PATTERSON UTI ENERGY INC
For the period ended Mar 31, 2025. Filed Apr 29, 2025.
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A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Mar 31, 2025 · Filed Apr 29, 2025
PTEN$9.92-0.3%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-Q
Period ended 2024-09-30; filed 2024-10-28.
0000889900-24-000016
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2025-03-31; filed 2025-04-29.
0001628280-25-020675
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 152 previous paragraphs and 111 current paragraphs.
32 unchanged; 51 reworded; 25 added; 63 removed; 6 previous and 3 current paragraphs rearranged.
Tables are not compared: 17 previous and 11 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (25)
Current report
To address evolving customer preferences for emissions-reducing equipment, we have invested in natural gas-powered equipment, including electric, direct drive, and dual fuel pumps, to replace legacy diesel completion services equipment.
Current report
Recent Developments in Market Conditions and Outlook — Commodity prices have historically been volatile but were relatively range-bound from the end of 2022 through the first quarter of 2025. The current demand for equipment and services remains impacted by macro conditions, including commodity prices, geopolitical environment, changes to international tariffs and trade policies, inflationary pressures, economic conditions in the United States and elsewhere, as well as customer consolidation and focus by exploration and production companies and service companies on capital returns. Subsequent to March 31, 2025, global economic conditions deteriorated, in part, because of recently enacted trade policies and tariffs implemented by the United States and other governments, as well as uncertainty regarding potential future changes to global trade policies and tariffs. Additionally, subsequent to March 31, 2025, several OPEC+ countries announced plans to phase out existing crude oil output cuts earlier than anticipated. These developments and geopolitical tensions have introduced increased uncertainty in global energy markets, which has contributed to a decline in our share price, lowered crude oil futures prices and increased uncertainty regarding the future economic environment in which we operate. The recent deterioration in macroeconomic conditions and the decline in our share price occurred after the balance sheet date and do not reflect conditions that existed as of March 31, 2025. Accordingly, these developments have not been reflected in the unaudited condensed consolidated financial statements for the three months ended March 31, 2025. While the full effects are yet to be determined, prolonged trade tensions and sustained lower crude oil futures prices could adversely affect our future outlook on activity and profitability. Oil prices averaged $71.78 per barrel in the first quarter of 2025, as compared to $70.73 per barrel in the fourth quarter of 2024, and closed at $63.48 per barrel on April 21, 2025. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $4.14 per MMBtu in the first quarter of 2025 as compared to an average of $2.45 per MMBtu in the fourth quarter of 2024, and closed at $3.16 per MMBtu on April 21, 2025.
Current report
In our Drilling Services segment for the second quarter of 2025, we expect our average daily rig count to remain relatively steady compared to the first quarter. We expect adjusted gross profit within the Drilling Services segment to decline slightly, with the sequential change driven by a reduction in average contracted revenue as existing term contracts with more favorable pricing expire, as well as some normal seasonal increase in costs.
Current report
In our Completion Services segment for the second quarter of 2025, we currently expect activity to remain relatively steady as compared to activity levels at the end of the first quarter, although current oil prices may impact demand for completion services later in the second quarter. We expect second quarter Completion Services adjusted gross profit to decline slightly, sequentially.
Current report
In our Drilling Products segment for the second quarter of 2025, we expect sequential adjusted gross profit to remain relatively flat compared to the first quarter, with steady activity in the United States. We expect impacts from the normal seasonal spring breakup in Canada to be mostly offset by higher International revenue in the rest of the world.
Current report
The Credit Agreement provides for a committed senior unsecured credit facility that permits aggregate revolving credit borrowings of up to $500 million, with a letter of credit sub-facility of $100 million and a swing line sub-facility that, at any time outstanding, is limited to the lesser of $50 million and the amount of the swing line provider’s unused commitment. Subject to customary conditions, we may request that the lenders’ aggregate commitments be increased by up to $200 million, not to exceed total commitments of $700 million. For a description of the Credit Agreement, see “Liquidity and Capital Resources” below.
Current report
Revenues and direct operating costs, both on a total and per operating day basis, were relatively flat between sequential quarters.
Current report
The decrease in depreciation, amortization and impairment expense was attributable to a lower depreciable asset base in the first quarter of 2025, in part, due to the abandonment of 42 legacy non-super-spec rigs and equipment in the third quarter of 2024.
Current report
Completion services revenues and direct operating costs increased primarily due to seasonal recovery as customer budgets reset in the first quarter. The higher revenues and direct operating costs were primarily from our fracturing operations, which increased $86 million and $82 million, or 17% and 18%, respectively. The increases were primarily activity driven, with pumping hours increasing 23% during the first quarter of 2025.
Current report
Depreciation, amortization and impairment expense decreased primarily due to $20.8 million of accelerated depreciation recognized in the fourth quarter of 2024.
Current report
Completion services revenues and direct operating costs decreased primarily due to lower activity in our fracturing operations. Revenues and direct operating costs from our fracturing operations decreased by $170 million and $84 million, or 21% and 13%, respectively.
Current report
Depreciation, amortization and impairment expense decreased primarily due to fewer capital additions placed in service relative to asset retirements between the periods.
Current report
We reduced capital expenditures in response to the changing macroeconomic conditions between the periods.
