Management Overview — We are a Houston, Texas-based leading provider of drilling and completion services to oil and natural gas exploration and production companies in the United States and other select countries, including contract drilling services, integrated well completion services and directional drilling services in the United States, and specialized drill bit solutions in North America, the Middle East and many other regions around the world. We operate under three reportable business segments: (i) drilling services, (ii) completion services and (iii) drilling products. Drilling Services Our contract drilling business operates primarily in the continental United States, 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. As of June 30, 2026, we had 148 marketed land-based drilling rigs based in the following regions: Region Number of Rigs West Texas 63 Appalachia 21 Oklahoma 16 Rockies 22 South Texas 13 East Texas 7 Colombia 3 Ecuador 1 Argentina(1) 2 Total 148 (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. 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 June 30, 2026, our rig fleet included 137 marketed Tier-1, super-spec rigs. Completion Services 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. 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. We are also advancing our Vertex™ fully automated, closed-loop completions process, a component of our proprietary digital completions management platform, eos™, which offers our customers the opportunity for greater operational efficiency, lower costs and improved performance, while laying the foundation for integrating AI-driven reservoir technologies. 25 Drilling Products 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. 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. 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. During the first half of 2026, energy markets experienced increased volatility driven by geopolitical developments in the Middle East, including the conflict with Iran and ongoing disruptions to global oil supply and key transportation routes. These events contributed to fluctuations in commodity prices, customer spending expectations and overall market sentiment. In addition, global energy markets continue to be influenced by OPEC+ production decisions, changes in worldwide supply and demand balances and broader macroeconomic conditions. While the full effects are yet to be determined, we believe these dynamics contributed to increased activity in the second quarter of 2026, particularly North America, and could support continued increases in activity in the second half of 2026, as operators reassess capital allocation and activity levels commensurate with commodity prices and long-term supply chain dependability. Oil prices averaged $95.65 per barrel in the second quarter of 2026, as compared to $72.74 per barrel in the first quarter of 2026, and closed at $84.25 per barrel on July 27, 2026. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $2.95 per MMBtu in the second quarter of 2026 as compared to an average of $4.71 per MMBtu in the first quarter of 2026, and closed at $2.63 per MMBtu on July 27, 2026. Our drilling activity in the United States remained relatively stable in the second quarter of 2026, with an average active rig count in the United States of 92 rigs, consistent with the first quarter of 2026 and supported in part by term contracts. Activity strengthened as the quarter progressed, and we exited the quarter with 96 rigs operating, reflecting a higher level of activity than the quarterly average. 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 June 30, 2026 was approximately $365 million. Approximately 15% of our total contract drilling backlog in the United States at June 30, 2026 is reasonably expected to remain at June 30, 2027. See Note 2 of Notes to unaudited condensed consolidated financial statements for additional information on backlog. In our drilling services segment for the third quarter of 2026, we expect adjusted gross profit to be higher than the second quarter. We expect our average U.S. rig count to be approximately 100 in the third quarter, and we expect to exit the quarter higher than the quarterly average. In our completion services segment for the third quarter of 2026, we expect adjusted gross profit to be higher than the second quarter, supported by near-full utilization across our active frac equipment and additional pricing improvement compared to the second quarter. In our drilling products segment for the third quarter of 2026, we expect adjusted gross profit to be higher