PATTERSON UTI ENERGY INC
For the period ended Mar 31, 2026. Filed Apr 28, 2026.
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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, 2026 · Filed Apr 28, 2026
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 2025-09-30; filed 2025-10-28.
0000889900-25-000074
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2026-03-31; filed 2026-04-28.
0000889900-26-000033
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 150 previous paragraphs and 123 current paragraphs.
38 unchanged; 40 reworded; 42 added; 65 removed; 7 previous and 3 current paragraphs rearranged.
Tables are not compared: 16 previous and 12 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 (42)
Current report
(1)In January 2026, we signed a multi-year agreement to lease two rigs to DLS Archer Ltd. S.A. to support Archer’s operations in Argentina’s Vaca Muerta formation.
Current report
Recent Developments in Market Conditions and Outlook — Our revenues, profitability and cash flows are highly dependent upon capital expenditures of exploration and production companies (“E&Ps”), which are largely driven by capital budgets set to achieve respective production targets in relation to current and expected future prices for oil and natural gas, as well as broader macroeconomic conditions. Commodity prices have historically been volatile and are affected by global supply and demand dynamics, geopolitical conditions and other factors, but were relatively range-bound in recent years. The current demand for equipment and services remains impacted by macro conditions that are outside of our control, including commodity prices, geopolitical environment, changes to international tariffs and trade policies, inflationary pressures, global economic conditions, as well as customer consolidation and focus by E&Ps and service companies on capital returns.
Current report
During 2025, global economic conditions weakened in part due to uncertainty related to trade policies and tariffs implemented or proposed by the United States and other governments. At the same time, oil markets were affected by evolving supply dynamics, including changes in production policies by OPEC+ countries and increasing non-OPEC supply. These factors contributed to periods of downward pressure on crude oil prices and increased uncertainty in global energy markets.
Current report
In the first quarter of 2026, energy markets experienced high volatility, driven in large part by instability in the Middle East, including the conflict with Iran, and concerns regarding potential disruptions to global supply and transportation routes, which has contributed to fluctuations in commodity prices and market sentiment. Geopolitical uncertainty, even in the absence of actual supply disruptions, may contribute to short-term commodity price volatility as market participants adjust expectations regarding potential sanctions, production levels and regional stability. While the full effects are yet to be determined, we believe these dynamics could support increased activity in second half of 2026, particularly in North America, as operators reassess capital allocation and activity levels commensurate with commodity prices and supply chain dependability.
Current report
In our drilling services segment for the second quarter of 2026, we expect adjusted gross profit will decline slightly, sequentially. We expect our active rig count to average around 90 rigs, and we expect to exit the quarterat a higher level than the quarterly average, potentially 92 to 95 rigs, as we reactivate rigs during the second half of the quarter.
Current report
In our completion services segment for the second quarter of 2026, we expect adjusted gross profit to be higher than the first quarter. We will continue to prioritize investments that high-grade our assets with technologies that we believe will generate attractive long-term returns, versus investing to extend the life of diesel equipment.
Current report
In our drilling products segment for the second quarter of 2026, we expect adjusted gross profit will decline slightly, sequentially. We expect lower activity in Canada with normal seasonal spring breakup, as well as an increase in international costs, particularly in the Middle East.
Current report
(1)Adjusted gross profit, which is considered a non-GAAP financial measure, 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
General and administrative expense increased primarily due to certain internal reorganization initiatives and employee separation costs incurred during the first quarter of 2026.
Current report
General and administrative expense increased primarily due to certain internal reorganization initiatives and employee separation costs incurred during the first quarter of 2026.
Current report
(1)Adjusted gross profit, which is considered a non-GAAP financial measure, 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
Completion services revenues and direct operating costs decreased primarily due to our fracturing operations, which were largely the result of disruptions caused by winter storm conditions. Revenues and direct operating costs from our fracturing operations decreased by approximately $7.2 million and $2.2 million, or 1% and 0.5%, respectively, which was primarily due to a 2% decline in total pumping hours. Other completion services revenue and direct operating costs decreased $14.7 million and $7.3 million, or 12% and 7%, respectively, mainly due to lower activity for our power solutions and cementing operations.
Current report
General and administrative decreased, benefiting from cost reduction activities.
Current report
Other operating expense (income), net in the fourth quarter of 2025 reflected a favorable contract settlement.
