PATTERSON-UTI ENERGY, INC. Management Overview - We are a
Our contract drilling business operates in the continentalUnited States 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 horizontal wellbore placement. 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 .
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$63.27 per barrel onJanuary 6, 2020 , declined to negative$36.98 per barrel onApril 20, 2020 , and closed at$40.83 per barrel onJuly 20, 2020 . In response to the rapid decline in commodity prices, E&P companies acted swiftly to reduce drilling and completion activity starting late in the first quarter. Our average active rig count for the second quarter of 2020 was 82 rigs. This was a decrease from our average active rig count of 123 rigs for the first quarter of 2020. Our rig count started to decline late in the first quarter and has continued to decline through the end of the second quarter. We expect our average rig count for the third quarter will be 59 rigs. Based on contracts currently in place, we expect an average of 51 rigs operating under term contracts (contracts with a duration of six months or more) during the third quarter of 2020 and an average of 38 rigs operating under term contracts during the twelve months endingJune 30, 2021 . Due to the downturn in completions activity since March, we averaged four active pressure pumping spreads during the second quarter compared to an average of ten active spreads during the first quarter. We have scaled our pressure pumping business for the reduced level of activity. We intend for our pressure pumping business to generate positive Adjusted EBITDA and cash flow for the last six months of 2020. During the three months endedJune 30, 2020 , we implemented a restructuring plan to improve operating margins, achieve operational efficiencies and reduce indirect support costs. The restructuring included workforce reductions, changes to management structure and facility consolidations and closures. We recorded$38.3 million of charges associated with this plan in the three and six months endedJune 30, 2020 . There were no restructuring charges in the comparable periods of 2019. We anticipate completing the restructuring plan during the third quarter of 2020 and do not expect to incur significant additional expenses related to the plan. In particular with our pressure pumping business, we believe these restructuring changes are structural and will result in significant cost savings. The restructuring charges during the three and six months endedJune 30, 2020 consisted of the following, as further described in Note 16 of Notes to unaudited condensed consolidated financial statements:
The following table presents restructuring expenses by reportable segment for
the three and six months ended
Contract Pressure Directional
drilling pumping drilling Other operations Corporate Total
Severance costs $ 1,821 $ 3,460 $ 503 $ 501 $ 215 $ 6,500
Contract termination costs - 20,373 - - - 20,373
Other exit costs 523 194 827 - - 1,544
ROU asset abandonments 86 7,304 1,845 - 686 9,921
Total $ 2,430 $ 31,331 $ 3,175 $ 501 $ 901 $ 38,338
We estimate that the 2020 restructuring plan will result in annual cost savings
of approximately $94 million , beginning in the third quarter of 2020. Of these
estimated annual cost savings, approximately $14 million , $43 million , $7
million and $8 million are attributable to operating expense savings for
contract drilling, pressure pumping, directional drilling and other operations,
respectively. Annual selling, general and administrative cost savings are
estimated to be approximately $22 million .
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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.
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 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, including as a result of the COVID-19 pandemic. 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 December 31, 2019 .
For the three and six months ended
Three Months Ended June 30, Six Months Ended June 30,
2020 2019 2020 2019
Contract drilling
59,533 23.8 % 251,008 37.2 % 184,640 26.5 % 498,609 36.1 %
Directional drilling 11,742 4.7 % 50,218 7.4 % 46,227 6.6 % 103,177 7.5 %
Other operations 7,971 3.2 % 26,401 3.9 % 26,942 3.9 % 57,620 4.2 %
$ 250,380 100.0 % $ 675,765 100.0 % $ 696,307 100.0 % $ 1,379,936 100.0 %
Contract Drilling
Contract drilling revenues accounted for 68.3% of our consolidated second quarter 2020 revenues and decreased 50.8% 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. TheU.S. land rig industry refers to certain high specification rigs as "super-spec" rigs. We consider a super-spec rig to be 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. As ofJune 30, 2020 , our rig fleet included 198 APEX® rigs, of which 150 were 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 as ofJune 30, 2020 was approximately$334 million . Approximately 24% of the total contract drilling backlog atJune 30, 2020 is reasonably expected to remain atJune 30, 2021 . We generally calculate our backlog by multiplying the dayrate under our term drilling contracts by the number of days remaining under the contract. The calculation does not include any revenues related to fees for other services such as for mobilization, other than initial mobilization, demobilization and customer reimbursables, nor does it include potential reductions in rates for unscheduled standby or during periods in which the rig is moving or incurring maintenance and repair time in excess of what is permitted under the drilling contract. For contracts that contain variable dayrate pricing, our backlog calculation uses the dayrate in effect for periods where the dayrate is fixed, and, for periods that remain subject to variable pricing, uses the commodity price in effect atJune 30, 2020 . In addition, our term drilling contracts are generally subject to termination by the customer on short notice and provide for an early termination payment to us in the event that the contract is terminated by the customer. For contracts on which we have received notice for the rig to be placed on standby, our backlog calculation uses the standby rate for the period over which we expect to receive the standby rate. For contracts on which we have received an early termination notice, our backlog calculation includes the early termination rate, instead of the dayrate, for the period over which we expect to receive the lower rate. 29
-------------------------------------------------------------------------------- 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. Pressure Pumping Pressure pumping revenues accounted for 23.8% of our consolidated second quarter 2020 revenues and decreased 76.3% from the comparable 2019 period. As ofJune 30, 2020 , we had approximately 1.3 million horsepower in our pressure pumping fleet. The pressure pumping market remains oversupplied. In response to oversupplied market conditions, we started implementing changes to further streamline our operations, improve our efficiencies, and reduce our overall cost structure, while maintaining our customer service levels. Directional Drilling Directional drilling revenues accounted for 4.7% of our consolidated second quarter 2020 revenues and decreased 76.6% from the comparable 2019 period. We provide a comprehensive suite of directional drilling services in most major producing onshore oil and gas basins inthe United States . Our directional drilling services include directional drilling, downhole performance motors, measurement-while-drilling, and wireline steering tools, and we provide services that improve the statistical accuracy of horizontal wellbore placement. Other Operations Other operations revenues accounted for 3.2% of our consolidated second quarter 2020 revenues and decreased 69.8% 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 inTexas andNew Mexico .
