active rigs and around 300 new wells. European drilling activity in 2026 is concentrated in the Black Sea and the mature North Sea, with Romania advancing multi-well development drilling at Neptun Deep and Norway sustaining high levels of development and tie-back drilling despite sharp cost inflation. Elsewhere, exploration momentum is building in the eastern Mediterranean, while UK North Sea activity remains selective as fiscal pressure tempers investment even as projects near existing infrastructure move ahead. African drilling activity is projected to grow by 2% in 2026 to an average of 124 active rigs, accounting for a total of about 900 new wells. Onshore drilling in Africa is forecast to increase 1% in 2026 to an average of 108 active land rigs, accounting for about 740 new wells drilled. Offshore activity is projected to jump by 7% in 2026, averaging 16 active rigs while totaling around 150 new wells. In recent years several African nations have reformed their fiscal and legislative environments, making them more attractive to investment than they have been in some time. In addition, offshore discoveries having potentially multibillion-barrel reserves have attracted significant global interest. While oil exploration remains crucial, there is growing interest in natural gas to meet both domestic energy needs and international export demand, particularly from Europe. Nonetheless, the region faces several challenges including high operating costs, lack of infrastructure, and political/security issues in some key producing countries, which can slow or deter major investment.
MENA: Middle Eastern drilling activity is now expected to increase 1% in 2026 to an average of 509 active rigs accounting for a total of almost 3,000 new wells drilled. Onshore drilling is projected to increase 1% in 2026 to an average of 428 rigs and over 2,700 new wells drilled. Offshore drilling activity is also expected to grow by 1% to an average of 82 rigs drilling some 275 new wells. The main growth drivers for 2026 in the region include Abu Dhabi, Iraq, Kuwait and Oman, offsetting a slowdown in Saudi Arabian activity. For 2026, E&P activity in the Middle East is primarily focused on leveraging the region's vast, low-cost reserves to maintain and expand its oil and gas production capacity to meet global demand. Activity is characterized by massive investments and a dominant role for state-owned enterprises such as Saudi Aramco, ADNOC (UAE), and QatarEnergy. While oil remains crucial, there is an ongoing emphasis on developing the region’s natural gas reserves and associated LNG infrastructure. The region is on track to become the second largest gas-producing region globally.
APAC: Drilling activity in Asia-Pacific is forecast to average 185 active rigs in 2026 (up by 3%), accounting for 2,425 new wells drilled. India, Indonesia and Thailand are the three most active drillers in this geo-market. Onshore drilling in the region is forecast to increase 2% in 2026 to an average of 135 active land rigs, with over 1,675 new wells drilled. Offshore activity is projected to improve 2% in 2026 at an average of 50 active rigs drilling almost 750 new wells. Rapid economic growth, urbanization, and industrialization in India, and Southeast Asia to soaring energy demand and an increasing reliance on imports. A primary characteristic of increased activity in this region is the strong governmental push to boost domestic oil and gas production to reduce import dependency and ensure long-term energy security. The natural gas segment is a major focus of new exploration efforts and investments across the region, particularly in Malaysia, Indonesia, and Vietnam. The offshore segment is a fast growing segment of the upstream market. Investment in deepwater and ultra-deepwater drilling is rising, supported by the potential for large reserve discoveries in frontier areas
How We Evaluate Our Operations
We use a number of financial and operational measures to routinely analyze and evaluate the performance of our business, including Revenue and Adjusted EBITDA.
Revenue: We analyze our performance by comparing actual monthly revenue by operating segments and areas of capabilities to our internal projections for each month. Our revenue is primarily derived from well construction, well flow management, subsea well access and well intervention and integrity solutions.
Adjusted EBITDA: We regularly evaluate our financial performance using Adjusted EBITDA. Our management believes Adjusted EBITDA is a useful financial performance measure as it excludes non-cash charges and other transactions not related to our core operating activities and allows more meaningful analysis of the trends and performance of our core operations.
Adjusted EBITDA is a non-GAAP financial measure. Please refer to the section titled “Non-GAAP Financial Measures” for a reconciliation of Adjusted EBITDA to net income (loss), the most directly comparable financial performance measure calculated and presented in accordance with GAAP.