Current report
Revenues and direct operating costs were relatively flat between sequential quarters.
Current report
Revenues and direct operating costs were relatively flat between the quarters.
Current report
Revenues and direct operating costs were relatively flat between sequential quarters.
Current report
Revenues and direct operating costs decreased primarily due to lower activity as a result of lower crude oil and natural gas market prices. Oil prices averaged $71.78 per barrel in the first quarter of 2025, as compared to $77.50 per barrel in the first quarter of 2024.
Current report
Selling, general and administrative expense decreased primarily due to certain severance costs incurred in the fourth quarter that did not recur as well as a continued focus on cost reduction efforts.
Current report
Other income (expense) during the first quarter of 2025 included $1.4 million of income from an unconsolidated joint venture.
Current report
On January 31, 2025, we entered into the Credit Agreement, which amended and restated the Prior Credit Agreement. The commitments under the Credit Agreement are $500 million, and the loans and commitments under the Credit Agreement mature on January 31, 2030.
Current report
As of March 31, 2025, we had working capital of $499 million, including cash, cash equivalents and restricted cash of $225 million, compared to working capital of $453 million, including cash, cash equivalents and restricted cash of $241 million, at December 31, 2024.
Current report
•$2.6 million for payments related to finance leases, and
Current report
•$12.1 million for other investing and financing activities.
Current report
Impact of Inflation and Trade Policies
Current report
Moderate inflationary pressures and uncertainty regarding recently enacted and potential future changes to international tariffs and trade policies have contributed, or may contribute, to increases in the cost of certain goods, services, and labor. While the full effects are yet to be determined, prolonged trade tensions could, among other things, increase the costs of certain products used in our businesses, such as drill pipe, parts, and electronics. We continue to actively monitor market trends primarily related to sourcing of labor, supplies and equipment.
Removed paragraphs (63)
Previous report
Recent Developments in Market Conditions and Outlook — Commodity price volatility in the second quarter of 2023 resulted in a decline in industry activity; commodity prices subsequently increased during the third quarter before declining in the fourth quarter of 2023. Oil prices increased during the first quarter of 2024, moderately fluctuated during the second quarter of 2024 and declined in the third quarter of 2024. While natural gas prices declined significantly during the first quarter of 2024, natural gas prices increased slightly during the second quarter of 2024 and moderately fluctuated during the third quarter of 2024. The current demand for equipment and services remains dependent on macro conditions, including commodity prices, geopolitical environment, inflationary pressures, economic conditions in the United States and elsewhere, as well as customer consolidation and focus by exploration and production companies and service companies on capital returns. Oil prices reached a low of $66.73 per barrel and averaged $76.43 per barrel in the third quarter of 2024, as compared to $81.81 per barrel in the second quarter of 2024. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $2.11 per MMBtu in the third quarter of 2024 as compared to an average of $2.07 per MMBtu in the second quarter of 2024.
Previous report
Inour Completion Services segment, during the fourth quarter, we expect a sequential slowdown in activity due to typical holiday seasonality and capital discipline being exercised by our customers into the end of the year.
Previous report
In our Drilling Products segment for the fourth quarter, we expect a slight sequential increase in revenue and adjusted gross profit, driven by growth in our International operations, while U.S. revenue is expected to decline slightly on lower industry rig count.
Previous report
For the fourth quarter of 2024, we expect total capital expenditures of approximately $150 million.
Previous report
Negative market indicators such as lower industry-wide drilling rig and pressure pumping fleet count forecasts, increased volatility and pricing declines in the pressure pumping market, and continued efficiency gains and technology advancements reducing operating days have led to a reduced outlook for activity. We viewed the reduction in activity forecasts combined with the recent decline in the market price of our common stock as a triggering event that warranted a quantitative assessment for goodwill impairment. As a result, we recorded an $885 million impairment charge to goodwill for the completion services reporting unit during the third quarter of 2024. See Note 7 of Notes to unaudited condensed consolidated financial statements for additional information.
Previous report
We also evaluated our fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type. As a result of this evaluation, during the three months ended September 30, 2024, we identified 42 legacy, non-Tier-1 super-spec drilling rigs and related equipment to be abandoned. Based on the strong customer preference across the industry for Tier-1 super-spec drilling rigs, in addition to efficiency gains and technology advancements that have reduced the total number of rigs needed for the U.S. drilling market, we believe the 42 rigs that were abandoned had limited commercial opportunity. Accordingly, we recorded a $114 million abandonment charge during the third quarter of 2024. See Note 6 of Notes to unaudited condensed consolidated financial statements for additional information.
Previous report
Our net loss attributable to common shareholders for the three months ended September 30, 2024 was $979 million or $2.50 per common share. Excluding the $885 million goodwill impairment, $114 million asset abandonment charge, and $7 million of merger and integration expenses net of income tax benefits totaling $25.4 million, adjusted net income attributable to common shareholders for the three months ended September 30, 2024 was $2 million or $0.00 per common share. See Non-GAAP Financial Measures below for a reconciliation of GAAP net income (loss) attributable to common shareholders to adjusted net income attributable to common shareholders.
