PATTERSON-UTI ENERGY, INC. Management Overview and Recent Developments in Market Conditions - We are aHouston, Texas -based oilfield services company that primarily owns and operates one of the largest fleets of land-based drilling rigs inthe United States and a large fleet of pressure pumping equipment. Our contract drilling business operates in the continentalUnited States and internationally inColombia and, from time to time, we pursue contract drilling opportunities in other select markets. Our pressure pumping business operates primarily inTexas and the Appalachian region. We also provide a comprehensive suite of directional drilling services in most major producing onshore oil and gas basins inthe United States , and we provide services that improve the statistical accuracy of directional and horizontal wellbores. We have other operations through which we provide oilfield rental tools in select markets inthe United States . We also service equipment for drilling contractors, and we provide electrical controls and automation to the energy, marine and mining industries, inNorth America and other select markets. In addition, we own and invest, as a non-operating working interest owner, in oil and natural gas assets that are primarily located inTexas andNew Mexico . Crude oil prices and demand for drilling and completions equipment and services increased in 2022, and industry supply of Tier-1, super-spec rigs remains constrained. We currently expect our average rig count to be down two to three rigs in the second quarter as activity transitions more to oil from natural gas. The current demand for equipment and services remains dependent on macro conditions, including commodity prices, geopolitical environment, inflationary pressures, economic conditions inthe United States and elsewhere and continued focus by exploration and production companies and service companies on capital discipline. Oil prices averaged$76.08 per barrel in the first quarter of 2023, as compared to$82.79 per barrel in the fourth quarter of 2022. Natural gas prices (based on the Henry Hub Spot Market Price) averaged$2.65 per MMBtu in the first quarter of 2023 as compared to an average of$5.55 per MMBtu in the fourth quarter of 2022. Our average active rig count inthe United States for the first quarter of 2023 was 131 rigs, consistent with the fourth quarter of 2022. Based on contracts in place inthe United States as ofApril 26, 2023 , we expect an average of 79 rigs operating under term contracts during the second quarter of 2023 and an average of 53 rigs operating under term contracts during the four quarters endingMarch 31, 2024 . Our average active spread count was 12 spreads in the first quarter, consistent with the fourth quarter of 2022. We calculated average active spreads as the average number of spreads that were crewed and actively marketed during the period. We expect to end the second quarter with 12 active pressure pumping spreads. With the recent slowdown in market activity, we have lowered our 2023 capital expenditure forecast from$550 million to$510 million , including approximately$30 million of customer-funded rig upgrades. Recent Developments in Financial Matters - OnNovember 9, 2022 , we entered into Amendment No. 3 to Amended and Restated Credit Agreement ("Amendment No. 3"), which amended our amended and restated credit agreement, dated as ofMarch 27, 2018 (as amended, the "Credit Agreement"), among us, as borrower,Wells Fargo Bank, National Association , as administrative agent, letter of credit issuer, swing line lender and lender and each of the other letter of credit issuers and lenders party thereto. Amendment No. 3, among other things, (i) revised the capacity under the letter of credit facility to$100 million ; (ii) revised the capacity under the swing line facility to the lesser of$50 million and the amount of the swing line provider's unused commitment; (iii) changed the LIBOR reference rate to a SOFR reference rate; and (iv) extended the maturity date for$416.7 million of revolving credit commitments of certain lenders under the Credit Agreement fromMarch 27, 2025 toMarch 27, 2026 . As a result, of the$600 million of revolving credit commitments under the Credit Agreement, the maturity date for$416.7 million of such commitments isMarch 27, 2026 ; the maturity date for$133.3 million of such commitments isMarch 27, 2025 ; and the maturity date for the remaining$50 million of such commitments isMarch 27, 2024 .