Current report
General and administrative decreased, benefiting from cost reduction activities.
Current report
Other operating expense (income), net in the fourth quarter of 2025 reflected a favorable contract settlement.
Current report
(1)Adjusted gross profit, which is considered a non-GAAP financial measure, 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
Revenue and direct operating costs declined primarily due to lower activity in the United States. Revenues and direct operating costs in the United States decreased by approximately $4.1 million and $1.2 million, or 7% and 3%, respectively. The decrease in direct operating costs in the United States was partially offset by higher raw material and labor costs.
Current report
Capital expenditures increased primarily due to higher raw material costs, particularly tungsten powder used in certain matrix bit applications.
Current report
Revenue and direct operating costs declined primarily due to lower activity in the United States. Revenues in the United States decreased by approximately $4.6 million or 8%. The decrease in direct operating costs was partially offset by higher raw material costs and repair expenses.
Current report
Depreciation, amortization and impairment expense decreased year over year primarily due to the diminishing impact of the purchase‑accounting step‑up to fair value related to our drill bits.
Current report
Revenues increased primarily due to higher oil production and higher realized pricing on crude oil. Market prices for crude oil averaged $72.74 per barrel in the first quarter of 2026, as compared to $59.62 per barrel in the fourth quarter of 2025.
Current report
Depreciation, depletion, amortization and impairment expense decreased primarily due to a $1.7 million impairment charge recorded in our oil and natural gas properties business during the first quarter of 2025. There was no impairment charge in the first quarter of 2026.
Current report
General and administrative increased primarily due to higher share‑based compensation expense related to cash-settled liability awards and employee separation costs incurred during the first quarter of 2026.
Current report
Other operating (income) expenses, net includes net losses associated with the disposal of assets. Accordingly, the related gains or losses have been excluded from the results of specific segments. The change in other operating (income) expenses, net was primarily due to a $4.5 million reversal of cumulative compensation costs associated with certain performance-based restricted stock units during the first quarter of 2026.
Current report
General and administrative increased primarily due to higher share‑based compensation expense related to cash-settled liability awards and employee separation costs incurred during the first quarter of 2026
Current report
Other operating (income) expenses, net includes net losses associated with the disposal of assets. Accordingly, the related gains or losses have been excluded from the results of specific segments. The change in other operating (income) expenses, net was primarily due to a $4.5 million reversal of cumulative compensation costs associated with certain performance-based restricted stock units during the first quarter of 2026.
Current report
We continue to monitor income tax developments, including OECD Pillar 2 legislation, in the United States and other countries where we have legal entities or operations. We will incorporate into our future financial statements the impacts, if any, of future regulations and additional authoritative guidance when finalized.
Current report
Overview
Current report
Cash Flows
Current report
Our cash flows for the three months ended March 31, 2026 and 2025 are summarized below:
Current report
Operating Activities —The decrease in cash provided by operating activities between the three months ended March 31, 2026 and 2025 was primarily attributable to lower activity in 2026.
Current report
Investing Activities — The decrease in cash used in investing activities between the three months ended March 31, 2026 and 2025 was primarily attributable to lower capital spending due to timing of order placement, lower maintenance capital expenditures due to fewer operating days, and an increase in proceeds from the sale of assets.
Current report
Financing Activities —The decrease in cash used in financing activities between the three months ended March 31, 2026 and 2025 was primarily attributable to fewer share repurchases as well as the repayment of debt during 2025. The decrease was partially offset by an increase in dividends paid during the first quarter of 2026.
Current report
Credit Agreement
Current report
On April 24, 2026, we entered into the Assignment and Amendment No. 1 to Second Amended and Restated Credit Agreement, which amended the Second Amended and Restated Credit Agreement, whereby, among other things, (i) extends the maturity date for $450 million of revolving credit commitments of certain lenders under the Credit Agreement from January 31, 2030 to January 31, 2031, but we may request two one-year extensions, subject to the satisfaction of certain conditions, and (ii) assigns $25 million of the revolving credit commitments from HSBC Bank USA, N.A., to JPMorgan Chase Bank, N.A., in each case, on the terms and subject to the conditions set forth therein.
Current report
Reimbursement Agreement
Current report
For additional information regarding our long-term debt, see Note 9 of Notes to consolidated financial statements in Item 8 of our Annual Report.
