EXPRO GROUP HOLDINGS N.V. (XPRO)

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 2024 and 2023 items and year-to-year comparisons between 2024 and 2023. Discussions of 2022 items and year-to-year comparisons between 2023 and 2022 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, 2023.

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.

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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, 2024, approximately 82% of our revenue was generated outside of the United States and approximately 67% of our revenue was generated by activities related to offshore oil and gas operations. Approximately 68% of our revenue was generated by services tied to drilling and completions-related activities, which are generally funded by customers’ capital expenditures, and approximately 32% of our revenue was generated by production optimization related activities, which are generally funded by customers’ operating expenditures.

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Commodity Prices and Market Conditions

Commodity Prices

Average daily oil demand in the fourth quarter of 2024 exceeded the average daily demand levels in the fourth quarter of 2023, as well as the full year average for 2023, with liquid demand growing by 0.9 million b/d in 2024 over 2023. Brent crude oil prices remained relatively unchanged over the fourth quarter, averaging $74/bbl in both September and December 2024. The lack of price movement has been largely due to a relatively balanced market combined with an apparent reduction in geopolitical risk premia and weakening demand growth limiting upward pressure, with OPEC+ supply restrictions providing a floor for prices.

Market Conditions

We have continued to see positive market signs, as commodity prices remain generally supportive of the current levels of upstream investment and activity, despite a slowing in demand growth and the possibility of supply increases. Market uncertainty remains regarding the commitment and ability of OPEC+ to manage supply, geopolitical tensions and sanctioning impacts, tariffs, and macroeconomic factors. There are several market factors that have had, and may continue to have, an effect on our business, including:

Outlook

Global liquids demand increased in the fourth quarter of 2024 compared to the previous quarter and average year-on-year consumption is expected to continue to grow in 2025, though at a reduced rate. The market remained relatively balanced and oil prices were generally stable over the fourth quarter, with continued OPEC+ supply discipline offsetting an apparent reduction in geopolitical risk premia and weakening demand growth.

The U.S. Energy Information Administration (“EIA”) estimates that global liquids fuels demand will average 104.1 million b/d in 2025, increasing by 1.3 million b/d over 2024. Consumption is then expected to grow by a further 1.1 million b/d in 2026 to average 105.1 million b/d. Global growth in oil demand is slower than the pre-pandemic trend; average annual growth was 1.5 million b/d between 2010 and 2019. Non-OECD countries are expected to drive almost all forecasted demand growth. Much of this growth is in Asia, where India is now the leading source of global demand growth, driven by rising demand for transportation fuels. China’s liquid fuels consumption is estimated to increase by 0.2 million b/d in 2025, up from an increase of less than 0.1 million b/d in 2024, as economic stimulus efforts are expected to drive higher demand growth. OECD oil consumption is forecast to increase by 0.2 million b/d in 2025.

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The EIA estimates that global liquid fuels production will grow by 1.8 million b/d in 2025 to average 104.4 million b/d. Global liquid fuels supply is then predicted to grow a further 1.5 million b/d in 2026 to average 105.9 million b/d. Production growth in 2025 is due to a combination of an expected relaxation of OPEC+ production cuts and further production growth from countries outside of OPEC+. Countries outside of OPEC+, including the United States, Canada, Brazil and Guyana, are expected to lead the growth in oil production, collectively increasing by 1.6 million b/d. OPEC+ countries are expected to contribute 0.2 million b/d to global supply growth in 2025 as voluntary production cuts are expected to gradually unwind. OPEC+ output is expected to remain significantly below the group’s current targets, with continued OPEC+ supply management expected to avoid significant inventory increases and, therefore, price declines.

Oil prices remained largely flat over the fourth quarter of 2024 as global inventories remained balanced, despite tepid demand growth from China and a reduction in apparent geopolitical risk premia associated with on-going conflicts in the Middle East and Eastern Europe. Prices are expected to see modest upward movement in early 2025 before generally declining from mid-2025 through to 2026 as expected global oil production outpaces expected growth in oil demand. As a result, the EIA forecasts that the Brent price will average $74/bbl in 2025 and $66/bbl in 2026. The expected early 2025 increase in prices is largely because of the latest OPEC+ extension of production cuts leading to global oil inventory withdrawals. However, OPEC+ members are expected to increase production by the second quarter of 2025, which combined with further supply growth from outside of OPEC+ and relatively modest demand growth, will likely drive oil inventory builds. Potential inventory builds would be expected to put downward pressure on prices from the second quarter of 2025 onwards. Uncertainties remain regarding OPEC+ members’ commitment to continuing production restraint, conflicts and sanctioning, and global demand. As a general matter, if customers have confidence that oil prices will remain above $65/bbl to $70/bbl, we believe the outlook for our business is stable to positive.

Along with a relatively constructive oil market outlook, international natural gas prices remain supportive of continued activity as the market tightens further in 2025.

The EIA forecasts that Henry Hub prices will increase to average $3.14 per million British thermal units (“MMBtu”) in 2025, up from an average of $2.19/MMBtu in 2024. The Henry Hub price is then expected to increase further to average $3.97/MMBtu in 2026. The forecast price increase is driven by the expectation that U.S. natural gas demand, driven by LNG exports, will outpace supply from production and imports, leading to inventory draws. Rystad Energy predicts that the European Title Transfer Facility (“TTF”) and Northeast Asian LNG spot prices will average $12.10/MMBtu and $12.60/MMBtu respectively in 2025, and $10.20/MMBtu and $10.80/MMBtu respectively in 2026. The 2025 prices are an increase over 2024 due to ongoing cold weather in Europe and strong storage withdrawals, as well as the requirement for increased LNG imports to replenish inventories and replace lost Russia pipeline supply transiting through Ukraine which ceased on January 1, 2025. Asian spot prices are likely to follow the TTF over the medium term.

Consequently, the market outlook for 2025 remains stable with commodity prices and energy security requirements supporting continued levels of upstream investments, despite a slowing in growth, and subsequent activity. Declining onshore investment is offset by an expected healthy growth in the deepwater and offshore segments with support from large projects in NLA, particularly in Guyana, Brazil and Mexico, as well as contributions from the KSA, the UAE and China.

In summary, we expect demand for our products and services will continue to increase over the next several years, despite our expectations for a relatively flat-to-modest-growth market in 2025.

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The following provides an outlook for 2025 by our reporting segments based on data from Spears and Associates Inc:

NLA: North American drilling activity is expected to fall by 3% in 2025 to an average of 579 active rigs and 16,300 new wells completed. Operators are expected to complete around 10,800 frac jobs in 2025, holding steady from 2024. The decline in activity is largely due to an increase in the average well depth as operators (with sufficient contiguous surface acreage) are expected to increasingly choose to increase the lateral length of horizontal wells rather than increase the number of new wells drilled as their preferred means of increasing formation exposure both to lift/sustain well productivity and reduce their environment footprint and well costs. It is expected that relatively stable commodity prices and a new, more pro-energy U.S. administration will have only a modest impact on U.S. rig activity in 2025. Continued consolidation amongst operators will likely weigh on drilling activity in 2025, particularly in the Permian Basin. In Latin America, drilling activity is projected to decrease by 3% in 2025 to an average of 156 active rigs, accounting for over 2,100 new wells. Onshore drilling is now forecast to drop by 6% in 2025 to an average of 111 active land rigs drilling almost 1,800 new wells, while offshore activity is expected to rise by 7%, averaging 45 active rigs, totaling almost 320 new wells. Mexican offshore and mature fields, Argentinean shale, offshore Brazil and Colombia’s mature fields are expected to collectively account for 85% of overall Latin American rig activity in 2025, with on-going development activity in Guyana also contributing to increased activity.

