# Patterson Uti Energy Inc: Form 10-Q for the period ended Mar 31, 2025

- Company: [Patterson Uti Energy Inc](/companies/pten.md) (CIK 889900)
- Form: 10-Q
- Filed: 2025-04-29
- Accepted by EDGAR: Apr 29, 2025, 16:10 ET
- Period: 2025-03-31
- Accession: 0001628280-25-020675
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/889900/000162828025020675/pten-20250331.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/889900/000162828025020675/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2025-03-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2025-01-01 to 2025-03-31 | $1.26bn | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Selling, general and administrative | 3 months, 2025-01-01 to 2025-03-31 | $66.9m | us-gaap:SellingGeneralAndAdministrativeExpense |
| Operating income | 3 months, 2025-01-01 to 2025-03-31 | $16.9m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2025-01-01 to 2025-03-31 | $17.7m | us-gaap:InterestExpenseNonoperating |
| Income tax | 3 months, 2025-01-01 to 2025-03-31 | $1.4m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2025-01-01 to 2025-03-31 | $1.0m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2025-01-01 to 2025-03-31 | $0.00 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2025-01-01 to 2025-03-31 | $0.00 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2025-01-01 to 2025-03-31 | 387,044,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 3 months, 2025-01-01 to 2025-03-31 | $208.1m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 3 months, 2025-01-01 to 2025-03-31 | $161.8m | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Dividends paid | 3 months, 2025-01-01 to 2025-03-31 | $30.9m | us-gaap:PaymentsOfDividends |
| Share repurchases | 3 months, 2025-01-01 to 2025-03-31 | $20.3m | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Cash and equivalents | at 2025-03-31 | $223.1m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2025-03-31 | $1.32bn | us-gaap:AssetsCurrent |
| Total assets | at 2025-03-31 | $5.77bn | us-gaap:Assets |
| Current liabilities | at 2025-03-31 | $818.3m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2025-03-31 | $2.33bn | us-gaap:Liabilities |
| Long-term debt | at 2025-03-31 | $1.22bn | us-gaap:LongTermDebtNoncurrent |
| Current portion of debt | at 2025-03-31 | $3.2m | us-gaap:LongTermDebtCurrent |
| Shareholders' equity | at 2025-03-31 | $3.43bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 48,022 characters.

*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 service and re-certify equipment for drilling contractors, and we provide electrical controls and automation to the energy, marine and mining industries, in North America and other select markets.

As of March 31, 2025, we had 152 marketed land-based drilling rigs based in the following regions:

| Region | Number of Rigs |
| --- | ---: |
| West Texas | 71 |
| Appalachia | 21 |
| Oklahoma | 16 |
| Rockies | 16 |
| South Texas | 11 |
| East Texas | 9 |
| Colombia | 7 |
| Ecuador | 1 |
| Total | 152 |

We have addressed our customers’ needs for drilling horizontal wells in shale and other unconventional resource plays by improving the capabilities of our drilling fleet. The U.S. land rig industry has in recent years referred to certain high specification rigs as “super-spec” rigs, which we consider to be at least a 1,500 horsepower, AC-powered rig that has at least a 750,000-pound hookload, a 7,500-psi circulating system, and is pad-capable. Due to evolving customer preferences, we refer to certain premium rigs as “Tier-1, super spec” rigs, which we consider as being a super-spec rig that also has a third mud pump and raised drawworks that allows for more clearance underneath the rig floor. As of March 31, 2025, our rig fleet included 135 Tier-1, super-spec rigs.

### 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 evolving customer preferences for emissions-reducing equipment, we have invested in natural gas-powered equipment, including electric, direct drive, and dual fuel pumps, to replace legacy diesel completion services equipment.

### Drilling Products

We serve the energy and mining markets by manufacturing and distributing drill bits throughout North America and internationally in over 30 countries. Our drilling equipment is used in oil and natural gas exploration and production and in mining operations. We have manufacturing and repair facilities located in Fort Worth, Texas, Leduc, Alberta and Saudi Arabia and repair facilities located in Argentina, Colombia and Oman.