For the three and six months ended
Six Months Ended
Three Months Ended June 30, June 30,
2020 2019 2020 2019
Contract drilling $ (30,742 ) $ 16,494 $ (434,760 ) $ 37,711
Pressure pumping (68,554 ) (14,408 ) (104,040 ) (33,176 )
Directional drilling (14,385 ) (5,290 ) (24,980 ) (10,957 )
Other operations (10,355 ) (7,317 ) (29,126 ) (12,521 )
Corporate (35,048 ) (37,604 ) (60,588 ) (52,565 )
$ (159,084 ) $ (48,125 ) $ (653,494 ) $ (71,508 ) Additional discussion of our operating revenues and operating loss follows in the "Results of Operations" section.
Our consolidated net loss for the second 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 $ 171,134 $ 348,138 (50.8 )%
Direct operating costs 87,127 201,792 (56.8 )%
Margin (1) 84,007 146,346 (42.6 )%
Restructuring expenses 2,430 - NA
Other operating expenses (income), net (4,155 ) - NA
Selling, general and administrative 1,344 1,450 (7.3 )%
Depreciation, amortization and impairment 115,130 128,402 (10.3 )%
Operating income (loss) $ (30,742 ) $ 16,494 NA
Operating days (2) 7,450 14,385 (48.2 )%
Average revenue per operating day $ 22.97 $ 24.20 (5.1 )%
Average direct operating costs per operating day
(16.6 )%
Average margin per operating day (1) $ 11.28 $ 10.17 10.8 %
Average rigs operating 82 158 (48.2 )%
Capital expenditures $ 42,501 $ 47,664 (10.8 )%
(1) Margin is defined as revenues less direct operating costs and excludes
restructuring expenses, other operating expenses (income), net, 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 second quarter of 2020, our average number
of rigs operating was 82, compared to 158 in the second quarter of 2019. Our
average revenue per operating day is largely dependent on the pricing terms of
our rig contracts. The decrease in average revenue per operating day includes
the impact of a higher percentage of rigs on standby during the 2020 period.
Revenues and direct operating costs decreased primarily due to a decrease in
operating days. Average direct operating costs per operating day decreased due
to cost reduction efforts and a higher percentage of rigs on standby during the
2020 period. Rigs on standby have very little associated cost.
Restructuring expenses were recognized in the second quarter of 2020 and primarily related to severance costs. See Note 16 of Notes to unaudited condensed consolidated financial statements for additional information.
The increase in other operating expenses (income), net is primarily due to an insurance reimbursement for damaged drilling equipment.
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.
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The decrease in capital expenditures was primarily due to higher maintenance
capital expenditures in the second quarter of 2019 when activity levels were
higher and reduced capital expenditures in 2020 due to lower activity.
Pressure Pumping 2020 2019 % Change
(dollars in thousands)
Revenues $ 59,533 $ 251,008 (76.3 )%
Direct operating costs 56,268 206,137 (72.7 )%
Margin (1) 3,265 44,871 (92.7 )%
Restructuring expenses 31,331 - NA
Selling, general and administrative 1,677 3,094 (45.8 )%
Depreciation, amortization and impairment 38,811 56,185 (30.9 )%
Operating loss $ (68,554 ) $ (14,408 ) 375.8 %
Fracturing jobs 35 122 (71.3 )%
Other jobs 152 193 (21.2 )%
Total jobs 187 315 (40.6 )%
Average revenue per fracturing job $ 1,549.71 $ 2,028.33 (23.6 )%
Average revenue per other job $ 34.82 $ 18.40 89.2 %
Average revenue per total job $ 318.36 $ 796.85 (60.0 )%
Average direct operating costs per total job $ 300.90 $ 654.40 (54.0 )%
Average margin per total job (1) $ 17.46 $ 142.45 (87.7 )%
Margin as a percentage of revenues (1) 5.5 % 17.9 % (69.3 )%
Capital expenditures $ 1,947 $ 38,802 (95.0 )%
(1) Margin is defined as revenues less direct operating costs and excludes
restructuring expenses, 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 35 fracturing jobs during the second quarter of 2020, compared to 122 fracturing jobs in the second quarter of 2019. Our average revenue per fracturing job was$1.550 million in the second quarter of 2020, compared to$2.028 million in the second quarter of 2019. 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. Restructuring expenses were recognized in the second quarter of 2020. These restructuring expenses included$7.3 million related to ROU asset abandonments,$3.5 million of severance costs and$20.4 million of contract termination costs. See Note 16 of Notes to unaudited condensed consolidated financial statements for additional information.