ESSA: European drilling activity is projected to average 93 active rigs in 2025, down by 2%, accounting for almost 750 new wells. Onshore drilling in Europe is forecast to average 70 active rigs in 2025, down 1%, accounting for over 470 new wells drilled, while offshore drilling is expected to decline by 4%, averaging 23 active rigs with 275 new wells drilled. The main drivers of the decline in drilling activity are the outlook for oil prices and energy transition and fiscal policies in the UK, with the government planning to increase the rate and duration of the Energy Profits Levy. Ukraine and Norway are forecast to collectively account for around 65% of overall European rig activity in 2025. African drilling activity is expected to fall by 1% in 2025 to average 132 active rigs, accounting for a total of over 975 new wells. Onshore drilling is forecast to slow 2% to an average of 110 active land rigs, with over 730 new wells drilled, while offshore activity is projected to grow by 5% in 2025, averaging 22 active rigs, totaling almost 250 new wells drilled. Offshore activity growth is largely driven by exploration activity in Senegal and Namibia as well as development campaigns in Nigeria and Angola.

MENA: On the strength of higher activity in the UAE (driven by gas expansion developments) and Kuwait, drilling in the Middle East is now projected to average 340 active rigs in 2025, up by 3% on 2024, accounting for over 2,925 new wells. Onshore drilling is projected to increase by 4% in 2025 to an average of 302 active land rigs, drilling over 2,600 new wells, while offshore activity in the region is forecast to increase by 3% to an average of 38 active rigs, with over 300 new wells drilled. The KSA, Abu Dhabi and Iraq are expected to collectively account for around 60% of overall Middle Eastern rig activity in 2025.

APAC: Based on the outlook for oil prices, drilling activity in Asia-Pacific is forecast to average 192 active rigs in 2025, an increase of 1% over 2024, accounting for over 2,775 new wells drilled. Onshore drilling in the region is forecast to rise 2% to an average of 137 active land rigs and over 1,700 new wells while offshore drilling is expected to hold steady at an average of 55 active rigs totaling over 1,050 new wells. India, Indonesia and Australia remain the three most active drilling markets in APAC. Several large gas and LNG projects in these countries continue to drive activity as the region looks to meet an increase in global gas demand.

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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, 2024 compared to year ended December 31, 2023

Certain highlights of our financial results and other key developments include:

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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):

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Selected Unaudited Financial Information for the Three Months Ended December 31, 2024 and September 30, 2024

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, 2024 and September 30, 2024:

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, 2024 and September 30, 2024:

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Quarter ended December 31, 2024 compared to quarter ended September 30, 2024

NLA

Revenue for NLA was $139.3 million for the three months ended December 31, 2024, a decrease of $0.1 million, or 0.1%, compared to $139.4 million for the three months ended September 30, 2024. The modest decrease was primarily due to lower well construction revenue in the U.S., Canada, and Mexico and lower Coretrax revenue, offset by higher well flow management revenue in the U.S. and Brazil.

Segment EBITDA for NLA was $30.1 million, or 21.6% of revenue, during the three months ended December 31, 2024, compared to $33.1 million, or 23.7% of revenue, during the three months ended September 30, 2024. The decrease of $3.0 million in Segment EBITDA was largely attributable to a seasonal reduction in activity on higher margin well construction projects in the U.S. during the three months ended December 31, 2024.

ESSA

Revenue for ESSA was $142.8 million for the three months ended December 31, 2024, an increase of $11.3 million, or 8.6%, compared to $131.5 million for the three months ended September 30, 2024. The increase in revenue was primarily driven by higher subsea well access revenue in Angola, partially offset by lower well flow management in the U.K., Norway and Denmark, and lower well construction revenue in Senegal and Angola.

Segment EBITDA for ESSA was $53.0 million, or 37.1% of revenue, for the three months ended December 31, 2024, an increase of $20.8 million, or 64.7%, compared to $32.2 million, or 24.5% of revenue, for the three months ended September 30, 2024. The increase in Segment EBITDA and Segment EBITDA margin was primarily attributable to higher subsea well access revenue in Angola and a non-repeat of losses recognized on our Congo productions solutions project in the third quarter of 2024.

MENA

Revenue for MENA was $92.6 million for the three months ended December 31, 2024, an increase of $5.8 million, or 6.7%, compared to $86.7 million for the three months ended September 30, 2024. The increase in revenue was driven by higher well flow management services revenue in Algeria, Iraq and the KSA, partially offset by lower well intervention and integrity revenue in Qatar.

Segment EBITDA for MENA was $32.6 million, or 35.2% of revenue, for the three months ended December 31, 2024, an increase of $2.6 million, or 8.5%, compared to $30.0 million, or 34.6% of revenue, for the three months ended September 30, 2024. 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, 2024.

APAC

Revenue for APAC was $62.2 million for the three months ended December 31, 2024, a decrease of $3.0 million, or 4.6%, compared to $65.2 million for the three months ended September 30, 2024. The decrease in revenue was primarily due to lower well flow management revenue in Malaysia and Australia and lower well intervention and integrity revenue in Brunei, partially offset by higher subsea well access revenue in China and India.

Segment EBITDA for APAC was $15.5 million, or 24.8% of revenue, for the three months ended December 31, 2024, a decrease of $0.7 million compared to $16.2 million, or 24.8% of revenue, for the three months ended September 30, 2024.

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Results of Operations for the years ended December 31, 2024, 2023 and 2022

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, 2024, 2023 and 2022:

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, 2024, 2023 and 2022:

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Year ended December 31, 2024 compared to the year ended December 31, 2023

NLA

Revenue for NLA was $566.0 million for the year ended December 31, 2024, an increase of $54.2 million, or 10.6%, compared to $511.8 million for the year ended December 31, 2023. The increase in revenue is primarily due to higher subsea well access revenue in the U.S. and Trinidad and Tobago, higher well flow management revenue in the U.S. and Mexico, higher well intervention and integrity activity in South America and the Coretrax acquisition. These increases were partially offset by lower well construction revenue in the U.S. and Mexico.

Segment EBITDA for NLA was $142.0 million, or 25.1% of revenue, during the year ended December 31, 2024, compared to $132.9 million or 26.0% of revenue during the year ended December 31, 2023, an increase of $9.1 million. The increase in Segment EBITDA was attributable to increased activity, particularly related to the PRT acquisition and Coretrax acquisition, while the decrease in Segment EBITDA margin reflects reduced activity on high margin well construction activity during the year ended December 31, 2024.

ESSA

Revenue for ESSA was $564.4 million for the year ended December 31, 2024, an increase of $43.5 million, or 8.3%, compared to $521.0 million for the year ended December 31, 2023. The increase in revenue was primarily driven by increased subsea well access activity in Angola, higher well flow management revenue in the U.K., Norway and Denmark, and the Coretrax acquisition, partially offset by lower well flow management revenue in Congo.

Segment EBITDA for ESSA was $145.4 million, or 25.8% of revenue, during the year ended December 31, 2024, compared to $136.0 million, or 26.1% of revenue, during the year ended December 31, 2023, an increase of $9.4 million. The increase in Segment EBITDA was attributable to higher activity, particularly subsea well access activity in Angola, while the decrease in Segment EBITDA margin primarily reflects a decrease in expected margins for the construction phase of our Congo production solutions project during the year ended December 31, 2024.

MENA

Revenue for MENA was $332.2 million for the year ended December 31, 2024, an increase of $98.7 million, or 42.3%, compared to $233.5 million for the year ended December 31, 2023. The increase in revenue was driven by higher well flow management activity in the KSA and Algeria, higher well construction revenue in United Arab Emirates, Egypt and Oman, and the Coretrax acquisition.

Segment EBITDA for MENA was $115.8 million, or 34.8% of revenue, during the year ended December 31, 2024, compared to $71.2 million, or 30.5% of revenue during the year ended December 31, 2023. The increase of $44.6 million was attributable to increased activity on higher-margin well flow management projects in Algeria and additional activity as a result of the Coretrax acquisition during the year ended December 31, 2024.

APAC

Revenue for APAC was $250.1 million for the year ended December 31, 2024, an increase of $3.6 million, or 1.5%, compared to $246.5 million for the year ended December 31, 2023. The increase in revenue was primarily due to increased well construction activity in Indonesia and Australia, well flow management revenue in Thailand and the Coretrax acquisition. This was partially offset by lower subsea well access activity in Australia.

