PATTERSON UTI ENERGY INC (PTEN)

CIK: 0000889900. SIC: 1381 Drilling Oil & Gas Wells. Latest 10-K as of: 2026-02-10.

SIC breadcrumb: Mining > SIC Major Group 13 > SIC 1381 Drilling Oil & Gas Wells

SEC company page: https://www.sec.gov/edgar/browse/?CIK=889900. Latest filing source: 0000889900-26-000013.

Selected Fundamentals

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-10. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000889900.json. Derived margins are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Missing metrics are omitted rather than fabricated.

Financial Charts

Quarterly

Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-04-28. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000889900.json.

Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived.

Quarterly Charts

Macro Cross-References

• CPIAUCSL - Consumer Price Index for All Urban Consumers: All Items in U.S. City Average
• UNRATE - Unemployment Rate
• FEDFUNDS - Federal Funds Effective Rate
• CES0500000003 - Average Hourly Earnings of All Employees, Total Private
• DFEDTARU - Federal Funds Target Range - Upper Limit
• DFEDTARL - Federal Funds Target Range - Lower Limit
• DGS3MO - Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity
• DGS2 - Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity
• DGS10 - Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity
• DGS30 - Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity
• T10Y2Y - 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity
• CPILFESL - Consumer Price Index for All Urban Consumers: All Items Less Food and Energy
• CPIUFDSL - Consumer Price Index for All Urban Consumers: Food
• CPIENGSL - Consumer Price Index for All Urban Consumers: Energy
• CUSR0000SAH1 - Consumer Price Index for All Urban Consumers: Shelter
• PCEPI - Personal Consumption Expenditures: Chain-type Price Index
• PCEPILFE - Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index
• PPIACO - Producer Price Index by Commodity: All Commodities
• T10YIE - 10-Year Breakeven Inflation Rate
• U6RATE - Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons
• PAYEMS - All Employees, Total Nonfarm
• CIVPART - Labor Force Participation Rate
• EMRATIO - Employment-Population Ratio
• UNEMPLOY - Unemployed
• CE16OV - Employment Level
• ICSA - Initial Claims
• JTSJOL - Job Openings: Total Nonfarm
• JTSQUR - Quits: Total Nonfarm
• GDPC1 - Real Gross Domestic Product
• A191RL1Q225SBEA - Real Gross Domestic Product: Percent Change from Preceding Period
• INDPRO - Industrial Production: Total Index
• TCU - Capacity Utilization: Total Index
• HOUST - New Privately-Owned Housing Units Started: Total Units
• PERMIT - New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units
• RSAFS - Advance Retail Sales: Retail Trade
• PCE - Personal Consumption Expenditures
• DSPIC96 - Real Disposable Personal Income
• PSAVERT - Personal Saving Rate
• M2SL - M2
• BOPGSTB - U.S. International Trade in Goods and Services: Balance
• MSPUS - Median Sales Price of Houses Sold for the United States
• HSN1F - New One Family Houses Sold: United States
• RHORUSQ156N - Homeownership Rate in the United States
• TTLCONS - Total Construction Spending: Total Construction in the United States
• RRVRUSQ156N - Rental Vacancy Rate in the United States
• TOTALSL - Total Consumer Credit Owned and Securitized
• REVOLSL - Revolving Consumer Credit Owned and Securitized
• DRCCLACBS - Delinquency Rate on Credit Card Loans, All Commercial Banks
• GDP - Gross Domestic Product
• GPDI - Gross Private Domestic Investment
• GCE - Government Consumption Expenditures and Gross Investment
• PCEC - Personal Consumption Expenditures
• NETEXP - Net Exports of Goods and Services
• GFDEBTN - Federal Debt: Total Public Debt
• GFDEGDQ188S - Federal Debt: Total Public Debt as Percent of Gross Domestic Product
• FYFSD - Federal Surplus or Deficit
• FGRECPT - Federal Government Current Receipts
• FGEXPND - Federal Government: Current Expenditures
• MANEMP - All Employees, Manufacturing
• USCONS - All Employees, Construction
• USTRADE - All Employees, Retail Trade
• USFIRE - All Employees, Financial Activities
• USGOVT - All Employees, Government
• AWHAETP - Average Weekly Hours of All Employees, Total Private
• DGORDER - Manufacturers' New Orders: Durable Goods
• NEWORDER - Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft
• BUSINV - Total Business Inventories
• EXPGS - Exports of Goods and Services
• IMPGS - Imports of Goods and Services
• IR - Import Price Index (End Use): All Commodities
• PPIFIS - Producer Price Index by Commodity: Final Demand

Latest quarter (10-Q)

Latest 10-Q source: 0000889900-26-000033.

Extracted between Part I Item 2 and the next Item 3/4 or Part II heading after HTML sanitization. Confidence: high. Filing date: 2026-04-28. Report date: 2026-03-31.

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 the United States, 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 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.

As of March 31, 2026, we had 152 marketed land-based drilling rigs based in the following regions:

Region

Number of Rigs

West Texas

68

Appalachia

21

Oklahoma

15

Rockies

18

South Texas

13

East Texas (1)

9

Colombia

7

Ecuador

1

Total

152

(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 March 31, 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.

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

23

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.

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.

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.

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.

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 quarter at a higher level than the quarterly average, potentially 92 to 95 rigs, as we reactivate rigs during the second half of the quarter.

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.

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.