Selling, general and administrative expenses decreased primarily as a result of cost reduction efforts.
Depreciation, amortization and impairment expense decreased due to the significant decline in capital expenditures and 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 second quarter of 2020.
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The decrease in capital expenditures was primarily due to higher maintenance
capital expenditures in the second quarter of 2019 when activity levels were
higher and reduced capital expenditures in 2020 due to lower activity.
Directional Drilling 2020 2019 % Change
(dollars in thousands)
Revenues $ 11,742 $ 50,218 (76.6 )%
Direct operating costs 12,265 42,102 (70.9 )%
Margin (1) (523 ) 8,116 NA
Restructuring expenses 3,175 - NA
Selling, general and administrative 1,010 2,536 (60.2 )%
Depreciation, amortization, and impairment 9,677 10,870 (11.0 )%
Operating loss $ (14,385 ) $ (5,290 ) 171.9 %
Capital expenditures $ 2,044 $ 3,450 (40.8 )%
(1) Margin is defined as revenues less direct operating costs and excludes
restructuring expenses, depreciation, amortization and impairment and
selling, general and administrative expenses.
Revenue decreased by
Directional drilling direct operating costs decreased by
Restructuring expenses were recognized in the second quarter of 2020 and were primarily attributable to ROU asset abandonments. See Note 16 of Notes to unaudited condensed consolidated financial statements for additional information.
Selling, general and administrative expenses decreased primarily as a result of cost reduction efforts.
The decrease in capital expenditures was primarily due to higher maintenance
capital expenditures in the second quarter of 2019 when activity levels were
higher and reduced capital expenditures in 2020 due to lower activity.
Other Operations 2020 2019 % Change
(dollars in thousands)
Revenues $ 7,971 $ 26,401 (69.8 )%
Direct operating costs 9,086 17,612 (48.4 )%
Margin (1) (1,115 ) 8,789 NA
Restructuring expenses 501 - NA
Selling, general and administrative 763 4,649 (83.6 )%
Depreciation, depletion, amortization and
impairment 7,976 11,457 (30.4 )%
Operating loss $ (10,355 ) $ (7,317 ) 41.5 %
Capital expenditures $ 2,808 $ 6,230 (54.9 )%
(1) Margin is defined as revenues less direct operating costs and excludes
restructuring expenses, depreciation, depletion, amortization and impairment
and selling, general and administrative expenses.
Other operations revenue decreased by $18.4 million from the second quarter of
2019 primarily due to a decrease in the volume of services provided by our
oilfield rentals business and a decline in the average price per barrel of crude
received by our oil and natural gas assets.
Other operations direct operating costs decreased by
Restructuring expenses were recognized in the second quarter of 2020 and related to severance costs. See Note 16 of Notes to unaudited condensed consolidated financial statements for additional information.
Selling, general and administrative expense decreased primarily as a result of cost reduction efforts.
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--------------------------------------------------------------------------------Depreciation, depletion, amortization and impairment decreased over the comparable prior year period primarily due to a decrease in production from our oil and natural gas assets.
The decrease in capital expenditures was primarily due to higher maintenance
capital expenditures in the second quarter of 2019 when activity levels were
higher and reduced capital expenditures in 2020 due to lower activity and
commodity prices.
Corporate 2020 2019 % Change
(dollars in thousands)
Selling, general and administrative $ 19,197 $ 23,165 (17.1 )%
Restructuring expenses $ 901 $ - NA
Depreciation $ 1,491 $ 1,774 (16.0 )%
Other operating expenses (income), net
Net loss (gain) on asset disposals $ (1,222 ) $ (3,971 ) (69.2 )%
Legal-related expenses and settlements, net
of insurance reimbursements 50 - NA
Research and development 843 371 127.2 %
Other 9,237 12,671 (27.1 )%
Other operating expenses (income), net $ 8,908 $ 9,071 (1.8 )%
Credit loss expense $ 4,551 3,594 26.6 %
Interest income $ 334 $ 1,756 (81.0 )%
Interest expense $ 10,984 $ 13,298 (17.4 )%
Other income $ 85 $ 92 (7.6 )%
Capital expenditures $ 373 $ 773 (51.7 )%
Selling, general and administrative expense decreased primarily as a result of cost reduction efforts.
Restructuring expenses were recognized in the second quarter of 2020 and were primarily attributable to severance and ROU asset abandonments. See Note 16 of Notes to unaudited condensed consolidated financial statements for additional information. Other operating expenses (income), net includes net gains or losses 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 and pressure pumping equipment. Other operating expenses (income), net includes charges of$9.2 million and$12.7 million in the second quarter of 2020 and 2019, respectively related to a 2017 capacity reservation agreement that required a cash deposit to increase our access to finer grades of sand for our pressure pumping business. As market prices for sand substantially decreased since 2017, we purchased lower cost sand outside of this capacity reservation contract and revalued the deposit at its expected realizable value. The deposit related to the capacity reservation agreement has no balance remaining subsequent to the charge recorded in the quarter endedJune 30, 2020 .