than the second quarter, driven by higher drilling activity in the United States and the seasonal recovery from spring breakup in Canada. Recent Developments in Business and Financial Matters — During the second quarter of 2026, management approved a plan to exit our Colombian contract drilling operations, which resulted in incremental operating expenses totaling $21.0 million within the Drilling Services segment. Changes in Colombia’s political environment, coupled with continued reductions in activity forecasts and challenging market conditions in the region, have reduced the attractiveness of additional investment. The exit activity is expected to be substantially completed over the next year. 26 On May 19, 2026, we completed an offering of $500 million in aggregate principal amount of 6.05% senior notes due 2036 (the “2036 Notes”). The net proceeds before offering expenses from the offering of the 2036 Notes were approximately $496 million, which we used to fully redeem our outstanding 2028 Notes and for general corporate purposes. On June 4, 2026, we completed our redemption of all the approximately $483 million aggregate principal amount of the outstanding 2028 Notes. The 2028 Notes were redeemed at a redemption price of 100% of the principal amount of the 2028 Notes outstanding, plus accrued and unpaid interest to the redemption date. The total amount of the redemption was approximately $483 million, which was funded using a portion of the net proceeds from our 2036 Notes offering. We recognized a non-cash loss on extinguishment of debt of $0.9 million, primarily related to the write-off of unamortized debt issuance cost associated with the 2028 Notes, which is included in “Interest expense, net of amount capitalized” in the consolidated statement of operations. For the three months ended June 30, 2026 and March 31, 2026 and for the six months ended June 30, 2026 and June 30, 2025, our operating revenues consisted of the following (dollars in thousands): Three Months Ended Six Months Ended June 30, March 31, June 30, June 30, 2026 2026 2026 2025 Drilling Services $ 373,501 30.4 % $ 351,717 31.5 % $ 725,218 30.9 % $ 816,665 32.7 % Completion Services 753,641 61.4 % 679,587 60.8 % 1,433,228 61.1 % 1,485,412 59.4 % Drilling Products 91,333 7.4 % 79,797 7.1 % 171,130 7.3 % 174,053 7.0 % Other 9,492 0.8 % 6,230 0.6 % 15,722 0.7 % 23,727 0.9 % $ 1,227,967 100.0 % $ 1,117,331 100.0 % $ 2,345,298 100.0 % $ 2,499,857 100.0 % Results of Operations The following tables summarize results of operations by business segment for the three months ended June 30, 2026 and March 31, 2026: Three Months Ended June 30, March 31, Drilling Services 2026 2026 % Change (dollars in thousands) Revenues $ 373,501 $ 351,717 6.2 % Direct operating costs 259,619 217,861 19.2 % Adjusted gross profit (1) 113,882 133,856 (14.9) % General and administrative 6,617 7,097 (6.8) % Depreciation, amortization and impairment 85,490 83,944 1.8 % Other operating expense (income), net (962) (1,488) (35.3) % Operating income (loss) $ 22,737 $ 44,303 (48.7) % Capital expenditures $ 60,148 $ 54,421 10.5 % Operating days – U.S. (2) 8,361 8,301 0.7 % (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 the section of this Report titled “Non-GAAP Financial Measures” for a reconciliation of GAAP gross profit to adjusted gross profit by segment. (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. 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. Total revenues increased primarily due to higher activity in our directional drilling business, where operating days increased 16% and contributed approximately $12.6 million of the total segment revenue increase. Additionally, revenues from our contract 27 drilling business benefitted from our new multi-year, sales-type lease agreements for two rigs to DLS Archer Ltd. S.A. in support of Archer's operations in Argentina, contributing approximately $7.8 million of revenue during the period. Direct operating costs increased primarily due to costs incurred to reactive rigs in our contract drilling business and the higher activity in our directional drilling business. In addition, direct operating costs were approximately $20.0 million higher due to our decision to exit our contract drilling operations in Colombia. See Note 16 of Notes to unaudited condensed consolidated financial statements for additional information. Capital expenditures increased primarily due to the timing of order placement and incremental growth capital investments, including additional drilling rig structural upgrades. Three Months Ended June 30, March 