24

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):

Three Months Ended

March 31,

December 31,

March 31,

2026

2025

2025

Drilling Services

$

351,717 

31.5

%

$

360,777 

31.3

%

$

412,860 

32.2

%

Completion Services

679,587 

60.8

%

701,560 

61.0

%

766,080 

59.8

%

Drilling Products

79,797 

7.1

%

83,774 

7.3

%

85,663 

6.7

%

Other

6,230 

0.6

%

4,702 

0.4

%

15,934 

1.3

%

$

1,117,331 

100.0

%

$

1,150,813 

100.0

%

$

1,280,537 

100.0

%

Results of Operations

The following tables summarize results of operations by business segment for the three months ended March 31, 2026, December 31, 2025 and March 31, 2025:

Three Months Ended

March 31,

December 31,

March 31,

% Change

Drilling Services

2026

2025

2025

Sequential

Year-over-year

(dollars in thousands)

Revenues

$

351,717 

$

360,777 

$

412,860 

(2.5)

%

(14.8)

%

Direct operating costs

217,861 

228,426 

247,629 

(4.6)

%

(12.0)

%

Adjusted gross profit (1)

133,856 

132,351 

165,231 

1.1 

%

(19.0)

%

General and administrative

7,097 

4,013 

3,945 

76.9 

%

79.9 

%

Depreciation, amortization and impairment

83,944 

85,044 

84,972 

(1.3)

%

(1.2)

%

Other operating expense (income), net

(1,488)

298 

— 

(599.3)

%

NA

Operating income (loss)

$

44,303 

$

42,996 

$

76,314 

3.0 

%

(41.9)

%

Capital expenditures

$

54,421 

$

61,194 

$

73,458 

(11.1)

%

(25.9)

%

Operating days – U.S. (2)

8,301 

8,596 

9,573 

(3.4)

%

(13.3)

%

(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 Non-GAAP Financial Measures below 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.

Sequential quarter comparison

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 and direct operating costs decreased primarily due to a decrease in operating days in our contract drilling business within the United States.

General and administrative expense increased primarily due to certain internal reorganization initiatives and employee separation costs incurred during the first quarter of 2026.

Capital expenditures decreased primarily due to the timing of order placement as well as lower maintenance capital expenditures due to fewer operating days.

25

Year-over-year quarter comparison

Total revenues and direct operating costs decreased primarily due to a decrease in operating days in our contract drilling business within the United States.

General and administrative expense increased primarily due to certain internal reorganization initiatives and employee separation costs incurred during the first quarter of 2026.

Capital expenditures decreased primarily due to the timing of

[Excerpt truncated for page length; source filing is linked above.]

Latest 10-K MD&A

Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high. Filing date: 2026-02-10. Report date: 2025-12-31.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 the United States, 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 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 provide electrical controls and automation to the energy, marine and mining industries, in North America and other select markets.

33

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 December 31, 2025, our rig fleet included 137 Tier-1, super-spec rigs marketed.

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 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.

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.

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 — 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 second half 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 $59.62 per barrel in the fourth quarter of 2025 and closed at $61.60 per barrel on February 2, 2026. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $3.73 per MMBtu in the fourth quarter of 2025 and closed at $4.40 per MMBtu on February 2, 2026.

34

Quarterly average oil prices and our quarterly average number of rigs operating in the United States for 2023, 2024 and 2025 are as follows:

1st

Quarter

2nd

Quarter

3rd

Quarter

4th

Quarter

2023

Average oil price per Bbl (1)

$

75.93 

$

73.54 

$

82.25 

$

78.53 

Average rigs operating per day – U.S. (2)

131

128

120

118

2024

Average oil price per Bbl (1)

$

77.50 

$

81.81 

$

76.43 

$

70.73 

Average rigs operating per day – U.S. (2)

121

114

107

105

2025

Average oil price per Bbl (1)

$

71.78 

$

64.57 

$

65.78 

$

59.62 

Average rigs operating per day – U.S. (2)

106

104

95

93 

(1)The average oil price represents the average monthly WTI spot price as reported by the United States Energy Information Administration.

(2)A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.

In our drilling services segment, our average active rig count in the United States for the fourth quarter of 2025 was 93 rigs. This was a decrease from our average active rig count for the third quarter of 2025 of 95 rigs. Our active rig count in the United States at December 31, 2025 of 93 rigs was less than the rig count of 105 rigs at December 31, 2024, reflecting the industry-wide activity declines due, in part, to expectations regarding future crude oil prices, increased drilling efficiencies and market consolidation. We expect our rig count in the United States will be in the low-to-mid 90s in the first quarter of 2026. Term contracts help support our operating rig count. Based on contracts in place in the United States as of February 4, 2026, we expect an average of 49 rigs operating under term contracts during the first quarter of 2026 and an average of 27 rigs operating under term contracts during 2026.

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 December 31, 2025 and 2024 was approximately $291 million and $426 million, respectively. Approximately 9% of our total contract drilling backlog in the United States at December 31, 2025 is reasonably expected to remain after 2026. See Note 3 of Notes to consolidated financial statements in Item 8 of this Report and “Item 1A. Risk Factors – Our current backlog of contract drilling revenue may decline and may not ultimately be realized, as fixed-term contracts may in certain instances be terminated without an early termination payment.”

In our completion services segment, activity and pricing for the fourth quarter of 2025 were steady compared to the previous quarter. We expect activity to decline slightly in the first quarter due to impacts from first quarter winter weather.

In our drilling products segment, U.S. and Canadian activity remains strong. International revenue was down slightly in the fourth quarter of 2025 compared to the third quarter of 2025 due to lower-than-expected sales in the Middle East, although we delivered revenue growth in several key markets, including Latin America and Asia-Pacific. We expect slightly lower U.S. revenue in the first quarter in this segment due to lower activity, which we expect will be offset by an increase in activity and revenue from our International business.