Current report
Sources and Uses of Cash
Current report
Our revenues, profitability and cash flows are highly dependent upon capital expenditures of exploration and production companies (“E&Ps”), which are largely driven by capital budgets set to achieve respective production targets in relation to current and expected future prices for oil and natural gas, as well as broader macroeconomic conditions. Commodity prices have historically been volatile and are affected by global supply and demand dynamics, geopolitical conditions and other factors, but were relatively range-bound in recent years. The current demand for equipment and services remains impacted by macro conditions that are outside of our control, including commodity prices, geopolitical environment, changes to international tariffs and trade policies, inflationary pressures, global economic conditions, as well as customer consolidation and focus by E&Ps and service companies on capital returns.
Showing the first 40 of 42 passages. Open the source sections for the rest.
Removed paragraphs (65)
Previous report
In our Drilling Services segment for the fourth quarter of 2025, we expect our average rig count will be similar to the third quarter, which reflects activity remaining relatively steady, compared to our current rig count, through the end of 2025. We expect adjusted gross profit within the Drilling Services segment to slightly decline, sequentially.
Previous report
In our Completion Services segment for the fourth quarter of 2025, we expect adjusted gross profit to decline, sequentially. From an activity perspective, we expect less seasonality compared to the fourth quarter of 2024.
Previous report
In our Drilling Products segment for the fourth quarter of 2025, we expect adjusted gross profit will improve slightly, sequentially. We expect relatively steady results in the United States and Canada, with higher revenue and adjusted gross profit from our International business.
Previous report
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 report
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 report
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 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 profit to adjusted gross profit by segment.
Previous report
Depreciation, amortization and impairment expense decreased primarily due to a $27.8 million impairment charge to Latin American drilling equipment during the second quarter of 2025. See Note 5 of Notes to unaudited condensed consolidated financial statements for additional information.
Previous report
Other operating expense (income), net included a gain from a favorable legal settlement, offset by a legal accrual taken during the third quarter of 2025, and included insurance proceeds received during the second quarter of 2025. Legal accrual is included in “Accrued liabilities” in our consolidated balance sheets.
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 profit to adjusted gross profit by segment.
Previous report
Revenues declined modestly due to reduced sales of sand and chemical products.
Previous report
Direct operating costs decreased, benefiting from improved efficiency, as well as cost reduction activities.
Previous report
Other operating expense (income), net included a legal accrual taken during the third quarter of 2025, which is included in “Accrued liabilities” in our consolidated balance sheets.
Previous report
Capital expenditures increased primarily due to the timing of order placement and spending on committed deliveries.
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 profit to adjusted gross profit by segment.
Previous report
Revenue declined primarily due to lower activity in Saudi Arabia.
Previous report
Direct operating costs increased due to higher than normal bit repair expense during the third quarter of 2025.
Previous report
Direct operating costs and depreciation, amortization and impairment expense were approximately $0.8 million and $1.6 million higher than they would have otherwise been for the three months ended September 30, 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 June 30, 2025, direct operating costs and depreciation, amortization and impairment expense were approximately $0.5 million and $1.6 million higher than they would have otherwise been, respectively, as a result of the step up to fair value of our drill bits.
Previous report
Capital expenditures decreased primarily due to the timing of order placement and spending on committed deliveries.
Previous report
Depreciation, depletion, amortization and impairment expense, excluding the effects of our oilfield rentals business divestiture, decreased due to a $1.9 million impairment that was recorded in the second quarter of 2025, while no impairment was recorded in the third quarter of 2025.
Previous report
Results of Operations
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 profit to adjusted gross profit by segment.
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 2025.
Previous report
Depreciation, amortization and impairment decreased 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 in 2024. See Note 5 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 profit to adjusted gross profit by segment.
Previous report
Depreciation, amortization and impairment expense decreased primarily due to fewer capital additions placed in service relative to asset retirements between the periods.
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 6 of Notes to unaudited condensed consolidated financial statements for additional information.
Previous report
Other operating expense (income), net included a legal accrual taken during the third quarter of 2025, whereas in 2024 was due to gain on legal settlements. Legal accrual is included in “Accrued liabilities” in our consolidated balance sheets.
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 profit to adjusted gross profit by segment.