As of
During the fourth quarter of 2022, we elected to repurchase portions of our 3.95% Senior Notes due 2028 (the "2028 Notes") and our 5.15% Senior Notes due 2029 (the "2029 Notes") in the open market. The principal amounts retired through these transactions totaled$21.0 million of our 2028 Notes and$1.4 million of our 2029 Notes, plus accrued interest. We recorded corresponding gains on the extinguishment of these amounts totaling$2.3 million and$0.1 million , respectively, net of the proportional write-off of associated deferred financing costs and original issuance discounts. 22 -------------------------------------------------------------------------------- During the first quarter of 2023, we elected to repurchase portions of our 2028 Notes and 2029 Notes in the open market. The principal amounts retired through these transactions totaled$6.0 million of our 2028 Notes and$3.0 million of our 2029 Notes, plus accrued interest. We recorded corresponding gains on the extinguishment of these amounts totaling$0.8 million and$0.3 million , respectively, net of the proportional write-off of associated deferred financing costs and original issuance discounts. These gains are included in "Interest expense, net of amount capitalized" in our unaudited condensed consolidated statements of operations. 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 and upon our customers' ability to access 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 capital, the demand for our services generally weakens, and we experience downward pressure on pricing for our services. Even during periods of historically moderate or high prices for oil and natural gas, companies exploring for oil and natural gas may cancel or curtail programs or reduce their levels of capital expenditures for exploration and production for a variety of reasons, which could reduce demand for our services. We may also be impacted by delayed customer payments and payment defaults associated with customer liquidity issues and bankruptcies. The North American oil and natural gas services industry is cyclical and at times experiences downturns in demand. During these periods, there has been substantially more oil and natural gas service equipment available than necessary to meet demand. As a result, oil and natural gas service contractors have had difficulty sustaining profit margins and, at times, have incurred losses during the downturn periods. We cannot predict either the future level of demand for our oil and natural gas services or future conditions in the oil and natural gas service businesses. 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 pressure pumping business, 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 on Form 10-K for the fiscal year endedDecember 31, 2022 .
For the three months ended
Three Months Ended
March 31 , December 31,
2023 2022
Contract drilling
$ 791,802 100.0 %$ 788,476 100.0 % Contract Drilling 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. TheU.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 allow for more clearance underneath the rig floor. As ofMarch 31, 2023 , our rig fleet included 172 super-spec rigs, of which 120 were Tier-1, super-spec rigs. 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 inthe United States as ofMarch 31, 2023 was approximately$890 million . Approximately 26% of the total contract drilling backlog inthe United States atMarch 31, 2023 is reasonably expected to remain atMarch 31, 2024 . See Note 2 of Notes to unaudited condensed consolidated financial statements for additional information on backlog.
Pressure Pumping
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As of March 31, 2023 , we had approximately 1.2 million horsepower in our
pressure pumping fleet. We provide pressure pumping services to oil and natural
gas operators primarily in Texas and the Appalachian region. Substantially all
of the revenue in the pressure pumping segment is from well stimulation
services, such as hydraulic fracturing, for completion of new wells and remedial
work on existing wells. We also provide cementing services through the pressure
pumping segment.
Directional Drilling
We provide a comprehensive suite of directional drilling services in most major
producing onshore oil and gas basins in the United States . Our directional
drilling services include directional drilling, measurement-while-drilling and
supply and rental of downhole performance motors. We also provide services that
improve the statistical accuracy of directional and horizontal wellbores.
Other Operations
Our oilfield rentals business, with a fleet of premium oilfield rental tools, along with the results of our ownership, as a non-operating working interest owner, in oil and gas assets located inTexas andNew Mexico , provide the largest revenue contributions to our other operations. Other operations also includes the results of our electrical controls and automation business and the results of our drilling equipment service business.
Results of Operations
The following tables summarize results of operations by business segment for the
three months ended
Three Months Ended
March 31, December 31,
Contract Drilling 2023 2022 % Change
(dollars in thousands)
Revenues $ 419,026 $ 399,402 4.9 %
Direct operating costs 230,358 232,142 (0.8 )%
Adjusted gross margin (1) 188,668 167,260 12.8 %
Selling, general and administrative 1,450 2,306 (37.1 )%
Depreciation, amortization and impairment 86,866 86,734 0.2 %
Other operating (income) expenses, net 22 (30 ) NA
Operating income $ 100,330 $ 78,250 28.2 %
Operating days - U.S. (2) 11,751 12,072 (2.7 )%
Average revenue per operating day - U.S. $ 34.76 $ 31.83 9.2 %
Average direct operating costs per operating day
- U.S. $ 18.88 $ 18.38 2.7 %
Average adjusted gross margin per operating day
- U.S. (3) $ 15.88 $ 13.45 18.1 %
Average rigs operating - U.S. (2) 131 131 (- )%
Capital expenditures $ 80,149 $ 86,195 (7.0 )%
(1)Adjusted gross margin is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross margin to adjusted gross margin by segment.