Previous report
Recent Developments in Joint Ventures and Business Combinations— On September 30, 2024, one of our subsidiaries signed the previously announced joint venture agreement with subsidiaries of ADNOC Drilling and SLB. Our subsidiary will hold a 15 percent interest in a newly created company named Turnwell Industries, which has been awarded a contract to drill and complete 144 unconventional wells for ADNOC.
Previous report
On September 1, 2023, we completed our merger (the “NexTier merger”) with NexTier Oilfield Solutions Inc. (“NexTier”). Each share of common stock of NexTier issued and outstanding immediately prior to the effective time (including outstanding restricted shares) was converted into the right to receive 0.752 shares of our common stock, which based on the closing price of our common stock of $14.91 on September 1, 2023, valued the transaction at approximately $2.8 billion, including the assumption of debt. NexTier is a predominately U.S. land-focused oilfield service provider, with a diverse set of well completion and production services across a variety of active basins.
Previous report
On August 14, 2023, we completed our acquisition (the “Ulterra acquisition”) of Ulterra Drilling Technologies, L.P. (“Ulterra”). Total consideration for the acquisition included the issuance of 34.9 million shares of our common stock and payment of approximately $373 million of cash (after purchase price adjustments), which based on the closing price of our common stock of $14.94 on August 14, 2023, valued the transaction at closing at approximately $894 million. Ulterra is a global provider of specialized drill bit solutions.
Previous report
The Commitment Increase Agreement increased the commitments under our Credit Agreement to $615 million. The maturity date for $567 million of such commitments is March 27, 2026; and the maturity date for $48.3 million of such commitments is March 27, 2025.
Previous report
Effective as of the third quarter of 2023, we revised our reportable segments to align with certain changes in how our Chief Operating Decision Maker (“CODM”) manages and allocates resources to our business as a result of the Ulterra acquisition and
Previous report
(1)Drilling services segment represents our contract drilling, directional drilling, oilfield technology and electrical controls and automation businesses.
Previous report
(2)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.
Previous report
Total revenues and direct operating costs decreased primarily due to a decrease in operating days in our contract drilling business within the United States. Average revenue and average direct operating costs per operating day were relatively flat between sequential quarters.
Previous report
Depreciation, amortization and impairment increased primarily due to a charge of $114 million related to the abandonment of 42 legacy, non-Tier-1 super-spec drilling rigs and related equipment. See Note 6 of Notes to unaudited condensed consolidated financial statements for additional information.
Previous report
(1)Completion services represents the combination of well completion business from the NexTier merger and our legacy pressure pumping business.
Previous report
(2)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.
Previous report
Completion services direct operating costs increased disproportionately to the increase in revenues, which negatively impacted our adjusted gross profit. The higher direct operating costs resulted from unplanned gaps for several of our fleets, which impacted fixed cost leverage on those fleets.
Previous report
During the three months ended September 30, 2024, we recorded an $885 million impairment charge to goodwill associated with our completion services reporting unit. See Note 7 of Notes to unaudited condensed consolidated financial statements for additional information.
Previous report
Capital expenditures increased due to the timing of order placement and spending on committed deliveries.
Previous report
Revenues and direct operating costs increased slightly primarily due to market share gains in our U.S. and Canadian markets.
Previous report
Revenue and direct operating costs decreased due to a lower volume of services provided by our oilfield rentals business.
Previous report
Corporate activities were relatively flat between sequential quarters.
Previous report
Other operating expense (income), net includes net gains or losses associated with the disposal of assets. Accordingly, the related gains or losses have been excluded from the results of specific segments. The $5.8 million change in other operating expense (income), net is primarily the result of gains on the disposal of assets in the second quarter of 2024 that did not recur in the third quarter.
Previous report
Results of Operations
Previous report
(1)Drilling services segment represents our contract drilling, directional drilling, oilfield technology and electrical controls and automation businesses.
Previous report
(2)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross margin to adjusted gross profit by segment.
Previous report
Total revenues and direct operating costs decreased primarily due to a decrease in operating days in our contract drilling business within the United States. Average revenue per operating day remained relatively flat while average direct operating costs per operating day increased. The decline in operating days impacted the fixed cost leverage for U.S. drilling rigs during the nine months ended September 30, 2024.
Previous report
The decrease in operating days for our U.S. contract drilling business reflects the industry-wide activity declines during the first nine months of 2024 due to increased drilling efficiencies and market consolidation.
Previous report
Depreciation, amortization and impairment increased primarily due to a charge of $114 million related to the abandonment of 42 legacy, non-Tier-1 super-spec drilling rigs and related equipment. See Note 6 of Notes to unaudited condensed consolidated financial statements for additional information.
Previous report
(1)Completion services represents the combination of well completion business from the NexTier merger and our legacy pressure pumping business.
Previous report
(2)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross margin to adjusted gross profit by segment.
Previous report
The changes in the results of our completion services segment for the nine months ended September 30, 2024 as compared to September 30, 2023 can be primarily attributed to the NexTier merger, which closed on September 1, 2023. The NexTier merger had a material impact on our reported results of operations. The results for the nine months ended September 30, 2024 represent the combination of the well completion business from the NexTier merger and our legacy pressure pumping business. Due to the full integration of our legacy pressure pumping business into the NexTier legal entity in the first quarter of 2024, we are unable to provide a meaningful year-over-year comparison excluding the impact of the NexTier merger.