Cash capital expenditures for 2025 totaled $589 million. This was a decrease from the $678 million of cash capital expenditures in 2024 due to a decrease in business activity in 2025. Additionally, we received proceeds from sale of assets or idle equipment and insurance recoveries of $44.1 million and $25.8 million in 2025 and 2024, respectively. Based on our current outlook for activity, we expect our capital expenditures for 2026 to be approximately $500 million on a gross basis and less than $500 million, net of asset sales.

Recent Developments in Financial Matters — On January 31, 2025, we entered into the Second Amended and Restated Credit Agreement with the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent, and the other parties thereto (the “Credit Agreement”). The Credit Agreement amended and restated our Amended and Restated Credit Agreement dated as of March 27, 2018 (as amended, restated, supplemented or otherwise modified at December 31, 2024, the “Prior Credit Agreement”). The commitments under the Credit Agreement are $500 million, and the loans and commitments under the Credit Agreement mature on January 31, 2030.

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

35

limited to the lesser of $50 million and the amount of the swing line provider’s unused commitment. Subject to customary conditions, we may request that the lenders’ aggregate commitments be increased by up to $200 million, not to exceed total commitments of $700 million. For a description of the Credit Agreement, see “Liquidity and Capital Resources” included in Part II, Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Report.

As of December 31, 2025, we had no borrowings outstanding under our Credit Agreement. We had $5.0 million in letters of credit outstanding under the Credit Agreement at December 31, 2025 and, as a result, had available borrowing capacity of approximately $495 million under the Credit Agreement at that date.

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 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.

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.

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. See “Risk Factors” in Item 1A of this Report.

For the three years ended December 31, 2025, our operating revenues consisted of the following (dollars in thousands):

2025

2024

2023

Drilling Services

$

1,557,642 

32.3 

%

$

1,727,810 

32.1

%

$

1,919,759 

46.3

%

Completion Services

2,892,247 

59.9 

%

3,232,785 

60.1

%

2,017,440 

48.7

%

Drilling Products

343,707 

7.1 

%

351,651 

6.5

%

134,679 

3.2

%

Other

33,028 

0.7 

%

65,665 

1.3

%

74,578 

1.8

%

$

4,826,624 

100.0 

%

$

5,377,911 

100.0

%

$

4,146,456 

100.0

%

Results of Operations

Comparison of the years ended December 31, 2024 and 2023

A discussion of our financial condition and results of operations for the fiscal year ended December 31, 2024 compared to the fiscal year ended December 31, 2023 is included in Part II, Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2024, filed with the SEC on February 11, 2025.

36

Comparison of the years ended December 31, 2025 and 2024

The following tables summarize results of operations by business segment for the years ended December 31, 2025 and 2024:

Year Ended December 31,

Drilling Services

2025

2024

% Change

(Dollars in thousands)

Revenues

$

1,557,642 

$

1,727,810 

(9.8

%)

Direct operating costs

977,234 

1,029,591 

(5.1

%)

Adjusted gross profit (1)

580,408 

698,219 

(16.9

%)

Selling, general and administrative

16,079 

16,502 

(2.6)

%

Depreciation, amortization and impairment

366,763 

477,398 

(23.2

%)

Other operating expense (income), net

530 

— 

NA

Operating income (loss)

$

197,036 

$

204,319 

(3.6

%)

Capital expenditures

$

236,517 

$

264,667 

(10.6

%)

Operating days – U.S. (2)

36,371

40,899

(11.1

%)

(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.

(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 due, in part, to expectations regarding future crude oil prices, increased drilling efficiencies and market consolidation.

Total revenues declined in line with fewer operating days in our contract drilling business. The decrease was partially offset by a $30 million increase in directional drilling revenue driven by higher activity and job counts.

Direct operating costs decreased due to cost control initiatives and lower activity, although not at the same rate as operating days primarily due to fixed cost leverage. This decrease was partially offset by a $23 million increase in directional drilling operating costs from higher activity.

Depreciation, amortization and impairment expense 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 6 of Notes to consolidated financial statements for additional information.

Capital expenditures decreased primarily due to a reduced capital expenditure budget as well as lower maintenance capital expenditures due to fewer operating days.

37

Year Ended December 31,

Completion Services

2025

2024

% Change

(Dollars in thousands)

Revenues

$

2,892,247 

$

3,232,785 

(10.5

%)

Direct operating costs

2,461,539 

2,658,170 

(7.4

%)

Adjusted gross profit (1)

430,708 

574,615 

(25.0

%)

Selling, general and administrative

39,816 

41,557 

(4.2

%)

Depreciation, amortization and impairment

463,599 

564,155 

(17.8

%)

Impairment of goodwill

— 

885,240 

NA

Other operating expense (income), net

6,700 

(17,792)

NA

Operating income (loss)

$

(79,407)

$

(898,545)

(91.2

%)

Capital expenditures

$

271,528 

$

320,329 

(15.2

%)

(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.

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 $306 million and $184 million, or 12% and 8%, respectively. Total pumping hours from our fracturing operations were relatively flat year over year, with most of the decline driven by lower service and materials pricing. Other completion services revenue decreased $34 million mainly due to lower service pricing for our wireline and power solutions operations and a decline in activity for our wireline and cementing operations.

Direct operating costs declined due to lower labor costs and improved maintenance efficiencies. This decline was partially offset by an $11 million increase in power solutions operating expenses driven by higher commodity costs.

Depreciation, amortization and impairment expense decreased primarily due to fewer capital additions placed in service relative to asset retirements between the periods.