(2)
A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day. Average rigs operating is defined as operating days divided by the number of days in the period.
(3)
Average adjusted gross margin per operating day is defined as adjusted gross margin divided by operating days.
Generally, the revenues in our contract drilling segment are most impacted by two primary factors: our average number of rigs operating and our average revenue per operating day. Our average revenue per operating day is largely dependent on the pricing terms of our rig contracts. Revenues increased primarily due to improved pricing.
The decrease in capital expenditures was primarily due to the timing of order
placement and spending on committed deliveries that more heavily impacted the
fourth quarter of 2022.
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Three Months Ended
March 31, December 31,
Pressure Pumping 2023 2022 % Change
(dollars in thousands)
Revenues $ 293,268 $ 306,783 (4.4 )%
Direct operating costs 220,116 220,758 (0.3 )%
Adjusted gross margin (1) 73,152 86,025 (15.0 )%
Selling, general and administrative 2,695 2,465 9.3 %
Depreciation, amortization and impairment 26,025 24,918 4.4 %
Operating income $ 44,432 $ 58,642 (24.2 )%
Average active spreads (2) 12 12 (- )%
Fracturing jobs 147 142 3.5 %
Other jobs 153 157 (2.5 )%
Total jobs 300 299 0.3 %
Average revenue per fracturing job $ 1,959.10 $ 2,124.44 (7.8 )%
Average revenue per other job $ 34.51 $ 32.56 6.0 %
Average revenue per total job $ 977.56 $ 1,026.03 (4.7 )%
Average direct operating costs per total job $ 733.72 $ 738.32 (0.6 )%
Average adjusted gross margin per total job (3)
287.71 (15.2 )%
Adjusted gross margin as a percentage of revenues (3) 24.9 % 28.0 % (11.0 )%
Capital expenditures $ 21,425 $ 23,266 (7.9 )%
(1)Adjusted gross margin is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross margin to adjusted gross margin by segment.
(2)
Average active spreads is the average number of spreads that were crewed and actively marketed during the period.
(3)
Average adjusted gross margin per total job is defined as adjusted gross margin divided by total jobs. Adjusted gross margin as a percentage of revenues is defined as adjusted gross margin divided by revenues.
Generally, the revenues in our pressure pumping segment are most impacted by the number and design of fracturing jobs (including whether or not we provide proppant and other materials). Direct operating costs are also most impacted by these same factors. Our average revenue per fracturing job is largely dependent on the pricing terms of our pressure pumping contracts and the design of the jobs.
Revenues decreased primarily due to lower utilization.
Three Months Ended
March 31, December 31,
Directional Drilling 2023 2022 % Change
(dollars in thousands)
Revenues $ 56,263 $ 59,468 (5.4 )%
Direct operating costs 48,046 48,298 (0.5 )%
Adjusted gross margin (1) 8,217 11,170 (26.4 )%
Selling, general and administrative 1,938 1,733 11.8 %
Depreciation, amortization and impairment 4,171 4,169 0.0 %
Operating income $ 2,108 $ 5,268 (60.0 )%
Capital expenditures $ 9,074 $ 4,486 102.3 %
(1)Adjusted gross margin is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross margin to adjusted gross margin by segment.
Revenue decreased due to decreased job activity. We averaged 41 jobs per day
during the three months ended
The increase in capital expenditures was primarily due the purchase of rotary steerable system tools and the timing of order placement that more heavily impacted the first quarter of 2023.