*Recent Developments in Market Conditions and Outlook —* Commodity prices have historically been volatile but were relatively range-bound from the end of 2022 through the first quarter of 2025. The current demand for equipment and services remains impacted by macro conditions, including commodity prices, geopolitical environment, changes to international tariffs and trade policies, inflationary pressures, economic conditions in the United States and elsewhere, as well as customer consolidation and focus by exploration and production companies and service companies on capital returns. Subsequent to March 31, 2025, global economic conditions deteriorated, in part, because of recently enacted trade policies and tariffs implemented by the United States and other governments, as well as uncertainty regarding potential future changes to global trade policies and tariffs. Additionally, subsequent to March 31, 2025, several OPEC+ countries announced plans to phase out existing crude oil output cuts earlier than anticipated. These developments and geopolitical tensions have introduced increased uncertainty in global energy markets, which has contributed to a decline in our share price, lowered crude oil futures prices and increased uncertainty regarding the future economic environment in which we operate. The recent deterioration in macroeconomic conditions and the decline in our share price occurred after the balance sheet date and do not reflect conditions that existed as of March 31, 2025. Accordingly, these developments have not been reflected in the unaudited condensed consolidated financial statements for the three months ended March 31, 2025. While the full effects are yet to be determined, prolonged trade tensions and sustained lower crude oil futures prices could adversely affect our future outlook on activity and profitability. Oil prices averaged $71.78 per barrel in the first quarter of 2025, as compared to $70.73 per barrel in the fourth quarter of 2024, and closed at $63.48 per barrel on April 21, 2025. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $4.14 per MMBtu in the first quarter of 2025 as compared to an average of $2.45 per MMBtu in the fourth quarter of 2024, and closed at $3.16 per MMBtu on April 21, 2025.

Our average active rig count in the United States for the first quarter of 2025 was 106 rigs. This was an increase from our average active rig count for the fourth quarter of 2024 of 105. Term contracts help support our operating rig count. Based on contracts in place in the United States as of April 24, 2025, we expect an average of 62 rigs operating under term contracts during the second quarter of 2025 and an average of 35 rigs operating under term contracts during the four quarters ending March 31, 2026.

We maintain a backlog of commitments for contract drilling services under term contracts, which we define as contracts with a duration of six months or more. Our contract drilling backlog in the United States as of March 31, 2025 was approximately $407 million. Approximately 9% of our total contract drilling backlog in the United States at March 31, 2025 is reasonably expected to remain at March 31, 2026. See Note 2 of Notes to unaudited condensed consolidated financial statements for additional information on backlog.

In our Drilling Services segment for the second quarter of 2025, we expect our average daily rig count to remain relatively steady compared to the first quarter. We expect adjusted gross profit within the Drilling Services segment to decline slightly, with the sequential change driven by a reduction in average contracted revenue as existing term contracts with more favorable pricing expire, as well as some normal seasonal increase in costs.

In our Completion Services segment for the second quarter of 2025, we currently expect activity to remain relatively steady as compared to activity levels at the end of the first quarter, although current oil prices may impact demand for completion services later in the second quarter. We expect second quarter Completion Services adjusted gross profit to decline slightly, sequentially.

In our Drilling Products segment for the second quarter of 2025, we expect sequential adjusted gross profit to remain relatively flat compared to the first quarter, with steady activity in the United States. We expect impacts from the normal seasonal spring breakup in Canada to be mostly offset by higher International revenue in the rest of the world.

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

The Credit Agreement provides for a committed senior unsecured credit facility that permits aggregate revolving credit borrowings of up to $500 million, with a letter of credit sub-facility of $100 million and a swing line sub-facility that, at any time outstanding, is limited to the lesser of $50 million and the amount of the swing line provider’s unused commitment. Subject to customary conditions, we may request that the lenders’ aggregate commitments be increased by up to $200 million, not to exceed total commitments of $700 million. For a description of the Credit Agreement, see “Liquidity and Capital Resources” below.