A provision for credit losses was recognized in the second quarter of 2020 with respect to accounts receivable balances that are estimated to be uncollectible.
Interest expense was lower in the second quarter of 2020 due to the repayment of long-term debt in the third quarter of 2019.
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The following tables summarize results of operations by business segment for
the six months ended
Contract Drilling 2020 2019 % Change
(dollars in thousands)
Revenues $ 438,498 $ 720,530 (39.1 )%
Direct operating costs 250,547 420,994 (40.5 )%
Margin (1) 187,951 299,536 (37.3 )%
Restructuring expenses 2,430 - NA
Other operating expenses (income), net (4,155 ) - NA
Selling, general and administrative 2,808 3,106 (9.6 )%
Depreciation, amortization and impairment 226,568 258,719 (12.4 )%
Impairment of goodwill 395,060 - NA
Operating income (loss) $ (434,760 ) $ 37,711 NA
Operating days (2) 18,685 30,172 (38.1 )%
Average revenue per operating day $ 23.47 $ 23.88 (1.7 )%
Average direct operating costs per operating day
(3.9 )%
Average margin per operating day (1) $ 10.06 $ 9.93 1.3 %
Average rigs operating 103 167 (38.4 )%
Capital expenditures $ 91,946 $ 123,389 (25.5 )%
(1) Margin is defined as revenues less direct operating costs and excludes
restructuring expenses, other operating expenses (income), net, 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 half of 2020, our average number of
rigs operating was 103, compared to 167 in the same period of 2019. Our average
revenue per operating day is largely dependent on the pricing terms of our rig
contracts. The decrease in average revenue per operating day includes the impact
of a higher percentage of rigs on standby during the 2020 period.
Revenues and direct operating costs decreased primarily due to a decrease in
operating days. Average direct operating costs per operating day decreased due
to cost reduction efforts and a higher percentage of rigs on standby during the
2020 period. Rigs on standby have very little associated cost.
Restructuring expenses were recognized in the second quarter of 2020 and primarily related to severance costs. See Note 16 of Notes to unaudited condensed consolidated financial statements for additional information.
The increase in other operating expenses (income), net is primarily due to an insurance reimbursement for damaged drilling equipment.
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 endedMarch 31, 2020 . See Note 6 of Notes to unaudited condensed consolidated financial statements for additional information. 35
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The decrease in capital expenditures was primarily due to higher maintenance capital expenditures in 2019 when activity levels were higher and reduced capital expenditures in 2020 due to lower activity.
Pressure Pumping 2020 2019 % Change
(dollars in thousands)
Revenues $ 184,640 $ 498,609 (63.0 )%
Direct operating costs 171,123 408,885 (58.1 )%
Margin (1) 13,517 89,724 (84.9 )%
Restructuring expenses 31,331 - NA
Selling, general and administrative 4,744 6,580 (27.9 )%
Depreciation, amortization and impairment 81,482 116,320 (30.0 )%
Operating loss $ (104,040 ) $ (33,176 ) 213.6 %
Fracturing jobs 124 286 (56.6 )%
Other jobs 361 456 (20.8 )%
Total jobs 485 742 (34.6 )%
Average revenue per fracturing job $ 1,413.11 $ 1,711.92 (17.5 )%
Average revenue per other job $ 26.08 $ 19.73 32.1 %
Average revenue per total job $ 380.70 $ 671.98 (43.3 )%
Average direct operating costs per total job $ 352.83 $ 551.06 (36.0 )%
Average margin per total job (1) $ 27.87 $ 120.92 (77.0 )%
Margin as a percentage of revenues (1) 7.3 % 18.0 % (59.3 )%
Capital expenditures and acquisitions $ 16,227 $ 70,202 (76.9 )%
(1) Margin is defined as revenues less direct operating costs and excludes
restructuring expenses, 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 124 fracturing jobs during the first half of 2020, compared to 286 fracturing jobs in the same period of 2019. Our average revenue per fracturing job was$1.413 million in first half of 2020, compared to$1.712 million in the same period of 2019. 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. Restructuring expenses were recognized in the second quarter of 2020. These restructuring expenses included$7.3 million related to ROU asset abandonments,$3.5 million of severance costs and$20.4 million of contract termination costs. See Note 16 of Notes to unaudited condensed consolidated financial statements for additional information.
Selling, general and administrative expenses decreased primarily as a result of cost reduction efforts.
Depreciation, amortization and impairment expense decreased due to the significant decline in capital expenditures and 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 half of 2020.
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--------------------------------------------------------------------------------The decrease in capital expenditures was primarily due to higher maintenance capital expenditures in 2019 when activity levels were higher and reduced capital expenditures in 2020 due to lower activity.
