PATTERSON-UTI ENERGY, INC. Management Overview - We are a
Our contract drilling business operates in the continental
Reduced demand for crude oil and refined products related to the COVID-19
pandemic, combined with production increases from OPEC+, has led to a
significant reduction in crude oil prices and demand for drilling and completion
services in
Oil prices remain extremely volatile, as the closing price of oil (WTI-Cushing)
reached a first quarter 2020 high of
Our average active rig count for the first quarter of 2020 was 123 rigs, which
included 123 rigs operating in
Due to the downturn in completions activity in March, we ended the first quarter with five active pressure pumping spreads compared to 11 at the end of the fourth quarter. We expect to average approximately four active spreads in the second quarter. We have scaled our pressure pumping business for the operation of four spreads in 2020, while still preserving growth potential for a future improved market. We intend for our pressure pumping business to generate positive Adjusted EBITDA and cash flow for the last two quarters of 2020.
In response to the significant reduction in crude oil prices and the resulting
fall in demand for drilling and completion services in
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, such as now, when oil and natural gas prices deteriorate 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. 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. Currently, there is an excess supply of drilling rigs, pressure pumping equipment and directional drilling equipment. 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.
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We are highly impacted by operational risks, competition, labor issues, weather,
the availability 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
"Risk Factors" included in Part II, Item 1A of this Report and Item 1A of our
Annual Report on Form 10-K for the fiscal year ended
For the three months ended
Three Months Ended March 31,
2020 2019
Contract drilling
$ 445,927 100.0 %$ 704,171 100.0 % Contract Drilling
Contract drilling revenues accounted for 60.0% of our consolidated first quarter 2020 revenues and decreased 28.2% from the comparable 2019 period.
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 during the last several years. The
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 as of
Ongoing factors which could continue to adversely affect utilization rates and pricing, even in an environment of high oil and natural gas prices and increased drilling activity, include:
• movement of drilling rigs from region to region,
• reactivation of drilling rigs,
• refurbishment and upgrades of existing drilling rigs,
• development of new technologies that enhance drilling efficiency, and
• construction of new technology drilling rigs.
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Pressure Pumping
Pressure pumping revenues accounted for 28.1% of our consolidated first quarter
2020 revenues and decreased 49.5% from the comparable 2019 period. As of
Directional Drilling
Directional drilling revenues accounted for 7.7% of our consolidated first
quarter 2020 revenues and decreased 34.9% from the comparable 2019 period. We
provide a comprehensive suite of directional drilling services in most major
producing onshore oil and gas basins in
Other Operations
Other operations revenues accounted for 4.2% of our consolidated first quarter
2020 revenues and decreased 39.2% from the comparable 2019 period. Our oilfield
rentals business, with a fleet of premium oilfield rental tools, provides the
largest revenue contribution to our other operations and provides specialized
services for land-based oil and natural gas drilling, completion and workover
activities. Other operations also includes the results of our electrical
controls and automation business, the results of our drilling equipment service
business, and the results of our ownership, as a non-operating working interest
owner, in oil and natural gas assets that are primarily located in
For the three months ended
Three Months Ended March 31,
2020 2019
Contract drilling $ (404,018 ) $ 21,217
Pressure pumping (35,486 ) (18,768 )
Directional drilling (10,595 ) (5,667 )
Other operations (18,771 ) (5,204 )
Corporate (25,540 ) (14,961 )
$ (494,410 ) $ (23,383 ) Additional discussion of our operating revenues and operating loss follows in the "Results of Operations" section.