Segment EBITDA for APAC was $57.7 million, or 23.1% of revenue, during the year ended December 31, 2024, compared to $1.8 million, or 0.7% of revenue, during the year ended December 31, 2023. The increase in Segment EBITDA was primarily due to increased activity, particularly the additional activity as a result of the Coretrax acquisition and non-repeat of unrecoverable LWI-related costs in APAC. Excluding $35.9 million of unrecoverable LWI-related costs during the year ended December 31, 2023, APAC Segment EBITDA would have been $37.7 million and APAC Segment EBITDA margin would have been 15.3%.

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Corporate Costs

Corporate costs for the year ended December 31, 2024 increased by $24.0 million, or 22.6%, to $129.8 million, as compared to $105.9 million, for the year ended December 31, 2023. The increase in the corporate costs was due to higher research and development costs, higher corporate headcount, and Coretrax-related corporate costs. The remaining increase was generally proportional with increases in activity and revenue.

Equity in income of joint ventures

Equity in income of joint ventures for the year ended December 31, 2024 increased by $3.6 million, or 27.8%, to $16.4 million as compared to $12.9 million for the year ended December 31, 2023. The increase reflects higher income from our joint venture in China compared to the previous year.

Merger and integration expense

Merger and integration expense for the year ended December 31, 2024 increased by $6.6 million, to $16.3 million as compared to $9.8 million for the year ended December 31, 2023. The increase is attributable to the acquisition of Coretrax and ongoing integration expenses for the PRT and Coretrax acquisitions.

Severance and other expense

Severance and other expense for the year ended December 31, 2024 increased by $2.7 million, to $17.0 million as compared to $14.4 million for the year ended December 31, 2023. The increase was primarily attributable to the recognition of restructuring costs partially offset by a valuation adjustment of contingent consideration.

Stock-based compensation expense

Stock-based compensation expense for the year ended December 31, 2024 increased by $6.8 million, to $26.4 million as compared to $19.6 million for the year ended December 31, 2023. The increase is primarily attributable higher grant date fair value of stock-based compensation awarded in the 2024 annual LTIP grant cycle.

Foreign exchange loss

Foreign exchange loss for the year ended December 31, 2024 increased by $4.4 million, to $13.6 million as compared to $9.2 million for the year ended December 31, 2023. The change was primarily due to unfavorable changes in various exchange rates, including the Argentine Peso, and higher activity in jurisdictions with local currencies that depreciated relative to the U.S. dollar.

Interest and finance expense, net

Interest and finance expense, net, for the year ended December 31, 2024, was $12.5 million compared to $3.9 million for the year ended December 31, 2023. The increase in interest and finance expense of $8.6 million was primarily due to the Coretrax acquisition and the resulting higher average balances on our revolving credit facility in 2024.

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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, 2024, total available liquidity was $320.3 million, including cash and cash equivalents and restricted cash of $184.7 million and $135.6 million available for borrowings under our Amended and Restated Facility Agreement. 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 $120.0 million and $130.0 million for 2025. Our total capital expenditures were $143.6 million for the year ended December 31, 2024, 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 December 12, 2024, the Company’s Board of Directors (the “Board”) approved an extension to its stock repurchase program, pursuant to which the Company is authorized to acquire up to $100.0 million of its outstanding common stock from October 25, 2023 through November 24, 2025 (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, 2024 and 2023, we repurchased approximately 1.2 million shares in each year of our common stock under the Stock Repurchase Program for a total cost of approximately $14.2 million and $20.0 million, respectively. Approximately $75.8 million remained authorized for repurchases under the Stock Repurchase Program as of December 31, 2024, subject to the limitation set in our shareholder authorization for repurchases of our common stock.

Credit Facility

Revolving Credit Facility

On October 6, 2023, we amended and restated our previous revolving credit facility agreement pursuant to an amendment and restatement agreement (the “Amended and Restated Facility Agreement”) with DNB Bank ASA, London Branch, as agent in order to extend the maturity of the Amended and Restated Facility Agreement for a further 36 months and increase the total commitments to $250.0 million, of which $166.7 million was available for drawdowns as loans and $83.3 million was available for letters of credit. The Company has the ability to increase the commitments to $350.0 million.

On May 15, 2024, the Company established an incremental facility under its Amended and Restated Facility Agreement, in order to increase its existing $250.0 million revolving credit facility by an additional $90.0 million in commitments, to a total of $340.0 million. The establishment of the incremental facility was accomplished by a notice entered into with DNB Bank ASA as Agent, together with a consortium of banks as lenders. The incremental facility has the same terms and conditions as the existing facility provided under the Amended and Restated Facility Agreement. The incremental facility is available for the same general corporate purposes as the existing facility provided under the Amended and Restated Facility Agreement, including acquisitions. On May 15, 2024, the Company drew down on the new facility in the amount of approximately $76.1 million to partially finance the acquisition of Coretrax.

Please see Note 16 “Interest bearing loans” in the Notes to the Consolidated Financial Statements for additional information.

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Cash flow from operating, investing and financing activities

Cash flows provided by our operations, investing and financing activities are summarized below (in thousands):

Analysis of cash flow changes between the years ended December 31, 2024 and 2023

Net cash provided by operating activities

Net cash provided by operating activities was $169.5 million during the year ended December 31, 2024 as compared to $138.3 million during the year ended December 31, 2023. The increase in net cash provided by operating activities of $31.2 million for the year ended December 31, 2024, was primarily driven by an increase in Adjusted EBITDA partially offset by an increase in working capital, and an increase in cash paid for severance and other expenses.

Net cash used in investing activities

Net cash used in investing activities was $165.1 million during the year ended December 31, 2024 as compared to $148.2 million during the year ended December 31, 2023, an increase of $16.9 million, which includes an increase in capital expenditures of $21.5 million.

Net cash provided by (used in) financing activities

Net cash provided by financing activities was $29.6 million during the year ended December 31, 2024 as compared to net cash used in financing activities of $49.3 million during the year ended December 31, 2023. The change in net cash provided by financing activities is primarily due to the net proceeds received from borrowings of $88.0 million and the decrease in repurchases of common stock of $5.9 million, partially offset by payment of acquisition-related contingent consideration of $13.9 million during the current year.

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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, 2024, 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.

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, 2024, 2023 and 2022. 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.

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Defined benefit plans

Our post-retirement benefit obligations are described in detail in Note 19 “Post-retirement benefits” of our consolidated financial statements. Defined pension benefits are calculated using significant inputs to the actuarial models that measure pension benefit obligations and related effects on operations. Two assumptions, discount rate and expected return on assets, are important elements of plan asset/liability measurement and are updated on an annual basis, or more frequently if events or changes in circumstances so indicate.

We evaluate these critical assumptions at least annually on a plan and country specific basis. We periodically evaluate other assumptions involving demographic factors such as retirement age, mortality and turnover, and update them to reflect our experience and expectations for the future. Actual results in any given year will often differ from actuarial assumptions because of economic and other factors.

The discount rate that we use reflects the market rate of a portfolio of high-quality corporate bonds with maturities approximately matching the expected timing of payment of the related benefit obligations. The discount rates used to determine the benefit obligations for our principal pension plans were 5.4% in 2024, 4.5% in 2023 and 4.7% in 2022, reflecting market interest rates. As of December 31, 2024, we estimate that a 1% increase or decrease in the discount rate would result in an impact of approximately $16.4 million to our present value of defined benefit obligations as of December 31, 2024.

The expected rate of return on plan assets represents the average rate of return expected to be earned on plan assets over the period that benefits included in the benefit obligation are expected to be paid, with consideration given to the distribution of investments by asset class and historical rates of return for each individual asset class. The weighted average expected rate of return on plan assets for the pension plans was 6.5% in 2024, 5.8% in 2023 and 5.6% in 2022. A change in the expected rate of return of 1% would impact our net periodic pension expense by $1.3 million.

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.

New accounting pronouncements

See Note 2 “Basis of presentation and significant accounting policies” in our consolidated financial statements under the heading “Recent accounting pronouncements.”

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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 2023 and 2022 items and year-to-year comparisons between 2023 and 2022. Discussions of 2021 items and year-to-year comparisons between 2022 and 2021 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, 2022.