As of March 31, 2025, we had no borrowings outstanding under our Credit Agreement. We had $2.0 million in letters of credit outstanding under the Credit Agreement at March 31, 2025 and, as a result, had available borrowing capacity of approximately $498 million at that date.

*Impact on our Business from Oil and Natural Gas Prices and Other Factors —* Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas, expectations about future prices, and upon our customers’ ability to access, and willingness to deploy, capital to fund their operating and capital expenditures. During periods of improved oil and natural gas prices, the capital spending budgets of oil and natural gas operators tend to expand, which generally results in increased demand for our services. Conversely, in periods when oil and natural gas prices are relatively low or when our customers have a reduced ability to access, or willingness to deploy, capital, the demand for our services generally weakens, and we experience downward pressure on pricing for our services. Even during periods of historically moderate or high prices for oil and natural gas, companies exploring for oil and natural gas may cancel or curtail programs or reduce their levels of capital expenditures for exploration and production for a variety of reasons, including the depletion of capital expenditure budgets and/or meeting annual drilling and completion targets, which could reduce demand for our services. We may also be impacted by delayed customer payments and payment defaults associated with customer liquidity issues and bankruptcies.

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. Please see Item 1A of our Annual Report.

For the three months ended March 31, 2025, December 31, 2024, and March 31, 2024 our operating revenues consisted of the following (dollars in thousands):

|  | Three Months Ended March 31, 2025 |  | December 31, 2024 |  | March 31, 2024 |  |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Drilling Services | $412,860 | 32.2% | $408,385 | 35.1% | $457,573 | 30.3% |
| Completion Services | 766,080 | 59.8% | 650,848 | 56.0% | 944,997 | 62.6% |
| Drilling Products | 85,663 | 6.7% | 86,522 | 7.4% | 89,973 | 6.0% |
| Other | 15,934 | 1.3% | 16,380 | 1.5% | 17,817 | 1.1% |
|  | $1,280,537 | 100.0% | $1,162,135 | 100.0% | $1,510,360 | 100.0% |

30

### Results of Operations

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

*(dollars in thousands)*

| Drilling Services | Three Months Ended March 31, 2025 | December 31, 2024 | March 31, 2024 | % Change Sequential | Year-over-year |
| --- | ---: | ---: | ---: | ---: | ---: |
| Revenues | $412,860 | $408,385 | $457,573 | 1.1% | (9.8)% |
| Direct operating costs | 247,629 | 245,480 | 271,737 | 0.9% | (8.9)% |
| Adjusted gross profit (1) | 165,231 | 162,905 | 185,836 | 1.4% | (11.1)% |
| Selling, general and administrative | 3,945 | 4,741 | 3,879 | (16.8)% | 1.7% |
| Depreciation, amortization and impairment | 84,972 | 85,174 | 92,345 | (0.2)% | (8.0)% |
| Operating income | $76,314 | $72,990 | $89,612 | 4.6% | (14.8)% |
| Capital expenditures | $73,458 | $54,321 | $82,793 | 35.2% | (11.3)% |
| Operating days – U.S. (2) | 9,573 | 9,617 | 11,024 | (0.5)% | (13.2)% |
| Average revenue per operating day – U.S. (2) | $35.72 | $35.29 | $35.68 | 1.2% | 0.1% |
| Average direct operating costs per operating day – U.S. (2) | $19.55 | $19.57 | $19.51 | (0.1)% | 0.2% |
| Average adjusted gross profit per operating day – U.S. (2) | $16.17 | $15.72 | $16.17 | 2.9% | 0.0% |

(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.

#### 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.

Revenues and direct operating costs, both on a total and per operating day basis, were relatively flat between sequential quarters.

Capital expenditures increased primarily due to spending related to maintenance capital and the timing of order placement that more heavily impacted the first quarter of 2025.

#### Year-over-year quarter comparison

Revenues and direct operating costs decreased due to a decrease in operating days for our U.S. contract drilling operations.

The decrease in depreciation, amortization and impairment expense was attributable to a lower depreciable asset base in the first quarter of 2025, in part, due to the abandonment of 42 legacy non-super-spec rigs and equipment in the third quarter of 2024.