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Three Months Ended
March 31, December 31,
Other Operations 2023 2022 % Change
(dollars in thousands)
Revenues $ 23,245 $ 22,823 1.8 %
Direct operating costs 14,139 14,619 (3.3 )%
Adjusted gross margin (1) 9,106 8,204 11.0 %
Selling, general and administrative 692 806 (14.1 )%
Depreciation, depletion, amortization and
impairment 7,579 6,259 21.1 %
Operating income $ 835 $ 1,139 (26.7 )%
Capital expenditures $ 5,279 $ 5,647 (6.5 )%
(1)
Adjusted gross margin is defined as revenues less direct operating costs
(excluding depreciation, depletion, amortization and impairment expense). See
Non-GAAP Financial Measures below for a reconciliation of GAAP gross margin to
adjusted gross margin by segment.
Other operations revenue increased primarily due to a $1.6 million increase in
our oilfield rentals business revenues, which was offset by a $1.0 million
decline in oil and natural gas revenues primarily as a result of lower crude oil
and natural gas market prices. The average WTI-Cushing price for the first
quarter of 2023 was $76.08 per barrel as compared to $82.79 per barrel in the
fourth quarter of 2022. Natural gas prices (based on the Henry Hub Spot Market
Price) averaged $2.65 per MMBtu in the first quarter of 2023 as compared to
$5.55 per MMBtu in the fourth quarter of 2022.
Depreciation, depletion, amortization and impairment increased primarily due to
a $2.0 million impairment in our oil and natural gas business recorded in the
first quarter of 2023 as compared to a $0.8 million impairment recorded in the
fourth quarter of 2022.
Three Months Ended
March 31, December 31,
Corporate 2023 2022 % Change
(dollars in thousands)
Selling, general and administrative
(12.7 )% Depreciation$ 3,539 $ 1,224 189.1 % Other operating (income) expenses, net Net gain on asset disposals$ 538 $ (1,517 )
NA
Legal-related expenses and settlements 38 (546 ) NA Research and development 136 250 (45.6 )% Other (6,300 ) (184 ) 3,323.9 % Other operating (income) expenses, net$ (5,588 ) $ (1,997 ) 179.8 % Interest income$ 1,240 $ 273 354.2 % Interest expense$ 8,826 $ 8,058 9.5 % Other income (expense)$ 1,486 $ (629 ) NA Capital expenditures$ 1,674 $ (350 ) NA Selling, general and administrative expense decreased primarily due to the fair value remeasurements of the phantom unit awards. See Note 10 of Notes to unaudited condensed consolidated financial statements for additional information on phantom unit awards. Other operating (income) expenses, net includes net losses associated with the disposal of assets. Accordingly, the related gains or losses have been excluded from the results of specific segments. Other operating (income) expenses, net increased due to a$6.5 million reversal of cumulative compensation costs associated with certain performance-based restricted stock units.