Previous report
During the nine months ended September 30, 2024, we recorded an $885 million impairment charge to goodwill associated with our completion services reporting unit. See Note 7 of Notes to unaudited condensed consolidated financial statements for additional information.
Previous report
(1)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross margin to adjusted gross profit by segment.
Previous report
The changes in the results of our drilling products segment for the nine months ended September 30, 2024 as compared to September 30, 2023 are attributable to the Ulterra acquisition, which closed on August 14, 2023. The results for the nine months ended September 30, 2023 included 45 days of operating results, and as such, there was no meaningful year-over-year comparison.
Previous report
(1)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, depletion, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross margin to adjusted gross profit by segment.
Previous report
Revenue decreased due to a lower volume of services provided by our oilfield rentals business.
Previous report
Depreciation, depletion, amortization and impairment decreased primarily due to a $6.2 million impairment recorded in our oil and natural gas business during the nine months ended September 30, 2023 compared to a $3.4 million impairment for the comparable period in 2024.
Showing the first 40 of 63 passages. Open the source sections for the rest.
Reworded paragraphs (51)
Previous wording
Our contract drilling business operates in the continental United States and internationally in South America and, from time to time, we pursue contract drilling opportunities in other select markets. We also provide a comprehensive suite of directional drilling services in most major producing onshore oil and natural gas basins in the United States, and we provide services that improve the statistical accuracy of wellbore placement for directional and horizontal wells. We also service and re-certify equipment for drilling contractors, and we provide electrical controls and automation to the energy, marine and mining industries, in North America and other select markets.
Current wording
Our contract drilling business operates in the continental United States and internationally in Colombia and Ecuador and, from time to time, we pursue contract drilling opportunities in other select markets. We also provide a comprehensive suite of directional drilling services in most major producing onshore oil and natural gas basins in the United States, and we provide services that improve the statistical accuracy of wellbore placement for directional and horizontal wells. We also service and re-certify equipment for drilling contractors, and we provide electrical controls and automation to the energy, marine and mining industries, in North America and other select markets.
Previous wording
We have addressed our customers’ needs for drilling horizontal wells in shale and other unconventional resource plays by improving the capabilities of our drilling fleet. The U.S. land rig industry has in recent years referred to certain high specification rigs as “super-spec” rigs, which we consider to be at least a 1,500 horsepower, AC-powered rig that has at least a 750,000-pound hookload, a 7,500-psi circulating system, and is pad-capable. Due to evolving customer preferences, we refer to certain premium rigs as “Tier-1, super spec” rigs, which we consider as being a super-spec rig that also has a third mud pump and raised drawworks that allows for more clearance underneath the rig floor. As of September 30, 2024, our rig fleet included 134 Tier-1, super-spec rigs.
Current wording
We have addressed our customers’ needs for drilling horizontal wells in shale and other unconventional resource plays by improving the capabilities of our drilling fleet. The U.S. land rig industry has in recent years referred to certain high specification rigs as “super-spec” rigs, which we consider to be at least a 1,500 horsepower, AC-powered rig that has at least a 750,000-pound hookload, a 7,500-psi circulating system, and is pad-capable. Due to evolving customer preferences, we refer to certain premium rigs as “Tier-1, super spec” rigs, which we consider as being a super-spec rig that also has a third mud pump and raised drawworks that allows for more clearance underneath the rig floor. As of March 31, 2025, our rig fleet included 135 Tier-1, super-spec rigs.
Previous wording
We serve the energy and mining markets by manufacturing and distributing drill bits through North America and internationally in over 30 countries. Our drilling equipment is used in oil and natural gas exploration and production and in mining operations. We have manufacturing and repair facilities located in Fort Worth, Texas, Leduc, Alberta and Saudi Arabia and repair facilities located in Argentina, Colombia and Oman.
Current wording
We serve the energy and mining markets by manufacturing and distributing drill bits throughout North America and internationally in over 30 countries. Our drilling equipment is used in oil and natural gas exploration and production and in mining operations. We have manufacturing and repair facilities located in Fort Worth, Texas, Leduc, Alberta and Saudi Arabia and repair facilities located in Argentina, Colombia and Oman.
Previous wording
Our average active rig count in the United States for the third quarter of 2024 was 107 rigs. This was a decrease from our average active rig count for the second quarter of 2024 of 114. We expect our rig count in the United States will average approximately 106 rigs during the fourth quarter of 2024. Term contracts help support our operating rig count. Based on contracts in place in the United States as of October 23, 2024, we expect an average of 58 rigs operating under term contracts during the fourth quarter of 2024 and an average of 33 rigs operating under term contracts during the four quarters ending September 30, 2025.
Current wording
Our average active rig count in the United States for the first quarter of 2025 was 106 rigs. This was an increase from our average active rig count for the fourth quarter of 2024 of 105. Term contracts help support our operating rig count. Based on contracts in place in the United States as of April 24, 2025, we expect an average of 62 rigs operating under term contracts during the second quarter of 2025 and an average of 35 rigs operating under term contracts during the four quarters ending March 31, 2026.