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Executive Overview
Year ended December 31, 2025 compared to year ended December 31, 2024
Certain highlights of our financial results and other key developments include:
•
Revenue for the year ended December 31, 2025 decreased by $105.7 million, or 6.2%, to $1,607.1 million, compared to $1,712.8 million for the year ended December 31, 2024. Activity and revenue across our geography-based operating segments decreased during the year ended December 31, 2025, most notably in ESSA and APAC, partially offset by increased revenue in MENA. Revenue for our segments is discussed separately below under the heading “Operating Segment Results.”
•
We reported net income for the year ended December 31, 2025 of $51.7 million, compared to $51.9 million for the year ended December 31, 2024. The decrease in net income reflects higher Adjusted EBITDA (up $5.6 million year-over-year), lower foreign exchange losses (down $14.5 million), lower merger and integration expense (down $10.2 million) and lower income tax expense (down $11.4 million), partially offset by higher depreciation and amortization expense (up $28.6 million), higher severance and other expense (up $11.5 million), and higher stock-based compensation expense (up $2.8 million).
•
Adjusted EBITDA for the year ended December 31, 2025 increased by $5.6 million, or 1.6%, to $353.0 million from $347.4 million for the year ended December 31, 2024. Adjusted EBITDA margin increased to 22.0% during the year ended December 31, 2025, as compared to 20.3% during the year ended December 31, 2024. The increase in Adjusted EBITDA and Adjusted EBITDA margin, despite the decrease in revenue, is primarily attributable to a more favorable activity mix, particularly in the ESSA and MENA segments.
•
Net cash provided by operating activities was $210.2 million during the year ended December 31, 2025 as compared to $169.5 million during the year ended December 31, 2024. The increase of $40.7 million in net cash provided by operating activities for the year ended December 31, 2025 was primarily driven by a lower consumption of working capital during the current year as compared to the previous year.
Non-GAAP Financial Measures
We include in this Form 10-K the non-GAAP financial measures Adjusted EBITDA and Adjusted EBITDA margin. We provide reconciliations of net income (loss), the most directly comparable financial performance measure calculated and presented in accordance with GAAP, to Adjusted EBITDA.
Adjusted EBITDA and Adjusted EBITDA margin are used as supplemental financial measures by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others. These non-GAAP financial measures allow our management and others to assess our financial and operating performance as compared to those of other companies in our industry, without regard to the effects of our capital structure, asset base, items outside the control of management and other charges outside the normal course of business.
We define Adjusted EBITDA as net income (loss) adjusted for (a) income tax expense (benefit), (b) depreciation and amortization expense, (c) impairment expense, (d) severance and other expense, net, (e) stock-based compensation expense, (f) merger and integration expense, (g) gain (loss) on disposal of assets, (h) other income (expense), net, (i) interest and finance (income) expense, net and (j) foreign exchange (gain) loss. Adjusted EBITDA margin reflects our Adjusted EBITDA as a percentage of revenue.
Adjusted EBITDA and Adjusted EBITDA margin have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. As Adjusted EBITDA may be defined differently by other companies in our industry, our presentation of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
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The following table presents a reconciliation of net income (loss) to Adjusted EBITDA for each of the periods presented (in thousands):
Year ended
December 31,
2025
2024
2023
Net income (loss)
$
51,686
$
51,918
$
(23,360
)
Income tax expense
$
34,653
$
46,048
$
44,307
Depreciation and amortization expense
192,106
163,468
172,260
Severance and other expense
28,527
17,048
14,388
Merger and integration expense
6,161
16,334
9,764
Other (income) expenses, net (1)
(2,646
)
105
(1,234
)
Stock-based compensation expense
29,172
26,352
19,574
Foreign exchange (gain) loss
(916
)
13,613
9,238
Interest and finance expense, net
14,281
12,517
3,943
Adjusted EBITDA
$
353,024
$
347,403
$
248,880
Net income (loss) margin
3.2
%
3.0
%
(1.5
)%
Adjusted EBITDA margin
22.0
%
20.3
%
16.5
%
(1)
Other (income) expenses, net, is comprised of immaterial, unusual or infrequently occurring transactions which, in management’s view, do not provide useful measures of the underlying operating performance of the business.