Capital expenditures decreased primarily due to reduced investment in our ancillary drilling services not included within our contract drilling business.

*(dollars in thousands)*

| Completion Services | Three Months Ended March 31, 2025 | December 31, 2024 | March 31, 2024 | % Change Sequential | Year-over-year |
| --- | ---: | ---: | ---: | ---: | ---: |
| Revenues | $766,080 | $650,848 | $944,997 | 17.7% | (18.9)% |
| Direct operating costs | 657,681 | 555,527 | 745,594 | 18.4% | (11.8)% |
| Adjusted gross profit (1) | 108,399 | 95,321 | 199,403 | 13.7% | (45.6)% |
| Selling, general and administrative | 11,409 | 9,703 | 10,964 | 17.6% | 4.1% |
| Depreciation, amortization and impairment | 115,826 | 135,852 | 148,680 | (14.7)% | (22.1)% |
| Other operating income, net | — | — | (9,870) | NA | (100.0)% |
| Operating income (loss) | $(18,836) | $(50,234) | $49,629 | (62.5)% | NA |
| Capital expenditures | $62,173 | $61,469 | $123,377 | 1.1% | (49.6)% |

(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.

#### Sequential quarter comparison

Completion services revenues and direct operating costs increased primarily due to seasonal recovery as customer budgets reset in the first quarter. The higher revenues and direct operating costs were primarily from our fracturing operations, which increased $86 million and $82 million, or 17% and 18%, respectively. The increases were primarily activity driven, with pumping hours increasing 23% during the first quarter of 2025.

Depreciation, amortization and impairment expense decreased primarily due to $20.8 million of accelerated depreciation recognized in the fourth quarter of 2024.

#### Year-over-year quarter comparison

Completion services revenues and direct operating costs decreased primarily due to lower activity in our fracturing operations. Revenues and direct operating costs from our fracturing operations decreased by $170 million and $84 million, or 21% and 13%, respectively.

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

Other operating income, net in the first quarter of 2024 was due to a gain on legal settlement.

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

*(dollars in thousands)*

| Drilling Products | Three Months Ended March 31, 2025 | December 31, 2024 | March 31, 2024 | % Change Sequential | Year-over-year |
| --- | ---: | ---: | ---: | ---: | ---: |
| Revenues | $85,663 | $86,522 | $89,973 | (1.0)% | (4.8)% |
| Direct operating costs | 46,940 | 49,186 | 48,630 | (4.6)% | (3.5)% |
| Adjusted gross profit (1) | 38,723 | 37,336 | 41,343 | 3.7% | (6.3)% |
| Selling, general and administrative | 9,119 | 10,209 | 7,661 | (10.7)% | 19.0% |
| Depreciation, amortization and impairment | 22,876 | 27,328 | 27,182 | (16.3)% | (15.8)% |
| Operating income (loss) | $6,728 | $(201) | $6,500 | NA | 3.5% |
| Capital expenditures | $18,222 | $15,834 | $15,586 | 15.1% | 16.9% |

(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.

#### Sequential quarter comparison

Revenues and direct operating costs were relatively flat between sequential quarters.

Direct operating costs and depreciation, amortization and impairment expense were approximately $0.6 million and $2.3 million higher than they would have otherwise been for the three months ended March 31, 2025, respectively, as a result of the step up to fair value of our drill bits in accordance with purchase accounting. For the three months ended December 31, 2024, direct operating costs and depreciation, amortization and impairment expense were approximately $3.1 million and $6.1 million higher than they would have otherwise been, respectively, as a result of the step up to fair value of our drill bits.

#### Year-over-year quarter comparison

Revenues and direct operating costs were relatively flat between the quarters.

Direct operating costs and depreciation, amortization and impairment expense were approximately $0.6 million and $2.3 million higher than they would have otherwise been for the three months ended March 31, 2025, respectively, as a result of the step up to fair value of our drill bits in accordance with purchase accounting. For the three months ended March 31, 2024, direct operating costs and depreciation, amortization and impairment were approximately $2.2 million and $5.8 million higher, respectively, as a result of the step up to fair value of our drill bits.