31, Completion Services 2026 2026 % Change (dollars in thousands) Revenues $ 753,641 $ 679,587 10.9 % Direct operating costs 630,716 581,486 8.5 % Adjusted gross profit (1) 122,925 98,101 25.3 % General and administrative 7,230 7,330 (1.4) % Depreciation, amortization and impairment 108,838 111,472 (2.4) % Other operating expense (income), net (1,328) — NA Operating income (loss) $ 8,185 $ (20,701) NA Capital expenditures $ 75,023 $ 45,101 66.3 % (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 the section of this Report titled “Non-GAAP Financial Measures” for a reconciliation of GAAP gross profit to adjusted gross profit by segment. Completion services revenues and direct operating costs increased primarily due to our fracturing operations. First quarter results were lower, which were largely the result of disruptions caused by winter storm conditions. Revenues and direct operating costs from our fracturing operations increased by approximately $55.1 million and $42.8 million, or 10% and 9%, respectively, which was primarily due to a 6% increase in total pumping hours. Other completion services revenue and direct operating costs increased $19.0 million and $6.4 million, or 17% and 7%, respectively, mainly due to higher activity for our power solutions and cementing operations. Capital expenditures increased primarily due to the timing of order placement and incremental growth capital investments including expansion of Emerald 100% natural gas completions equipment. Three Months Ended June 30, March 31, Drilling Products 2026 2026 % Change (dollars in thousands) Revenues $ 91,333 $ 79,797 14.5 % Direct operating costs 54,194 46,924 15.5 % Adjusted gross profit (1) 37,139 32,873 13.0 % General and administrative 8,344 7,923 5.3 % Depreciation, amortization and impairment 20,478 19,846 3.2 % Operating income (loss) $ 8,317 $ 5,104 63.0 % Capital expenditures $ 18,711 $ 15,842 18.1 % (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 the section of this Report titled “Non-GAAP Financial Measures” for a reconciliation of GAAP gross profit to adjusted gross profit by segment. Revenue and direct operating costs increased primarily due to higher activity in the United States. Revenues and direct operating costs in the United States increased by approximately $9.1 million and $5.1 million, or 17% and 15%, respectively. 28 Capital expenditures increased primarily due to higher raw material costs, particularly tungsten powder used in certain matrix bit applications. Three Months Ended June 30, March 31, Other 2026 2026 % Change (dollars in thousands) Revenues $ 9,492 $ 6,230 52.4 % Direct operating costs 2,800 2,884 (2.9) % Adjusted gross profit (1) 6,692 3,346 100.0 % General and administrative — 2 (100.0) % Depreciation, depletion, amortization and impairment 1,639 1,269 29.2 % Operating income (loss) $ 5,053 $ 2,075 143.5 % Capital expenditures $ 1,910 $ 1,111 71.9 % (1)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 the section of this Report titled “Non-GAAP Financial Measures” for a reconciliation of GAAP gross profit to adjusted gross profit by segment. Revenues increased primarily due to higher realized pricing on crude oil. Market prices for crude oil averaged $95.65 per barrel in the second quarter of 2026, as compared to $72.74 per barrel in the first quarter of 2026. Three Months Ended June 30, March 31, Corporate 2026 2026 % Change (dollars in thousands) General and administrative $ 45,314 $ 46,411 (2.4) % Depreciation $ 1,336 $ 1,863 (28.3) % Other operating expense (income), net $ 4,604 $ (3,176) NA Interest income $ 2,902 $ 2,765 5.0 % Interest expense, net of amount capitalized $ (20,398) $ (17,485) 16.7 % Other income (expense) $ (3,464) $ 965 NA Capital expenditures $ 132 $ 153 (13.7) % General and administrative was relatively flat between sequential quarters. 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 and a $2.2 million increase in credit loss expense during the second quarter of 2026. Interest expense, net of amounts capitalized, increased due to a $0.9 million loss on extinguishment of debt and higher interest expense associated with the 2036 Notes issued during the second quarter of 2026. The change in other income (expense) was due to a $4.5 million write-down of minority equity investments during the second quarter of 2026. 