Previous report
Revenue declined primarily due to lower activity in Saudi Arabia.
Previous report
Direct operating costs increased due to higher than normal bit repair expense during the third quarter of 2025.
Previous report
Direct operating costs and depreciation, amortization and impairment expense were approximately $1.9 million and $5.4 million higher than they would have otherwise been for the nine months ended September 30, 2025, 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 expense 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.
Previous report
Excluding the effects of our oilfield rentals business divestiture, the decrease in revenue and direct operating costs was driven by lower realized crude oil prices. Oil prices averaged $67.31 per barrel in the nine months ended September 30, 2025 as compared to $78.58 per barrel in the nine months ended September 30, 2024.
Previous report
Depreciation, depletion, amortization and impairment expense, excluding the effects of our oilfield rentals business divestiture, was relatively flat between the periods.
Previous report
Capital expenditures decreased due to our oilfield rentals business divestiture in the second quarter of 2025.
Previous report
Corporate activities were relatively flat between the periods.
Previous report
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.
Previous 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.
Previous report
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 September 30, 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 report
None of our subsidiaries are currently required to be a guarantor under the Credit Agreement. However, if any subsidiary guarantees or incurs debt, which does not qualify for certain limited exceptions and is otherwise, in the aggregate with all other similar debt, in excess of Priority Debt (as defined in the Credit Agreement), such subsidiary is required to become a guarantor under the Credit Agreement.
Showing the first 40 of 65 passages. Open the source sections for the rest.
Reworded paragraphs (40)
Previous 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.
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 aim to improve the statistical accuracy of wellbore placement for directional and horizontal wells. We also 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, 2025, our rig fleet included 136 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, 2026, our rig fleet included 137 marketed Tier-1, super-spec rigs.
Previous wording
Our well completion services business consists of services for hydraulic fracturing, wireline and pumping, completion support, and cementing. It also includes our power solutions natural gas fueling business and our proppant last mile logistics and storage business. Our completion services business operates in several of the most active basins in the continental United States including the Permian, the Marcellus Shale/Utica, the Eagle Ford, Mid-Continental, Haynesville, and the Bakken/Rockies.
Current wording
Our well completion services business consists of services for hydraulic fracturing, wireline and pumping, completion support and cementing. It also includes our power solutions natural gas fueling business and our proppant last mile logistics and storage business. Our completion services business operates in many of the most active basins in the continental United States including the Permian, the Marcellus Shale/Utica, the Eagle Ford, Mid-Continental, Haynesville and the Bakken/Rockies.
Previous wording
To address customer demand for lower-emission and more cost efficient operations, we continue to expand our portfolio of natural gas-powered solutions, including electric, direct drive, and dual fuel pumps, to replace legacy diesel completion services equipment.
Current wording
In an effort to address customer demand for lower-emission and more cost-efficient operations, we continue to expand our portfolio of natural gas-powered solutions, including electric, direct drive and dual fuel pumps, to replace legacy diesel completion services equipment.
Previous 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.
Current wording
We serve the energy and mining markets by manufacturing and distributing drill bits and downhole tools throughout North America and internationally in over 30 countries. Our drilling equipment is used in oil and natural gas exploration and production and in geothermal and 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
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. During the second quarter of 2025, global economic conditions deteriorated, in part, because of enacted and proposed trade policies and tariffs by the United States and other governments, as well as uncertainty regarding potential future changes to global trade policies and tariffs. Additionally, during the second quarter of 2025, OPEC+ countries began phasing out voluntary crude oil production cuts, leading to an increase in global supply. These developments, combined with rising geopolitical tensions— particularly in the Middle East— heightened uncertainty in global energy markets, which contributed to a decline in our share price, lowered average crude oil futures prices and increased uncertainty regarding the future economic environment in which we operate. During the third quarter of 2025, global economic conditions and the global energy market remained uncertain, with ongoing effects from trade policy uncertainty, the phase-out of voluntary crude oil production cuts by OPEC+ countries, and downward pressure on crude oil futures prices. 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 $65.78 per barrel in the third quarter of 2025, as compared to $64.57 per barrel in the second quarter of 2025, and closed at $58.34 per barrel on October 20, 2025. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $3.03 per MMBtu in the third quarter of 2025 as compared to an average of $3.19 per MMBtu in the second quarter of 2025, and closed at $2.99 per MMBtu on October 20, 2025.