*(dollars in thousands)*

| Other | Three Months Ended March 31, 2025 | December 31, 2024 | March 31, 2024 | % Change Sequential | Year-over-year |
| --- | ---: | ---: | ---: | ---: | ---: |
| Revenues | $15,934 | $16,380 | $17,817 | (2.7)% | (10.6)% |
| Direct operating costs | 9,164 | 9,466 | 11,178 | (3.2)% | (18.0)% |
| Adjusted gross profit (1) | 6,770 | 6,914 | 6,639 | (2.1)% | 2.0% |
| Selling, general and administrative | 204 | 59 | 240 | 245.8% | (15.0)% |
| Depreciation, depletion, amortization and impairment | 6,336 | 4,790 | 5,411 | 32.3% | 17.1% |
| Operating income | $230 | $2,065 | $988 | (88.9)% | (76.7)% |
| Capital expenditures | $3,596 | $2,894 | $3,797 | 24.3% | (5.3)% |

(1) Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, depletion, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.

#### Sequential quarter comparison

Revenues and direct operating costs were relatively flat between sequential quarters.

Depreciation, depletion, amortization and impairment expense increased primarily due to a $1.7 million impairment charge recorded in our oil and natural gas properties business during the first quarter of 2025.

#### Year-over-year quarter comparison

Revenues and direct operating costs decreased primarily due to lower activity as a result of lower crude oil and natural gas market prices. Oil prices averaged $71.78 per barrel in the first quarter of 2025, as compared to $77.50 per barrel in the first quarter of 2024.

*(dollars in thousands)*

| Corporate | Three Months Ended March 31, 2025 | December 31, 2024 | March 31, 2024 | % Change Sequential | Year-over-year |
| --- | ---: | ---: | ---: | ---: | ---: |
| Selling, general and administrative | $42,253 | $48,367 | $42,240 | (12.6)% | 0.0% |
| Merger and integration expense | $432 | $3,460 | $12,233 | (87.5)% | (96.5)% |
| Depreciation | $1,856 | $1,455 | $1,338 | 27.6% | 38.7% |
| Other operating expense, net | $2,950 | $2,673 | $3,919 | 10.4% | (24.7)% |
| Interest income | $1,464 | $928 | $2,189 | 57.8% | (33.1)% |
| Interest expense, net of amount capitalized | $(17,697) | $(17,725) | $(18,335) | (0.2)% | (3.5)% |
| Other income (expense) | $1,968 | $(1,333) | $850 | NA | 131.5% |
| Capital expenditures | $4,382 | $5,832 | $1,388 | (24.9)% | 215.7% |

#### Sequential quarter comparison

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

Other income (expense) during the first quarter of 2025 included $1.4 million of income from an unconsolidated joint venture.

#### Year-over-year quarter comparison

Merger and integration expense decreased due to the passage of time since closing the NexTier merger and the Ulterra acquisition in third quarter of 2023.

### 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 March 31, 2025 was 51.9%, compared with (3.9)% for the three months ended December 31, 2024. The difference in effective income tax rates between the periods was primarily attributable to the impact of valuation allowances on deferred tax assets between periods, as well as the impact of goodwill impairments and permanent differences against earnings between periods.

Our effective income tax rate for the three months ended March 31, 2025 was 51.9%, compared with 27.9% for the three months ended March 31, 2024. The difference in effective income tax rates between the periods was primarily attributable to the impact of permanent differences against earnings between periods.

We continue to monitor income tax developments in the United States and other countries where we have legal entities. 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

Our primary sources of liquidity are cash and cash equivalents, availability under our Credit Agreement and cash provided by operating activities. As of March 31, 2025, we had approximately $499 million in working capital, including $223 million of cash and cash equivalents, and approximately $498 million available under our Credit Agreement.

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

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 these covenants at March 31, 2025.