Our consolidated net loss for the first quarter of 2020 was
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Results of Operations
The following tables summarize results of operations by business segment for the
three months ended
Contract Drilling 2020 2019 % Change
(dollars in thousands)
Revenues $ 267,364 $ 372,392 (28.2 )%
Direct operating costs 163,420 219,202 (25.4 )%
Margin (1) 103,944 153,190 (32.1 )%
Selling, general and administrative 1,464 1,656 (11.6 )%
Depreciation, amortization and impairment 111,438 130,317 (14.5 )%
Impairment of goodwill 395,060 - NA
Operating income (loss) $ (404,018 ) $ 21,217 NA
Operating days (2) 11,235 15,787 (28.8 )%
Average revenue per operating day $ 23.80 $ 23.59 0.9 %
Average direct operating costs per operating day $ 14.55 $ 13.88 4.8 %
Average margin per operating day (1) $ 9.25 $ 9.70 (4.7 )%
Average rigs operating 123 175 (29.6 )%
Capital expenditures $ 49,445 $ 75,725 (34.7 )%
(1) Margin is defined as revenues less direct operating costs and excludes
depreciation, amortization and impairment and selling, general and
administrative expenses. Average margin per operating day is defined as
margin divided by operating days.
(2) A rig is considered to be operating if it is earning revenue pursuant to a
contract on a given day.
Generally, the revenues in our contract drilling segment are most impacted by two primary factors: our average number of rigs operating and our average revenue per operating day. During the first quarter of 2020, our average number of rigs operating was 123, compared to 175 in the first quarter of 2019. Our average revenue per operating day is largely dependent on the pricing terms of our rig contracts.
Revenues and direct operating costs decreased primarily due to a decrease in operating days. Average direct operating costs per operating day increased slightly due primarily to lower fixed cost absorption with the decrease in operating days.
Depreciation, amortization and impairment expense decreased primarily due to the retirement of 36 legacy non-APEX® drilling rigs and related equipment in the third quarter of 2019, which resulted in no depreciation expense being recorded for this equipment in 2020.
All of the goodwill associated with our contract drilling reporting unit was
impaired during the three months ended
The decrease in capital expenditures was primarily due to higher maintenance capital expenditures in the first quarter of 2019 when activity levels were higher.
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Pressure Pumping 2020 2019 % Change
(dollars in thousands)
Revenues $ 125,107 $ 247,601 (49.5 )%
Direct operating costs 114,855 202,748 (43.4 )%
Margin (1) 10,252 44,853 (77.1 )%
Selling, general and administrative 3,067 3,486 (12.0 )%
Depreciation, amortization and impairment 42,671 60,135 (29.0 )%
Operating loss $ (35,486 ) $ (18,768 ) 89.1 %
Fracturing jobs 89 164 (45.7 )%
Other jobs 209 263 (20.5 )%
Total jobs 298 427 (30.2 )%
Average revenue per fracturing job $ 1,359.39 $ 1,476.55 (7.9 )%
Average revenue per other job $ 19.72 $ 20.71 (4.8 )%
Average revenue per total job $ 419.82 $ 579.86 (27.6 )%
Average direct operating costs per total job $ 385.42 $ 474.82 (18.8 )%
Average margin per total job (1) $ 34.40 $ 105.04 (67.2 )%
Margin as a percentage of revenues (1) 8.2 % 18.1 % (54.7 )%
Capital expenditures $ 14,280 $ 31,400 (54.5 )%
(1) Margin is defined as revenues less direct operating costs and excludes
depreciation, amortization and impairment and selling, general and
administrative expenses. Average margin per total job is defined as margin
divided by total jobs. Margin as a percentage of revenues is defined as
margin divided by revenues.
Generally, the revenues in our pressure pumping segment are most impacted by our
number of fracturing jobs and the size (including whether or not we provide
proppant and other materials) of those jobs, which is reflected in our average
revenue per fracturing job. 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. We completed 89
fracturing jobs during the first quarter of 2020, compared to 164 fracturing
jobs in the first quarter of 2019. Our average revenue per fracturing job was
Revenues and direct operating costs decreased primarily due to a decline in the number of fracturing jobs. Average revenue and direct operating costs per job were impacted by lower demand, more customers self-sourcing products and decreases in product prices.
Selling, general and administrative expenses decreased primarily as a result of cost reduction efforts.
Depreciation, amortization and impairment expense decreased primarily due to the write-down of pressure pumping equipment in the third quarter of 2019, which resulted in no depreciation expense being recorded for this equipment in the first quarter of 2020.