29 Results of Operations The following tables summarize results of operations by business segment for the six months ended June 30, 2026 and June 30, 2025: Six Months Ended June 30, June 30, Drilling Services 2026 2025 % Change (dollars in thousands) Revenues $ 725,218 $ 816,665 (11.2) % Direct operating costs 477,480 502,401 (5.0) % Adjusted gross profit (1) 247,738 314,264 (21.2) % General and administrative 13,714 8,097 69.4 % Depreciation, amortization and impairment 169,434 197,619 (14.3) % Other operating expense (income), net (2,450) (8,368) (70.7) % Operating income (loss) $ 67,040 $ 116,916 (42.7) % Capital expenditures $ 114,569 $ 128,632 (10.9) % Operating days – U.S. (2) 16,662 19,038 (12.5) % (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 the section of this Report titled “Non-GAAP Financial Measures” for a reconciliation of GAAP gross profit to adjusted gross profit by segment. (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. Total revenues and direct operating costs decreased primarily due to a decrease in operating days in our contract drilling business within the United States. The decrease in operating days for our U.S. contract drilling business reflects the industry-wide activity declines at the beginning of 2026. Direct operating costs during the six months ended June 30, 2026, were approximately $20.0 million higher due to our decision to exit our contract drilling operations in Colombia. See Note 16 of Notes to unaudited condensed consolidated financial statements for additional information. General and administrative increased primarily due to certain internal reorganization initiatives and employee separation costs incurred during the first half of 2026. Depreciation, amortization and impairment expense decreased due to a $27.8 million impairment charge to Latin American drilling equipment during the second quarter of 2025. Other operating expense (income), net, reflected insurance proceeds received during the second quarter of 2025. Capital expenditures decreased primarily due to the timing of order placement as well as lower maintenance capital expenditures due to fewer operating days. Six Months Ended June 30, June 30, Completion Services 2026 2025 % Change (dollars in thousands) Revenues $ 1,433,228 $ 1,485,412 (3.5) % Direct operating costs 1,212,202 1,276,764 (5.1) % Adjusted gross profit (1) 221,026 208,648 5.9 % General and administrative 14,560 21,132 (31.1) % Depreciation, amortization and impairment 220,310 235,600 (6.5) % Other operating expense (income), net (1,328) — NA Operating income (loss) $ (12,516) $ (48,084) (74.0) % Capital expenditures $ 120,124 $ 131,158 (8.4) % 30 (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 the section of this Report titled “Non-GAAP Financial Measures” for a reconciliation of GAAP gross profit to adjusted gross profit by segment. Completion services revenues decreased primarily due to lower activity in our wireline and power solutions operations. Revenues from our wireline operations were $24.8 million lower, or 18%, resulting from fewer stages perforated. Revenues from our power solutions operations were $13.0 million lower, or 20%, due primarily to fewer working days. Revenue from our fracturing operations was resilient, only declining $6.9 million, or 1%, due to slightly lower pumping hours. Direct operating costs declined across our fracturing, power solutions, and wireline operations by $26.6 million, $13.5 million, and $20.2 million, or 3%, 30%, and 17%, respectively. The declines in direct operating costs for our fracturing and wireline operations primarily resulted from lower activity, but we also saw incremental cost savings from reduced maintenance expense. The decrease in power solutions direct operating costs was primarily due to fewer working days. General and administrative decreased, benefiting from cost reduction activities. Depreciation, amortization and impairment expense decreased primarily due to less new equipment placed in service relative to asset retirements between the periods. Capital expenditures decreased primarily due to the timing of order placement. Six Months Ended June 30, June 30, Drilling Products 2026 2025 % Change (dollars in thousands) Revenues $ 171,130 $ 174,053 (1.7) % Direct operating costs 101,118 96,275 5.0 % Adjusted gross profit (1) 70,012 77,778 (10.0) % General and administrative 16,267 17,770 (8.5) % Depreciation, amortization and impairment 40,324 46,460 (13.2) % Operating income (loss) $ 13,421 $ 13,548 (0.9) % Capital expenditures $ 34,553 $ 33,474 3.2 % (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 the section of this Report titled “Non-GAAP Financial Measures” for a reconciliation of GAAP gross profit to adjusted gross profit by segment. Revenues were relatively flat between the periods. Direct operating cost increased due to higher raw material and labor costs. 