On March 16, 2015, we entered into a Reimbursement Agreement (as amended from time to time, the “Reimbursement Agreement”) with The Bank of Nova Scotia (“Scotiabank”), pursuant to which we may from time to time request that Scotiabank issue an unspecified amount of letters of credit. As of March 31, 2025, we had $38.8 million in letters of credit outstanding under the Reimbursement Agreement.

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.

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 $42.8 million of outstanding letters of credit at March 31, 2025, which was comprised of $38.8 million outstanding under the Reimbursement Agreement, $2.0 million outstanding under the Credit Agreement, and $2.0 million outstanding with financial institutions providing for short-term borrowing capacity, overdraft protection and bonding requirements. We maintain these letters of credit primarily for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under terms of the underlying insurance contracts and compliance with contractual obligations. These letters of credit expire annually at various times during the year and are typically renewed. As of March 31, 2025, no amounts had been drawn under the letters of credit. As of March 31, 2025, we had $35.0 million in surety bond exposure issued as financial assurance on an insurance agreement.

Our outstanding long-term debt at March 31, 2025 was $1.2 billion and consisted of $483 million of our 2028 Notes, $345 million of our 2029 Notes, $400 million of our 2033 Notes and $3.2 million of secured equipment financing term loans. We were in compliance with all covenants under the associated agreements and indentures at March 31, 2025.

For a full description of the Credit Agreement, the Reimbursement Agreement, the 2028 Notes, the 2029 Notes, and the 2033 Notes, see Note 8 of Notes to unaudited condensed consolidated financial statements.

### 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 levels.

We anticipate $44.7 million of expenditures for the remainder of 2025 related to various contractual obligations such as certain commitments to purchase proppants and lease liabilities.

As of March 31, 2025, we had working capital of $499 million, including cash, cash equivalents and restricted cash of $225 million, compared to working capital of $453 million, including cash, cash equivalents and restricted cash of $241 million, at December 31, 2024.

During the three months ended March 31, 2025, our sources of cash flow included:

- $208 million from operating activities, and
- $4.3 million in proceeds from the disposal of property and equipment.

During the three months ended March 31, 2025, our uses of cash flow included:

- $162 million to make capital expenditures for the betterment and refurbishment of drilling services and completion services equipment and, to a much lesser extent, equipment for our other businesses, to acquire and procure equipment to support our drilling services, completion services, drilling products, and other operations,
- $20.3 million for repurchases of our common stock,
- $30.9 million to pay dividends on our common stock,
- $2.6 million for payments related to finance leases, and
- $12.1 million for other investing and financing activities.

We paid cash dividends during the three months ended March 31, 2025 as follows:

*(in thousands)*

|  | Per Share | Total |
| --- | ---: | ---: |
| Paid on March 17, 2025 | $0.08 | $30,877 |

On April 23, 2025, our Board of Directors approved a cash dividend on our common stock in the amount of $0.08 per share to be paid on June 16, 2025 to holders of record as of June 2, 2025. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our debt agreements and other factors. Our Board of Directors may, without advance notice, reduce or suspend our dividend for any reason, including to improve our financial flexibility and position our company for long-term success. There can be no assurance that we will pay a dividend in the future.

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 March 31, 2025, we had remaining authorization to purchase approximately $741 million of our outstanding common stock under the stock buyback program. Shares of stock purchased under the buyback program are held as treasury shares.

Treasury stock acquisitions during the three months ended March 31, 2025 were as follows (dollars in thousands):

|  | Shares | Cost |
| --- | ---: | ---: |
| Treasury shares at beginning of period | 133,440,028 | $1,951,067 |
| Purchases pursuant to stock buyback program | 2,078,723 | 18,062 |
| Acquisitions pursuant to long-term incentive plans (1) | 258,558 | 2,233 |
| Treasury shares at end of period | 135,777,309 | $1,971,362 |

(1) We withheld 258,558 shares during the three months ended March 31, 2025 with respect to employees’ tax withholding obligations upon the vesting of restricted stock units. These shares were acquired at fair market value. These acquisitions were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2021 Long-Term Incentive Plan, as amended and the NexTier Oilfield Solutions Inc. Equity and Incentive Award Plan, and not pursuant to the stock buyback program.

*Commitments —* As of March 31, 2025, we had commitments to purchase major equipment totaling approximately $111 million. Our completion services segment has entered into agreements to purchase minimum quantities of proppants from certain vendors. As of March 31, 2025, the remaining minimum obligation under these agreements was approximately $18.7 million, of which approximately $13.6 million and $5.1 million relate to the remainder of 2025 and 2026, respectively.

See Note 9 of Notes to unaudited condensed consolidated financial statements for additional information on our current commitments and contingencies as of March 31, 2025.

Operating lease liabilities totaled $45.7 million and finance lease liabilities totaled $23.0 million as of March 31, 2025.

*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 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 (including 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).

*(in thousands)*

|  | Three Months Ended March 31, 2025 | December 31, 2024 | March 31, 2024 |
| --- | ---: | ---: | ---: |
| Net income (loss) | $1,290 | $(51,392) | $51,706 |
| Income tax expense | 1,390 | 1,927 | 19,997 |
| Net interest expense | 16,233 | 16,797 | 16,146 |
| Depreciation, depletion, amortization and impairment | 231,866 | 254,599 | 274,956 |
| Merger and integration expense | 432 | 3,460 | 12,233 |
| Adjusted EBITDA | $251,211 | $225,391 | $375,038 |

### Adjusted Gross Profit

We define “Adjusted gross profit” as revenues less direct operating costs (excluding depreciation, depletion, amortization and impairment expense). Adjusted gross profit is included as a supplemental disclosure because it is a useful indicator of our operating performance.

*(in thousands)*

| For the three months ended March 31, 2025 | Drilling Services | Completion Services | Drilling Products | Other |
| --- | ---: | ---: | ---: | ---: |
| Revenues | $412,860 | $766,080 | $85,663 | $15,934 |
| Less direct operating costs | (247,629) | (657,681) | (46,940) | (9,164) |
| Less depreciation, depletion, amortization and impairment | (84,972) | (115,826) | (22,876) | (6,336) |
| GAAP gross profit (loss) | 80,259 | (7,427) | 15,847 | 434 |
| Depreciation, depletion, amortization and impairment | 84,972 | 115,826 | 22,876 | 6,336 |
| Adjusted gross profit | $165,231 | $108,399 | $38,723 | $6,770 |
| **For the three months ended December 31, 2024** |  |  |  |  |
| Revenues | $408,385 | $650,848 | $86,522 | $16,380 |
| Less direct operating costs | (245,480) | (555,527) | (49,186) | (9,466) |
| Less depreciation, depletion, amortization and impairment | (85,174) | (135,852) | (27,328) | (4,790) |
| GAAP gross profit (loss) | 77,731 | (40,531) | 10,008 | 2,124 |
| Depreciation, depletion, amortization and impairment | 85,174 | 135,852 | 27,328 | 4,790 |
| Adjusted gross profit | $162,905 | $95,321 | $37,336 | $6,914 |
| **For the three months ended March 31, 2024** |  |  |  |  |
| Revenues | $457,573 | $944,997 | $89,973 | $17,817 |
| Less direct operating costs | (271,737) | (745,594) | (48,630) | (11,178) |
| Less depreciation, depletion, amortization and impairment | (92,345) | (148,680) | (27,182) | (5,411) |
| GAAP gross profit | 93,491 | 50,723 | 14,161 | 1,228 |
| Depreciation, depletion, amortization and impairment | 92,345 | 148,680 | 27,182 | 5,411 |
| Adjusted gross profit | $185,836 | $199,403 | $41,343 | $6,639 |

### 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. 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 prevailing prices for oil and natural gas and expectations about future prices, and upon 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. Subsequent to March 31, 2025, global economic conditions deteriorated, in part, because of recently enacted trade policies and tariffs implemented by the United States and other governments, as well as uncertainty regarding potential future changes to global trade policies and tariffs. Additionally, subsequent to March 31, 2025, several OPEC+ countries announced plans to phase out existing crude oil output cuts earlier than anticipated. These developments and geopolitical tensions have introduced increased uncertainty in global energy markets, which has contributed to a decline in our share price, lowered crude oil futures prices and increased uncertainty regarding the future economic environment in which we operate. The recent deterioration in macroeconomic conditions and the decline in our share price occurred after the balance sheet date and do not reflect conditions that existed as of March 31, 2025. Accordingly, these developments have not been reflected in the unaudited condensed consolidated financial statements for the three months ended March 31, 2025. While the full effects are yet to be determined, prolonged trade tensions and sustained lower crude oil futures prices could adversely affect our future outlook on activity and profitability. Oil prices averaged $71.78 per barrel in the first quarter of 2025, as compared to $70.73 per barrel in the fourth quarter of 2024, and closed at $63.48 per barrel on April 21, 2025. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $4.14 per MMBtu in the first quarter of 2025 as compared to an average of $2.45 per MMBtu in the fourth quarter of 2024, and closed at $3.16 per MMBtu on April 21, 2025.

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 potential future changes to international tariffs and trade policies have contributed, or may contribute, to increases in the cost of certain goods, services, and labor. While the full effects are yet to be determined, prolonged trade tensions could, among other things, increase the costs of certain products used in our businesses, such as drill pipe, parts, and electronics. We continue to actively monitor market trends primarily related to sourcing of labor, supplies and equipment.

## Market risk

As filed, 2,798 characters.

We may be exposed to certain market risks arising from the use of financial instruments in the ordinary course of business. For quantitative and qualitative disclosures about market risk, see Part II, Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” in our Annual Report. There have been no material changes in our exposure to market risk.

As of March 31, 2025, we would have had exposure to interest rate market risk associated with any outstanding borrowings and letters of credit that we had under the Credit Agreement and amounts owed under the Reimbursement Agreement.

Loans under the Credit Agreement bear interest by reference, at our election, to the SOFR rate (plus a 0.10% per annum adjustment) or base rate, in each case subject to a 0% floor. The applicable margin on SOFR rate loans varies from 1.25% to 2.25% and the applicable margin on base rate loans varies from 0.25% to 1.25%, in each case determined based on our credit rating. As of March 31, 2025, the applicable margin on SOFR rate loans was 1.75% and the applicable margin on base rate loans was 0.75% A letter of credit fee is payable by us equal to the applicable margin for SOFR rate loans times the daily amount available to be drawn under outstanding letters of credit. The commitment fee rate payable to the lenders varies from 0.15% to 0.35% based on our credit rating. As of March 31, 2025, we had $2.0 million in letters of credit outstanding under the Credit Agreement and, as a result, had available borrowing capacity of approximately $498 million at that date.

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. We are obligated to pay 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.

Our functional currency is primarily the U.S. dollar. Approximately 98% of our revenue during the first quarter of 2025 was denominated in U.S. dollars. As such, we do not believe we are significantly exposed to foreign currency exchange rate risk. However, a portion of our revenues in foreign countries are denominated in U.S. dollars, and therefore, changes in foreign currency exchange rates impact our earnings to the extent that costs associated with those U.S. dollar revenues are denominated in the local currency. Similarly, a portion of our revenues are denominated in foreign currencies, but have associated U.S. dollar costs, which also give rise to foreign currency exchange rate exposure.

The carrying values of cash, cash equivalents and restricted cash, trade receivables and accounts payable approximate fair value due to the short-term maturity of these items.

## Controls and procedures

As filed, 1,406 characters.

*Disclosure Controls and Procedures —* We maintain disclosure controls and procedures (as such terms are defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Exchange Act), designed to ensure that the information required to be disclosed in the reports that we file with the SEC under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate, to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10‑Q. Based on that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of March 31, 2025.

*Changes in Internal Control Over Financial Reporting —*There were no changes in our internal control over financial reporting during our most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act.

Filed Apr 29, 2025.
Source: SEC EDGAR, the filing index for accession 0001628280-25-020675. Last ingested by Listed: Nov 2, 2026, 18:44 ET. No prices; not investment advice.