The
Income Taxes
Our effective income tax rate fluctuates from theU.S. statutory tax rate based on, among other factors, changes in pretax income in jurisdictions with varying statutory tax rates, the impact ofU.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. 26 -------------------------------------------------------------------------------- Our effective income tax rate for the three months endedMarch 31, 2023 was 16.8%, compared with 7.7% for the three months endedDecember 31, 2022 . The change in our effective income tax rate for the three months endedMarch 31, 2023 compared toDecember 31, 2022 , was primarily attributable to the impact of valuation allowances on deferred tax assets. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized, and when necessary, valuation allowances are provided. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. We assess the realizability of our deferred tax assets quarterly and consider carryback availability, the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. In the first quarter of 2023, the effective tax rate takes into consideration the estimated valuation allowance based on forecasted 2023 income. We continue to monitor income tax developments inthe 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 revolving credit facility and cash provided by operating activities. As ofMarch 31, 2023 , we had approximately$293 million in working capital, including$157 million of cash and cash equivalents, and$600 million available under our revolving credit facility. Our Credit Agreement is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to$600 million , including a letter of credit facility that, at any time outstanding, is limited to$100 million and a swing line facility that, at any time outstanding, is limited to the lesser of$50 million and the amount of the swing line provider's unused commitment. As ofMarch 31, 2023 , we had no borrowings outstanding under our revolving credit facility, and no letters of credit outstanding under the Credit Agreement and, as a result, had available borrowing capacity of approximately$600 million at that date. Of the revolving credit commitments,$50 million expires onMarch 27, 2024 ,$133.3 million expires onMarch 27, 2025 , and the remaining$416.7 million expires onMarch 27, 2026 . Subject to customary conditions, we may request that the lenders' aggregate commitments be increased by up to$300 million , not to exceed total commitments of$900 million . Additionally, we have the option, subject to certain conditions, to exercise one one-year extension of the maturity date. Loans under the Credit Agreement bear interest by reference, at our election, to the SOFR rate or base rate, as described in "Item 3" below. If our credit rating is below investment grade at both Moody's and S&P, we will become subject to a restricted payment covenant. The Credit Agreement also contains a financial covenant that requires our total debt to capitalization ratio, expressed as a percentage, not exceed 50%. We also have a Reimbursement Agreement (the "Reimbursement Agreement") with The Bank of Nova Scotia ("Scotiabank"), pursuant to which we may from time to time request that Scotiabank issue an unspecified amount of letters of credit. Under the terms of the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any letters of credit. Fees, charges and other reasonable expenses for the issuance of letters of credit are payable by us at the time of issuance at such rates and amounts as are in accordance with Scotiabank's prevailing practice. We are obligated to pay to Scotiabank interest on all amounts not paid by us on the date of demand or when otherwise due at the LIBOR rate plus 2.25% per annum. A letter of credit fee is payable by us equal to 1.50% times the amount of outstanding letters of credit. We had$65.0 million of outstanding letters of credit atMarch 31, 2023 , which was comprised of$65.0 million outstanding under the Reimbursement Agreement and no amounts outstanding under the Credit Agreement. 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. These letters of credit expire annually at various times during the year and are typically renewed. As ofMarch 31, 2023 , no amounts had been drawn under the letters of credit. Our outstanding long-term debt atMarch 31, 2023 was$827 million and consisted of$482 million of our 2028 Notes and$345 million of our 2029 Notes. We were in compliance with all covenants under the associated indentures atMarch 31, 2023 . For a full description of the Credit Agreement, the Reimbursement Agreement, the 2028 Notes and the 2029 Notes, please see Note 7 of Notes to unaudited condensed consolidated financial statements. 27 --------------------------------------------------------------------------------
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 and pay cash dividends for at least the next 12 months. If we pursue opportunities for growth 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. A portion of our capital expenditures can be adjusted and managed by us to match market demand and activity levels. With the recent slowdown in market activity, we have lowered our 2023 capital expenditure forecast from$550 million to$510 million , including approximately$30 million of customer-funded rig upgrades.
The majority of these expenditures are expected to be used for normal, recurring items necessary to support our business.
During the three months ended
•
•
During the three months ended
•
$118 million to make capital expenditures for the betterment and refurbishment of drilling and pressure pumping equipment and, to a much lesser extent, equipment for our other businesses, to acquire and procure equipment to support our contract drilling, pressure pumping, directional drilling, oilfield rentals and manufacturing operations, and to fund investments in oil and natural gas properties on a non-operating working interest basis,
•
•
•
•
We paid cash dividends during the three months ended
Per Share Total
(in thousands)
Paid on March 16, 2023 $ 0.08 $ 16,916
On April 26, 2023 , 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 15, 2023 to holders of
record as of June 1, 2023 . 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 in order
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
October 2022 , our Board of Directors approved an increase of the authorization
under the stock buyback program to allow for an aggregate of $300 million 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, 2023 , we
had remaining authorization to purchase approximately $169 million of our
outstanding common stock under the stock buyback program. Shares of
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stock purchased under the buyback program are held as treasury shares. On April
26, 2023 , our Board of Directors approved another increase of the authorization
under the stock buyback program to allow for an aggregate of $300 million of
future share repurchases.