During the year ended December 31, 2024, we recorded an $885 million impairment charge to goodwill associated with our completion services reporting unit. See Note 7 of Notes to consolidated financial statements for additional information.

Other operating expense (income), net reflected a legal accrual that was partially offset by a favorable contract settlement, whereas other operating income in 2024 was due to gain on legal settlements.

We reduced capital expenditures in response to changing macroeconomic conditions between the periods.

Year Ended December 31,

Drilling Products

2025

2024

% Change

(Dollars in thousands)

Revenues

$

343,707 

$

351,651 

(2.3)

%

Direct operating costs

196,130 

191,107 

2.6 

%

Adjusted gross profit (1)

147,577 

160,544 

(8.1)

%

Selling, general and administrative

33,167 

35,860 

(7.5)

%

Depreciation, amortization and impairment

88,301 

100,610 

(12.2)

%

Operating income (loss)

$

26,109 

$

24,074 

8.5 

%

Capital expenditures

$

61,421 

$

61,687 

(0.4)

%

(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.

The $7.9 million decline in total revenue was primarily driven by reduced activity in Saudi Arabia and a lower U.S. rig count, which together contributed to a $14.1 million decrease. The decrease was partially offset by higher revenues from our Canadian operations where we gained market share, particularly during the second half of 2025, and improved pricing despite a reduction in Canadian rig count.

38

Direct operating costs increased primarily due to higher-than-normal bit repair expense during the second half of 2025. We enhanced our quality control procedures to offset the impact of these increases, and we observed measurable improvements in late 2025.

Direct operating costs and depreciation, amortization and impairment expense were approximately $2.6 million and $6.5 million higher than they would have otherwise been for the year ended December 31, 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 $7.9 million and $17.7 million higher than they would have otherwise been for the year ended December 31, 2024, respectively, as a result of the step up to fair value of our drill bits in accordance with purchase accounting.

Year Ended December 31,

Other (1)

2025

2024

% Change

(Dollars in thousands)

Revenues

$

33,028 

$

65,665 

(49.7)

%

Direct operating costs

21,599 

41,001 

(47.3

%)

Adjusted gross profit (2)

11,429 

24,664 

(53.7)

%

Selling, general and administrative

110 

708 

(84.5

%)

Depreciation, depletion, amortization and impairment

13,226 

24,043 

(45.0

%)

Operating income (loss)

$

(1,907)

$

(87)

2092.0

%

Capital expenditures

$

10,954 

$

21,813 

(49.8)

%

(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 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.

The changes for the year ended December 31, 2025 as compared to the year ended December 31, 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.

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 $65.39 per barrel in 2025 as compared to $76.63 per barrel in 2024.

Excluding the effects of our oilfield rentals business divestiture, depreciation, depletion, amortization and impairment expense, and capital expenditures, were relatively flat between the periods.

Year Ended December 31,

Corporate

2025

2024

% Change

(Dollars in thousands)

Selling, general and administrative

$

165,900 

$

173,710 

(4.5

%)

Merger and integration expense

$

1,016 

$

33,037 

(96.9

%)

Depreciation

$

8,375 

$

5,667 

47.8

%

Other operating expense (income), net

$

7,370 

$

7,084 

4.0

%

Interest income

$

6,649 

$

5,729 

16.1

%

Interest expense, net of amount capitalized

$

(70,508)

$

(71,963)

(2.0

%)

Other income (expense)

$

1,698 

$

(975)

NA

Capital expenditures

$

8,609 

$

9,890 

(13.0

%)

Selling, general and administrative expense decreased primarily due to certain severance costs incurred in the fourth quarter of 2024 that did not recur in 2025, as well as a continued focus on cost reduction efforts.

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.

39

Depreciation expense increased due to the enhancement of our main corporate office, primarily arising from office consolidation following the NexTier merger and the completion of our digital performance center.

Income Taxes

The effective tax rate increased to 9.6% for 2025 compared to (1.0%) for 2024. Our effective income tax rate fluctuates based on, among other factors, changes in pre-tax income in countries with varying statutory tax rates, changes in valuation allowances, and the impacts of various other permanent adjustments.

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.

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 December 31, 2025, we had approximately $554 million in working capital, including cash, cash equivalents of $419 million, and approximately $495 million available under our Credit Agreement.

Cash Flows

Our cash flows for the fiscal years ended December 31, 2025, 2024 and 2023 are summarized below:

Year Ended December 31,

2025

2024

2023

(in thousands)

Net cash provided by (used in):

Operating activities

$

961,219 

$

1,175,536 

$

1,005,914 

Investing activities

(567,153)

(654,744)

(1,017,590)

Financing activities

(210,732)

(474,992)

65,567 

Effect of exchange rate changes on cash, cash equivalents and restricted cash

(3,985)

2,813 

1,236 

Net increase in cash and cash equivalents and restricted cash

$

179,349 

$

48,613 

$

55,127 

Operating Activities — The decrease in cash provided by operating activities between fiscal years 2025 and 2024 was primarily attributable to lower activity in 2025. The increase in cash provided by operating activities between fiscal years 2024 and 2023 was primarily driven by the increased activities as a result of NexTier merger and Ulterra acquisition during the third quarter of 2023.

Investing Activities — The decrease in cash used in investing activities between fiscal years 2025 and 2024 was primarily attributable to our reduction of capital spending in response to changing industry conditions as well as lower maintenance capital expenditures due to fewer operating days. The decrease was partially offset by investment in an unconsolidated affiliate and investments in internally developed technology. The decrease in cash used in investing activities between fiscal years 2024 and 2023 was primarily driven by the cash paid as part of the NexTier merger and Ulterra acquisition during the third quarter of 2023.