Unless otherwise indicated, references to the terms “Frank’s” refers to Frank’s International N.V., the predecessor reporting entity prior to the Merger, references to “Legacy Expro” refer to Expro Group Holdings International Limited, the entity acquired by the Company, and references to “Expro,” the “Company,” “we,” “our,” and “us” refer to Expro Group Holdings N.V., following the consummation of the Merger and unless the context otherwise requires, Frank’s prior to the consummation of the Merger.

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. The Company’s extensive portfolio of capabilities spans well construction, well flow management, subsea well access, and well intervention and integrity solutions.

With roots dating to 1938, we have approximately 8,000 employees and provide services and solutions to leading exploration and production companies in both onshore and offshore environments in approximately 60 countries.

Our broad portfolio of products and services are designed to enhance production and improve recovery across the well lifecycle from exploration through abandonment, including:

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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.

For the year ended December 31, 2023, approximately 82% of our revenue was generated outside of the United States and approximately 66% of our revenue was generated by activities related to offshore oil and gas operations. Approximately 63% of our revenue was generated by services tied to drilling and completions-related activities, which are generally funded by customers’ capital expenditures, and approximately 37% of our revenue was generated by production optimization related activities, which are generally funded by customers’ operating expenditures.

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Market Conditions and Price of Oil and Gas

The fourth quarter of 2023 has seen continued growth and increased activity as the market rebounds from the effects of the COVID-19 pandemic and Russia’s invasion of Ukraine, with limited effect currently from the heightened tensions resulting from the ongoing conflicts in the Middle East. There are a number of market factors that have had, and may continue to have, an effect on our business, including:

Outlook

Global liquids demand growth continued in the final quarter of 2023 and is forecast to continue to grow in 2024. Demand growth combined with a slowing production growth due to the extension of voluntary OPEC+ supply cuts, as well as reduced non-OPEC supply growth, is expected to lead to inventory withdrawals in the first quarter of 2024, which in turn will continue to support higher oil prices.

The U.S. Energy Information Administration (“EIA”) predicts that global liquid fuels consumption will average 102.5 million b/d in 2024, continuing growth from pre-pandemic levels and increasing by 1.4 million b/d over 2023. Global liquids demand is then expected to grow by an additional 1.2 million b/d to reach 103.7 million b/d in 2025. Global liquids demand growth is mostly from countries outside the Organization for Economic Co-operation and Development (“OECD”) in Asia, led by China and India, with OECD countries demand growth expected to remain mostly flat in 2024 and 2025.

The EIA forecasts that global liquids production will average 102.3 million b/d in 2024 - an increase of 0.6 million b/d over 2023 – and average 104.0 million b/d in 2025, a further 1.6 million b/d increase over 2024. Supply growth in 2024 is down from the increases seen in 2023 as a result of extended OPEC+ production cuts and slowing non-OPEC growth. OPEC+ crude oil production is expected to decline by 0.6 million b/d in 2024, which is offset by 1.2 million b/d production growth outside of the group. The main drivers of the slowdown in production growth are the United States, Canada and Brazil, offset by supply growth from Guyana.

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As a result of the inventory withdrawals expected in the first quarter of 2024, the EIA forecasts that Brent prices will average $85/bbl for this period. Supply and demand dynamics are then expected to improve with relatively balanced markets for the remainder of 2024 placing downward pressure on crude oil prices. As a result, the EIA expects Brent crude oil prices to average $82/bbl for 2024 and $79/bbl for 2025.

In addition to the continued positive oil market outlook, global natural gas prices are expected to remain elevated as the market remains fundamentally tight.

The EIA estimates that annual average Henry Hub prices will remain under $3.00 per million British thermal unit (“MMBtu”) for 2024 and 2025, though they are expected to increase from an average of $2.54/MMBtu in 2023 to reach $2.66/MMBtu in 2024 and $2.95/MMBtu in 2025, respectively. The modest increase in prices is driven by an increase in LNG exports, however, further upward pricing pressure is limited by high levels of inventory. Rystad Energy forecasts spot prices at the European Title Transfer Facility and Northeast Asian LNG will average $12.20/MMBtu and $13.20/MMBtu respectively for 2024, as balances have loosened through a milder winter. Prices are expected to see higher than normal volatility where shocks in demand or supply may drive short-term price spikes.

Consequently, the market outlook for 2024 is generally constructive with high commodity prices relative to the last several years driving growth in exploration and production expenditures and the highest level of upstream investment expected since 2015. Strong investment growth is expected in the deepwater and offshore shelf segments with support from large projects in Norway, Brazil, Guyana and the continuation of production capacity expansion projects in the Middle East, driven by Saudi Arabia, the United Arab Emirates and Qatar.

As a result, we expect demand for our services and solutions to continue trending positively throughout 2024. The following provides an outlook for 2024 by our reporting segments based on data from Spears and Associates, Inc.

NLA: Drilling activity in North America is forecast to decline by 6% in 2024 to an average of 648 active rigs as both large and small operators strive for continued capital discipline, creating a ceiling on potential growth as they prioritize financial returns. Completion activity is expected to hold steady in 2024, with a total of about 18,100 well completions and 13,000 frac jobs. The uptick in merger and acquisition activity in 2023 and continuing into 2024 may contribute to a slower recovery in drilling activity as new owners prioritize production growth from existing assets. In Latin America, drilling activity is estimated to increase by 6% in 2024 to an average of 191 active rigs, accounting for over 2,500 new wells driven by Mexico, Argentina and Brazil. Mexico, Argentina and Colombia are expected to collectively account for 75-80% of overall Latin American rig activity in 2024. After Brazil, the top four producing nations in Latin America are Mexico, Venezuela, Colombia and Argentina, with Guyana expected to soon take over third place.

ESSA: European drilling activity is now expected to average 101 active rigs in 2024, up by 4%, accounting for over 850 new wells. Ukraine, Norway and the U.K. are expected to collectively account for over approximately 75% of overall European rig activity in 2024. Onshore drilling in Europe is forecast to average 68 active rigs in 2024, up by 5%, accounting for over 450 new wells. Offshore drilling activity is predicted to grow by 3% in 2024, averaging 33 active rigs as North Sea activity is constrained by the exodus of rigs from Norwegian waters for international contracts in Namibia, Brazil and Australia. Drilling activity in Africa is projected to average 156 active rigs in 2024, up by 15%, accounting for almost 1,250 new wells, with activity in Namibia and Uganda continuing to increase. Onshore drilling activity is expected to improve by 16% in 2024 to average 124 active rigs, drilling 850 new wells, while offshore drilling activity is predicted to increase by 10% to average 32 active rigs, drilling around 375 new wells.

MENA: In the Middle East, drilling activity is now expected to average 343 active rigs in 2024, up by 9%, accounting for almost 2,600 new wells. Saudi Arabia, Iraq and Abu Dhabi are expected to collectively account for around 65% of overall Middle Eastern rig activity in 2024. The growth is driven by analysts estimates that state-owned national oil companies in the region could potentially spend up to $100 billion this year on upstream investment, despite some projections that crude oil could reach peak demand before the end of this decade. Onshore drilling in the Middle East is now projected to increase by 10% in 2024 to an average of 296 active land rigs, drilling about 2,500 new wells, while offshore activity is forecast to increase by 12%, averaging 46 active rigs drilling almost 340 new wells. In addition, there is increasing focus on carbon capture, utilization and storage projects, with one NOC recently doubling its CO2 capture target, for example

APAC: Based on the outlook for oil prices, drilling activity in the Asia Pacific region is now forecast to average 191 active rigs in 2024, up by 6%, accounting for almost 2,800 new wells. India, Indonesia and Australia are projected to collectively account for around 75% of overall rig activity in the region in 2024. Onshore drilling in the region is forecast to increase by 5% to average 143 active land rigs drilling about 1,750 new wells, while offshore activity is projected to rise by 7% to an average of 48 active rigs, accounting for a total of almost 1,050 new wells. LNG development projects are driving the activity growth in Australia and Indonesia as operators look to meet the increased global demand driven by energy security concerns and the energy transition.