Directional Drilling 2020 2019 % Change
(dollars in thousands)
Revenues $ 46,227 $ 103,177 (55.2 )%
Direct operating costs 44,594 87,704 (49.2 )%
Margin (1) 1,633 15,473 (89.4 )%
Restructuring expenses 3,175 - NA
Selling, general and administrative 3,340 5,193 (35.7 )%
Depreciation, amortization, and impairment 20,098 21,237 (5.4 )%
Operating loss $ (24,980 ) $ (10,957 ) 128.0 %
Capital expenditures $ 4,052 $ 5,562 (27.1 )%
(1) Margin is defined as revenues less direct operating costs and excludes
restructuring expenses, depreciation, amortization and impairment and
selling, general and administrative expenses.
Directional drilling revenue decreased by
Directional drilling direct operating costs decreased by
Restructuring expenses were recognized in the second quarter of 2020 and were primarily attributable to severance and ROU asset abandonments. See Note 16 of Notes to unaudited condensed consolidated financial statements for additional information.
Selling, general and administrative expenses decreased primarily as a result of cost reduction efforts.
The decrease in capital expenditures was primarily due to higher maintenance capital expenditures in 2019 when activity levels were higher and reduced capital expenditures in 2020 due to lower activity.
Other Operations 2020 2019 % Change
(dollars in thousands)
Revenues $ 26,942 $ 57,620 (53.2 )%
Direct operating costs 25,110 39,385 (36.2 )%
Margin (1) 1,832 18,235 (90.0 )%
Restructuring expenses 501 - NA
Selling, general and administrative 2,222 7,511 (70.4 )%
Depreciation, depletion, amortization and
impairment 28,235 23,245 21.5 %
Operating loss $ (29,126 ) $ (12,521 ) 132.6 %
Capital expenditures $ 8,072 $ 14,003 (42.4 )%
(1) Margin is defined as revenues less direct operating costs and excludes
restructuring expenses, depreciation, depletion, amortization and impairment
and selling, general and administrative expenses.
Other operations revenue decreased by $30.7 million from the six months ended
June 30, 2019 primarily due to a decrease in the volume of services provided by
our oilfield rentals business and a decline in the average price per barrel of
crude received by our oil and natural gas assets.
Other operations direct operating costs decreased by $14.3 million from the six
months ended June 30, 2019 primarily due to a decrease in the volume of services
provided by our oilfield rentals business.
Restructuring expenses were recognized in the second quarter of 2020 and related
to severance costs. See Note 16 of Notes to unaudited condensed consolidated
financial statements for additional information.
Selling, general and administrative expense decreased primarily as a result of cost reduction efforts.
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Depreciation, depletion, amortization and impairment increased over the
comparable prior year period primarily due to a $11.2 million impairment related
to certain of our oil and natural gas assets recorded in the first six months of
2020, whereas $2.2 million of oil and natural gas property impairments were
recorded in 2019. The increased oil and natural gas property impairments were
partially offset by decreased 2020 depletion on our oil and natural gas assets,
which was primarily due to a decrease in production.
The decrease in capital expenditures was primarily due to higher maintenance capital expenditures in 2019 when activity levels were higher and reduced capital expenditures in 2020 due to lower activity and commodity prices.
Corporate 2020 2019 % Change
(dollars in thousands)
Selling, general and administrative $ 41,223 $ 45,059 (8.5 )%
Restructuring expenses 901 $ - NA
Depreciation $ 3,499 $ 3,577 (2.2 )%
Other operating expenses (income), net
Net loss (gain) on asset disposals $ (2,461 ) $ (10,516 ) (76.6 )%
Legal-related expenses and settlements, net
of insurance reimbursements 850 (3,471 ) NA
Research and development 1,738 1,726 0.7 %
Other 9,232 12,596 (26.7 )%
Other operating expenses (income), net $ 9,359 $ 335 2,693.7 %
Credit loss expense $ 5,606 3,594 56.0 %
Interest income $ 991 $ 2,788 (64.5 )%
Interest expense $ 22,208 $ 26,282 (15.5 )%
Other income $ 170 $ 209 (18.7 )%
Capital expenditures $ 1,304 $ 2,104 (38.0 )%
Selling, general and administrative expense decreased primarily as a result of cost reduction efforts.
Restructuring expenses were recognized in the second quarter of 2020 and were primarily attributable to severance and ROU asset abandonments. See Note 16 of Notes to unaudited condensed consolidated financial statements for additional information. Other operating expenses (income), net includes net gains or losses 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. Other operating expenses (income), net includes charges of$9.2 million and$12.7 million in 2020 and 2019, respectively related to a 2017 capacity reservation agreement that required a cash deposit to increase our access to finer grades of sand for our pressure pumping business. As market prices for sand substantially decreased since 2017, we purchased lower cost sand outside of this capacity reservation contract and revalued the deposit at its expected realizable value. The deposit related to the capacity reservation agreement has no balance remaining subsequent to the charge recorded in the quarter endedJune 30, 2020 .
A provision for credit losses was recognized in the six months ended
Interest expense was lower in the six months ended
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, and other differences related to the recognition of income and expense betweenU.S. GAAP and tax accounting. 38
-------------------------------------------------------------------------------- Our effective income tax rate for the three months endedJune 30, 2020 was 11.4%, compared with 17.0% for the three months endedJune 30, 2019 . The lower effective income tax rate for the three months endedJune 30, 2020 was primarily attributable to the non-deductible portion of the goodwill impairment recorded in the first quarter of 2020. Our effective income tax rate for the six months endedJune 30, 2020 was 13.3%, compared with 17.7% for the six months endedJune 30, 2019 . The lower effective income tax rate for the six months endedJune 30, 2020 was primarily attributable to the non-deductible portion of the goodwill impairment recorded in the first quarter of 2020. We continue to monitor income tax developments inthe United States and other countries where we operate. During the first quarter of 2020,the United States enacted legislation related to COVID-19, which includes tax provisions. We have considered these tax provisions and do not currently expect any material impact to our financial statements. 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
During the three months endedJune 30, 2020 , we implemented a restructuring plan to improve operating margins, achieve operational efficiencies and reduce indirect support costs. The restructuring included workforce reductions, changes to management structure and facility consolidations and closures. We recorded$38.3 million of charges associated with this plan in the three and six months endedJune 30, 2020 . There were no restructuring charges in the comparable periods of 2019. We anticipate completing the restructuring plan during the third quarter of 2020 and do not expect to incur significant additional expenses related to the plan. We reduced our planned capital expenditures for 2020 by$110 million to$140 million . Our focus throughout the remainder of 2020 will be on further cost reductions and cash preservation during this period of significant uncertainty and volatility. While oilfield services activity and revenues declined significantly in the second quarter, we aligned our cost structure with the changing activity levels and enhanced our liquidity position. Our liquidity as ofJune 30, 2020 included approximately$245 million in working capital, including$247 million of cash and cash equivalents, and approximately$600 million available under our revolving credit facility. OnJanuary 19, 2018 , we completed an offering of$525 million in aggregate principal amount of our 3.95% Senior Notes due 2028 (the "2028 Notes"). We used$239 million of the net proceeds from the offering to repay amounts outstanding under our revolving credit facility. As described below, onMarch 27, 2018 , we entered into an amended and restated credit agreement, which 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$150 million and a swing line facility that, at any time outstanding, is limited to$20 million . OnAugust 22, 2019 , we entered into a term loan agreement (the "Term Loan Agreement"), which permits a single borrowing of up to$150 million , which we drew in full onSeptember 23, 2019 . Subject to customary conditions, we may request that the lenders' aggregate commitments be increased by up to$75 million , not to exceed total commitments of$225 million . OnSeptember 25, 2019 , we used$150 million of borrowings from the Term Loan Agreement and approximately$158 million of cash on hand to prepay our 4.97% Series A Senior Notes dueOctober 5, 2020 . The total amount of the prepayment, including the applicable "make-whole" premium, was approximately$308 million , plus accrued interest to the prepayment date. We repaid$50 million of the borrowings under the Term Loan Agreement onDecember 16, 2019 , and we had$100 million in outstanding borrowings under the Term Loan Agreement as ofJune 30, 2020 . OnNovember 15, 2019 , we completed an offering of$350 million in aggregate principal amount of our 5.15% Senior Notes due 2029 (the "2029 Notes"). The net proceeds before offering expenses were approximately$347 million . OnDecember 16, 2019 , we used a portion of the net proceeds from the offering to prepay our 4.27% Series B Senior Notes dueJune 14, 2022 (the "Series B Notes"). The total amount of the prepayment, including the applicable "make-whole" premium, was approximately$315 million , plus accrued interest to the prepayment date. The remaining net proceeds and available cash on hand was used to repay$50 million of the borrowings under the Term Loan Agreement. 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. 39 --------------------------------------------------------------------------------
During the six months ended
•$219 million from operating activities, and •$7.3 million in proceeds from the disposal of property and equipment.
During the six months ended
• to make capital expenditures for the acquisition, betterment and
refurbishment of drilling and pressure pumping equipment and, to a much
lesser extent, equipment for our other businesses,
• to acquire and procure equipment to support our drilling, pressure pumping,
directional drilling, oilfield rentals and manufacturing operations, and
• to fund investments in oil and natural gas properties on a non-operating,
working interest basis.
We paid cash dividends during the six months endedJune 30, 2020 as follows: Per Share Total (in thousands) Paid on March 19, 2020$ 0.04 $ 7,629 Paid on June 18, 2020$ 0.02 $ 3,735$ 0.06 $ 11,364 OnJuly 22, 2020 , our Board of Directors approved a cash dividend on our common stock in the amount of$0.02 per share to be paid onSeptember 17, 2020 to holders of record as ofSeptember 3, 2020 . 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. OnSeptember 6, 2013 , our Board of Directors approved a stock buyback program that authorized purchases of up to$200 million of our common stock in open market or privately negotiated transactions. OnJuly 25, 2018 , our Board of Directors approved an increase of the authorization under the stock buyback program to allow for$250 million of future share repurchases. OnFebruary 6, 2019 , our Board of Directors approved another increase of the authorization under the stock buyback program to allow for$250 million of future share repurchases. OnJuly 24, 2019 , our Board of Directors approved another increase of the authorization under the stock buyback program to allow for$250 million of future share repurchases. All purchases executed to date have been through open market transactions. Purchases under the 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. Shares of stock purchased under the buyback program are held as treasury shares. There is no expiration date associated with the buyback program. As ofJune 30, 2020 , we had remaining authorization to purchase approximately$130 million of our outstanding common stock under the stock buyback program.
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) 165,266
935
Treasury shares at end of period 83,327,919$ 1,366,069
(1) We withheld 165,266 shares during the first two quarters of 2020 with respect
to employees' tax withholding obligations upon the settlement of performance
unit awards and the vesting of restricted stock and restricted stock units.
These shares were acquired at fair market value. These acquisitions were made
pursuant to the terms of the
2014 Long-Term Incentive Plan, as amended, and not pursuant to the stock
buyback program.
2019 Term Loan Agreement - On
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The Term Loan Agreement is a committed senior unsecured term loan facility that
permits a single borrowing of up to $150 million , which we drew in full on
September 23, 2019 . Subject to customary conditions, we may request that the
lenders' aggregate commitments be increased by up to $75 million , not to exceed
total commitments of $225 million . The maturity date under the Term Loan
Agreement is June 10, 2022 . We repaid $50 million of the borrowings under the
Term Loan Agreement on December 16, 2019 .
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
June 30, 2020 , the applicable margin on LIBOR rate loans and base rate loans was
1.375% and 0.375%, respectively.
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 June 30, 2020 .
As of
Credit Agreement - OnMarch 27, 2018 , we entered into an amended and restated credit agreement (the "Credit Agreement") among us, as borrower,Wells Fargo Bank, National Association , as administrative agent, letter of credit issuer, swing line lender and lender, each of the other lenders and letter of credit issuers party thereto, The Bank ofNova Scotia andU.S. Bank National Association , as Co-Syndication Agents, Royal Bank of Canada, asDocumentation Agent andWells Fargo Securities, LLC , The Bank ofNova Scotia andU.S. Bank National Association , as Co-Lead Arrangers and Joint Book Runners. The 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$150 million and a swing line facility that, at any time outstanding, is limited to$20 million . 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 . The original maturity date under the Credit Agreement wasMarch 27, 2023 . OnMarch 26, 2019 , we entered into Amendment No. 1 to Amended and Restated Credit Agreement, which amended the Credit Agreement to, among other things, extend the maturity date under the Credit Agreement fromMarch 27, 2023 toMarch 27, 2024 . OnMarch 27, 2020 , we entered into Amendment No. 2 to Amended and Restated Credit Agreement to, among other things, extend the maturity date for$550 million of revolving credit commitments of certain lenders under the Credit Agreement fromMarch 27, 2024 toMarch 27, 2025 . We have the option, subject to certain conditions, to exercise one additional one-year extension of the maturity date. 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.
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.
41
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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 June 30, 2020 .
As of June 30, 2020 , we had no borrowings outstanding under our revolving credit
facility. We had $0.1 million in letters of credit outstanding under the Credit
Agreement at June 30, 2020 and, as a result, had available borrowing capacity of
approximately $600 million at that date.
2015 Reimbursement Agreement - On March 16, 2015 , we entered into 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. As of June 30,
2020 , we had $60.7 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 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 - OnJanuary 19, 2018 , we completed an offering of$525 million in aggregate principal amount of our 2028 Notes. The net proceeds before offering expenses were approximately$521 million , of which we used$239 million to repay amounts outstanding under our revolving credit facility. OnNovember 15, 2019 , we completed an offering of$350 million in aggregate principal amount of our 2029 Notes. The net proceeds before offering expenses were approximately$347 million , of which we used$315 million to repay in full our Series B Notes, and the remainder to repay a portion of the borrowings under the Term Loan Agreement. We pay interest on the 2028 Notes onFebruary 1 andAugust 1 of each year. The 2028 Notes will mature onFebruary 1, 2028 . The 2028 Notes bear interest at a rate of 3.95% per annum. We pay interest on the 2029 Notes onMay 15 andNovember 15 of each year. The 2029 Notes will mature onNovember 15, 2029 . The 2029 Notes bear interest at a rate of 5.15% per annum. 42
-------------------------------------------------------------------------------- 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 onNovember 1, 2027 , in the case of the 2028 Notes, and onAugust 15, 2029 , in the case of the 2029 Notes, we, at our option, may redeem the respective Senior Notes in whole or in part, at a redemption price equal to 100% of the principal amount of the Senior Notes to be redeemed, plus accrued and unpaid interest, if any, on those Senior Notes to the redemption date. 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 ofJune 30, 2020 , we maintained letters of credit in the aggregate amount of$60.8 million primarily for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire annually at various times during the year and are typically renewed. As ofJune 30, 2020 , no amounts had been drawn under the letters of credit.
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 2022. As ofJune 30, 2020 , the remaining minimum obligation under these agreements was approximately$26.4 million , of which approximately$13.0 million ,$10.0 million , and$3.4 million relate to the remainder of 2020, 2021, and 2022, respectively. 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. 43 --------------------------------------------------------------------------------
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 ("U.S. GAAP"). We define Adjusted EBITDA as net
income (loss) plus net interest expense, income tax expense (benefit) and
depreciation, depletion, amortization and impairment expense (including
impairment of goodwill). We present Adjusted EBITDA 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 U.S. GAAP measure of net income (loss). Our
computations of Adjusted EBITDA may not be the same as other similarly titled
measures of other companies. Set forth below is a reconciliation of the non-U.S.
GAAP financial measure of Adjusted EBITDA to the U.S. GAAP financial measure of
net income (loss).
Three Months Ended Six Months Ended
June 30, June 30,
2020 2019 2020 2019
(in thousands)
Net loss $ (150,332 ) $ (49,447 ) $ (585,054 ) $ (78,061 )
Income tax benefit (19,317 ) (10,128 ) (89,487 ) (16,732 )
Net interest expense 10,650 11,542 21,217 23,494
Depreciation, depletion, amortization and
impairment 173,085 208,688 359,882 423,098
Impairment of goodwill - - 395,060 -
Adjusted EBITDA $ 14,086 $ 160,655 $ 101,618 $ 351,799
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.
On a periodic basis, we evaluate our fleet of drilling rigs for marketability
based on the condition of inactive rigs, expenditures that would be necessary to
bring them to working condition and the expected demand for drilling services by
rig type. The components comprising rigs that will no longer be marketed are
evaluated, and those components with continuing utility to our other marketed
rigs are transferred to other rigs or to our yards to be used as spare
equipment. The remaining components of these rigs are retired. During the three
months ended June 30, 2020 , we recorded an impairment of $8.3 million related to
the closing of our Canadian drilling operations.
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 decline in the market price of our
common stock and commodity prices in the first quarter of 2020, 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 March 31, 2020 . We performed an analysis as required by ASC
360-10-35 to assess the recoverability of the asset groups within our contract
drilling, pressure pumping, directional drilling and oilfield rentals operating
segments as of March 31, 2020 . With respect to these asset groups, future cash
flows were estimated over the expected remaining life of the assets, and we
determined that, on an undiscounted basis, expected cash flows exceeded the
carrying value of the asset groups, and no impairment was indicated. Expected
cash flows, on an undiscounted basis, exceeded the carrying values of the asset
groups within the contract drilling, pressure pumping, directional drilling and
oilfield rentals operating segments by approximately 15%, 22%, 3% and 9%,
respectively.
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For the assessment performed as of March 31, 2020 , the expected cash flows for
our asset groups included assumptions about utilization, revenue and costs for
our equipment and services that were estimated based upon our existing contract
backlog, as well as recent contract tenders and customer inquiries. Also, the
expected cash flows for the contract drilling, pressure pumping, directional
drilling and oilfield rentals asset groups were based on the assumption that
activity levels in all four segments would generally be lower than levels
experienced in the second half of 2019 and first quarter of 2020 and would begin
to recover in 2022 in response to improved oil prices. While we believe these
assumptions with respect to future oil pricing are reasonable, actual future
prices and activity levels may vary significantly from the ones that were
assumed. The timeframe over which oil prices and activity levels may recover is
highly uncertain.
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.
We have concluded that no triggering events occurred during the quarter endedJune 30, 2020 with respect to our asset groups based on our recent results of operations, our expectations of operating results in future periods and prevailing commodity prices at the time.Goodwill -Goodwill is considered to have an indefinite useful economic life and is not amortized.Goodwill is evaluated at least annually as ofDecember 31 , or when circumstances require, to determine if the fair value of recorded goodwill has decreased below its carrying value. For impairment testing purposes, goodwill is evaluated at the reporting unit level. Our reporting units for impairment testing are our operating segments. We determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value after considering qualitative, market and other factors, and if this is the case, any necessary goodwill impairment is determined using a quantitative impairment test. From time to time, we may perform quantitative testing for goodwill impairment in lieu of performing the qualitative assessment. If the resulting fair value of goodwill is less than the carrying value of goodwill, an impairment loss would be recognized for the amount of the shortfall. Due to the decline in the market price of our common stock and commodity prices in the first quarter of 2020, 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 ofMarch 31, 2020 . In completing the assessment, the fair value of our contract drilling operating segment was estimated using the income approach. The estimate of fair value required the use of significant unobservable inputs, representative of a Level 3 fair value measurement. The inputs included assumptions related to the future performance of our contract drilling reporting unit, such as future oil and natural gas prices and projected demand for our services, and assumptions related to discount rate and long-term growth rate. Based on the results of the goodwill impairment test as ofMarch 31, 2020 , impairment was indicated in our contract drilling reporting unit. We recognized an impairment charge of$395 million in the quarter endedMarch 31, 2020 associated with the impairment of all of the goodwill in our contract drilling reporting unit. Use of estimates - The preparation of financial statements in conformity withU.S. 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.
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$63.27 per barrel onJanuary 6, 2020 , declined to negative$36.98 per barrel onApril 20, 2020 , and closed at$40.83 per barrel onJuly 20, 2020 . In response to the rapid decline in commodity prices, E&P companies acted swiftly to reduce drilling and completion activity starting late in the first quarter. 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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