Shares Cost
94,387,839 $ 1,527,386
Commitments - As of March 31, 2023 , we had commitments to purchase major
equipment totaling approximately $129 million for our drilling, pressure
pumping, directional drilling and oilfield rentals businesses. Our pressure
pumping business has entered into agreements to purchase minimum quantities of
proppants and chemicals from certain vendors. As of March 31, 2023 , the
remaining minimum obligation under these agreements was approximately $17.5
million , of which approximately $14.5 million and $3.0 million relate to the
remainder of 2023 and 2024, respectively.
See Note 8 of Notes to unaudited condensed consolidated financial statements for
additional information on our current commitments and contingencies as of March
31, 2023 .
Operating lease liabilities totaled $23.4 million at March 31, 2023 . There have
been no material changes to our operating lease liabilities since December 31,
2022 .
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 plus income tax expense, net interest expense, and depreciation,
depletion, amortization and impairment 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 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. 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.
Three Months Ended
March 31, December 31,
2023 2022
(in thousands)
Net income $ 99,678 $ 100,097
Income tax expense 20,185 8,294
Net interest expense 7,586 7,785
Depreciation, depletion, amortization and impairment 128,180 123,304
Adjusted EBITDA $ 255,629 $ 239,480
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Adjusted Gross Margin
We define "Adjusted gross margin" as revenues less direct operating costs (excluding depreciation, depletion, amortization and impairment expense). Adjusted gross margin is included as a supplemental disclosure because it is a useful indicator of our operating performance.
Contract Pressure Directional
Drilling Pumping Drilling Other Operations
(in thousands)
For the three months ended March 31,
2023
Revenues $ 419,026 $ 293,268 $ 56,263 $ 23,245
Less direct operating costs (230,358 ) (220,116 ) (48,046 ) (14,139 )
Less depreciation, depletion,
amortization and impairment (86,866 ) (26,025 ) (4,171 ) (7,579 )
GAAP gross margin 101,802 47,127 4,046 1,527
Depreciation, depletion, amortization
and impairment 86,866 26,025 4,171 7,579
Adjusted gross margin $ 188,668 $ 73,152 $ 8,217 $ 9,106
For the three months ended December 31,
2022
Revenues $ 399,402 $ 306,783 $ 59,468 $ 22,823
Less direct operating costs (232,142 ) (220,758 ) (48,298 ) (14,619 )
Less depreciation, depletion,
amortization and impairment (86,734 ) (24,918 ) (4,169 ) (6,259 )
GAAP gross margin 80,526 61,107 7,001 1,945
Depreciation, depletion, amortization
and impairment 86,734 24,918 4,169 6,259
Adjusted gross margin $ 167,260 $ 86,025 $ 11,170 $ 8,204
Critical Accounting Estimates
Our consolidated financial statements are impacted by certain estimates and
assumptions made by management. A detailed discussion of our critical accounting
estimates is included in our Annual Report on Form 10-K for the fiscal year
ended December 31, 2022 . There have been no material changes in these critical
accounting estimates.
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 revenue, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and expectations about future prices. Crude oil prices and demand for drilling and completions equipment and services increased in 2022, and industry supply of Tier-1, super-spec rigs remains constrained. We currently expect our average rig count to be down two to three rigs in the second quarter as activity transitions more to oil from natural gas. The current demand for equipment and services remains dependent on macro conditions, including commodity prices, geopolitical environment, inflationary pressures, economic conditions inthe United States and elsewhere and continued focus by exploration and production companies and service companies on capital discipline. Oil prices averaged$76.08 per barrel in the first quarter of 2023, as compared to$82.79 per barrel in the fourth quarter of 2022. Natural gas prices (based on the Henry Hub Spot Market Price) averaged$2.65 per MMBtu in the first quarter of 2023 as compared to an average of$5.55 per MMBtu in the fourth quarter of 2022. In light of these and other factors, we expect oil and natural gas prices to continue to be volatile 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 sources of 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 30 --------------------------------------------------------------------------------
or reduce their levels of capital expenditures for exploration and production for a variety of reasons, which could reduce demand for our services.
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