Financing Activities — The decrease in cash used in financing activities between fiscal years 2025 and 2024 was primarily attributable to fewer share repurchases and a reduction in finance lease payments. The decrease in finance lease payments was due to the expiration of finance leases and equipment buyout options exercised during 2024. We derecognized $36.1 million of right‑of‑use assets as a result of these buyout options. The increase in cash used in financing activities between fiscal years 2024 and 2023 was primarily attributable to the issuance of the 2033 Senior Notes in 2023, as well as higher share repurchases and finance lease payments. As part of the Ulterra acquisition and NexTier merger in 2023, we acquired additional finance leases.

40

Credit Agreement

On January 31, 2025, we entered into the Credit Agreement, which amended and restated the Prior Credit Agreement. The commitments under the Credit Agreement are $500 million, and the loans and commitments under the Credit Agreement mature on January 31, 2030.

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.

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 December 31, 2025, the applicable margin on SOFR rate loans was 1.75% and the applicable margin on base rate loans was 0.75%. A letter of credit fee is payable by us equal to the applicable margin for SOFR rate loans times the daily amount available to be drawn under outstanding letters of credit. The commitment fee rate payable to the lenders varies from 0.15% to 0.35% based on our credit rating.

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.

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 the covenants under the Credit Agreement at December 31, 2025.

Reimbursement Agreement

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 December 31, 2025, we had $32.0 million in letters of credit outstanding under the Reimbursement Agreement.

Under the terms of the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any of our letters of credit issued thereunder. Fees, charges and other reasonable expenses for the issuance of letters of credit are payable by us at the time of issuance at such rates and amounts as are in accordance with Scotiabank’s prevailing practice. We are obligated to pay to Scotiabank interest on all amounts not paid by us on the date of demand or when otherwise due at the Prime rate plus 2.00% per annum, calculated daily and payable monthly, in arrears, on the basis of a calendar year for the actual number of days elapsed, with interest on overdue interest at the same rate as on the reimbursement amounts. A letter of credit fee is payable by us equal to 1.50% times the amount of outstanding letters of credit.

We have also agreed that if obligations under the Credit Agreement are secured by liens on any of our or our subsidiaries’ property, then our reimbursement obligations and (to the extent similar obligations would be secured under the Credit Agreement) other obligations under the Reimbursement Agreement and any letters of credit will be equally and ratably secured by all property subject to such liens securing the Credit Agreement.

41

Pursuant to a Continuing Guaranty dated as of March 16, 2015, our payment obligations under the Reimbursement Agreement are jointly and severally guaranteed as to payment and not as to collection by our subsidiaries that from time to time guarantee payment under the Credit Agreement. None of our subsidiaries are currently required to guarantee payment under the Credit Agreement.

We had $39.1 million of outstanding letters of credit at December 31, 2025, which was comprised of $32.0 million outstanding under the Reimbursement Agreement, $5.0 million outstanding under the Credit Agreement, and $2.0 million outstanding with financial institutions providing for short-term borrowing capacity, overdraft protection and bonding requirements. We maintain these letters of credit primarily for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under terms of the underlying insurance contracts and compliance with contractual obligations. These letters of credit expire annually at various times during the year and are typically renewed. As of December 31, 2025, no amounts had been drawn under the letters of credit. As of December 31, 2025, we had $37.0 million in surety bond exposure issued as financial assurance on an insurance agreement.

Our outstanding long-term debt at December 31, 2025 was $1.2 billion and consisted of $483 million of our 3.95% Senior Notes due 2028, $345 million of our 5.15% Senior Notes due 2029 and $400 million of our 7.15% Senior Notes due 2033. We were in compliance with all covenants under the associated agreements and indentures at December 31, 2025.

For a full description of the Credit Agreement, the Reimbursement Agreement and our senior notes, see Note 9 of Notes to consolidated financial statements included as a part of Item 8 of this 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.

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. Based on our current outlook for activity, we expect our capital expenditures for 2026 to be approximately $500 million on a gross basis and less than $500 million, net of asset sales.

Sources and Uses of Cash

During 2025, our sources of cash flow included:

•$1.0 billion from operating activities, and

•$44.1 million in proceeds from the disposal of property and equipment, including insurance recoveries.

During 2025, our uses of cash flow included:

•$589 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,

•$122 million to pay dividends on our common stock,

•$69.6 million for repurchases of our common stock,

•$10.5 million for an investment in an unconsolidated affiliate,

•$6.4 million to repay the Equipment Loans,

•$7.8 million for payments related to finance leases, and

•$16.2 million for other investing and financing activities.

42

We paid cash dividends during the year ended December 31, 2025 as follows:

Per Share

Total

(in thousands)

Paid on March 17, 2025

$

0.08 

$

30,877 

Paid on June 16, 2025

0.08 

30,742 

Paid on September 15, 2025

0.08 

30,495 

Paid on December 15, 2025

0.08 

30,339 

Total cash dividends

$

0.32 

$

122,453 

On February 4, 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 March 16, 2026 to holders of record as of March 2, 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 December 31, 2025, 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.

We acquired shares of stock from employees during 2025, 2024 and 2023 that are accounted for as treasury stock. Certain of these shares were acquired to satisfy the exercise price and employees’ tax withholding obligations upon the exercise of stock options. The remainder of these shares were acquired to satisfy payroll withholding obligations upon the settlement of performance unit awards and 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. Amended and Restated 2014 Long-Term Incentive Plan, as amended (the “2014 Plan”), the Patterson-UTI Energy, Inc. 2021 Long-Term Incentive Plan (the “2021 Plan”), the NexTier Oilfield Solutions Inc. Equity and Incentive Award Plan and the NexTier Oilfield Solutions Inc. (Former C&J Energy) Management Incentive Plan, and not pursuant to the stock buyback program.

Treasury stock acquisitions during the years ended December 31, 2025, 2024 and 2023 were as follows (dollars in thousands):

2025

2024

2023

Shares

Cost

Shares

Cost

Shares

Cost

Treasury shares at beginning of period

133,440,028

$

1,951,067 

105,580,011

$

1,657,675 

88,758,722

$

1,453,079 

Purchases pursuant to stock buyback program

10,278,723

65,274 

26,646,698

280,327 

14,086,229

168,631 

Acquisitions pursuant to long-term incentive plan

716,501

4,373 

1,213,319

13,065 

2,735,060

35,965 

Treasury shares at end of period

144,435,252

$

2,020,714 

133,440,028

$

1,951,067 

105,580,011

$

1,657,675 

Commitments — As of December 31, 2025, we had commitments to purchase major equipment totaling approximately $47.5 million.

43

Our completion services segment has entered into agreements to purchase minimum quantities of proppants from certain vendors. As of December 31, 2025, the remaining minimum obligation under these agreements was approximately $21.7 million, of which approximately $16.9 million and $4.8 million relate to 2026 and 2027, respectively.

See Note 10 of Notes to consolidated financial statements in Item 8 of this Report for additional information on our current commitments and contingencies as of December 31, 2025.

Operating lease liabilities totaled $46.3 million and finance lease liabilities totaled $13.2 million at December 31, 2025. See Note 13 of Notes to consolidated financial statements in Item 8 of this Report for additional information on our operating and finance leases as of December 31, 2025.

We anticipate $45.1 million of expenditures in 2026 related to various contractual obligations such as certain commitments to purchase proppants and lease liabilities.

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.

Critical Accounting Estimates

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. Accounting estimates and assumptions discussed in this section are those considered to be the most critical to an understanding of our financial statements because they involve significant judgments and uncertainties. We believe the following critical accounting estimates used in preparing our consolidated financial statements address all important areas where the nature of the estimates or assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change. For additional information on our accounting policies, see Note 1 of Notes to consolidated financial statements included as a part of Item 8 of this Report.

Depreciation and amortization — Our industry is very capital intensive, as property and equipment represented 48.7% of our total assets as of December 31, 2025 and depreciation, depletion, amortization and impairment represented 19.3% of our total operating costs and expenses in 2025. Our property and equipment is carried at cost less accumulated depreciation and amortization. No provision for salvage value is considered in determining depreciation of our property and equipment. We calculate depreciation and amortization on our assets based on the estimated useful lives that we believe are reasonable. The estimated useful lives are subject to key assumptions such as maintenance, utilization and job variation. These estimates may change due to a number of factors such as changes in operating conditions or advances in technology. The method of depreciation does not change whenever equipment becomes idle. Maintenance and repairs are charged to expense when incurred. Renewals and betterments which extend the life or improve existing property and equipment are capitalized.

The following table outlines a 10% change in the useful lives on our major categories of property and equipment and the impact on operating income for the year ended December 31, 2025:

Useful Lives

Change

Impact

(in thousands)

Drilling services equipment

1-15 years

10%

$

58,353 

Completion services equipment

1-25 years

10%

38,971 

$

97,324 

Impairment of long-lived assets — We review our long-lived assets, including property and equipment and definite-lived intangible assets, for impairment whenever events or changes in circumstances indicate that the carrying amounts of certain assets may not be recovered over their estimated remaining useful lives (“triggering events”). In connection with this review, assets are grouped at the lowest level at which identifiable cash flows are largely independent of other asset groupings. We estimate undiscounted future cash flows over the life of the respective assets or asset groupings in our assessment of its recoverability. These estimates of cash flows are based on historical trends in the industry as well as our expectations regarding the continuation of these trends in the future.

During the second quarter of 2025, negative market indicators such as lower industry-wide drilling rig and pressure pumping fleet count forecasts, increased volatility and margin compression for certain of our asset groups led to our reduced outlook for activity. The

44

reduction in activity forecasts combined with the decline in the market price of our common stock were considered a triggering event indicating certain of our long-lived tangible and intangible assets may be impaired. We deemed it necessary to perform recoverability tests on our hydraulic fracturing asset group within our completion services reporting unit and our Latin American contract drilling asset group during the second quarter of 2025. We estimated future cash flows over the expected remaining life of the primary asset for each asset group.

On an undiscounted basis, the expected cash flows exceeded the carrying value of our hydraulic fracturing asset group within our completion services reporting unit, indicating that no impairment was required during the second quarter of 2025.

The recoverability test for our Latin American contract drilling asset group during the second quarter of 2025 indicated that estimated undiscounted cash flows did not exceed its carrying value. Accordingly, we performed an impairment test and estimated the fair value of the asset group using the income approach. Under this approach, we used a discounted cash flow model, which utilized present values of cash flows to estimate fair value. Forecasted cash flows reflected known market conditions in the second quarter of 2025 and management’s anticipated business outlook for the asset group. Future cash flows were projected based on estimates of revenue, gross profit, selling, general and administrative expense, changes in working capital, and capital expenditures. Future cash flows were then discounted using a market-participant, risk-adjusted weighted average cost of capital. Based on the results of the analysis performed, we recorded a $27.8 million impairment charge to Latin American drilling equipment during the second quarter of 2025 in our drilling services segment.

While the full effects of recent market developments 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. If these conditions persist or deteriorate further, or if other unforeseen macroeconomic conditions emerge, they could negatively impact the expected cash flows used in our recoverability tests for our asset groups. Such changes could result in impairment charges in the future, which could be material to our results of operations and financial statements as a whole.

Fair values of assets acquired and liabilities assumed in acquisitions — Assets acquired and liabilities assumed in a business combination are recorded at their estimated fair values on the date of acquisition. The difference between the purchase price amount and the net fair value of assets acquired and liabilities assumed is recognized as goodwill on the balance sheet if the purchase price exceeds the estimated net fair value or as a bargain purchase gain on the income statement if the purchase price is less than the estimated net fair value. We apply significant judgment in estimating the fair value of assets acquired and liabilities assumed, which involves the use of significant estimates and assumptions with respect to rig counts, cash flow projections, estimated economic useful lives, operating and capital cost estimates, customer attrition rates, contributory asset charges, royalty rates and discount rates. Changes in these judgments or estimates can have a material impact on the valuation of the respective assets and liabilities acquired and our results of operations in periods after acquisition, such as through depreciation and amortization expense. The allocation of the purchase price may be modified up to one year after the acquisition date as more information is obtained about the fair value of assets acquired and liabilities assumed. See Note 2 of Notes to consolidated financial statements included as a part of Item 8 of this Report.

Goodwill — We assess goodwill at least annually on July 31, or more frequently when events or circumstances occur indicating recorded goodwill may be impaired. Goodwill is tested at the reporting unit level, which is at or one level below our operating segments. We determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value after considering qualitative, market and other factors. Any necessary goodwill impairment is determined using a quantitative impairment test. If the resulting fair value of goodwill is less than the carrying value of goodwill, an impairment loss would be recognized for the amount of the shortfall. The fair value of a reporting unit is determined using significant unobservable inputs, or level 3 in the fair value hierarchy. These inputs are based on forecasts and significant judgment.

We determined our drilling products operating segment consists of a single reporting unit to which the goodwill from our 2023 acquisition of Ulterra was allocated. We determined our completion services operating segment consisted of two reporting units: completion services, which was primarily comprised of our hydraulic fracturing operations and other integrated service offerings, and cementing services.

During the fourth and third quarters of 2025, we evaluated whether events or changes in circumstances indicated that the fair value of our goodwill may be less than its carrying amount. As part of this qualitative assessment, we considered the results of our most recent quantitative analysis performed in the second quarter of 2025, along with other factors such as macroeconomic conditions, market trends and indicators of potential changes in the fair value of our reporting units. Based on this assessment, we concluded that it was more likely than not that the fair value of our goodwill exceeded its carrying amount. Therefore, no impairment was indicated, and a Step 1 quantitative goodwill impairment test was not required.

During the second quarter of 2025, we viewed the reduction in activity forecasts combined with the decline in the market price of our common stock as a triggering event that warranted a quantitative assessment for goodwill impairment.

45

We estimated the fair value of the drilling products and cementing services reporting units using the income approach. Under this approach, we used a discounted cash flow model, which utilized present values of cash flows to estimate fair value. Forecasted cash flows reflected known market conditions in the second quarter of 2025 and the expected market outlook. Future cash flows were projected based on estimates of revenue growth rates, gross profit, selling, general and administrative expense, changes in working capital, and capital expenditures. The terminal period used within the discounted cash flow model included a growth rate. Future cash flows were then discounted using a market-participant, risk-adjusted weighted average cost of capital. Financial and credit market volatility directly impacts our fair value measurement through the weighted average cost of capital used to determine a discount rate. During times of volatility, significant judgment must be applied to determine whether credit market changes are a short-term or long-term trend.

The forecast for the cementing services reporting unit assumed lower activity in 2026 compared to estimated average activity for full year 2025 and moderate growth estimates thereafter. Those estimates were based on future drilling rig count forecasts during the second quarter of 2025 and estimated market share. Based on the results of the goodwill impairment test, the fair value of the cementing services reporting unit exceeded its carrying value with a substantial cushion. Accordingly, no impairment was recorded in the second quarter of 2025.

The forecast for the drilling products reporting unit assumed lower activity during 2025 relative to 2024, with growth estimates thereafter. The increases in estimated activity assumed growth in both domestic and international markets. Those growth estimates were based on drilling rig count forecasts and estimated market share. Geopolitical instability in regions in which we expect to maintain and grow market share, an unfavorable legal proceeding outcome, a global decrease in the demand of drilling products or other unforeseen macroeconomic considerations could negatively impact the key assumptions used in our goodwill assessment for our drilling products reporting unit. Based on the results of the goodwill impairment test, the fair value of the drilling products reporting unit exceeded its carrying value by approximately 8%. Accordingly, no impairment was recorded in the second quarter of 2025.

Assuming all changes are isolated, a decrease of 100 bps in our long-term revenue growth rate for our drilling products reporting unit would reduce our estimated fair value by approximately 7%, while a 100 bps increase to our discount rate would reduce our estimated fair value by approximately 10%.

A decrease in fair value resulting from unfavorable changes to these assumptions, or others, could result in goodwill impairment in future periods that could be material to our results of operations and financial statements as a whole.

Accruals for self-insured levels of insurance coverage — We maintain insurance coverage for fire, windstorm and other risks of physical loss to our equipment and certain other assets, employers’ liability, automobile liability, commercial general liability, workers’ compensation and insurance for other specific risks. We also self-insure a number of other risks, including loss of earnings and business interruption and most of our cybersecurity risks, and do not carry a significant amount of insurance to cover risks of underground reservoir damage. Our insurance accruals are based on claims filed and estimates of claims incurred but not reported and are developed by our management with assistance from our third-party actuary and third-party claims administrator. The insurance accruals are influenced by our past claims experience factors and by published industry development factors. If we experience insurance claims or costs above or below our historically evaluated levels, our estimates could be materially affected. The frequency and number of claims or incidents could vary significantly over time, which could materially affect our self-insurance liabilities. Additionally, the actual costs to settle the self-insurance liabilities could materially differ from the original estimates and cause us to incur additional costs in future periods associated with prior year claims. A sensitivity analysis of the impact on earnings for these periods if other assumptions had been used in recording these liabilities is not practicable given the number of underlying assumptions and the wide range of reasonably possible outcomes. See “Item 1A. Risk Factors – Our operations are subject to a number of operational risks, including environmental and weather risks, which could expose us to significant losses and damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us.”

Income taxes — We are subject to income taxes in the United States and other foreign jurisdictions. We compute our provision for income taxes using the asset and liability method, under which deferred tax assets and liabilities are recognized for operating loss and tax credit carryforwards and for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. In assessing the realizability of our deferred tax assets, if it is more likely than not that a portion of the deferred tax assets will not be realized in a future period, the deferred tax assets will be reduced by a valuation allowance. We believe the valuation allowance is a critical accounting estimate because it is susceptible to change from period to period, requires assumptions about our future income over the lives of the deferred tax assets, and because the impact of increasing or decreasing the valuation allowance is potentially material to our results of operations.

Our methodology for recording income taxes requires a significant amount of judgment in the use of assumptions and estimates.

46

Additionally, we forecast certain tax elements, such as future taxable income, as well as evaluate the feasibility of implementing tax planning strategies. Given the inherent uncertainty involved with the use of such variables, there can be significant variation between anticipated and actual results. Unforeseen events may significantly impact these variables, and changes to these variables could have a material impact on our income tax accounts. The final determination of our income tax liabilities involves the interpretation of local tax laws and related authorities in each jurisdiction. Changes in the operating environments, including changes in tax law, could impact the determination of our income tax liabilities for a tax year.

We continue to monitor income tax developments, including OECD Pillar 2 legislation, in the United States and other countries where we have legal entities. We recognize tax benefits related to uncertain tax positions when, in our judgment, it is more likely than not that such positions will be sustained on examination, including resolutions of any related appeals or litigation, based on the technical merits. We adjust our liabilities for uncertain tax positions when our judgment changes as a result of new information previously unavailable. We routinely monitor the potential impact of these situations. As of December 31, 2025, we have no unrecognized tax benefits.

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 prevailing prices for oil and natural gas, expectations about future prices, and our customers’ ability to access, and willingness to deploy, capital to fund their operating and capital expenditures. 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 second half 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 $59.62 per barrel in the fourth quarter of 2025. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $3.73 per MMBtu in the fourth quarter of 2025.

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 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 labor, supplies and equipment.

Recently Issued Accounting Standards

For a discussion of recently issued accounting standards, see Note 1 of Notes to consolidated financial statements included as a part of Item 8 of this Report.

47

Non-GAAP Financial Measures

Adjusted EBITDA

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).

Year Ended December 31,

2025

2024

2023

(in thousands)

Net income (loss)

$

(93,054)

$

(966,399)

$

245,952 

Income tax expense (benefit)

(9,937)

9,453 

61,152 

Net interest expense

63,859 

66,234 

46,748 

Depreciation, depletion, amortization and impairment

940,264 

1,171,873 

731,416 

Legal accruals and settlements

15,415 

(17,792)

— 

Impairment of goodwill

— 

885,240 

— 

Merger and integration expense

1,016 

33,037 

98,077 

Adjusted EBITDA

$

917,563 

$

1,181,646 

$

1,183,345 

48

Adjusted Gross Profit

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 year ended December 31, 2025

Revenues

$

1,557,642 

$

2,892,247 

$

343,707 

$

33,028 

Less direct operating costs

(977,234)

(2,461,539)

(196,130)

(21,599)

Less depreciation, depletion, amortization and impairment

(366,763)

(463,599)

(88,301)

(13,226)

GAAP gross profit (loss)

213,645 

(32,891)

59,276 

(1,797)

Depreciation, depletion, amortization and impairment

366,763 

463,599 

88,301 

13,226 

Adjusted gross profit (loss)

$

580,408 

$

430,708 

$

147,577 

$

11,429 

For the year ended December 31, 2024

Revenues

$

1,727,810 

$

3,232,785 

$

351,651 

$

65,665 

Less direct operating costs

(1,029,591)

(2,658,170)

(191,107)

(41,001)

Less depreciation, depletion, amortization and impairment

(477,398)

(564,155)

(100,610)

(24,043)

GAAP gross profit (loss)

220,821 

10,460 

59,934 

621 

Depreciation, depletion, amortization and impairment

477,398 

564,155 

100,610 

24,043 

Adjusted gross profit (loss)

$

698,219 

$

574,615 

$

160,544 

$

24,664 

For the year ended December 31, 2023

Revenues

$

1,919,759 

$

2,017,440 

$

134,679 

$

74,578 

Less direct operating costs

(1,119,200)

(1,567,940)

(81,555)

(42,624)

Less depreciation, depletion, amortization and impairment

(364,312)

(283,230)

(48,467)

(28,237)

GAAP gross profit (loss)

436,247 

166,270 

4,657 

3,717 

Depreciation, depletion, amortization and impairment

364,312 

283,230 

48,467 

28,237 

Adjusted gross profit (loss)

$

800,559 

$

449,500 

$

53,124 

$

31,954 

49