Current wording
Oil prices averaged $72.74 per barrel in the first quarter of 2026, as compared to $59.62 per barrel in the fourth quarter of 2025, and closed at $91.06 per barrel on April 20, 2026. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $4.71 per MMBtu in the first quarter of 2026 as compared to an average of $3.73 per MMBtu in the fourth quarter of 2025, and closed at $2.81 per MMBtu on April 20, 2026.
Previous wording
Our average active rig count in the United States for the third quarter of 2025 was 95 rigs. This was a decrease from our average active rig count for the second quarter of 2025 of 104. Term contracts help support our operating rig count. 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, 2025 was approximately $256 million. Approximately 9% of our total contract drilling backlog in the United States at September 30, 2025 is reasonably expected to remain at September 30, 2026. See Note 2 of Notes to unaudited condensed consolidated financial statements for additional information on backlog.
Current wording
Our drilling activity in the United States remained relatively stable in the first quarter of 2026, with an average active rig count in the United States of 92 rigs, compared to our average active rig count of 93 in the fourth quarter of 2025, supported in part by term contracts. Term contracts help support our operating rig count. 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, 2026 was approximately $260 million. Approximately 7% of our total contract drilling backlog in the United States at March 31, 2026 is reasonably expected to remain at March 31, 2027. See Note 2 of Notes to unaudited condensed consolidated financial statements for additional information on backlog.
Previous wording
For the three months ended September 30, 2025 and June 30, 2025 and for the nine months ended September 30, 2025 and September 30, 2024 our operating revenues consisted of the following (dollars in thousands):
Current wording
For the three months ended March 31, 2026, December 31, 2025 and March 31, 2025 our operating revenues consisted of the following (dollars in thousands):
Previous wording
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 approximately $360 million and $223 million, or 17% and 13%, respectively.
Current wording
Completion services revenues and direct operating costs decreased primarily due to our fracturing operations. Revenues and direct operating costs from our fracturing operations decreased by approximately $39.8 million and $45.4 million, or 7% and 9%, respectively due to lower activities. Total pumping hours from our fracturing operations declined 6% year over year. Other completion services revenue and direct operating costs decreased $46.7 million and $31.0 million, or 30% and 25%, respectively, primarily due to lower service pricing and decline in activity for our power solutions operations and a decline in activity in our wireline and cementing operations.
Previous wording
(2)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 profit to adjusted gross profit by segment.
Current wording
(2)Adjusted gross profit, which is considered a non-GAAP financial measure, 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 profit to adjusted gross profit by segment.
Previous wording
Revenues and direct operating costs, excluding the effects of our oilfield rentals business divestiture, were relatively flat between sequential quarters.
Current wording
Revenues and direct operating costs were relatively flat between sequential quarters.
Previous wording
The increase in capital expenditures was primarily due to the expansion of our Corporate office.
Current wording
Capital expenditures decreased primarily due to the expansion of our Corporate office in 2025.
Previous wording
Our effective income tax rate for the three months ended September 30, 2025 was 15.3%, compared with (2.5)% for the three months ended June 30, 2025. The difference in effective income tax rates between the periods was primarily attributable to the impact of permanent differences and book impairments against earnings between periods.
Current wording
Our effective income tax rate for the three months ended March 31, 2026 was 12.8%, compared with 39.2% for the three months ended December 31, 2025. 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 effective income tax rate for the nine months ended September 30, 2025 was 4.6%, compared with (0.8)% for the nine months ended September 30, 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 permanent differences against earnings between periods.
Current wording
Our effective income tax rate for the three months ended March 31, 2026 was 12.8%, compared with 51.9% for the three months ended March 31, 2025. 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
We continue to monitor income tax developments in the United States and other countries where we have legal entities. On July 4, 2025, the One Big Beautiful Bill Act (the “OBBBA”) was signed into law in the United States. This legislation includes several changes to existing income tax provisions with certain changes effective during 2025 and other changes effective after 2025. We continue to evaluate the impact of the OBBBA on our consolidated financial statements.
Current wording
On July 4, 2025, the One Big Beautiful Bill Act (the “OBBBA”) was signed into law in the United States. This legislation includes several changes to existing income tax provisions with certain changes effective during 2025 and other changes effective after 2025.