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. Capital expenditures increased primarily due to the timing of order placement and higher raw material costs, particularly tungsten powder used in certain matrix bit applications. 31 Six Months Ended June 30, June 30, Other (1) 2026 2025 % Change (dollars in thousands) Revenues $ 15,722 $ 23,727 (33.7) % Direct operating costs 5,684 15,337 (62.9) % Adjusted gross profit (2) 10,038 8,390 19.6 % General and administrative 2 286 (99.3) % Depreciation, depletion, amortization and impairment 2,908 9,874 (70.5) % Operating income (loss) $ 7,128 $ (1,770) NA Capital expenditures $ 3,021 $ 5,398 (44.0) % (1)Other includes our oilfield rentals business, prior to its divestiture in April 2025, and oil and natural gas working interests. (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 the section of this Report titled “Non-GAAP Financial Measures” for a reconciliation of GAAP gross profit to adjusted gross profit by segment. The changes for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025 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. Excluding the effects of our oilfield rentals business divestiture, revenue increased $5.5 million, or 54%, related to our non-operating working interests in oil and natural gas properties. The increase was primarily driven by higher realized crude oil prices. Oil prices averaged $84.29 per barrel during the six months ended June 30, 2026 as compared to $68.12 per barrel during the six months ended June 30, 2025. Direct operating costs were consistent across both periods. Depreciation, depletion, amortization and impairment expense, excluding the effects of our oilfield rentals business divestiture, decreased $4.2 million, or 59% due to a $3.6 million impairment recorded during the six months ended June 30, 2025. Capital expenditures decreased due to our oilfield rentals business divestiture in the second quarter of 2025. Six Months Ended June 30, June 30, Corporate 2026 2025 % Change (dollars in thousands) General and administrative $ 91,725 $ 83,753 9.5 % Depreciation $ 3,199 $ 4,171 (23.3) % Other operating expense (income), net $ 1,428 $ 5,227 (72.7) % Interest income $ 5,667 $ 2,736 107.1 % Interest expense, net of amount capitalized $ (37,883) $ (35,342) 7.2 % Other income (expense) $ (2,499) $ 324 NA Capital expenditures $ 285 $ 7,375 (96.1) % General and administrative increased primarily due to certain internal reorganization initiatives, higher share‑based compensation expense related to cash-settled liability awards and employee compensation costs, and software subscription fees incurred during the first half of 2026 compared to the same period of 2025. 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. Interest expense, net of amounts capitalized, increased due to a $0.9 million loss on extinguishment of debt and higher interest expense associated with senior notes issued in the second quarter of 2026. 32 The change in other income (expense) was due to a $4.5 million write-down of minority equity investments in the second quarter of 2026. Capital expenditures decreased primarily due to higher spending in 2025, which was related to our corporate office expansion. Income Taxes Our effective income tax rate fluctuates from the U.S. statutory tax rate based on, among other factors, changes in pretax income in jurisdictions with varying statutory tax rates, the impact of U.S. state and local taxes, the realizability of deferred tax assets and other differences related to the recognition of income and expense between GAAP and tax accounting. Our effective income tax rate for the three months ended June 30, 2026 was 31.0%, compared with 12.8% for the three months ended March 31, 2026. The difference in effective income tax rates between the periods was primarily attributable to the impact of permanent differences against earnings between periods. Our effective income tax rate for the six months ended June 30, 2026 was 21.9%, compared with (5.8)% for the six months ended June 30, 2025. The difference in effective income tax rates between the periods was primarily attributable to the impact of permanent differences against earnings between periods. 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. 