The decrease in capital expenditures was primarily due to higher maintenance
capital expenditures in the first quarter of 2019 when activity levels were
higher.
Directional Drilling 2020 2019 % Change
(dollars in thousands)
Revenues $ 34,485 $ 52,959 (34.9 )%
Direct operating costs 32,329 45,602 (29.1 )%
Margin (1) 2,156 7,357 (70.7 )%
Selling, general and administrative 2,330 2,657 (12.3 )%
Depreciation, amortization, and impairment 10,421 10,367 0.5 %
Operating loss $ (10,595 ) $ (5,667 ) 87.0 %
Capital expenditures $ 2,008 $ 2,112 (4.9 )%
(1) Margin is defined as revenues less direct operating costs and excludes
depreciation, amortization and impairment and selling, general and
administrative expenses.
Directional drilling revenue decreased by
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Directional drilling direct operating costs decreased by
Selling, general and administrative expenses decreased primarily as a result of
cost reduction efforts.
Other Operations 2020 2019 % Change
(dollars in thousands)
Revenues $ 18,971 $ 31,219 (39.2 )%
Direct operating costs 16,024 21,773 (26.4 )%
Margin (1) 2,947 9,446 (68.8 )%
Selling, general and administrative 1,459 2,862 (49.0 )%
Depreciation, depletion, amortization and
impairment 20,259 11,788 71.9 %
Operating loss $ (18,771 ) $ (5,204 ) 260.7 %
Capital expenditures $ 5,264 $ 7,773 (32.3 )%
(1) Margin is defined as revenues less direct operating costs and excludes
depreciation, depletion, amortization and impairment and selling, general and
administrative expenses.
Other operations revenue decreased by
Other operations direct operating costs decreased by
Selling, general and administrative expense decreased primarily as a result of cost reduction efforts.
Depreciation, depletion, amortization and impairment increased over the
comparable prior year period primarily due to a
The decrease in capital expenditures was primarily due to higher maintenance
capital expenditures in the first quarter of 2019 when activity levels were
higher.
Corporate 2020 2019 % Change
(dollars in thousands)
Selling, general and administrative $ 22,026 $ 21,894 0.6 %
Depreciation $ 2,008 $ 1,803 11.4 %
Other operating expenses (income), net
Net gain on asset disposals $ (1,239 ) $ (6,545 ) (81.1 )%
Legal-related expenses and settlements, net
of insurance reimbursements 800 (3,471 ) NA
Research and development 895 1,355 (33.9 )%
Other (5 ) (75 ) (93.3 )%
Other operating expenses (income), net $ 451 $ (8,736 ) NA
Credit loss expense $ 1,055 $ - NA
Interest income $ 657 $ 1,032 (36.3 )%
Interest expense $ 11,224 $ 12,984 (13.6 )%
Other income $ 85 $ 117 (27.4 )%
Capital expenditures $ 931 $ 1,331 (30.1 )%
Other operating expenses (income), net includes net gains associated with the disposal of assets. Accordingly, the related gains or losses have been excluded from the results of specific segments. The majority of the net gain on asset disposals during 2019 reflect gains on disposal of drilling equipment. Legal-related expenses and settlements in 2019 includes proceeds from insurance claims.
A provision for credit losses was recognized in the first quarter of 2020 with respect to accounts receivable balances that are estimated to be uncollectible.
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Interest expense was lower in the first quarter of 2020 due to the repayment of long-term debt in the third quarter of 2019.
Income Taxes
Our effective income tax rate fluctuates from the
Our effective income tax rate for the three months ended
We continue to monitor income tax developments in
Liquidity and Capital Resources
In response to the significant reduction in crude oil prices and the resulting
fall in demand for drilling and completion services in
Our liquidity as of
On
On
On
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
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additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.
During the three months ended
•$73.3 million from operating activities, and •$4.3 million in proceeds from the disposal of property and equipment.
During the three months ended
• to make capital expenditures for the acquisition, 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 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 19, 2020 $ 0.04 $ 7,629
On
On
Shares Cost
Treasury shares at beginning of period 77,336,387 $ 1,345,134
Purchases pursuant to stock buyback program 5,826,266 20,000
Acquisitions pursuant to long-term incentive plan (1) 3,139 25
Treasury shares at end of period 83,165,792 $ 1,365,159 (1) We withheld 3,139 shares during the first quarter of 2020 with respect to
employees' tax withholding obligations upon the vesting of restricted stock.
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, and not pursuant to the stock
buyback program.
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2019 Term Loan Agreement - On
The Term Loan Agreement is a committed senior unsecured term loan facility that
permits a single borrowing of up to
Loans under the Term Loan Agreement bear interest by reference, at our election,
to the LIBOR rate or base rate. The applicable margin on LIBOR rate loans varies
from 1.00% to 1.375%, and the applicable margin on base rate loans varies from
0.00% to 0.375%, in each case determined based upon our credit rating. As of
The Term Loan 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 incur debt and grant liens. 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 require us to have a Pro Forma Debt Service Coverage Ratio (as defined in the Term Loan 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 one of the two ratings agencies.
The Term Loan Agreement requires mandatory prepayment in an amount equal to 100%
of the net cash proceeds from the issuance of new senior indebtedness (other
than certain permitted indebtedness) if our credit rating is below investment
grade at both Moody's and S&P. Our credit rating is currently investment grade
at one of the two ratings agencies. The Term Loan Agreement also requires that
our total debt to capitalization ratio, expressed as a percentage, not exceed
50%. The Term Loan 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
As of
Credit Agreement - On
The Credit Agreement is a committed senior unsecured revolving credit facility
that permits aggregate borrowings of up to
Loans under the Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base rate. The applicable margin on LIBOR rate loans varies from 1.00% to 2.00% and the applicable margin on base rate loans varies from 0.00% to 1.00%, in each case determined based upon our credit rating. A letter of credit fee is payable by us equal to the applicable margin for LIBOR 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 0.10% to 0.30% based on our credit rating.
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None of our subsidiaries are currently required to be a guarantor under the Credit Agreement. However, if any subsidiary guarantees or incurs debt in excess of the Priority Debt Basket (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 incur debt and grant
liens. 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 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 one of the two
ratings agencies. The Credit Agreement also requires that our total debt to
capitalization ratio, expressed as a percentage, not exceed 50%. 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
As of
2015 Reimbursement Agreement - On
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, 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.
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
2028 Senior Notes and 2029 Senior Notes - On
We pay interest on the 2028 Notes on
We pay interest on the 2029 Notes on
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The 2028 Notes and 2029 Notes (together, the "Senior Notes") are our senior unsecured obligations, which rank equally with all of our other existing and future senior unsecured debt and will rank senior in right of payment to all of our other future subordinated debt. The Senior Notes will be effectively subordinated to any of our future secured debt to the extent of the value of the assets securing such debt. In addition, the Senior Notes will be structurally subordinated to the liabilities (including trade payables) of our subsidiaries that do not guarantee the Senior Notes. None of our subsidiaries are currently required to be a guarantor under the Senior Notes. If our subsidiaries guarantee the Senior Notes in the future, such guarantees (the "Guarantees") will rank equally in right of payment with all of the guarantors' future unsecured senior debt and senior in right of payment to all of the guarantors' future subordinated debt. The Guarantees will be effectively subordinated to any of the guarantors' future secured debt to the extent of the value of the assets securing such debt.
We, at our option, may redeem the Senior Notes in whole or in part, at any time
or from time to time at a redemption price equal to 100% of the principal amount
of such Senior Notes to be redeemed, plus accrued and unpaid interest, if any,
on those Senior Notes to the redemption date, plus a "make-whole" premium.
Additionally, commencing on
The indentures pursuant to which the Senior Notes were issued include covenants that, among other things, limit our and our subsidiaries' ability to incur certain liens, engage in sale and lease-back transactions or consolidate, merge, or transfer all or substantially all of their assets. These covenants are subject to important qualifications and limitations set forth in the indentures.
Upon the occurrence of a change of control triggering event, as defined in the indentures, each holder of the Senior Notes may require us to purchase all or a portion of such holder's Senior Notes at a price equal to 101% of their principal amount, plus accrued and unpaid interest, if any, to, but excluding, the repurchase date.
The indentures also provide for events of default which, if any of them occurs, would permit or require the principal of, premium, if any, and accrued interest, if any, on the Senior Notes to become or to be declared due and payable.
Commitments- As of
As of
Our pressure pumping business has entered into agreements to purchase minimum
quantities of proppants and chemicals from certain vendors. The agreements
expire in years 2020 through 2023. As of
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.
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Adjusted EBITDA
Adjusted earnings before interest, taxes, depreciation and amortization
("Adjusted EBITDA") is not defined by accounting principles generally accepted
in
Three Months Ended
March 31,
2020 2019
(in thousands)
Net loss $ (434,722 ) $ (28,614 )
Income tax benefit (70,170 ) (6,604 )
Net interest expense 10,567 11,952
Depreciation, depletion, amortization and impairment 186,797 214,410
Impairment of goodwill 395,060 -
Adjusted EBITDA $ 87,532 $ 191,144
Critical Accounting Policies
In addition to established accounting policies, our consolidated financial statements are impacted by certain estimates and assumptions made by management. The following is a discussion of our critical accounting policies pertaining to property and equipment, goodwill, revenue recognition and the use of estimates.
Property and equipment - Property and equipment, including betterments that extend the useful life of the asset, are stated at cost. Maintenance and repairs are charged to expense when incurred. We provide for the depreciation of our property and equipment using the straight-line method over the estimated useful lives. Our method of depreciation does not change when equipment becomes idle; we continue to depreciate idled equipment on a straight-line basis. No provision for salvage value is considered in determining depreciation of our property and equipment.
We review our long-lived assets, including property and equipment, 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 future cash flows over the life of the respective assets or asset groupings in our assessment of impairment. These estimates of cash flows are based on historical cyclical trends in the industry as well as our expectations regarding the continuation of these trends in the future. Provisions for asset impairment are charged against income when estimated future cash flows, on an undiscounted basis, are less than the asset's net book value. Any provision for impairment is measured at fair value.
2020 Triggering Event Assessment - Due to the recent decline in the market price
of our common stock and commodity prices we lowered our expectations with
respect to future activity levels in certain of our operating segments. We
deemed it necessary to assess the recoverability of our contract drilling,
pressure pumping, directional drilling and oilfield rentals asset groups as of
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For the assessment performed as of
All of these factors are beyond our control. If the lower oil price environment experienced in 2020 were to last into late 2022 and beyond, our actual cash flows would likely be less than the expected cash flows used in these assessments and could result in impairment charges in the future, and such impairment charges could be material.
Due to the recent decline in the market price of our common stock and commodity
prices we lowered our expectations with respect to future activity levels in our
contract drilling reporting unit. We performed a quantitative impairment
assessment of our goodwill as of
Based on the results of the goodwill impairment test as of
Use of estimates - The preparation of financial statements in conformity with
Key estimates used by management include:
• allowance for doubtful accounts, • depreciation, depletion and amortization, • fair values of assets acquired and liabilities assumed in acquisitions, • goodwill and long-lived asset impairments, and • reserves for self-insured levels of insurance coverage.
For additional information on our accounting policies, see Note 1 of Notes to unaudited condensed consolidated financial statements included as a part of this Report.
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Recently Issued Accounting Standards
See Note 1 to our unaudited condensed consolidated financial statements for a discussion 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. For many
years, oil and natural gas prices and markets have been extremely volatile.
Prices are affected by many factors beyond our control. Oil prices remain
extremely volatile, as the closing price of oil (WTI-Cushing) reached a first
quarter 2020 high of
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, 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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