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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, Adjusted EBITDA, Adjusted Cash Flow from Operations and Cash Conversion.

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 Cash Flow from Operations: We regularly evaluate our operating cash flow performance using Adjusted Cash Flow from Operations. Our management believes Adjusted Cash Flow from Operations is a useful tool to measure the operating cash performance of the Company as it excludes exceptional payments, interest payments and non-cash charges not related to our core operating activities and allows more meaningful analysis of the trends and performance of our core operations.

Cash Conversion: We regularly evaluate our efficiency of generating cash from operations using Cash Conversion which provides a useful tool to measure Adjusted Cash Flow from Operations as a percentage of Adjusted EBITDA.

Adjusted EBITDA, Adjusted Cash Flow from Operations and Cash Conversion are non-GAAP financial measures. 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 accounting principles generally accepted in the United States of America (“GAAP”) and a reconciliation of Adjusted Cash Flow from Operations to net cash provided by (used in) operating activities, the most directly comparable liquidity measure calculated and presented in accordance with GAAP.

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Executive Overview

Year ended December 31, 2023 compared to year ended December 31, 2022

Certain highlights of our financial results and other key developments include:

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Non-GAAP Financial Measures

We include in this Form 10-K the non-GAAP financial measures Adjusted EBITDA, Adjusted EBITDA margin, Adjusted Cash Flow from Operations and Cash Conversion. We provide reconciliations of net income (loss), the most directly comparable financial performance measure calculated and presented in accordance with GAAP, to Adjusted EBITDA. We also provide a reconciliation of Adjusted Cash Flow from Operations to net cash provided by (used in) operating activities, the most directly comparable liquidity measure calculated and presented in accordance with GAAP.

Adjusted EBITDA, Adjusted EBITDA margin, Adjusted Cash Flow from Operations and Cash Conversion 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 revenues.

We define Adjusted Cash Flow from Operations as net cash provided by (used in) operating activities adjusted for cash paid during the period for interest, net, severance and other expense and merger and integration expense. We define Cash Conversion as Adjusted Cash Flow from Operations divided by Adjusted EBITDA.

Adjusted EBITDA, Adjusted EBITDA margin, Adjusted Cash Flow from Operations and Cash Conversion 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, Adjusted Cash Flow from Operations and Cash Conversion may be defined differently by other companies in our industry, our presentation of Adjusted EBITDA, Adjusted Cash Flow from Operations and Cash Conversion 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 loss to Adjusted EBITDA for each of the periods presented (in thousands):

The following table provides a reconciliation of net cash provided by operating activities to Adjusted Cash Flow from Operations for each of the periods presented (in thousands):

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Selected Unaudited Financial Information for the Three Months Ended December 31, 2023 and September 30, 2023

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, 2023 and September 30, 2023:

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 (loss) before income taxes for the three months ended December 31, 2023 and September 30, 2023:

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Quarter ended December 31, 2023 compared to quarter ended September 30, 2023

NLA

Revenue for the NLA segment was $145.5 million for the three months ended December 31, 2023, an increase of $40.2 million, or 38.2%, compared to $105.3 million for the three months ended September 30, 2023. The increase was primarily due to additional subsea well access revenue following the acquisition of PRT Offshore at the beginning of the fourth quarter, higher well flow management revenue in Mexico, and higher well construction revenue in the U.S. due to increased customer activity.

Segment EBITDA for the NLA segment was $44.3 million, or 30.5% of revenues, during the three months ended December 31, 2023, compared to $20.0 million, or 19.0% of revenues, during the three months ended September 30, 2023. The increase of $24.3 million in Segment EBITDA was attributable to higher activity and the increase in Segment EBITDA margin was attributable to improved operating leverage and a more favorable activity mix during the three months ended December 31, 2023.

ESSA

Revenue for the ESSA segment was $133.8 million for the three months ended December 31, 2023, a decrease of $1.6 million, or 1.2%, compared to $135.4 million for the three months ended September 30, 2023. The decrease in revenues was primarily driven by lower well flow management revenue in Congo, partially offset by higher well flow management and subsea well access revenue in Equatorial Guinea.

Segment EBITDA for the ESSA segment was $41.0 million, or 30.6% of revenues, for the three months ended December 31, 2023, an increase of $1.7 million, or 4.3%, compared to $39.3, or 29.0% of revenues, for the three months ended September 30, 2023. The increase in Segment EBITDA and Segment EBITDA margin was primarily attributable to a more favorable activity mix during the three months ended December 31, 2023.

MENA

Revenue for the MENA segment was $65.4 million for the three months ended December 31, 2023, an increase of $7.3 million, or 12.6%, compared to $58.1 million for the three months ended September 30, 2023. The increase in revenue was driven by higher well flow management services revenue in Algeria and the Kingdom of Saudi Arabia and by higher well construction revenue in Morocco.

Segment EBITDA for the MENA segment was $21.3 million, or 32.5% of revenues, for the three months ended December 31, 2023, an increase of $4.4 million, or 26.0%, compared to $16.9 million, or 29.1% of revenues, for the three months ended September 30, 2023. The increase in Segment EBITDA and Segment EBITDA margin was primarily due to higher activity, improved operating leverage and a more favorable activity mix during the three months ended December 31, 2023.

APAC

Revenue for the APAC segment was $62.1 million for the three months ended December 31, 2023, a decrease of $9.0 million, or 12.7%, compared to $71.1 million for the three months ended September 30, 2023. The decrease in revenue was primarily due to lower subsea well access revenue in Australia, where we suspended vessel-deployed LWI operations, and China, partially offset by higher subsea well access revenue in Malaysia and well flow management revenue in Malaysia and Australia.

Segment EBITDA for the APAC segment was $5.3 million, or 8.6% of revenues, for the three months ended December 31, 2023, an increase of $9.6 million compared to ($4.3) million, or (6.0)% of revenues, for the three months ended September 30, 2023. The increase in Segment EBITDA (despite the decrease in revenues) was primarily due to lower operating costs within our LWI business during the three months ended December 31, 2023 following our suspension of vessel-deployed LWI operations during the third quarter of 2023. For the three months ended December 31, 2023, Segment EBITDA includes unrecoverable LWI-related costs of $4.3 million. Segment EBITDA for the three months ended September 31, 2023 include unrecoverable LWI-related costs of $15.3 million. Excluding unrecoverable LWI-related costs, APAC Segment EBITDA for the fourth and third quarter of 2023 would have been $9.6 million or 15.5% of revenue and $11.0 million or 15.5% of revenue, respectively.

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Results of Operations for the years ended December 31, 2023, 2022 and 2021

Operating Segment Results

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.

The following table shows revenue by segment and revenue as a percentage of total revenue by segment for the years ended December 31, 2023, 2022 and 2021:

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The following table shows Segment EBITDA and Segment EBITDA margin by segment and a reconciliation to income (loss) before income taxes for the years ended December 31, 2023 and December 31, 2022:

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Year ended December 31, 2023 compared to the year ended December 31, 2022

NLA

Revenue for the NLA segment was $511.8 million for the year ended December 31, 2023, an increase of $12.0 million, or 2.4%, compared to $499.8 million for the year ended December 31, 2022. The increase in revenue is primarily due to higher subsea well access revenue in the U.S., higher well intervention and integrity activity in South America, and higher well construction activity in Mexico, offset by lower well flow management revenue in Mexico and Canada.

Segment EBITDA for the NLA segment was $132.9 million, or 26.0% of revenues, during the year ended December 31, 2023, compared to $135.2 million or 27.1% of revenues during the year ended December 31, 2022, a decrease of $2.3 million. The decrease was attributable to less favorable activity mix during the year ended December 31, 2023.

ESSA

Revenue for the ESSA segment was $521.0 million for the year ended December 31, 2023, an increase of $131.7 million, or 33.8%, compared to $389.3 million for the year ended December 31, 2022. The increase is primarily attributable to higher well flow management revenue during the year ended December 31, 2023, driven by a long-term, LNG related construction project in Congo. The increase in Congo revenue was supplemented by higher well intervention and integrity revenue in the U.K. and higher subsea well access revenue in Central and West Africa, Angola and Azerbaijan partially offset by lower subsea revenue in Norway. Also contributing to the increase in revenue was higher well construction revenue in Southeast Africa, offset by lower well construction revenue in Norway.