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. Liquidity and Capital Resources Overview Our primary sources of liquidity are cash and cash equivalents, availability under our Credit Agreement and cash provided by operating activities. As of June 30, 2026, we had approximately $588 million in working capital, including $201 million of cash and cash equivalents, and approximately $498 million available under our Credit Agreement. On May 19, 2026, we completed an offering of $500 million in aggregate principal amount of the 2036 Notes. The net proceeds before offering expenses from the offering of the 2036 Notes were approximately $496 million. We pay interest on the 2036 Notes on May 15 and November 15 of each year. The 2036 Notes will mature on May 15, 2036. The 2036 Notes bear interest at a rate of 6.05% per annum. See Note 8 of Notes to unaudited condensed consolidated financial statements for additional information. Cash Flows Our cash flows for the six months ended June 30, 2026 and 2025 are summarized below: Six Months Ended June 30, 2026 2025 (in thousands) Net cash provided by (used in): Operating activities $ 119,940 $ 347,890 Investing activities (259,270) (289,207) Financing activities (77,170) (112,720) Effect of exchange rate changes on cash, cash equivalents and restricted cash (973) (1,365) Net increase (decrease) in cash and cash equivalents and restricted cash $ (217,473) $ (55,402) Operating Activities — The decrease in cash provided by operating activities between the six months ended June 30, 2026 and 2025 was primarily attributable to changes related to timing of working capital payments and receipts. 33 Investing Activities — The decrease in cash used in investing activities between the six months ended June 30, 2026 and 2025 was primarily attributable to lower capital expenditures driven by the timing of order placement and reduced maintenance capital spending resulting from fewer operating days. These decreases were partially offset by lower proceeds from sales of assets. Financing Activities — The decrease in cash used in financing activities between the six months ended June 30, 2026 and 2025 was primarily due to fewer share repurchases and proceeds from the issuance of our 2036 Notes. These factors were partially offset by the redemption of our 2028 Notes and increased dividend payments. Credit Agreement 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 “Amended and Restated Credit Agreement”). The Credit Agreement amended and restated our Amended and Restated Credit Agreement dated as of March 27, 2018. As of June 30, 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. On April 24, 2026, we entered into the Assignment and Amendment No. 1 to Second Amended and Restated Credit Agreement, which amended the Amended and Restated Credit Agreement (as amended, the “Credit Agreement”), which, among other things, (i) extended 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) assigned $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. 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 June 30, 2026. No events of default had occurred at June 30, 2026. Reimbursement Agreement 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. We had $31.3 million of outstanding letters of credit at June 30, 2026, which was comprised of $27.0 million outstanding under the 2015 Reimbursement Agreement, $2.3 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 June 30, 2026, no amounts had been drawn under the letters of credit. As of June 30, 2026, we had $39.0 million in surety bond exposure issued as financial assurance on an insurance agreement. Our outstanding long-term debt at June 30, 2026 was $1.2 billion and consisted of $345 million of our 2029 Notes, $400 million of our 2033 Notes, and $500 million of our 2036 Notes. We were in compliance with all covenants under the associated agreements and indentures at June 30, 2026. For additional information regarding our long-term debt, see Note 9 of Notes to consolidated financial statements in Item 8 of our Annual Report. Cash Requirements We believe our current liquidity, together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to maintain and make improvements to our existing equipment, service our debt, pay cash dividends and repurchase our common stock and senior notes for at least the next 12 months. If we pursue other opportunities that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash flows from operating activities, borrowing capacity under our revolving credit facility or additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all. 34 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. Sources and Uses of Cash During the six months ended June 30, 2026, our sources of cash flow included: •$120 million from operating activities and •$14.9 million in proceeds from the disposal of property and equipment, including insurance recoveries, and •$496 