Previous wording
Our primary sources of liquidity are cash and cash equivalents, availability under our Credit Agreement and cash provided by operating activities. As of September 30, 2025, we had approximately $500 million in working capital, including $185 million of cash and cash equivalents, and approximately $495 million available under our Credit Agreement.
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, 2026, we had approximately $602 million in working capital, including $335 million of cash and cash equivalents, and approximately $497 million available under our Credit Agreement.
Previous wording
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. The commitments under the Credit Agreement are $500 million, and the loans and commitments under the Credit Agreement mature on January 31, 2030.
Current wording
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 of March 31, 2026, the commitments under the Credit Agreement were $500 million, and the loans and commitments under the Credit Agreement would mature on January 31, 2030.
Previous wording
The Credit Agreement contains representations, warranties, affirmative and negative covenants and events of default and associated remedies that we believe are customary for agreements of this nature, including certain restrictions on our ability and the ability of each of our subsidiaries to grant liens and on the ability of each of our non-guarantor subsidiaries to incur debt. If our credit rating is below investment grade at both Moody’s and S&P, we will become subject to a restricted payment covenant, which would generally require us to have a Pro Forma Debt Service Coverage Ratio (as defined in the Credit Agreement) greater than or equal to 1.50 to 1.00 immediately before and immediately after making any restricted payment. Restricted payments include, among other things, dividend payments, repurchases of our common stock, distributions to holders of our common stock or any other payment or other distribution to third parties on account of our or our subsidiaries’ equity interests. Our credit rating is currently investment grade at both credit rating agencies. The Credit Agreement also requires that our total debt to capitalization ratio, expressed as a percentage, not exceed 50% as of the last day of each fiscal quarter. The Credit Agreement generally defines the total debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the end of the most recently ended fiscal quarter. We were in compliance with these covenants at September 30, 2025.
Current wording
The Credit Agreement contains representations, warranties, affirmative and negative covenants and events of default and associated remedies that we believe are customary for agreements of this nature. We were in compliance with the covenants at March 31, 2026. No events of default had occurred at March 31, 2026.
Previous 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 September 30, 2025, we had $36.3 million in letters of credit outstanding under the Reimbursement Agreement.
Current wording
2015 Reimbursement Agreement — On March 16, 2015, we entered into a Reimbursement Agreement (as amended from time to time, the “2015 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.
Previous wording
We had $43.1 million of outstanding letters of credit at September 30, 2025, which was comprised of $36.3 million outstanding under the Reimbursement Agreement, $4.8 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 September 30, 2025, no amounts had been drawn under the letters of credit. As of September 30, 2025, we had $37.0 million in surety bond exposure issued as financial assurance on an insurance agreement.
Current wording
We had $32.4 million of outstanding letters of credit at March 31, 2026, which was comprised of $27.5 million outstanding under the 2015 Reimbursement Agreement, $2.8 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, 2026, no amounts had been drawn under the letters of credit. As of March 31, 2026, we had $37.0 million in surety bond exposure issued as financial assurance on an insurance agreement.
Previous wording
During the nine months ended September 30, 2025, our sources of cash flow included:
Current wording
During the three months ended March 31, 2026, our sources of cash flow included:
Previous wording
•$564 million from operating activities, and
Current wording
•$63.9 million from operating activities and
Previous wording
•$33.2 million in proceeds from the disposal of property and equipment, including insurance recoveries.
Current wording
•$12.2 million in proceeds from the disposal of property and equipment, including insurance recoveries.
Previous wording
During the nine months ended September 30, 2025, our uses of cash flow included:
Current wording
During the three months ended March 31, 2026, our uses of cash flow included:
Previous wording
•$451 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
•$117 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
•$92.1 million to pay dividends on our common stock,
Current wording
•$38.0 million to pay dividends on our common stock,
Previous wording
•$69.4 million for repurchases of our common stock,
Current wording
•$0.4 million for repurchases of our common stock,
Previous wording
•$6.2 million for payments related to finance leases, and
Current wording
•$2.0 million for payments related to finance leases and
Previous wording
•$13.4 million for other investing and financing activities.
Current wording
•$1.6 million for other investing and financing activities.
Previous wording
We paid cash dividends during the nine months ended September 30, 2025 as follows:
Current wording
We paid cash dividends during the three months ended March 31, 2026 as follows:
Previous wording
On October 22, 2025, our Board of Directors approved a cash dividend on our common stock in the amount of $0.08 per share to be paid on December 15, 2025 to holders of record as of December 1, 2025. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our debt agreements and other factors. Our Board of Directors may, without advance notice, reduce or suspend our dividend for any reason, including to improve our financial flexibility and position our company for long-term success. There can be no assurance that we will pay a dividend in the future.
Current wording
On April 22, 2026, our Board of Directors approved a cash dividend on our common stock in the amount of $0.10 per share to be paid on June 15, 2026 to holders of record as of June 1, 2026. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our debt agreements and other factors. Our Board of Directors may, without advance notice, reduce or suspend our dividend for any reason, including to improve our financial flexibility and position our company for long-term success. There can be no assurance that we will pay a dividend in the future.
Previous wording
Treasury stock acquisitions during the nine months ended September 30, 2025 were as follows (dollars in thousands):
Current wording
Treasury stock acquisitions during the three months ended March 31, 2026 were as follows (dollars in thousands):
Previous wording
(1)We withheld 680,817 shares during the nine months ended September 30, 2025 with respect to employees’ tax withholding obligations upon the vesting of restricted stock units. These shares were acquired at fair market value. These acquisitions were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2021 Long-Term Incentive Plan, as amended and the NexTier Oilfield Solutions Inc. Equity and Incentive Award Plan, and not pursuant to the stock buyback program.
Current wording
(1)We withheld 51,346 shares during the three months ended March 31, 2026 with respect to employees’ tax withholding obligations upon the vesting of restricted stock units. These shares were acquired at fair market value. These acquisitions were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2021 Long-Term Incentive Plan, as amended, and the NexTier Oilfield Solutions Inc. Equity and Incentive Award Plan, and not pursuant to the stock buyback program.
Previous wording
Commitments— As of September 30, 2025, we had commitments to purchase major equipment totaling approximately $72.5 million. Our completion services segment has entered into agreements to purchase minimum quantities of proppants from certain vendors. As of September 30, 2025, the remaining minimum obligation under these agreements was approximately $20.6 million, of which approximately $2.7 million, $13.1 million, and $4.8 million relate to the remainder of 2025, 2026, and 2027, respectively.
Current wording
Commitments— As of March 31, 2026, we had commitments to purchase major equipment totaling approximately $128 million. Our completion services segment has entered into agreements to purchase minimum quantities of proppants from certain vendors. As of March 31, 2026, the remaining minimum obligation under these agreements was approximately $21.7 million, of which approximately $16.9 million and $4.8 million relate to the remainder of 2026 and 2027, respectively.
Previous wording
Operating lease liabilities totaled $46.4 million and finance lease liabilities totaled $21.3 million as of September 30, 2025.
Current wording
Operating lease liabilities totaled $40.9 million and finance lease liabilities totaled $6.6 million as of March 31, 2026.
Previous wording
Adjusted earnings before interest, taxes, depreciation and amortization (“Adjusted EBITDA”) is not defined by accounting principles generally accepted in the United States of America (“GAAP”). We define Adjusted EBITDA as net income (loss) plus income tax expense (benefit), net interest expense, depreciation, depletion, amortization and impairment expense, legal accruals and settlements, impairment of goodwill, and merger and integration expense. We present Adjusted EBITDA as a supplemental disclosure because we believe it provides to both management and investors additional information with respect to the performance of our fundamental business activities and a comparison of the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be construed as an alternative to the GAAP measure of net income (loss). Our computations of Adjusted EBITDA may not be the same as similarly titled measures of other companies. Set forth below is a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income (loss).
Current wording
Adjusted earnings before interest, taxes, depreciation and amortization (“Adjusted EBITDA”) is not defined by GAAP. We define Adjusted EBITDA as net income (loss) plus income tax expense (benefit), net interest expense, depreciation, depletion, amortization and impairment expense, legal accruals and settlements, impairment of goodwill and merger and integration expense. We present Adjusted EBITDA as a supplemental disclosure because we believe it provides, to both management and investors, additional information with respect to the performance of our fundamental business activities and a comparison of the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be construed as an alternative to the GAAP measure of net income (loss). Our computations of Adjusted EBITDA may not be the same as similarly titled measures of other companies. Set forth below is a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income (loss).
Previous wording
We define “Adjusted gross profit” as revenues less direct operating costs (excluding depreciation, depletion, amortization and impairment expense, which does not include impairment of goodwill). Adjusted gross profit is included as a supplemental disclosure because it is a useful indicator of our operating performance.
Current wording
Adjusted gross profit is considered a non-GAAP financial measure. We define “Adjusted gross profit” as revenues less direct operating costs (excluding depreciation, depletion, amortization and impairment expense, which does not include impairment of goodwill). Adjusted gross profit is included as a supplemental disclosure because it is a useful indicator of our operating performance.
Previous wording
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from such estimates. There have been no material changes to our critical accounting estimates previously disclosed in Item 7 of our Annual Report, except as follows:
Current wording
The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from such estimates. There have been no material changes to our critical accounting estimates previously disclosed in Item 7 of our Annual Report.
Previous wording
A decline in demand for oil and natural gas, prolonged low oil or natural gas prices, expectations of decreases in oil and natural gas prices or a reduction in the ability of our customers to access capital would likely result in reduced capital expenditures by our customers and decreased demand for our services, which could have a material adverse effect on our operating results, financial condition and cash flows. 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.
Current wording
In light of these and other factors, we expect oil and natural gas prices to continue to be unpredictable and to affect our financial condition, operations and ability to access sources of capital. Higher oil and natural gas prices do not necessarily result in increased activity because demand for our services is generally driven by our customers’ expectations of future oil and natural gas prices, as well as our customers’ ability to access, and willingness to deploy, capital to fund their operating and capital expenditures. A decline in demand for oil and natural gas, prolonged low oil or natural gas prices, expectations of decreases in oil and natural gas prices or a reduction in the ability of our customers to access capital would likely result in reduced capital expenditures by our customers and decreased demand for our services, which could have a material adverse effect on our operating results, financial condition and cash flows. 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.
Previous wording
Moderate inflationary pressures and uncertainty regarding recently enacted and proposed changes to trade policies and tariffs by the United States and other governments, as well as uncertainty regarding potential future changes to global trade policies and tariffs, 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.
Current wording
Moderate inflationary pressures and uncertainty regarding recently enacted and proposed changes to trade policies and tariffs by the United States and other governments, as well as uncertainty regarding potential future changes to global trade policies and tariffs, 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 and raw materials 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.
Rearranged current paragraphs (3)
Current report — wording carried from elsewhere
Capital expenditures decreased primarily due to the timing of order placement.
Current report — wording carried from elsewhere
Capital expenditures decreased primarily due to the timing of order placement.
Current report — wording carried from elsewhere
Oil prices averaged $72.74 per barrel in the first quarter of 2026, as compared to $59.62 per barrel in the fourth quarter of 2025, and closed at $91.06 per barrel on April 20, 2026. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $4.71 per MMBtu in the first quarter of 2026 as compared to an average of $3.73 per MMBtu in the fourth quarter of 2025, and closed at $2.81 per MMBtu on April 20, 2026.
Rearranged previous paragraphs (7)
Previous report — wording carried elsewhere
Corporate expenses were relatively flat between sequential quarters.
Previous report — wording carried elsewhere
The following tables summarize results of operations by business segment for the nine months ended September 30, 2025 and September 30, 2024:
Previous report — wording carried elsewhere
(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 report — wording carried elsewhere
(1)Other includes our oilfield rentals business, prior to its divestiture in April 2025, and oil and natural gas working interests.
Previous report — wording carried elsewhere
(2)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 profit to adjusted gross profit by segment.
Previous report — wording carried elsewhere
The changes for the nine months ended September 30, 2025 as compared to the nine months ended September 30, 2024 can be primarily attributed to the divestiture of our oilfield rentals business during the second quarter of 2025. In order to provide a more meaningful basis for comparison, the discussion below is focused on changes between comparable periods excluding the effects of the divestiture.
Previous report — wording carried elsewhere
In light of these and other factors, we expect oil and natural gas prices to continue to be unpredictable and to affect our financial condition, operations and ability to access sources of capital. Higher oil and natural gas prices do not necessarily result in increased activity because demand for our services is generally driven by our customers’ expectations of future oil and natural gas prices, as well as our customers’ ability to access, and willingness to deploy, capital to fund their operating and capital expenditures.