Segment EBITDA for the ESSA segment was $136.0 million, or 26.1% of revenues, during the year ended December 31, 2023, compared to $74.7 million, or 19.2% of revenues, during the year ended December 31, 2022, an increase of $61.3 million. The increase was attributable to higher activity, improved absorption of geography-based support costs, and more favorable activity mix during the year ended December 31, 2023.

MENA

Revenue for the MENA segment was $233.5 million for the year ended December 31, 2023, an increase of $32.0 million, or 15.9%, compared to $201.5 million for the year ended December 31, 2022. The increase was driven by higher well flow management, well construction and well intervention and integrity revenue in Saudi Arabia, and higher well construction revenue in the United Arab Emirates, Egypt, and Morocco.

Segment EBITDA for the MENA segment was $71.2 million, or 30.5% of revenues, during the year ended December 31, 2023, compared to $63.3 million, or 31.4% of revenues during the year ended December 31, 2022. The increase of $7.9 million was attributable to higher activity during the year ended December 31, 2023.

APAC

Revenue for the APAC segment was $246.5 million for the year ended December 31, 2023, an increase of $57.7 million, or 30.6%, compared to $188.8 million for the year ended December 31, 2022. The increase was primarily attributable to higher subsea well access revenue in Australia, China and Malaysia. Also contributing to the increase was higher well intervention and integrity and well construction activity in Southeast Asia.

Segment EBITDA for the APAC segment was $1.8 million, or 0.7% of revenues, during the year ended December 31, 2023, compared to $4.9 million, or 2.6% of revenues, during the year ended December 31, 2022. The decrease in Segment EBITDA despite the increase in revenues was primarily due to unrecoverable LWI-related costs in APAC of $35.9 million incurred during the year ended December 31, 2023. Comparatively, during the year ended December 31, 2022, the Company incurred unrecoverable LWI-related costs of $27.7 million. Excluding $35.9 million and $27.7 million of unrecoverable LWI-related costs during the years ended December 31, 2023 and 2022, respectively, APAC Segment EBITDA would have been $37.7 million and $32.6 million and APAC segment Adjusted EBITDA margin would have been 15.3% and 17.3%, respectively.

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Corporate Costs

Corporate costs for the year ended December 31, 2023 increased by $18.3 million, or 20.9%, to $105.9 million, as compared to $87.6 million, for the year ended December 31, 2022. The increase in the corporate costs is generally proportional with increases in activity and revenue year over year.

Equity in income of joint ventures

Equity in income of joint ventures for the year ended December 31, 2023 decreased by $2.8 million, or 17.8%, to $12.9 million as compared to $15.7 million for the year ended December 31, 2022. The decrease reflects lower income from our joint venture in China compared to the previous year.

Depreciation and amortization expense

Depreciation and amortization expense for the year ended December 31, 2023 increased by $32.5 million or 23.2% to $172.3 million as compared to $139.8 million for the year ended December 31, 2022. The increase was primarily due to $19.3 million of accelerated depreciation expense related to the subsea module (“SSM”) of Expro’s vessel-deployed LWI system and related equipment.

Merger and integration expense

Merger and integration expense for the year ended December 31, 2023 decreased by $3.8 million, to $9.8 million as compared to $13.6 million for the year ended December 31, 2022. The decrease was primarily attributable to lower legal and other professional fees, and lower integration and other costs related to acquisitions incurred during the year ended December 31, 2023 as compared to the year ended December 31, 2022.

Severance and other expense

Severance and other expense for the year ended December 31, 2023 increased by $6.6 million, to $14.4 million as compared to $7.8 million for the year ended December 31, 2022. The increase was primarily attributable to unrecoverable LWI-related costs and a change in the fair value of deferred consideration.

Other income

Other income for the year ended December 31, 2023 was $1.2 million as compared to other income of $3.1 million for the year ended December 31, 2022. The decrease of $1.9 million is primarily attributable to increase in interest cost on post retirement benefits.

Interest and finance expense, net

Interest and finance expense, net, for the year ended December 31, 2023, was $3.9 million compared to $0.2 million for the year ended December 31, 2022. The increase in interest and finance expense of $3.7 million was primarily due to fees incurred with respect to the Amended and Restated Facility Agreement (as defined below) established during the year ended December 31, 2023.

Income tax (expense) benefit

Income tax expense for the year ended December 31, 2023 was $44.3 million, compared to an income tax expense of $41.2 million for the year ended December 31, 2022. Our statutory tax rate for the years ended December 31, 2023 and December 31, 2022 was 25.8%. The effective tax rate was 547.4% and 768.0% for the years ended December 31, 2023 and 2022 respectively. Our effective income tax rate fluctuates from the statutory tax rate based on, among other factors, changes in pretax income in jurisdictions with varying statutory tax rates along with jurisdictions utilizing a deemed profit taxation regime, the impact of valuation allowances, foreign inclusions and other permanent differences related to the recognition of income and expense.

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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, 2023, total available liquidity was $298.4 million, including cash and cash equivalents and restricted cash of $151.7 million and $146.7 million available for borrowings under our Amended and Restated Facility Agreement. 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 $130.0 million and $140.0 million for 2024. Our total capital expenditures were $122.1 million for the year ended December 31, 2023, 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 25, 2023, the Board approved an extension to the stock repurchase program first approved on June 16, 2022. Pursuant to the extended stock repurchase program, we are authorized to acquire up to $100.0 million of our outstanding common stock from October 25, 2023 through November 24, 2024 (the “Stock Repurchase Program”). Under the Stock Repurchase Program, we may repurchase shares of our 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 year ended December 31, 2023, under the Stock Repurchase Program we repurchased 1.2 million shares of our common stock at an average price of $16.70 for a total cost of approximately $20.0 million, including shares repurchased prior to the extension of the Stock Repurchase Program. During the year ended December 31, 2022, we repurchased 1.1 million shares at an average price of $11.81 per share, for a total cost of $13.0 million under the preceding program.

Credit Facility

Revolving Credit Facility

On October 6, 2023, we amended and restated our previous facility agreement pursuant to an amendment and restatement agreement (the “Amended and Restated Facility Agreement”) with DNB Bank ASA, London Branch, as agent in order to extend the maturity of the Amended and Restated Facility Agreement for a further 36 months and increase the total commitments to $250.0 million, of which $166.7 million was available for drawdowns as loans and $83.3 million was available for letters of credit. The Company has the ability to increase the commitments to $350.0 million.

Please see Note 16 “Interest bearing loans” in the Notes to the Consolidated Financial Statements for additional information.

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Cash flow from operating, investing and financing activities

Cash flows provided by our operations, investing and financing activities are summarized below (in thousands):

Analysis of cash flow changes between the years ended December 31, 2023 and 2022

Net cash provided by operating activities

Net cash provided by operating activities was $138.3 million during the year ended December 31, 2023 as compared to $80.2 million during the year ended December 31, 2022. The increase in net cash provided by operating activities of $58.1 million, was primarily driven by an increase in Adjusted EBITDA of $42.7 million and favorable movement in working capital by $22.0 million, partially offset by higher payments for income taxes of $11.1 million for the year ended December 31, 2023.

Adjusted Cash Flow from Operations during the year ended December 31, 2023 was $170.2 million compared to $115.3 million during the year ended December 31, 2022. Our primary uses of net cash provided by operating activities were capital expenditures, acquisitions and repurchases of company stock.

Net cash used in investing activities

Net cash used in investing activities was $148.2 million during the year ended December 31, 2023 as compared to $71.2 million during the year ended December 31, 2022, an increase of $77.0 million. Our principal recurring investing activity is our capital expenditures. The increase in net cash used in investing activities was primarily due to increase in capital expenditures of $40.0 million, payment for acquisition of business of $28.7 million, lower proceeds from sale/maturity of investments of $10.8 million and lower proceeds from disposal of assets of $5.2 million. In addition, cash used to acquire technology of $7.9 million during 2022 was not repeated in 2023.