million in net proceeds from the issuance of long-term debt. During the six months ended June 30, 2026, our uses of cash flow included: •$273 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, •$483 million for the repayment of the 2028 Notes, •$76.0 million to pay dividends on our common stock, •$9.5 million for repurchases of our common stock, •$3.3 million for payments related to finance leases and •$3.5 million for other investing and financing activities. We paid cash dividends during the six months ended June 30, 2026 as follows: Per Share Total (in thousands) Paid on March 16, 2026 $ 0.10 $ 37,960 Paid on June 15, 2026 0.10 38,056 $ 0.20 $ 76,016 On July 29, 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 September 15, 2026 to holders of record as of September 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. We may, at any time and from time to time, seek to retire or purchase our outstanding debt for cash through open-market purchases, privately negotiated transactions, redemptions or otherwise. Such repurchases, if any, will be upon such terms and at such prices as we may determine, and will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. In September 2013, our Board of Directors approved a stock buyback program. In February 2024, our Board of Directors approved an increase of the authorization under the stock buyback program to allow for an aggregate of $1.0 billion of future share repurchases. All purchases executed to date have been through open market transactions. Purchases under the buyback program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Purchases may be made at any time without prior notice. There is no expiration date associated with the buyback program. As of June 30, 2026, we had remaining authorization to purchase approximately $694 million of our outstanding common stock under the stock buyback program. Shares of stock purchased under the buyback program are held as treasury shares. 35 Treasury stock acquisitions during the six months ended June 30, 2026 were as follows (dollars in thousands): Shares Cost Treasury shares at beginning of period 144,435,252 $ 2,020,714 Acquisitions pursuant to long-term incentive plans (1) 817,628 9,478 Treasury shares at end of period 145,252,880 $ 2,030,192 (1)We withheld 817,628 shares during the six months ended June 30, 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. Commitments — As of June 30, 2026, we had commitments to purchase major equipment totaling approximately $169 million. Our completion services segment has entered into agreements to purchase minimum quantities of proppants from certain vendors. As of June 30, 2026, the remaining minimum obligation under these agreements was approximately $8.7 million, of which approximately $3.9 million and $4.8 million relate to the remainder of 2026 and 2027, respectively. See Note 9 of Notes to unaudited condensed consolidated financial statements for additional information on our current commitments and contingencies as of June 30, 2026. Operating lease liabilities totaled $44.6 million and finance lease liabilities totaled $6.8 million as of June 30, 2026. Trading and Investing — We have not engaged in trading activities that include high-risk securities, such as derivatives and non-exchange traded contracts. We invest cash primarily in highly liquid, short-term investments such as overnight deposits and money market accounts. Non-GAAP Financial Measures Adjusted EBITDA 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, exit costs, noncontrolling investment write-down, 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). Three Months Ended Six Months Ended June 30, March 31, June 30, 2026 2026 2026 2025 (in thousands) Net income (loss) $ (19,275) $ (24,476) $ (43,751) $ (47,407) Income tax expense (benefit) (8,647) (3,596) (12,243) 2,584 Net interest expense 17,496 14,720 32,216 32,606 Depreciation, depletion, amortization and impairment 217,781 218,394 436,175 493,724 Colombia contract drilling exit costs (1) 20,011 — 20,011 — Noncontrolling investment write-down (2) 4,520 — 4,520 — Legal accruals and settlements (3) — — — (4,585) Merger and integration expense — — — 920 Adjusted EBITDA $ 231,886 $ 205,042 $ 436,928 $ 477,842 36 (1)Colombia contract drilling exit costs represent inventory and other asset write-downs recorded in direct operating expenses within the consolidated statements of operations. These costs were excluded from Adjusted EBITDA as they relate to our decision to exit our Colombia contract drilling operations and are not considered representative of ongoing operating performance. See Note 16 of Notes to the unaudited condensed consolidated financial statements for additional information. (2)Noncontrolling investment write-down represents an impairment charge of certain minority equity investments. The charge was excluded from Adjusted EBITDA as it represents a non-operating item. (3)Legal accruals and settlements represent net expenses (income) arising from certain significant legal matters, including settlement activity and reserve adjustments related to prior-year claims. Unlike routine legal costs incurred in the ordinary course of business, these infrequent items are excluded from Adjusted EBITDA because management does not consider them representative of our current period operating performance. Adjusted Gross Profit 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. Drilling Services Completion Services Drilling Products Other (in thousands) For the three months ended June 30, 2026 Revenues $ 373,501 $ 753,641 $ 91,333 $ 9,492 Less direct operating costs (259,619) (630,716) (54,194) (2,800) Less depreciation, depletion, amortization and impairment (85,490) (108,838) (20,478) (1,639) GAAP gross profit 28,392 14,087 16,661 5,053 Depreciation, depletion, amortization and impairment 85,490 108,838 20,478 1,639 Adjusted gross profit $ 113,882 $ 122,925 $ 37,139 $ 6,692 For the three months ended March 31, 2026 Revenues $ 351,717 $ 679,587 $ 79,797 $ 6,230 Less direct operating costs (217,861) (581,486) (46,924) (2,884) Less depreciation, depletion, amortization and impairment (83,944) (111,472) (19,846) (1,269) GAAP gross profit (loss) 49,912 (13,371) 13,027 2,077 Depreciation, depletion, amortization and impairment 83,944 111,472 19,846 1,269 Adjusted gross profit $ 133,856 $ 98,101 $ 32,873 $ 3,346 For the six months ended June 30, 2026 Revenues $ 725,218 $ 1,433,228 $ 171,130 $ 15,722 Less direct operating costs (477,480) (1,212,202) (101,118) (5,684) Less depreciation, depletion, amortization and impairment (169,434) (220,310) (40,324) (2,908) GAAP gross profit 78,304 716 29,688 7,130 Depreciation, depletion, amortization and impairment 169,434 220,310 40,324 2,908 Adjusted gross profit $ 247,738 $ 221,026 $ 70,012 $ 10,038 For the six months ended June 30, 2025 Revenues $ 816,665 $ 1,485,412 $ 174,053 $ 23,727 Less direct operating costs (502,401) (1,276,764) (96,275) (15,337) Less depreciation, depletion, amortization and impairment (197,619) (235,600) (46,460) (9,874) GAAP gross profit (loss) 116,645 (26,952) 31,318 (1,484) Depreciation, depletion, amortization and impairment 197,619 235,600 46,460 9,874 Adjusted gross profit $ 314,264 $ 208,648 $ 77,778 $ 8,390 37 Critical Accounting Estimates 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. Recently Issued Accounting Standards See Note 1 of Notes to unaudited condensed consolidated financial statements for a discussion of the impact of recently issued accounting standards. Volatility of Oil and Natural Gas Prices and its Impact on Operations and Financial Condition 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. 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. During the first half of 2026, energy markets experienced increased volatility driven by geopolitical developments in the Middle East, including the conflict with Iran and concerns regarding potential disruptions to global oil supply and key transportation routes. These events contributed to fluctuations in commodity prices, customer spending expectations and overall market sentiment. In addition, global energy markets continue to be influenced by OPEC+ production decisions, changes in worldwide supply and demand balances and broader macroeconomic conditions. While the full effects are yet to be determined, we believe these dynamics could support increased activity in the second half of 2026, particularly in North America, as operators reassess capital allocation and activity levels commensurate with commodity prices and supply chain dependability. Oil prices averaged $95.65 per barrel in the second quarter of 2026, as compared to $72.74 per barrel in the first quarter of 2026, and closed at $84.25 per barrel on July 27, 2026. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $2.95 per MMBtu in the second quarter of 2026 as compared to an average of $4.71 per MMBtu in the first quarter of 2026, and closed at $2.63 per MMBtu on July 27, 2026. 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. Impact of Inflation and Trade Policies 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 38 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. 39