Selected Unaudited Financial Information for the Three Months Ended December 31, 2025 and September 30, 2025
We evaluate our business segment operating performance using segment revenue and Segment EBITDA, as described in Note 5 “Business segment reporting” in our consolidated financial statements. We believe Segment EBITDA is a useful operating performance measure as it excludes non-cash charges and other transactions not related to our core operating activities and corporate costs, and Segment EBITDA allows management to more meaningfully analyze the trends and performance of our core operations by segment as well as to make decisions regarding the allocation of resources to our segments
Operating Segment Results
The following table shows revenue by segment and revenue as a percentage of total revenue by segment for the three months ended December 31, 2025 and September 30, 2025:
Three Months Ended
Percentage
(in thousands)
December 31, 2025
September 30, 2025
December 31, 2025
September 30, 2025
NLA
$
130,305
$
150,868
34.1
%
36.7
%
ESSA
116,322
125,838
30.5
%
30.6
%
MENA
92,985
86,061
24.3
%
20.9
%
APAC
42,515
48,589
11.1
%
11.8
%
Total revenue
$
382,127
$
411,356
100.0
%
100.0
%
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The following table shows the Segment EBITDA and Segment EBITDA as a percentage of total revenue by segment (“Segment EBITDA margin”) and a reconciliation to income before income taxes for the three months ended December 31, 2025 and September 30, 2025:
Three Months Ended
Segment EBITDA Margin
(in thousands)
December 31, 2025
September 30, 2025
December 31, 2025
September 30, 2025
NLA
$
31,795
$
36,842
24.4
%
24.4
%
ESSA
40,039
40,503
34.4
%
32.2
%
MENA
36,121
29,862
38.8
%
34.7
%
APAC
6,952
10,049
16.4
%
20.7
%
Total Segment EBITDA
$
114,907
$
117,256
Corporate costs (1)
(30,372
)
(29,181
)
Equity in income of joint ventures
3,838
5,897
Depreciation and amortization expense
(53,774
)
(46,195
)
Merger and integration expense
(861
)
(1,293
)
Severance and other expense
(9,952
)
(5,782
)
Stock-based compensation expense
(7,689
)
(7,201
)
Foreign exchange loss
(463
)
(1,151
)
Other income, net
188
524
Interest and finance expense, net
(2,445
)
(4,106
)
Income before income taxes
$
13,377
$
28,768
(1)
Corporate costs include the costs of running our corporate head office and other central functions that support the operating segments but are not attributable to a particular operating segment, including central product line management, research, engineering and development, logistics, sales and marketing and health and safety.
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Quarter ended December 31, 2025 compared to quarter ended September 30, 2025
NLA
Revenue for NLA was $130.3 million for the three months ended December 31, 2025, a decrease of $20.6 million, or 13.6%, compared to $150.9 million for the three months ended September 30, 2025. The decrease was primarily due to lower subsea well access and well construction revenue in the U.S., offset by higher well intervention and integrity revenue in Argentina.
Segment EBITDA for NLA was $31.8 million, or 24.4% of revenue, during the three months ended December 31, 2025, compared to $36.8 million, or 24.4% of revenue, during the three months ended September 30, 2025. The decrease of $5.0 million in Segment EBITDA and Segment EBITDA margin was largely attributable to lower activity and less favorable product mix during the three months ended December 31, 2025.
ESSA
Revenue for ESSA was $116.3 million for the three months ended December 31, 2025, a decrease of $9.5 million, or 7.6%, compared to $125.8 million for the three months ended September 30, 2025. The decrease in revenue was primarily driven by lower subsea well access and well construction revenue in Angola, and central and west Africa, partially offset by higher well flow management revenue in Bulgaria.
Segment EBITDA for ESSA was $40.0 million, or 34.4% of revenue, for the three months ended December 31, 2025, a decrease of $0.5 million, or 1.1%, compared to $40.5 million, or 32.2% of revenue, for the three months ended September 30, 2025. The decrease in Segment EBITDA was primarily attributable to lower activity while the increase in Segment EBITDA margin reflects a more favorable product mix.
MENA
Revenue for MENA was $93.0 million for the three months ended December 31, 2025, an increase of $6.9 million, or 8.0%, compared to $86.1 million for the three months ended September 30, 2025. The increase in revenue was driven by higher well flow management revenue in Algeria and Saudi Arabia.
Segment EBITDA for MENA was $36.1 million, or 38.8% of revenue, for the three months ended December 31, 2025, an increase of $6.3 million, or 21.0%, compared to $29.9 million, or 34.7% of revenue, for the three months ended September 30, 2025. The increase in Segment EBITDA and Segment EBITDA margin was primarily due to higher well flow management activity and a resulting more favorable activity mix during the three months ended December 31, 2025.
APAC
Revenue for APAC was $42.5 million for the three months ended December 31, 2025, a decrease of $6.1 million, or 12.5%, compared to $48.6 million for the three months ended September 30, 2025. The decrease in revenue was primarily due to lower well flow management activity in Indonesia and India, lower well construction revenue in Australia, offset by higher subsea well access activity in Australia.
Segment EBITDA for APAC was $7.0 million, or 16.4% of revenue, for the three months ended December 31, 2025, a decrease of $3.1 million compared to $10.0 million, or 20.7% of revenue, for the three months ended September 30, 2025. The decrease in Segment EBITDA and Segment EBITDA margin was largely attributable to lower activity and less favorable product mix during the three months ended December 31, 2025.
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Results of Operations for the years ended December 31, 2025, 2024 and 2023
Operating Segment Results.
The following table shows revenue by segment and revenue as a percentage of total revenue by segment for the years ended December 31, 2025, 2024 and 2023:
Year Ended
Percentage
(in thousands)
December 31, 2025
December 31, 2024
December 31, 2023
December 31, 2025
December 31, 2024
December 31, 2023
NLA
$
558,033
$
566,048
$
511,800
34.7
%
33.0
%
33.8
%
ESSA
486,900
564,440
520,951
30.3
%
33.0
%
34.4
%
MENA
363,616
332,216
233,528
22.6
%
19.4
%
15.4
%
APAC
198,546
250,098
246,485
12.4
%
14.6
%
16.3
%
Total revenue
$
1,607,095
$
1,712,802
$
1,512,764
100.0
%
100.0
%
100.0
%
The following table shows Segment EBITDA and Segment EBITDA margin by segment and a reconciliation to income before income taxes for the years ended December 31, 2025, 2024 and 2023:
Year Ended
Segment EBITDA Margin
(in thousands)
December 31, 2025
December 31, 2024
December 31, 2023
December 31, 2025
December 31, 2024
December 31, 2023
NLA
$
132,931
$
141,977
$
132,869
23.8
%
25.1
%
26.0
%
ESSA
149,365
145,375
136,007
30.7
%
25.8
%
26.1
%
MENA
132,722
115,772
71,201
36.5
%
34.8
%
30.5
%
APAC
42,657
57,680
1,805
21.5
%
23.1
%
0.7
%
Total Segment EBITDA
$
457,675
$
460,804
$
341,882
Corporate costs (1)
(121,487
)
(129,823
)
(105,855
)
Equity in income of joint ventures
16,836
16,422
12,853
Depreciation and amortization expense
(192,106
)
(163,468
)
(172,260
)
Merger and integration expense
(6,161
)
(16,334
)
(9,764
)
Severance and other expense
(28,527
)
(17,048
)
(14,388
)
Stock-based compensation expense
(29,172
)
(26,352
)
(19,574
)
Foreign exchange gain (loss)
916
(13,613
)
(9,238
)
Other income (expenses), net
2,646
(105
)
1,234
Interest and finance expense, net
(14,281
)
(12,517
)
(3,943
)
Income before income taxes
$
86,339
$
97,966
$
20,947
(1)
Corporate costs include the costs of running our corporate head office and other central functions that support the operating segments but are not attributable to a particular operating segment, including central product line management, research, engineering and development, logistics, sales and marketing and health and safety.
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Year ended December 31, 2025 compared to the year ended December 31, 2024
NLA
Revenue for NLA was $558.0 million for the year ended December 31, 2025, a decrease of $8.0 million, or 1.4%, compared to $566.0 million for the year ended December 31, 2024. The decrease in revenue is primarily due to lower well construction revenue in the U.S. and Mexico, lower well flow management revenue in Mexico and lower well flow intervention and integrity revenue in Brazil, partially offset by higher subsea well access revenue in the U.S. and higher well flow management revenue in the U.S. and Brazil.
Segment EBITDA for NLA was $132.9 million, or 23.8% of revenue, during the year ended December 31, 2025, compared to $142.0 million or 25.1% of revenue during the year ended December 31, 2024, a decrease of $9.0 million. The decrease in Segment EBITDA and Segment EBITDA margin was primarily attributable to the decrease in revenue and a less favorable activity mix.
ESSA
Revenue for ESSA was $486.9 million for the year ended December 31, 2025, a decrease of $77.5 million, or 13.7%, compared to $564.4 million for the year ended December 31, 2024. The decrease in revenue was primarily driven by lower well flow management revenue in Congo and lower subsea well access revenue in Angola as a result of one-time projects in 2024 that did not reoccur in 2025, partially offset by higher well construction revenue in Cyprus and higher subsea well access revenue in the U.K. and Norway.
Segment EBITDA for ESSA was $149.4 million, or 30.7% of revenue, during the year ended December 31, 2025, compared to $145.4 million, or 25.8% of revenue, during the year ended December 31, 2024, an increase of $4.0 million. The increase in Segment EBITDA and Segment EBITDA margin, despite the decrease in revenue, was primarily attributable to an increase in activities on higher margin services during the year ended December 31, 2025.
MENA
Revenue for MENA was $363.6 million for the year ended December 31, 2025, an increase of $31.4 million, or 9.5%, compared to $332.2 million for the year ended December 31, 2024. The increase in revenue was driven by higher well flow management revenue in Iraq, Saudi Arabia, Algeria and higher well construction revenue in Saudi Arabia and the UAE.
Segment EBITDA for MENA was $132.7 million, or 36.5% of revenue, during the year ended December 31, 2025, compared to $115.8 million, or 34.8% of revenue during the year ended December 31, 2024. The increase of $17.0 million was attributable to higher revenue and a more favorable activity mix.
APAC
Revenue for APAC was $198.5 million for the year ended December 31, 2025, a decrease of $51.6 million, or 20.6%, compared to $250.1 million for the year ended December 31, 2024. The decrease in revenue was primarily due to lower subsea well access activity in China and Australia, and lower well flow management activity in Australia, partially offset by higher well construction activity in Australia and Brunei.
Segment EBITDA for APAC was $42.7 million, or 21.5% of revenue, during the year ended December 31, 2025, compared to $57.7 million, or 23.1% of revenue, during the year ended December 31, 2024. The decrease in Segment EBITDA was primarily due to decreased activity and less favorable product mix.
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Depreciation and amortization expense
Depreciation and amortization expense for the year ended December 31, 2025 increased by $28.6 million, or 17.5%, to $192.1 million, as compared to $163.5 million for the year ended December 31, 2024. The increase was generally proportional to the increase in property plant and equipment year over year, including impacts of the acquisition of CTL UK Holdco Limited, a company incorporated and registered in England and Wales ("Coretrax") in May 2024.
Merger and integration expense
Merger and integration expense for the year ended December 31, 2025 decreased by $10.2 million, to $6.2 million as compared to $16.3 million for the year ended December 31, 2024. The decrease was due to costs associated with the Coretrax acquisition in 2024 that did not repeat in 2025.
Severance and other expense
Severance and other expense for the year ended December 31, 2025 increased by $11.5 million, to $28.5 million as compared to $17.0 million for the year ended December 31, 2024. The increase was predominantly due to restructuring activity across all segments.
Foreign exchange gain (loss)
Foreign exchange gain for the year ended December 31, 2025 was $0.9 million as compared to a foreign exchange loss of $13.6 million for the year ended December 31, 2024. The change was primarily due to favorable changes in various exchange rates and higher activity in jurisdictions with local currencies that appreciated relative to the U.S. dollar.
Liquidity and Capital Resources
Liquidity
Our financial objectives include the maintenance of sufficient liquidity, adequate financial resources and financial flexibility to fund our business. As of December 31, 2025, total available liquidity was $550.9 million, including cash and cash equivalents and restricted cash of $197.5 million and $353.4 million available for borrowings under our New Credit Facility (as defined below). Expro believes these amounts, along with cash generated by ongoing operations, will be sufficient to meet future business requirements for the next 12 months and beyond. Our primary sources of liquidity have been cash flows from operations. Our primary uses of capital have been for capital expenditures, acquisitions and repurchases of company stock. We monitor potential capital sources, including equity and debt financing, in order to meet our investment and liquidity requirements.
Our total capital expenditures are estimated to range between $110.0 million and $120.0 million for 2026. Our total capital expenditures were $112.4 million for the year ended December 31, 2025, out of which approximately 90% were used for the purchase or manufacture of equipment to directly support customer-related activities and approximately 10% for other property, plant and equipment, inclusive of software costs. The actual amount of capital expenditures for the purchase and manufacture of equipment may fluctuate based on market conditions. We continue to focus on preserving and protecting our strong balance sheet, optimizing utilization of our existing assets and, where practical, limiting new capital expenditures.
On October 30, 2025, the Company’s Board of Directors (the “Board”) approved a new stock repurchase program, pursuant to which the Company is authorized to acquire up to $100.0 million of its outstanding common stock from October 30, 2025 through December 31, 2026 (the “Stock Repurchase Program”). Under the Stock Repurchase Program, the Company may repurchase shares of the Company’s common stock in open market purchases, in privately negotiated transactions or otherwise. The Stock Repurchase Program will continue to be utilized at management’s discretion and in accordance with federal securities laws. The timing and actual numbers of shares repurchased will depend on a variety of factors including price, corporate requirements, the constraints specified in the Stock Repurchase Program along with general business and market conditions. The Stock Repurchase Program does not obligate the Company to repurchase any particular amount of common stock, and it could be modified, suspended or discontinued at any time. During the years ended December 31, 2025 and 2024, we repurchased approximately 3.7 million and 1.2 million shares, respectively, of our common stock under the preceding stock repurchase program active at the time for a total cost of approximately $40.1 million and $14.2 million, respectively. Approximately $100.0 million remained authorized for repurchases under the Stock Repurchase Program as of December 31, 2025, subject to the limitation set in our shareholder authorization for repurchases of our common stock.
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Credit Facility
Revolving Credit Facility
On July 23, 2025, the Company and certain of its subsidiaries, including Exploration and Production Services (Holdings) Limited and Expro Holdings U.S. Inc., as borrowers, entered into a senior secured revolving credit facility (the “New Credit Facility”) by and among, inter alia, DNB Bank ASA, London Branch, as agent, and other lenders, in an initial aggregate principal amount of up to $500 million, of which up to $400 million is available as revolving facility loans and up to $100 million is available as term bridge loans. Proceeds of the revolving facility under the New Credit Facility may be used for general corporate and working capital purposes. Proceeds of the bridge facility under the New Credit Facility may be used for acquisitions and investments and capital expenditure in relation to acquisitions and fees, costs and expenses in connection with the foregoing. The New Credit Facility replaces the Company’s prior senior secured revolving credit facility entered into on October 1, 2021 and as amended and restated pursuant to an amendment and restatement agreement on October 6, 2023 (the “Prior Facility Agreement”). The maturity date of the New Credit Facility is July 30, 2029.
During the third quarter of 2025, the Company completed a $22.0 million voluntary prepayment of its New Credit Facility and during the fourth quarter of 2025 completed another $20 million voluntary prepayment. For the avoidance of doubt, any voluntary prepayment amounts remain available for future drawdowns, over the duration of the facility. The voluntary repayments reduced the outstanding drawn balance from $121.1 million under the Prior Facility Agreement as of June 30, 2025 to $79.1 million under the New Facility Agreement as of December 31, 2025.
Please see Note 16 “Interest bearing loans” in the Notes to the Consolidated Financial Statements for additional information.
Cash flow from operating, investing and financing activities
Cash flows provided by our operations, investing and financing activities are summarized below (in thousands):
Year Ended December 31,
(in thousands)
2025
2024
2023
Net cash provided by operating activities
$
210,172
$
169,479
$
138,309
Net cash used in investing activities
(107,387
)
(165,143
)
(148,232
)
Net cash (used in) provided by financing activities
(96,722
)
29,572
(49,339
)
Effect of exchange rate changes on cash activities
6,747
(2,411
)
(6,032
)
Net increase (decrease) to cash and cash equivalents and restricted cash
$
12,810
$
31,497
$
(65,294
)
Analysis of cash flow changes between the years ended December 31, 2025 and 2024
Net cash provided by operating activities
Net cash provided by operating activities was $210.2 million during the year ended December 31, 2025 as compared to $169.5 million during the year ended December 31, 2024. The increase of $40.7 million in net cash provided by operating activities for the year ended December 31, 2025 was primarily driven by a lower consumption of working capital during the current year as compared to the previous year.
Net cash used in investing activities
Net cash used in investing activities was $107.4 million during the year ended December 31, 2025 as compared to $165.1 million during the year ended December 31, 2024, a decrease of $57.8 million. The decrease was primarily a result of a decrease in capital expenditures of $31.2 million and $32.0 million paid for acquired businesses in 2024 that did not repeat in 2025.
Net cash (used in) provided by financing activities
Net cash used in financing activities was $96.7 million during the year ended December 31, 2025 as compared to net cash provided by financing activities of $29.6 million during the year ended December 31, 2024. The change in net cash used in financing activities is primarily due to the repayment of long-term borrowings of $42.0 million during 2025 as compared to net proceeds received from borrowings of $72.9 million in 2024 and the increase in repurchases of common stock of $25.9 million, partially offset by payment of acquisition-related contingent consideration of $13.9 million during 2024 that did not repeat in 2025.
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Off-balance sheet arrangements
We have outstanding letters of credit/guarantees that relate to performance bonds, custom/excise tax guaranties and facility lease/rental obligations. These were entered into in the ordinary course of business and are customary practices in the various countries where we operate. It is not practicable to estimate the fair value of these financial instruments. None of the off-balance sheet arrangements either have, or are likely to have, a material effect on our consolidated financial statements. As of December 31, 2025, we had no material off-balance sheet financing arrangements other than those discussed above.
Critical accounting policies and estimates
The preparation of consolidated financial statements and related disclosures in conformity with GAAP requires Expro to make estimates and assumptions that affect the reported amounts of revenue and associated costs as well as reported amounts of assets and liabilities and related disclosures of contingent liabilities. Certain accounting policies involve judgments and uncertainties. We evaluate estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. We consider the following policies to be the most critical to understanding the judgments that are involved and the uncertainties that could impact our results of operations, financial condition and cash flows.
Revenue recognition
Service revenue is recognized over a period of time as services are performed or rendered and the customer simultaneously consumes the benefit of the service while it is being rendered, and, therefore, reflects the amount of consideration to which we have a right to invoice. We generally perform services either under direct service purchase orders or master service agreements which are supplemented by individual call-out provisions. For customers contracted under such arrangements, an accrual is recorded in unbilled receivable for revenue earned but not yet invoiced. Revenue from the sale of goods is generally recognized at the point in time when the control has passed onto the customer which generally coincides with delivery and, where applicable, installation. We also regularly assess customer credit risk inherent in the carrying amounts of receivables, contract costs and estimated earnings, including the risk that contractual penalties may not be sufficient to offset our accumulated investment in the event of customer termination.
Where contractual arrangements contain multiple performance obligations, judgment is involved to analyze each performance obligation within the sales arrangement to determine whether they are distinct. The revenue for contracts involving multiple performance obligations is allocated to each distinct performance obligation based on relative selling prices and is recognized on satisfaction of each of the distinct performance obligations.
We recognize revenue for long-term construction-type contracts, involving significant design and engineering efforts in order to satisfy custom designs for customer-specific applications, on an over a period of time basis, using an input method, which represents the ratio of actual costs incurred to date on the project in relation to total estimated project costs. The estimate of total project costs has a significant impact on both the amount of revenue recognized as well as the related profit on a project. Revenue and profits on contracts can also be significantly affected by change orders and claims. Profits are recognized based on the estimated project profit multiplied by the percentage complete. Due to the nature of these projects, adjustments to estimates of contract revenue and total contract costs are often required as work progresses. Any expected losses on a project are recorded in full in the period in which they are identified.
We are required to determine the transaction price in respect of each of our contracts with customers. In making such judgment, we assess the impact of any variable consideration in the contract, due to discounts or penalties, the existence of any significant financing component and any non-cash consideration in the contract. In determining the impact of variable consideration, we use the “most-likely amount” method whereby the transaction price is determined by reference to the single most likely amount in a range of possible consideration amounts.
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Business Combinations
We record business combinations using the acquisition method of accounting. All of the assets acquired and liabilities assumed are recorded at estimated fair value as of the acquisition date. The excess of the purchase price over the estimated fair values of the net tangible and intangible assets acquired is recorded as goodwill.
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The application of the acquisition method of accounting for business combinations requires management to make significant estimates and assumptions in the determination of the fair value of assets acquired and liabilities assumed, in order to properly allocate purchase price consideration between assets that are depreciated and amortized from goodwill. The fair value assigned to tangible and intangible assets acquired and liabilities assumed are based on management’s estimates and assumptions, as well as other information compiled by management, including valuations that utilize customary valuation procedures and techniques. Significant assumptions and estimates include, but are not limited to, the cash flows that an asset is expected to generate in the future and what we believe to be an appropriate weighted-average cost of capital.
If the actual results differ from the estimates and judgments used in these estimates, the amounts recorded in the consolidated financial statements may be exposed to potential impairment of long-lived assets, including intangible assets and goodwill. Refer to Note 3 “Business combinations and dispositions” of our consolidated financial statements for further details.
Goodwill
We record the excess of purchase price over the fair value of the tangible and identifiable intangible assets acquired and liabilities assumed as goodwill. Goodwill is not subject to amortization and is tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired. A qualitative assessment is allowed to determine if goodwill is potentially impaired. We have the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the quantitative goodwill impairment test. The qualitative assessment determines whether it is more likely than not that a reporting unit’s fair value is less than its carrying amount. If it is more likely than not that the fair value of the reporting unit is less than the carrying amount, then a quantitative impairment test is performed. The quantitative goodwill impairment test is used to identify both the existence of impairment and the amount of impairment loss. The test compares the fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of the reporting unit is less than its carrying value, an impairment loss is recorded based on that difference.
No impairment expense was recorded for goodwill during the years ended December 31, 2025, 2024 and 2023. We used the income approach and the market approach to estimate the fair value of our reporting units. The income approach estimates the fair value by discounting the reporting unit’s estimated future cash flows using what we believe to be an appropriate risk-adjusted rate. The market approach includes the use of comparative multiples to corroborate the discounted cash flow results and involves significant judgment in the selection of the appropriate peer group companies and valuation multiples. The inputs used in the determination of fair value are generally level 3 inputs.
Income Taxes
We use the asset and liability method to account for income taxes whereby we calculate the deferred tax asset or liability account balances using tax laws and rates in effect at that time. Under this method, the balances of deferred tax liabilities and assets at the end of each period are determined using the tax rate expected to be in effect when taxes are actually paid or recovered. Valuation allowances are recorded to reduce gross deferred tax assets when it is more likely than not that all or some portion of the gross deferred tax assets will not be realized. In determining the need for valuation allowances, we have made judgments and considered estimates regarding estimated future taxable income and available tax planning strategies. These estimates and judgments include some degree of uncertainty, therefore changes in these estimates and assumptions could require us to adjust the valuation allowances for our deferred tax assets accordingly. The ultimate realization of the deferred tax assets depends on the generation of sufficient taxable income in the applicable taxing jurisdictions.
We operate in over 50 countries. As a result, we are subject to numerous domestic and foreign taxing jurisdictions and tax agreements and treaties among various governments. Determination of taxable income in any jurisdiction requires the interpretation of the related tax laws and regulations and the use of estimates and assumptions regarding future events, including the amount, timing and character of income, deductions, and tax credits. Changes in tax laws, regulations or agreements in each taxing jurisdiction could have an impact on the amount of income taxes that we provide during any given year.
Our tax filings for various periods are subject to audit by the tax authorities in most jurisdictions in which we operate, and these assessments can result in additional taxes. Estimating the outcome of audits and assessments by the tax authorities involves uncertainty. We review the facts of each case and apply judgments and assumptions to determine the most likely outcome and provide for taxes, interest and penalties on this basis. In line with GAAP, we recognize the effects of a tax position in the consolidated financial statements when it is more likely than not that, based on the technical merits, some level of tax benefit related to a tax position will be sustained upon audit by tax authorities. Our experience has been that the estimates and assumptions used to provide for future tax assessments have proven to be appropriate. However, past experience is only a guide, and the potential exists that tax resulting from the resolution of current and potential future tax disputes may differ materially from the amount accrued. In such an event, we will record additional tax expense or tax benefit in the period in which such resolution occurs.
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New accounting pronouncements
See Note 2 “Basis of presentation and significant accounting policies” in our consolidated financial statements under the heading “Recent accounting pronouncements.”