Net cash used in financing activities

Net cash used in financing activities was $49.1 million during the year ended December 31, 2023 as compared to $25.6 million during the year ended December 31, 2022. The increase of $23.5 million in net cash used in financing activities is primarily due to net repayments of long term borrowings of $15.1 million and an increase in the repurchase of our common stock of $7.0 million.

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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 has, or is likely to have, a material effect on our consolidated financial statements. As of December 31, 2023, 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 revenues 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.

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, 2023, 2022 and 2021. 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.

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Defined benefit plans

Our post-retirement benefit obligations are described in detail in Note 19 “Post-retirement benefits” of our consolidated financial statements. Defined pension benefits are calculated using significant inputs to the actuarial models that measure pension benefit obligations and related effects on operations. Two assumptions, discount rate and expected return on assets, are important elements of plan asset/liability measurement and are updated on an annual basis, or more frequently if events or changes in circumstances so indicate.

We evaluate these critical assumptions at least annually on a plan and country specific basis. We periodically evaluate other assumptions involving demographic factors such as retirement age, mortality and turnover, and update them to reflect our experience and expectations for the future. Actual results in any given year will often differ from actuarial assumptions because of economic and other factors.

The discount rate that we use reflects the market rate of a portfolio of high-quality corporate bonds with maturities approximately matching the expected timing of payment of the related benefit obligations. The discount rates used to determine the benefit obligations for our principal pension plans were 4.5% in 2023, 4.7% in 2022 and 1.8% in 2021, reflecting market interest rates. As of December 31, 2023, we estimate that a 1% increase or decrease in the discount rate would result in an impact of approximately $19.7 million to our present value of defined benefit obligations as of December 31, 2023.

The expected rate of return on plan assets represents the average rate of return expected to be earned on plan assets over the period that benefits included in the benefit obligation are expected to be paid, with consideration given to the distribution of investments by asset class and historical rates of return for each individual asset class. The weighted average expected rate of return on plan assets for the pension plans was 5.8% in 2023, 5.6% in 2022 and 3.2% in 2021. A change in the expected rate of return of 1% would impact our net periodic pension expense by $1.4 million.

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 approximately 60 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.

New accounting pronouncements

See Note 2 “Basis of presentation and significant accounting policies” in our consolidated financial statements under the heading “Recent accounting pronouncements”.

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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 2022 and 2021 items and year-to-year comparisons between 2022 and 2021. Discussions of 2020 items and year-to-year comparisons between 2021 and 2020 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, 2021.

Unless otherwise indicated, references to the terms “Frank’s” refers to Frank’s International N.V., the predecessor reporting entity prior to the Merger, references to “Legacy Expro” refer to Expro Group Holdings International Limited, the entity acquired by the Company, and references to “Expro,” the “Company,” “we,” “our,” and “us” refer to Expro Group Holdings N.V., following the consummation of the Merger and unless the context otherwise requires, Frank’s prior to the consummation of the Merger.

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. The Company’s extensive portfolio of capabilities spans well construction, well flow management, subsea well access, and well intervention and integrity solutions.

With roots dating to 1938, we have approximately 7,600 employees and provide services and solutions to leading exploration and production companies in both onshore and offshore environments in approximately 60 countries.

Our broad portfolio of products and services are designed to enhance production and improve recovery across the well lifecycle from exploration through abandonment, including:

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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) NLA, (ii) ESSA, (iii) MENA and (iv) 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, 2022, approximately 79% of our revenue was generated outside of the United States and approximately 70% of our revenue was generated by activities related to offshore oil and gas operations. Approximately 70% of our revenue was generated by services tied to drilling and completions-related activities, which are generally funded by customers’ capital expenditures, and approximately 30% of our revenue was generated by production optimization related activities, which are generally funded by customers’ operating expenditures rather than capital expenditures.

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Market Conditions and Price of Oil and Gas

Fiscal year 2022 has seen positive signs of recovery in the market following the impact of the COVID-19 pandemic and the Russian war in Ukraine. There are a number of market factors that have had, and may continue to have, an effect on our business, including:

Outlook

Demand continues to improve despite volatile oil prices, with oil demand forecast to return to pre-pandemic levels in early 2023. The U.S. Energy Information Administration (“EIA”) estimates that global liquids consumption will increase from an average of 99.4 million barrels per day ("b/d") in 2022 to 100.5 million b/d in 2023 (approximating 2019 consumption levels) and rise further to 102.2 million b/d in 2024.  The EIA expects continued OPEC+ production growth in 2023 and a further increase of 0.8 million b/d over 2022, to average 29.5 million b/d in 2024. The increase in OPEC+ production along with growth in U.S. oil production in 2023 (expected to rise to 12.4 million b/d in 2023 and 12.8 million b/d in 2024, greater than the highest annual average U.S. crude oil production on record) is expected to lead to an overall build in global oil inventories in 2023.  As a result, the EIA has reduced its forecast for Brent crude oil spot prices from its third quarter prediction to an average $83 per barrel in 2023 and $78 per barrel in 2024, compared to an average $101 per barrel in 2022. The EIA’s third quarter forecast was an average $102 per barrel in 2022 and $95 per barrel in 2023, so the EIA is increasingly forecasting a stabilizing oil price with lower price peaks.

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In addition to the improving oil market outlook, global natural gas prices remain elevated due to a combination of sustained economic activity and energy security concerns in Europe driving continued strong demand for LNG to replace Russian pipeline gas. The global demand for natural gas is set to decline from the highs of 2022 as domestic consumption from the electric power and industrial sectors is reduced and LNG exports remain relatively flat, limiting further upwards pricing pressures in 2023.

The EIA expects Henry Hub spot prices to decrease to an average of $4.90 per million British thermal unit (“MMBtu”) in 2023, down close to 25% from $6.42 MMBtu in 2022, then falling to $4.80/MMBtu in 2024 as natural gas production outpaces an increase in LNG exports resulting from rising LNG export capacity. Rystad forecasts the European and Asian LNG spot price to trade at approximately $32.0/MMBtu and $30.0/MMBtu respectively in 2023, a reduction from previous forecasts as record-strong LNG supplies have driven a storage build, suggesting a comparably softer market for 2023. The market does however remain tight for 2023 with upside risks due to further reduction in Russian gas and LNG exports, cold spells in the northern hemisphere, and a recovery in Chinese demand.

The outlook for 2023 indicates a continuing recovery in exploration and production expenditures, with investments expected to reach pre-pandemic levels with growth maintained in offshore shelf activity, driven by Latin America, shale / tight oil led by the U.S. land markets, and significant investments in incremental capacity in the Middle East, including Saudi Arabia, the United Arab Emirates and Qatar, in order to offset the decline in Russian gas supply.

As a result, we expect demand for our services and solutions to continue to trend positively through 2023. The following provides an outlook for 2023 by our reporting segments based on data from Spears and Associates, Inc.

NLA: In North America, activity is projected to increase in 2023 by approximately 12% to 810 active rigs and over 21,900 new well spuds, which will also support an increase of 6% in frac activity over 2022. Approximately 792 rigs are forecast to be active in onshore North America, and 18 rigs active offshore, a 20% increase over 2022 active offshore rig count. The rate of growth has decelerated recently, most likely due to increased oilfield inflation and fiscal discipline from operators looking to return excess cash to investors or use cash to reduce financial leverage. In Latin America, drilling activity is forecast to increase 19% in 2023 to 202 active rigs and approximately 2,700 new wells, driven by the continued recovery in Argentina and Mexico, two countries with the highest drilling activity in the region. Offshore drilling activity in Latin America is forecast to rise 13% to 44 active rigs and 280 wells, driven by Brazil and Mexico, but offshore activity in Guyana is also expected to remain buoyant.