Previous wording
We maintain a backlog of commitments for contract drilling services under term contracts, which we define as contracts with a duration of six months or more. Our contract drilling backlog in the United States as of September 30, 2024 was approximately $401 million. Approximately 9% of our total contract drilling backlog in the United States at September 30, 2024 is reasonably expected to remain at September 30, 2025. See Note 3 of Notes to unaudited condensed consolidated financial statements for additional information on backlog.
Current wording
We maintain a backlog of commitments for contract drilling services under term contracts, which we define as contracts with a duration of six months or more. Our contract drilling backlog in the United States as of March 31, 2025 was approximately $407 million. Approximately 9% of our total contract drilling backlog in the United States at March 31, 2025 is reasonably expected to remain at March 31, 2026. See Note 2 of Notes to unaudited condensed consolidated financial statements for additional information on backlog.
Previous wording
Recent Developments in Debt Financing — On April 5, 2024, we entered into a Commitment Increase Agreement (the “Commitment Increase Agreement”), which increased the commitments under our Amended and Restated Credit Agreement, dated as of March 27, 2018 (as modified by the Commitment Increase Agreement and as amended to date, the “Credit Agreement”), by and among us, as borrower, Wells Fargo Bank, National Association, as administrative agent, letter of credit issuer, swing line lender and lender and each of the other letter of credit issuers and lenders party thereto.
Current wording
Recent Developments in Debt Financing — On January 31, 2025, we entered into the Second Amended and Restated Credit Agreement with the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent, and the other parties thereto (the “Credit Agreement”). The Credit Agreement amended and restated our Amended and Restated Credit Agreement dated as of March 27, 2018 (as amended, restated, supplemented or otherwise modified at December 31, 2024, the “Prior Credit Agreement”). The commitments under the Credit Agreement are $500 million, and the loans and commitments under the Credit Agreement mature on January 31, 2030.
Previous wording
As of September 30, 2024, we had no borrowings outstanding under our revolving credit facility. We had $2.1 million in letters of credit outstanding under the Credit Agreement at September 30, 2024 and, as a result, had available borrowing capacity of approximately $613 million at that date.
Current wording
As of March 31, 2025, we had no borrowings outstanding under our Credit Agreement. We had $2.0 million in letters of credit outstanding under the Credit Agreement at March 31, 2025 and, as a result, had available borrowing capacity of approximately $498 million at that date.
Previous wording
Impact on our Business from Oil and Natural Gas Prices and Other Factors — Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas, expectations about future prices, and upon our customers’ ability to access, and willingness to deploy, capital to fund their operating and capital expenditures. During periods of improved oil and natural gas prices, the capital spending budgets of oil and natural gas operators tend to expand, which generally results in increased demand for our services. Conversely, in periods when oil and natural gas prices are relatively low or when our customers have a reduced ability to access, or willingness to deploy, capital, the demand for our services generally weakens, and we experience downward pressure on pricing for our services. Even during periods of historically moderate or high prices for oil and natural gas, companies exploring for oil and natural gas may cancel or curtail programs or reduce their levels of capital expenditures for exploration and production for a variety of reasons, which could reduce demand for our services. We may also be impacted by delayed customer payments and payment defaults associated with customer liquidity issues and bankruptcies.
Current wording
Impact on our Business from Oil and Natural Gas Prices and Other Factors — Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas, expectations about future prices, and upon our customers’ ability to access, and willingness to deploy, capital to fund their operating and capital expenditures. During periods of improved oil and natural gas prices, the capital spending budgets of oil and natural gas operators tend to expand, which generally results in increased demand for our services. Conversely, in periods when oil and natural gas prices are relatively low or when our customers have a reduced ability to access, or willingness to deploy, capital, the demand for our services generally weakens, and we experience downward pressure on pricing for our services. Even during periods of historically moderate or high prices for oil and natural gas, companies exploring for oil and natural gas may cancel or curtail programs or reduce their levels of capital expenditures for exploration and production for a variety of reasons, including the depletion of capital expenditure budgets and/or meeting annual drilling and completion targets, which could reduce demand for our services. We may also be impacted by delayed customer payments and payment defaults associated with customer liquidity issues and bankruptcies.
Previous wording
The North American oil and natural gas services industry is cyclical and at times experiences downturns in demand. During these periods, there has been substantially more oil and natural gas service equipment available than necessary to meet demand. As a result, oil and natural gas service contractors have had difficulty sustaining profit margins and, at times, have incurred losses during the downturn periods. We cannot predict either the future level of demand for our oil and natural gas services or future conditions in the oil and natural gas service businesses.
Current wording
The oil and natural gas services industry is cyclical and at times experiences downturns in demand. During these periods, there has been substantially more oil and natural gas service equipment available than necessary to meet demand. As a result, oil and natural gas service contractors have had difficulty sustaining profit margins and, at times, have incurred losses during the downturn periods. We cannot predict either the future level of demand for our oil and natural gas services or future conditions in the oil and natural gas service businesses.
Previous wording
In addition to the dependence on oil and natural gas prices and demand for our services, we are highly impacted by operational risks, competition, labor issues, weather, the availability, from time to time, of products used in our businesses, supplier delays and various other factors that could materially adversely affect our business, financial condition, cash flows and results of operations. Please see Item 1A of this Report and our Annual Report.
Current wording
In addition to the dependence on oil and natural gas prices and demand for our services, we are highly impacted by operational risks, competition, labor issues, weather, the availability, from time to time, of products used in our businesses, supplier delays and various other factors that could materially adversely affect our business, financial condition, cash flows and results of operations. Please see Item 1A of our Annual Report.
Previous wording
For the three months ended September 30, 2024 and June 30, 2024 and the nine months ended September 30, 2024 and 2023 our operating revenues consisted of the following (dollars in thousands):
Current wording
For the three months ended March 31, 2025, December 31, 2024, and March 31, 2024 our operating revenues consisted of the following (dollars in thousands):
Previous wording
(3)Operational data relates to our contract drilling business. A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.
Current wording
(2)Operational data relates to our contract drilling business. A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.
Previous wording
Generally, the revenues in our drilling services segment are most impacted by two primary factors: day rates and our average number of rigs operating.
Current wording
Generally, the revenues in our drilling services segment are most impacted by two primary factors: our contract drilling day rates and our average number of rigs operating.
Previous wording
Capital expenditures increased primarily due to the timing of order placement and spending on committed deliveries that more heavily impacted the third quarter of 2024.
Current wording
Capital expenditures increased primarily due to spending related to maintenance capital and the timing of order placement that more heavily impacted the first quarter of 2025.
Previous wording
The decrease in operating days for our U.S. contract drilling business reflects a modest reduction in our rig count mainly due to merger and acquisition activity for certain customers.
Current wording
Revenues and direct operating costs decreased due to a decrease in operating days for our U.S. contract drilling operations.
Previous wording
Capital expenditures decreased primarily due to reduced investment in our ancillary drilling services not included within our contract drilling business and timing of order placement.
Current wording
Capital expenditures decreased primarily due to reduced investment in our ancillary drilling services not included within our contract drilling business.
Previous wording
Other operating income, net in the second quarter of 2024 was due to gain on legal settlement.
Current wording
Other operating income, net in the first quarter of 2024 was due to a gain on legal settlement.
Previous wording
Direct operating costs and depreciation, amortization and impairment were approximately $4.8 million and $11.6 million higher than they would have otherwise been for the nine months ended September 30, 2024, respectively, as a result of the step up to fair value of our drill bits in accordance with purchase accounting. Direct operating costs and depreciation, amortization and impairment were approximately $6.4 million and $7.4 million higher than they would have otherwise been for the nine months ended September 30, 2023, respectively, as a result of the step up to fair value of our drill bits in accordance with purchase accounting.
Current wording
Direct operating costs and depreciation, amortization and impairment expense were approximately $0.6 million and $2.3 million higher than they would have otherwise been for the three months ended March 31, 2025, respectively, as a result of the step up to fair value of our drill bits in accordance with purchase accounting. For the three months ended December 31, 2024, direct operating costs and depreciation, amortization and impairment expense were approximately $3.1 million and $6.1 million higher than they would have otherwise been, respectively, as a result of the step up to fair value of our drill bits.
Previous wording
Depreciation, depletion, amortization and impairment decreased primarily due to a $3.4 million impairment recorded in our oil and natural gas properties business during the third quarter of 2024.
Current wording
Depreciation, depletion, amortization and impairment expense increased primarily due to a $1.7 million impairment charge recorded in our oil and natural gas properties business during the first quarter of 2025.
Previous wording
Merger and integration expense decreased due to the timing of the NexTier merger and the Ulterra acquisition, which both closed in the third quarter of 2023.
Current wording
Merger and integration expense decreased due to the passage of time since closing the NexTier merger and the Ulterra acquisition in third quarter of 2023.
Previous wording
Our effective income tax rate for the nine months ended September 30, 2024 was (0.8)%, compared with 13.9% for the nine months ended September 30, 2023. The difference in effective income tax rates between the periods was primarily attributable to the impact of valuation allowances on deferred tax assets between periods, as well as the impact of permanent differences against earnings between periods.
Current wording
Our effective income tax rate for the three months ended March 31, 2025 was 51.9%, compared with (3.9)% for the three months ended December 31, 2024. The difference in effective income tax rates between the periods was primarily attributable to the impact of valuation allowances on deferred tax assets between periods, as well as the impact of goodwill impairments and permanent differences against earnings between periods.
Previous wording
Our effective income tax rate for the three months ended September 30, 2024 was 3.0%, compared with 60.5% for the three months ended June 30, 2024. The difference in effective income tax rates between the periods was primarily attributable to the impact of permanent differences against earnings between periods.
Current wording
Our effective income tax rate for the three months ended March 31, 2025 was 51.9%, compared with 27.9% for the three months ended March 31, 2024. The difference in effective income tax rates between the periods was primarily attributable to the impact of permanent differences against earnings between periods.
Previous wording
Our primary sources of liquidity are cash and cash equivalents, availability under our revolving credit facility and cash provided by operating activities. As of September 30, 2024, we had approximately $444 million in working capital, including $115 million of cash and cash equivalents, and approximately $613 million available under our revolving credit facility.
Current wording
Our primary sources of liquidity are cash and cash equivalents, availability under our Credit Agreement and cash provided by operating activities. As of March 31, 2025, we had approximately $499 million in working capital, including $223 million of cash and cash equivalents, and approximately $498 million available under our Credit Agreement.
Previous wording
The Credit Agreement is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to $615 million, including a letter of credit facility that, at any time outstanding, is limited to $100 million and a swing line facility that, at any time outstanding, is limited to the lesser of $50.0 million and the amount of the swing line provider’s unused commitment.
Current wording
The Credit Agreement provides for a committed senior unsecured credit facility that permits aggregate revolving credit borrowings of up to $500 million, with a letter of credit sub-facility of $100 million and a swing line sub-facility that, at any time outstanding, is limited to the lesser of $50 million and the amount of the swing line provider’s unused commitment. Subject to customary conditions, we may request that the lenders’ aggregate commitments be increased by up to $200 million, not to exceed total commitments of $700 million.
Previous wording
Loans under the Credit Agreement bear interest by reference, at our election, to the SOFR rate (subject to a 0.10% per annum adjustment) or base rate, in each case subject to a 0% floor. The applicable margin on SOFR rate loans varies from 1.00% to 2.00% and the applicable margin on base rate loans varies from 0.00% to 1.00%, in each case determined based on our credit rating. As of September 30, 2024, the applicable margin on SOFR rate loans was 1.75% and the applicable margin on base rate loans was 0.75%. A letter of credit fee is payable by us equal to the applicable margin for SOFR rate loans times the daily amount available to be drawn under outstanding letters of credit. The commitment fee rate payable to the lenders varies from 0.10% to 0.30% based on our credit rating.
Current wording
Loans under the Credit Agreement bear interest by reference, at our election, to the SOFR rate (plus a 0.10% per annum adjustment) or base rate, in each case subject to a 0% floor. The applicable margin on SOFR rate loans varies from 1.25% to 2.25% and the applicable margin on base rate loans varies from 0.25% to 1.25%, in each case determined based on our credit rating. As of March 31, 2025, the applicable margin on SOFR rate loans was 1.75% and the applicable margin on base rate loans was 0.75%. A letter of credit fee is payable by us equal to the applicable margin for SOFR rate loans times the daily amount available to be drawn under outstanding letters of credit. The commitment fee rate payable to the lenders varies from 0.15% to 0.35% based on our credit rating.
Previous wording
On March 16, 2015, we entered into a Reimbursement Agreement (the “Reimbursement Agreement”) with The Bank of Nova Scotia (“Scotiabank”), pursuant to which we may from time to time request that Scotiabank issue an unspecified amount of letters of credit. As of September 30, 2024, we had $35.9 million in letters of credit outstanding under the Reimbursement Agreement.
Current wording
On March 16, 2015, we entered into a Reimbursement Agreement (as amended from time to time, the “Reimbursement Agreement”) with The Bank of Nova Scotia (“Scotiabank”), pursuant to which we may from time to time request that Scotiabank issue an unspecified amount of letters of credit. As of March 31, 2025, we had $38.8 million in letters of credit outstanding under the Reimbursement Agreement.
Previous wording
Under the terms of the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any of our letters of credit issued thereunder. Fees, charges and other reasonable expenses for the issuance of letters of credit are payable by us at the time of issuance at such rates and amounts as are in accordance with Scotiabank’s prevailing practice. We are obligated to pay to Scotiabank interest on all amounts not paid by us on the date of demand or when otherwise due at the LIBOR rate plus 2.25% per annum, calculated daily and payable monthly, in arrears, on the basis of a calendar year for the actual number of days elapsed, with interest on overdue interest at the same rate as on the reimbursement amounts. A letter of credit fee is payable by us equal to 1.50% times the amount of outstanding letters of credit.
Current wording
Under the terms of the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any of our letters of credit issued thereunder. Fees, charges and other reasonable expenses for the issuance of letters of credit are payable by us at the time of issuance at such rates and amounts as are in accordance with Scotiabank’s prevailing practice. We are obligated to pay to Scotiabank interest on all amounts not paid by us on the date of demand or when otherwise due at the Prime rate plus 2.00% per annum, calculated daily and payable monthly, in arrears, on the basis of a calendar year for the actual number of days elapsed, with interest on overdue interest at the same rate as on the reimbursement amounts. A letter of credit fee is payable by us equal to 1.50% times the amount of outstanding letters of credit.
Previous wording
We had $40.0 million of outstanding letters of credit at September 30, 2024, which was comprised of $35.9 million outstanding under the Reimbursement Agreement, $2.1 million outstanding under the Credit Agreement, and $1.9 million outstanding with financial institutions providing for short-term borrowing capacity, overdraft protection and bonding requirements. We maintain these letters of credit primarily for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under terms of the underlying insurance contracts and compliance with contractual obligations. These letters of credit expire annually at various times during the year and are typically renewed. As of September 30, 2024, no amounts had been drawn under the letters of credit. As of September 30, 2024, we had $35.0 million in surety bond exposure issued as financial assurance on an insurance agreement.
Current wording
We had $42.8 million of outstanding letters of credit at March 31, 2025, which was comprised of $38.8 million outstanding under the Reimbursement Agreement, $2.0 million outstanding under the Credit Agreement, and $2.0 million outstanding with financial institutions providing for short-term borrowing capacity, overdraft protection and bonding requirements. We maintain these letters of credit primarily for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under terms of the underlying insurance contracts and compliance with contractual obligations. These letters of credit expire annually at various times during the year and are typically renewed. As of March 31, 2025, no amounts had been drawn under the letters of credit. As of March 31, 2025, we had $35.0 million in surety bond exposure issued as financial assurance on an insurance agreement.
Previous wording
Our outstanding long-term debt at September 30, 2024 was $1.2 billion and consisted of $483 million of our 2028 Notes, $345 million of our 2029 Notes, $400 million of our 2033 Notes and $9.5 million of our Equipment Loans. We were in compliance with all covenants under the associated agreements and indentures at September 30, 2024.
Current wording
Our outstanding long-term debt at March 31, 2025 was $1.2 billion and consisted of $483 million of our 2028 Notes, $345 million of our 2029 Notes, $400 million of our 2033 Notes and $3.2 million of secured equipment financing term loans. We were in compliance with all covenants under the associated agreements and indentures at March 31, 2025.
Previous wording
For a full description of the Credit Agreement, the Reimbursement Agreement, the 2028 Notes, the 2029 Notes, the 2033 Notes and the Equipment Loans, see Note 9 of Notes to unaudited condensed consolidated financial statements.
Current wording
For a full description of the Credit Agreement, the Reimbursement Agreement, the 2028 Notes, the 2029 Notes, and the 2033 Notes, see Note 8 of Notes to unaudited condensed consolidated financial statements.
Previous wording
A portion of our capital expenditures can be adjusted and managed by us to match market demand and activity levels. For the fourth quarter, we expect total capital expenditures of approximately $150 million.
Current wording
The majority of our capital expenditures are expected to be used for normal, recurring items necessary to support our business. A portion of our capital expenditures can be adjusted and managed by us to match market demand and activity levels.
Previous wording
We anticipate $16.5 million of expenditures for the remainder of 2024 related to various contractual obligations such as certain commitments to purchase proppants and lease liabilities.
Current wording
We anticipate $44.7 million of expenditures for the remainder of 2025 related to various contractual obligations such as certain commitments to purchase proppants and lease liabilities.
Previous wording
During the nine months ended September 30, 2024, our sources of cash flow included:
Current wording
During the three months ended March 31, 2025, our sources of cash flow included:
Previous wording
•$860 million from operating activities, and
Current wording
•$208 million from operating activities, and
Previous wording
•$14.7 million in proceeds from the disposal of property and equipment.
Current wording
•$4.3 million in proceeds from the disposal of property and equipment.
Previous wording
During the nine months ended September 30, 2024, our uses of cash flow included:
Current wording
During the three months ended March 31, 2025, our uses of cash flow included:
Previous wording
•$538 million to make capital expenditures for the betterment and refurbishment of drilling services and completion services equipment and, to a much lesser extent, equipment for our other businesses, to acquire and procure equipment to support our drilling services, completion services, drilling products, and other operations,
Current wording
•$162 million to make capital expenditures for the betterment and refurbishment of drilling services and completion services equipment and, to a much lesser extent, equipment for our other businesses, to acquire and procure equipment to support our drilling services, completion services, drilling products, and other operations,
Previous wording
•$270 million for repurchases of our common stock,
Current wording
•$20.3 million for repurchases of our common stock,
Previous wording
•$95.6 million to pay dividends on our common stock, and
Current wording
•$30.9 million to pay dividends on our common stock,
Previous wording
We paid cash dividends during the nine months ended September 30, 2024 as follows:
Current wording
We paid cash dividends during the three months ended March 31, 2025 as follows:
Showing the first 40 of 51 pairs. Open the source sections for the rest.
Rearranged current paragraphs (3)
Current report — wording carried from elsewhere
(1)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.
Current report — wording carried from elsewhere
(1)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.
Current report — wording carried from elsewhere
Direct operating costs and depreciation, amortization and impairment expense were approximately $0.6 million and $2.3 million higher than they would have otherwise been for the three months ended March 31, 2025, respectively, as a result of the step up to fair value of our drill bits in accordance with purchase accounting. For the three months ended March 31, 2024, direct operating costs and depreciation, amortization and impairment were approximately $2.2 million and $5.8 million higher, respectively, as a result of the step up to fair value of our drill bits.
Rearranged previous paragraphs (6)
Previous report — wording carried elsewhere
NexTier merger. We now have the following reportable business segments: (i) drilling services, (ii) completion services and (iii) drilling products.
Previous report — wording carried elsewhere
The following tables summarize results of operations by business segment for the nine months ended September 30, 2024 and September 30, 2023:
Previous report — wording carried elsewhere
(3)Operational data relates to our contract drilling business. A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.
Previous report — wording carried elsewhere
Other operating income, net in 2024 was due to gain on legal settlements.
Previous report — wording carried elsewhere
The majority of these expenditures are expected to be used for normal, recurring items necessary to support our business.
Previous report — wording carried elsewhere
Solutions Inc. Equity and Incentive Award Plan and the NexTier Oilfield Solutions Inc. (Former C&J Energy) Management Incentive Plan and not pursuant to the stock buyback program.