ESSA: European drilling is projected to average 84 active rigs in 2023 (up 14%) accounting for approximately 775 new wells. Offshore drilling is projected to rise by 9% in 2023, averaging 35 rigs with 425 new wells. As a result of energy security concerns and a desire by European policy makers  to reduce reliance on Russian oil and gas imports, there remains an increased focus on North Sea operations and production optimization from existing assets, core areas of Expro’s expertise. In Sub-Saharan Africa, drilling activity is forecast to jump by 12% in 2023 to average 129 active rigs, drilling over 1,000 new wells. Sub-Saharan Africa growth is driven by offshore activity with 16% growth forecast in 2023, with the progression of development programs for a number of large offshore projects.  In addition, exploration campaigns in Namibia are also progressing. New gas and LNG projects are expected to boost Africa’s natural gas production to record levels over the next decade, driven by Europe’s demand for non-Russian imports and Africa’s own gas demand rising.

MENA: In the Middle East and North Africa, drilling activity is projected to rise substantially in 2023 (26%) to an average of 356 active rigs, drilling over 3,100 new wells as Saudi Arabia seeks to meet increased demand for its oil with several large oilfield expansion schemes. Abu Dhabi, Qatar and Iraq also plan to increase their production capacity. There also is increased focus on infield development and production optimization and enhancement projects to increase production rates (for example in Saudi Arabia, Iraq and Qatar), also adding to a positive future activity outlook.

APAC: In Asia-Pacific, drilling activity is forecast to increase by 11% with 189 active rigs drilling around 2,500 new wells in 2023. Offshore activity is forecast to grow 20% to an average of 49 rigs, with growth primarily in India, Indonesia, Malaysia and Thailand.  In addition, carbon capture, utilization and storage project interest is growing, with opportunities being investigated in Thailand as well as in Indonesia, Australia and Malaysia.  Production enhancement, well intervention and well abandonment activities are also gaining momentum.

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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, Adjusted EBITDA, Adjusted Cash Flow from Operations and Cash Conversion.

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 Cash Flow from Operations: We regularly evaluate our operating cash flow performance using Adjusted Cash Flow from Operations. Our management believes Adjusted Cash Flow from Operations is a useful tool to measure the operating cash performance of the Company as it excludes exceptional payments, interest payments and non-cash charges not related to our core operating activities and allows more meaningful analysis of the trends and performance of our core operations.

Cash Conversion: We regularly evaluate our efficiency of generating cash from operations using Cash Conversion which provides a useful tool to measure Adjusted Cash Flow from Operations as a percentage of Adjusted EBITDA.

Adjusted EBITDA, Adjusted Cash Flow from Operations and Cash Conversion are non-GAAP financial measures. Please refer to the section titled “Non-GAAP Financial Measures” for a reconciliation of Adjusted EBITDA to net loss, the most directly comparable financial performance measure calculated and presented in accordance with GAAP and a reconciliation of Adjusted Cash Flow from Operations to net cash provided by operating activities, the most directly comparable liquidity measure calculated and presented in accordance with GAAP.

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Executive Overview

Year ended December 31, 2022 compared to year ended December 31, 2021

Certain highlights of our financial results and other key developments include:

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Selected Unaudited Financial Information for the Three Months Ended December 31, 2022 and September 30, 2022

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, 2022 and September 30, 2022:

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 (loss) before income taxes for the three months ended December 31, 2022 and September 30, 2022:

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Quarter ended December 31, 2022 compared to quarter ended September 30, 2022

NLA

Revenue for the NLA segment was $131.7 million for the three months ended December 31, 2022, a decrease of $2.9 million, or 2.1%, compared to $134.6 million for the three months ended September 30, 2022. The decrease was primarily due to lower well management services revenue in Mexico and the U.S., partially offset by higher well construction services revenue in the Gulf of Mexico driven by higher customer activities.

Segment EBITDA for the NLA segment was $35.2 million, or 26.7% of revenues, during the three months ended December 31, 2022, compared to $39.7 million, or 29.5% of revenues, during the three months ended September 30, 2022. The decrease of $4.5 million in Segment EBITDA was attributable to lower activity and the reduction in Segment EBITDA margin was attributable to a less favorable product mix during the three months ended December 31, 2022.

ESSA

Revenue for the ESSA segment was $117.3 million for the three months ended December 31, 2022, an increase of $17.5 million, or 17.6%, compared to $99.8 million for the three months ended September 30, 2022. The increase in revenues was primarily driven by higher well flow management revenue in Congo from a new contract and in the U.K. from increased customer activities.

Segment EBITDA for the ESSA segment was $30.2 million, or 25.7% of revenues, for the three months ended December 31, 2022, an increase of $12.4 million, or 69.9%, compared to $17.8 million, or 17.8% of revenues, for the three months ended September 30, 2022. The increase in Segment EBITDA and Segment EBITDA margin was primarily attributable to higher activity levels and a more favorable activity mix during the three months ended December 31, 2022.

MENA

Revenue for the MENA segment was $55.4 million for the three months ended December 31, 2022, an increase of $5.4 million, or 10.7%, compared to $50.0 million for the three months ended September 30, 2022. The increase in revenue was driven by higher well flow management services revenue in Algeria and the Kingdom of Saudi Arabia.

Segment EBITDA for the MENA segment was $19.4 million, or 35.1% of revenues, for the three months ended December 31, 2022, an increase of $4.7 million, or 32.5%, compared to $14.7 million, or 29.3% of revenues, for the three months ended September 30, 2022. The increase in Segment EBITDA and Segment EBITDA margin was primarily due to higher activity and a more favorable activity mix during the three months ended December 31, 2022.

APAC

Revenue for the APAC segment was $46.6 million for the three months ended December 31, 2022, a decrease of $3.3 million, or 6.8%, compared to $49.9 million for the three months ended September 30, 2022. The decrease in revenue was primarily due to lower subsea well access revenue in Australia and Malaysia.

Segment EBITDA for the APAC segment was $3.7 million, or 7.9% of revenues, for the three months ended December 31, 2022, an increase of $12.3 million compared to $(8.6) million, or (17.3)% of revenues, for the three months ended September 30, 2022. The increase in Segment EBITDA (despite the decrease in revenues) was primarily due to lower start-up and commissioning costs incurred on a large subsea project during the three months December 31, 2022, as compared to the three months ended September 30, 2022. Excluding $4.8 million and $16.8 million of start-up and commissioning costs during the three months ended December 31, 2022 and September 30, 2022, respectively, Segment EBITDA would have been $8.5 million and $8.1 million and Segment EBITDA margin would have been 18.2% and 16.3% respectively, for the three months ended December 31, 2022 and September 30, 2022.

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Non-GAAP Financial Measures

We include in this Form 10-K the non-GAAP financial measures Adjusted EBITDA, Adjusted EBITDA margin, Adjusted Cash Flow from Operations and Cash Conversion. We provide reconciliations of net loss, the most directly comparable financial performance measure calculated and presented in accordance with GAAP, to Adjusted EBITDA. We also provide a reconciliation of Adjusted Cash Flow from Operations to net cash provided by operating activities, the most directly comparable liquidity measure calculated and presented in accordance with GAAP.

Adjusted EBITDA, Adjusted EBITDA margin, Adjusted Cash Flow from Operations and Cash Conversion 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 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 on disposal of assets, (h) other income, net, (i) interest and finance income (expense), net and (j) foreign exchange losses. Adjusted EBITDA margin reflects our Adjusted EBITDA as a percentage of revenues.

We define Adjusted Cash Flow from Operations as net cash provided by operating activities adjusted for cash paid during the period for interest, net, severance and other expense and merger and integration expense. We define Cash Conversion as Adjusted Cash Flow from Operations divided by Adjusted EBITDA.

Adjusted EBITDA, Adjusted EBITDA margin, Adjusted Cash Flow from Operations and Cash Conversion 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, Adjusted Cash Flow from Operations and Cash Conversion may be defined differently by other companies in our industry, our presentation of Adjusted EBITDA, Adjusted Cash Flow from Operations and Cash Conversion 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 loss to Adjusted EBITDA for each of the periods presented (in thousands):

The following table provides a reconciliation of net cash provided by operating activities to Adjusted Cash Flow from Operations for each of the periods presented (in thousands):

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Results of Operations

Operating Segment Results

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.

The following table shows revenue by segment and revenue as a percentage of total revenue by segment for the years ended December 31, 2022 and December 31, 2021: