# PATTERSON UTI ENERGY INC (PTEN) FY 2021 MD&A

Verbatim Item 7 Management's Discussion and Analysis from PATTERSON UTI ENERGY INC's 10-K for fiscal year 2021.

SEC filing source: https://www.sec.gov/Archives/edgar/data/889900/000095017022001347/pten-20211231.htm
Accession: 0000950170-22-001347
Filing date: 2022-02-16
Report date: 2021-12-31
Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary.
Confidence: high

Company profile: /company/PTEN/
All MD&A years: /company/PTEN/mda/
Next year: /company/PTEN/mda/fy2022/ (FY 2022)

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

Management Overview and Recent Developments in Market Conditions — We are a Houston, Texas-based oilfield services company that primarily owns and operates one of the largest fleets of land-based drilling rigs in the United States and a large fleet of pressure pumping equipment.

Our contract drilling business operates in the continental United States and internationally in Colombia and, from time to time, we pursue contract drilling opportunities in other select markets. Our pressure pumping business operates primarily in Texas and the Appalachian region. We also provide a comprehensive suite of directional drilling services in most major producing onshore oil and gas basins in the United States, and we provide services that improve the statistical accuracy of directional and horizontal wellbores. We have other operations through which we provide oilfield rental tools in select markets in the United States. We also service equipment for drilling contractors, and we provide electrical controls and automation to the energy, marine and mining industries, in North America and other select markets. In addition, we own and invest, as a non-operating working interest owner, in oil and natural gas assets that are primarily located in Texas and New Mexico.

During 2020, reduced demand for crude oil and refined products related to the COVID-19 pandemic, combined with production increases from OPEC+ early in the year, led to a significant reduction in crude oil prices and demand for drilling and completion services in the United States. Although OPEC+ agreed in April 2020 to cut oil production, OPEC+ has been gradually reducing such cuts, and in July 2021 agreed to further reduce such cuts on a monthly basis with a goal of phasing out all production cuts towards the end of 2022. There is no assurance that the most recent OPEC+ agreement will be observed by its parties, and OPEC+ may change its agreement based on market conditions or other reasons.

Oil prices remain extremely volatile, as the closing price of oil (WTI-Cushing) reached a first quarter 2020 high of $63.27 per barrel on January 6, 2020, declined to negative $36.98 per barrel on April 20, 2020, and recovered to reach a 2021 high of $85.64 per barrel on October 26, 2021. 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 of 2020. While oil prices have recovered in 2021, and demand for our services has improved since the commodity price decline in 2020, our average number of rigs operating remains well below the number of our available rigs, and a significant portion of our pressure pumping horsepower remains stacked. Oil prices averaged $77.45 per barrel in the fourth quarter of 2021.

Quarterly average oil prices and our quarterly average number of rigs operating in the United States for 2019, 2020 and 2021 are as follows:

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

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

Although our active rig count has not fully recovered to its 2019 levels, it increased in 2021 after a significant decline in 2020. Our average active rig count in the U.S. for the fourth quarter of 2021 was 106 rigs. This was an increase from our average active rig count for the third quarter of 2021 of 80 rigs. The increase was partially due to our acquisition of active U.S. rigs from Pioneer, which averaged 13 active rigs during the fourth quarter of 2021. Our active U.S. rig count at December 31, 2021 of 111 rigs was more than the rig count of 65 rigs at December 31, 2020, partially due to the increase in rigs from the Pioneer acquisition and, more significantly, due to the recovery of oil prices and improved demand for drilling services in the United States. Term contracts help support our operating rig count. Based on contracts currently in place in the United States, we expect an average of 51 rigs operating under term contracts during the first quarter, and an average of 39 rigs operating under term contracts during 2022.

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We ended the fourth quarter of 2021 with 11 active pressure pumping spreads compared to ten at the end of the third quarter. Our average active spread count was approximately ten spreads and effective utilization was close to 11 spreads for the fourth quarter of 2021. We calculated average active spreads as the average number of spreads that were crewed and actively marketed during the period, and we calculated effective utilization as total pumping days during the quarter divided by 75 days, which we consider full effective utilization for a spread for the period. We expect to average approximately 11 active spreads in the first quarter of 2022. The pressure pumping market has improved but remains oversupplied.

Due to improving activity levels and increasing tightness in the overall labor market, we saw general oilfield cost inflation across our segments during 2021, including increases in the cost of labor, services and supplies. This inflation, combined with the increasing challenge of attracting employees to the industry, is increasing the complexity of reactivating equipment. We believe this challenge, combined with the increasing market tightness for premium drilling and completion services, will support higher pricing for our services in 2022. During 2021, we increased our capital expenditure forecast to approximately $170 million, in part, based on conversations with customers about increasing activity levels into 2022. Actual 2021 capital expenditures excluding discontinued operations totaled $166 million.

Recent Developments in Financial Matters and Merger and Acquisition Activity — On October 1, 2021, we completed the acquisition of Pioneer by acquiring 100% of its equity interests. Total consideration for the acquisition included the issuance of approximately 26.3 million shares of our common stock and payment of $30 million cash, which based on the closing price of our common stock of $9.44 on October 1, 2021, valued the transaction at approximately $278 million.

Pioneer provided land-based contract drilling services and production services to a diverse group of oil and gas exploration and production companies in the United States and internationally in Colombia. Through the Pioneer acquisition, we acquired Pioneer’s 100% pad-capable drilling rig fleet consisting of 17 AC-powered rigs in the United States and eight SCR rigs in Colombia and production services assets consisting of 123 well servicing rigs and 72 wireline services units. We believe the acquisition of Pioneer enhances our position as a leading provider of contract drilling services in the United States and expands our geographic footprint into Latin America.

On December 31, 2021, we completed the sale of Pioneer Production Services to Clearwell. The sale price was $43.0 million in cash consideration, subject to customary purchase price adjustments at closing for cash and working capital. The results of operations of these businesses have been presented as a discontinued operation in these consolidated financial statements. In connection with the sale of our Pioneer Production Services business, we entered into a transition services agreement with Clearwell, pursuant to which we agreed to provide each other certain administrative and operational services on an interim, transitional basis through June 30, 2022.

On December 30, 2021, we repaid the final $50 million of borrowings under the Term Loan Agreement, and as a result had no remaining borrowings under the Term Loan Agreement as of December 31, 2021.

During the fourth quarter of 2020, we elected to repurchase portions of our 2028 Notes and 2029 Notes (as defined below) in the open market. The principal amounts retired through these transactions totaled $15.5 million related to our 2028 Notes and $0.8 million related to our 2029 Notes, plus accrued interest. We recorded corresponding gains on the extinguishment of these amounts totaling $3.4 million and $0.2 million, respectively, net of the proportional write-off of associated deferred financing costs and original issuance discounts. These gains are included in “Interest expense, net of amount capitalized” in the consolidated statements of operations.

On March 27, 2020, we entered into Amendment No. 2 to Amended and Restated Credit Agreement (“Amendment No. 2”) to, among other things, extend the maturity date for $550 million of revolving credit commitments of certain lenders under the Credit Agreement (as defined below) from March 27, 2024 to March 27, 2025. We have the option, subject to certain conditions, to exercise an additional one-year extension of the maturity date.

During the second quarter of 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 second quarter of 2020. We completed the restructuring plan during the third quarter of 2020 and did not incur additional expenses related to the plan. There have been no restructuring charges in 2021.

Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and upon our customers’ ability to access capital to fund their operating and capital expenditures. During periods of improved oil and natural gas prices, the capital spending budgets of oil and natural gas operators tend to expand, which generally results in increased demand for our services. Conversely, in periods when oil and natural gas prices are relatively low or when our customers have a reduced ability to access capital, the demand for our services generally weakens, and we experience downward pressure on pricing for our services. We may also be impacted by delayed customer payments and payment defaults associated with customer liquidity issues and bankruptcies.

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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. While the market for premium equipment has tightened, there remains 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, from time to time, of products used in our pressure pumping business, supplier delays and various other factors that could materially adversely affect our business, financial condition, cash flows and results of operations, including as a result of the COVID-19 pandemic. See “Risk Factors” in Item 1A of this Report.

For the three years ended December 31, 2021, our operating revenues consisted of the following (dollars in thousands):

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Contract Drilling

We have addressed our customers’ needs for drilling horizontal wells in shale and other unconventional resource plays by improving the capabilities of our drilling fleet during the last several years. The U.S. land rig industry has in recent years referred to certain high specification rigs as “super-spec” rigs, which we consider to be at least a 1,500 horsepower, AC-powered rig that has at least a 750,000-pound hookload, a 7,500-psi circulating system, and is pad-capable. Due to evolving customer preferences, we have begun to refer to certain premium rigs as “Tier-1, super spec” rigs, which we consider as being a super-spec rig that also has a third mud pump and raised drawworks that allow for more clearance underneath the rig floor. As of December 31, 2021, our rig fleet included 171 super-spec rigs, of which 107 were Tier-1, super-spec rigs.

We maintain a backlog of commitments for contract drilling services under term contracts, which we define as contracts with a duration of six months or more. Our contract drilling backlog in the United States as of December 31, 2021 and 2020 was approximately $325 million and $301 million, respectively. Approximately 22% of the total contract drilling backlog in the United States at December 31, 2021 is reasonably expected to remain after 2022. 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 at December 31, 2021. 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. See “Item 1A. Risk Factors – Our Current Backlog of Contract Drilling Revenue May Decline and May Not Ultimately Be Realized, as Fixed-Term Contracts May in Certain Instances Be Terminated Without an Early Termination Payment.”

Pressure Pumping

As of December 31, 2021, we had approximately 1.1 million horsepower in our pressure pumping fleet. The pressure pumping market has improved but remains oversupplied. In response to oversupplied market conditions, we implemented changes during the second quarter of 2020 that were intended to further streamline our operations, improve our efficiencies, and reduce our overall cost structure, while maintaining our customer service levels.

Directional Drilling

We provide a comprehensive suite of directional drilling services in most major producing onshore oil and gas basins in the United States. Our directional drilling services include directional drilling, measurement-while-drilling and supply and rental of downhole performance motors. We also provide services that improve the statistical accuracy of directional and horizontal wellbores.

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Other Operations

Our oilfield rentals business, with a fleet of premium oilfield rental tools, along with the results of our ownership, as a non-operating working interest owner, in oil and gas assets located in Texas and New Mexico, provide the largest revenue contributions to our other operations. Other operations also includes the results of our electrical controls and automation business and the results of our drilling equipment service business.

Capital Expenditures

Cash capital expenditures for 2021, excluding discontinued operations, totaled $166 million. This was an increase from the $145 million of cash capital expenditures for 2020, due largely to higher activity levels in 2021. Based on our current outlook for activity, we expect our capital expenditures for 2022 to be approximately $350 million.

For the three years ended December 31, 2021, our operating losses consisted of the following (dollars in thousands):

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[[/GREPCENT_TABLE]]

While demand for our services improved in 2021, our average number of rigs operating remains well below the number of our available rigs, and a significant portion of our pressure pumping horsepower remains stacked. This reduced demand, combined with impairments to our contract drilling, pressure pumping and directional drilling equipment contributed to a consolidated net loss of $655 million for 2021, compared to a consolidated net loss of $804 million for 2020 and consolidated net loss of $426 million for 2019.

Results of Operations

Comparison of the years ended December 31, 2021 and 2020

The following tables summarize results of operations by business segment for the years ended December 31, 2021 and 2020:

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[[/GREPCENT_TABLE]]

(1)
Adjusted gross margin is defined as revenues less direct operating costs and excludes restructuring expenses, other operating expenses (income), net, selling, general and administrative expenses, depreciation, amortization and impairment and impairment of goodwill. Average adjusted gross margin per operating day is defined as adjusted gross 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.

Reduced demand for crude oil and refined products related to the COVID-19 pandemic, combined with production increases from OPEC+, led to a significant reduction in crude oil prices and demand for contract drilling services in 2020 and early 2021.

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Generally, the revenues in our contract drilling segment are most impacted by two primary factors: our average number of rigs operating and our average revenue per operating day. Our average revenue per operating day is largely dependent on the pricing terms of our rig contracts. Lump sum early termination revenues were $4.1 million in 2021, which was less than the $13.3 million recorded during the comparable period of 2020.

Revenues remained relatively flat in 2021 as compared to 2020 despite this reduction in lump sum early termination revenues. However, $41.5 million of our revenues in 2021 related to additional drilling rigs from the Pioneer acquisition. Without the impact of the Pioneer acquisition, 2021 revenues would have been approximately $623 million, a 7% decrease, and operating days from our U.S. operations would have been 28,722, a 3.8% decrease from 2020. The reduction in lump sum early termination revenues from 2020 resulted in an incremental 1.4% decrease. Average revenue per operating day excluding the effects of the Pioneer acquisition did not change significantly.

The Pioneer acquisition added $30.5 million of direct operating costs in 2021, which contributed to an 8.0% increase as compared to 2020. Apart from the increase attributed to the Pioneer acquisition, direct operating costs increased $52.2 million, or 13.7%, as compared to 2020. Apart from the Pioneer acquisition, average direct operating costs per operating day in the U.S. were $15,069, an 18.8% increase. The increases in direct operating costs and average direct operating costs per day were primarily due to a reduction in the proportion of rigs on standby and rig reactivation costs. Rigs on standby have very little associated cost.

Restructuring expenses were recognized in 2020 and primarily related to severance costs. See Note 20 of Notes to Consolidated Financial Statements included in Item 8 of this Report.

The change in other operating expenses (income), net is primarily due to an insurance reimbursement for damaged drilling equipment in 2020.

Depreciation, amortization and impairment expense increased primarily due to a $220 million impairment charge related to abandonment of 43 legacy non-super-spec rigs and equipment. Based on the strong customer preference across the industry for super-spec drilling rigs, we believed the 43 rigs that were abandoned had limited commercial opportunity. In the second quarter of 2020 we recorded an impairment of $8.3 million related to the closing of our Canadian drilling operations. Without the impairment charge in 2021, depreciation and amortization expense would have decreased to approximately $399 million, an 8.1% decrease as compared to 2020. The decrease excluding impairment was due to lower cumulative capital expenditures in recent years, which reduced our depreciable asset base as depreciation, amortization and impairment outpaced capital expenditures between the periods. This decline was partially offset by incremental depreciation and amortization associated with the additional rigs from the Pioneer acquisition, which contributed three months of expense after the October 1, 2021 closing date.

All of the goodwill associated with our contract drilling reporting unit was impaired in 2020. See Note 7 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report.

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[[/GREPCENT_TABLE]]

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(1)
Adjusted gross margin is defined as revenues less direct operating costs and excludes restructuring expenses, selling, general and administrative expenses and depreciation, amortization and impairment. Average adjusted gross margin per total job is defined as adjusted gross margin divided by total jobs. Adjusted gross margin as a percentage of revenues is defined as adjusted gross margin divided by revenues.

(2)
Average active spreads is the average number of spreads that were crewed and actively marketed during the period.

(3)
Effective utilization is calculated as total pumping days during the year divided by 300 days, which we consider full effective utilization for a year.

Reduced demand for crude oil and refined products related to the COVID-19 pandemic, combined with production increases from OPEC+, led to a significant reduction in crude oil prices and demand for pressure pumping services in 2020 and early 2021.

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 and the size of the jobs.

Revenues and direct operating costs increased primarily due to an increase in fracturing jobs as activity levels continue to recover from the industry downturn in 2020. Average revenue per total job increased primarily due to a mix of activity weighted toward higher revenue fracturing jobs. Average direct operating costs per total job increased also as a result of the significant increase in fracturing jobs, which generally have higher direct operating costs. We exited 2021 with 11 active spreads as compared to five active spreads on December 31, 2020.

Restructuring expenses were recognized in the second quarter of 2020. These restructuring expenses included $7.3 million related to right-of-use asset abandonments, $3.5 million of severance costs and $20.4 million of contract termination costs. See Note 20 of Notes to Consolidated Financial Statements in Item 8 of this Report.

Selling, general and administrative expenses decreased primarily as a result of cost reduction efforts.

Depreciation, amortization and impairment expense increased as a result of a $32.2 million impairment charge related to the abandonment of approximately 0.2 million horsepower within our pressure pumping fleet. The majority of these units were frac pumps but also included pump down units. These units were abandoned due to a combination of customer preference for dual fuel units, advancements in technology, and prohibitive reactivation costs. Excluding the impairment charge in 2021, depreciation and amortization would have been $127 million, a 16.7% decline. The decrease excluding impairment is due to lower cumulative capital expenditures in recent years, which reduced our depreciable asset base as depreciation, amortization and impairment outpaced capital expenditures between periods.

Capital expenditures increased due to increased maintenance capital, mostly related to engines and transmissions as well as higher inflationary pressure on replacement items.

[[GREPCENT_TABLE]]
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[[/GREPCENT_TABLE]]

(1)
Adjusted gross margin is defined as revenues less direct operating costs and excludes restructuring expenses, selling, general and administrative expenses and depreciation, amortization and impairment.

Reduced demand for crude oil and refined products related to the COVID-19 pandemic, combined with production increases from OPEC+, led to a significant reduction in crude oil prices and demand for directional drilling services in 2020 and early 2021.

Directional drilling revenue and direct operating costs increased from 2020 primarily due to increased job activity. We averaged 30.1 jobs per day in 2021 as compared to 18.9 jobs per day for the comparable period in 2020. Additionally, a portion of the increase in direct operating costs relates to an inventory write-down of $4.0 million in 2021. Excluding the effects of this write-down, direct operating costs would have been approximately $97.6 million, an increase of 41.3% as compared to 2020. See Note 5 of Notes to Consolidated Financial Statements in Item 8 of this Report for additional information regarding the inventory write-down.

36

Restructuring expenses were recognized in the second quarter of 2020 and were primarily attributable to severance and right-of-use asset abandonments. See Note 20 of Notes to Consolidated Financial Statements in Item 8 of this Report for additional information.

Depreciation, amortization and impairment increased as a result of the abandonment of an $11.4 million developed technology intangible asset and $2.5 million of directional drilling equipment in 2021. Excluding these charges, depreciation and amortization expense would have been $26.4 million, a 27.8% decline as compared to 2020. The decrease excluding impairments is due to lower cumulative capital expenditures in recent years, which reduced our depreciable asset base as depreciation, amortization and impairment outpaced capital expenditures between the periods.

Capital expenditures increased due to higher levels of activity requiring premium equipment to meet market demands.

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["Other Operations","","2021","","","2020","","","% Change"],["","","(Dollars in thousands)"],["Revenues","","$","57,814","","","$","45,656","","","","26.6","%"],["Direct operating costs","","","40,911","","","","41,790","","","","(2.1",")%"],["Adjusted gross margin (1)","","","16,903","","","","3,866","","","","337.2","%"],["Restructuring expenses","","","\u2014","","","","501","","","NA"],["Selling, general and administrative","","","1,943","","","","3,539","","","","(45.1",")%"],["Depreciation, depletion, amortization and impairment","","","24,865","","","","41,511","","","","(40.1",")%"],["Operating loss","","$","(9,905",")","","$","(41,685",")","","","(76.2",")%"],["Capital expenditures","","$","11,638","","","$","12,378","","","","(6.0",")%"]]
[[/GREPCENT_TABLE]]

(1)
Adjusted gross margin is defined as revenues less direct operating costs and excludes restructuring expenses, selling, general and administrative expenses and depreciation, depletion, amortization and impairment.

Reduced demand for crude oil and refined products related to the COVID-19 pandemic, combined with production increases from OPEC+, led to a significant reduction in crude oil prices and demand for oilfield rental and other services in 2020 and early 2021.

Other operations revenue increased from 2020 primarily due to an $8.6 million increase in our oil and natural gas revenues as a result of favorable crude oil and natural gas market prices. Average WTI-Cushing prices in 2021 were $68.14 per barrel as compared to $39.16 per barrel in 2020. Because the increase in oil and natural gas revenues was driven by market pricing, we did not have a commensurate increase in direct operating costs for our oil and natural gas business. We also recognized a $4.7 million increase in revenue from our oilfield rentals business primarily due to an increase in our volume of services.

Other operations direct operating costs remained relatively flat despite the increase in revenues primarily due to the majority of the revenue increase being driven by market prices rather than incremental activity.

Restructuring expenses were recognized in 2020 and related to severance costs.

Selling, general and administrative expense decreased primarily as a result of cost reduction efforts.

Depreciation, depletion, amortization and impairment decreased primarily due to an $11.2 million impairment related to certain of our oil and natural gas assets in 2020 as compared to a $1.3 million impairment of oil and natural gas assets in 2021. Excluding the impairment to our oil and natural gas properties in both years, the decrease in depreciation, depletion and amortization would have been $6.7 million, a 22.2% decrease. The impairment in 2020 reduced our depreciable base, which lowered depreciation in subsequent periods. Additionally, the decrease in depreciation, depletion, amortization and impairment was partially due to lower cumulative capital expenditures in recent years, which also reduced our depreciable asset base as depreciation, depletion, amortization and impairment outpaced capital expenditures between the periods.

37

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["Corporate","","2021","","","2020","","","% Change"],["","","(Dollars in thousands)"],["Selling, general and administrative","","$","73,495","","","$","75,612","","","","(2.8",")%"],["Merger and integration expenses","","$","12,060","","","$","\u2014","","","NA"],["Restructuring expenses","","$","\u2014","","","$","901","","","NA"],["Depreciation","","$","5,859","","","$","6,494","","","","(9.8",")%"],["Other operating expenses (income), net"],["Net gain on asset disposals","","$","(1,426",")","","$","(3,079",")","","","(53.7",")%"],["Legal-related expenses and settlements, net of insurance reimbursements","","","762","","","","1,680","","","","(54.6",")%"],["Research and development","","","1,371","","","","3,411","","","","(59.8",")%"],["Other","","","31","","","","9,232","","","","(99.7",")%"],["Other operating expense (income), net","","$","738","","","$","11,244","","","","(93.4",")%"],["Credit loss expense","","$","(1,500",")","","$","5,606","","","NA"],["Interest income","","$","222","","","$","1,254","","","","(82.3",")%"],["Interest expense","","$","41,978","","","$","40,770","","","","3.0","%"],["Other income (expense)","","$","(275",")","","$","756","","","NA"],["Capital expenditures","","$","1,521","","","$","1,707","","","","(10.9",")%"]]
[[/GREPCENT_TABLE]]

Selling, general and administrative expense decreased primarily as a result of cost reduction efforts.

Merger and integration expenses were recognized in 2021 related to the Pioneer acquisition, which closed on October 1, 2021, and the subsequent divestiture of Pioneer’s well servicing rig business and wireline business, which closed on December 31, 2021. See Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Report.

Restructuring expenses were recognized in 2020 and were primarily attributable to severance and right-of-use asset abandonments. See Note 20 of Notes to Consolidated Financial Statements in Item 8 of this Report.

Other operating expenses (income), net includes net gains associated with the disposal of assets. Accordingly, the related gains have been excluded from the results of specific segments. The majority of the net gain on asset disposals in 2021 reflect gains on disposals of buildings, land and drilling equipment, while the gain on asset disposals in 2020 related to disposals of drilling and pressure pumping equipment. Additionally, other operating expenses (income), net includes charges of $9.2 million in the second quarter of 2020 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 had no balance remaining subsequent to the charge recorded in the second quarter of 2020.

A provision for credit losses of $5.6 million was recognized in 2020 with respect to accounts receivable balances that were estimated to be uncollectible. During 2021, we reversed $1.5 million of our credit loss provision related to certain customers who had previously experienced a deterioration in credit quality. Since initially recording loss provisions for these receivables, we have collected portions of the accounts that were deemed uncollectible.

Interest expense increased slightly as compared to 2020. However, 2020 interest expense was favorably impacted by a gain on debt extinguishment of $3.6 million associated with the repurchase of portions of our 2028 Notes and 2029 Notes. Excluding the effects of the gain, interest expense would have decreased by $2.4 million, a 5.5% decrease. Additionally, on December 30, 2021, we repaid the final $50 million of borrowings under the 2019 Term Loan Agreement, and as a result had no remaining borrowings under the Term Loan Agreement as of December 31, 2021. Accordingly, we will not incur interest expense related to the Term Loan Agreement in subsequent periods.

Comparison of the years ended December 31, 2020 and 2019

A discussion of our results of operations for the fiscal year ended December 31, 2020 compared to the fiscal year ended December 31, 2019 is included in Part II, Item 7— "Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year ended December 31, 2020, filed with the SEC on February 9, 2021.

38

Income Taxes

The effective tax rate decreased by approximately 5% to 8.7% for 2021 compared to 13.7% for 2020. The difference was primarily due to nondeductible goodwill impairment charges in 2020 impacting the effective tax rate and changes in valuation allowance positions between 2020 and 2021.

We continue to monitor income tax developments in the United States and other countries where we have legal entities. We will incorporate into our future financial statements the impacts, if any, of future regulations and additional authoritative guidance when finalized.

Liquidity and Capital Resources

During the second quarter of 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 second quarter of 2020. We completed the restructuring plan during the third quarter of 2020 and did not incur additional expenses related to the plan. There were no restructuring charges in 2021.

Our primary sources of liquidity are cash and cash equivalents, availability under our revolving credit facility and cash provided by operating activities. As of December 31, 2021, we had approximately $148 million in working capital, including $118 million of cash and cash equivalents, and approximately $600 million available under our revolving credit facility.

We have an amended and restated credit agreement (the “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. As of December 31, 2021, we had no borrowings outstanding under our revolving credit facility, and $0.1 million in letters of credit outstanding under the Credit Agreement and, as a result, had available borrowing capacity of approximately $600 million at that date. Of the revolving credit commitments, $50 million expires on March 27, 2024, and the remaining $550 million expires on March 27, 2025. Subject to customary conditions, we may request that the lenders’ aggregate commitments be increased by up to $300 million, not to exceed total commitments of $900 million. Additionally, we have the option, subject to certain conditions, to exercise one one-year extension of the maturity date.

Loans under the Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base rate, as described in “Item 7A” below. If our credit rating is below investment grade at both Moody’s and S&P, we will become subject to a restricted payment covenant. The Credit Agreement also contains a financial covenant that requires our total debt to capitalization ratio, expressed as a percentage, not exceed 50%.

We also have a Reimbursement Agreement (the “Reimbursement Agreement”) with The Bank of Nova Scotia (“Scotiabank”), pursuant to which we may from time to time request that Scotiabank issue an unspecified amount of letters of credit. Under the terms of the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any letters of credit. 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.

Our outstanding debt at December 31, 2021 was $859 million and consisted of $510 million of 3.95% Senior Notes due 2028 (the “2028 Notes”), $349 million of 5.15% Senior Notes due 2029 (the “2029 Notes”). We were in compliance with all covenants at December 31, 2021.

For a full description of the Credit Agreement, the Reimbursement Agreement, the 2028 Notes and the 2029 Notes, see Note 9 of Notes to consolidated financial statements in Item 8 of this Report.

We had $71.5 million of outstanding letters of credit at December 31, 2021, which were comprised of $71.4 million outstanding under the Reimbursement Agreement and $0.1 million outstanding under the Credit Agreement. We maintain these letters of credit primarily for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under terms of the underlying insurance contracts. These letters of credit expire annually at various times during the year and are typically renewed. As of December 31, 2021, no amounts had been drawn under the letters of credit.

39

Cash Requirements

We believe our current liquidity, together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to maintain and make improvements to our existing equipment, service our debt and pay cash dividends for at least the next 12 months.

If we pursue opportunities for growth that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash flows from operating activities, borrowing capacity under our revolving credit facility or additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

A portion of our capital expenditures can be adjusted and managed by us to match market demand and activity levels. Based on our current outlook for activity, we expect our capital expenditures for 2022 to be approximately $350 million. The majority of these expenditures are expected to be used for normal, recurring items necessary to support our business.

We anticipate $9.7 million of expenditures in 2022 related to various contractual obligations such as certain purchase commitments and operating lease liabilities.

As of December 31, 2021, we had working capital of $148 million, including cash and cash equivalents of $118 million, compared to working capital of $204 million, including cash and cash equivalents of $225 million, at December 31, 2020.

During 2021, our sources of cash flow included:

•
$95.5 million from operating activities,

•
$42.0 million in proceeds, net of disposed cash, from the disposal of the Pioneer Production Services business,

•
$23.3 million in proceeds from the disposal of property and equipment.

During 2021, we used $29.4 million, net of acquired cash, for the acquisition of Pioneer, $15.6 million to pay dividends on our common stock, $50 million to repay borrowings under our Term Loan Agreement and $166 million:

•
to make capital expenditures for the betterment and refurbishment of drilling and pressure pumping equipment and, to a much lesser extent, equipment for our other businesses,

•
to acquire and procure equipment to support our contract drilling, pressure pumping, directional drilling, oilfield rentals and manufacturing operations, and

•
to fund investments in oil and natural gas properties on a non-operating working interest basis.

We paid cash dividends during the year ended December 31, 2021 as follows:

[[GREPCENT_TABLE]]
[["","","Per Share","","","Total"],["","","","","","(in thousands)"],["Paid on March 18, 2021","","$","0.02","","","$","3,754"],["Paid on June 17, 2021","","","0.02","","","","3,769"],["Paid on September 16, 2021","","","0.02","","","","3,780"],["Paid on December 16, 2021","","","0.02","","","","4,302"],["Total cash dividends","","$","0.08","","","$","15,605"]]
[[/GREPCENT_TABLE]]

On February 9, 2022, our Board of Directors approved a cash dividend on our common stock in the amount of $0.04 per share to be paid on March 17, 2022 to holders of record as of March 3, 2022. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our debt agreements and other factors. Our Board of Directors may, without advance notice, reduce or suspend our dividend in order to improve our financial flexibility and best position our company for long-term success. There can be no assurance that we will pay a dividend in the future.

We may, at any time and from time to time, seek to retire or purchase our outstanding debt for cash through open-market purchases, privately negotiated transactions, redemptions or otherwise. Such repurchases, if any, will be upon such terms and at such prices as we may determine, and will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

40

On September 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. The authorized repurchases under this program were subsequently increased in July 2018 and February 2019, and on July 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. There is no expiration date associated with the buyback program. As of December 31, 2021, we had remaining authorization to purchase approximately $130 million of our outstanding common stock under the stock buyback program. Shares of stock purchased under the buyback program are held as treasury shares.

We acquired shares of stock from employees during 2021, 2020 and 2019 that are accounted for as treasury stock. Certain of these shares were acquired to satisfy the exercise price and employees’ tax withholding obligations upon the exercise of stock options. The remainder of these shares were acquired to satisfy payroll withholding obligations upon the settlement of performance unit awards and the vesting of restricted stock units. These shares were acquired at fair market value. These acquisitions were made pursuant to the terms of the Patterson-UTI Energy, Inc. Amended and Restated 2014 Long-Term Incentive Plan, as amended (the “2014 Plan”) and the Patterson-UTI Energy, Inc. 2021 Long-Term Incentive Plan (the “2021 Plan”), and not pursuant to the stock buyback program. Upon the issuance of shares for the Pioneer acquisition in October 2021, we withheld shares with respect to Pioneer employees’ tax withholding obligations.

Treasury stock acquisitions during the years ended December 31, 2021, 2020 and 2019 were as follows (dollars in thousands):

[[GREPCENT_TABLE]]
[["","","2021","","","2020","","","2019"],["","","Shares","","","Cost","","","Shares","","","Cost","","","Shares","","","Cost"],["Treasury shares at beginning of period","","","83,402,322","","","$","1,366,313","","","","77,336,387","","","$","1,345,134","","","","53,701,096","","","$","1,080,448"],["Purchases pursuant to stock buyback program","","","\u2014","","","","\u2014","","","","5,826,266","","","","20,000","","","","22,566,331","","","","250,109"],["Acquisitions pursuant to long-term incentive plan","","","451,196","","","","3,727","","","","239,669","","","","1,179","","","","1,037,947","","","","14,205"],["Purchases in connection with Pioneer acquisition","","","275,477","","","","2,601","","","","\u2014","","","","\u2014","","","","\u2014","","","","\u2014"],["Other","","","\u2014","","","","\u2014","","","","\u2014","","","","\u2014","","","","31,013","","","","372"],["Treasury shares at end of period","","","84,128,995","","","$","1,372,641","","","","83,402,322","","","$","1,366,313","","","","77,336,387","","","$","1,345,134"]]
[[/GREPCENT_TABLE]]

As of December 31, 2021, we had unrecognized compensation costs of $17.3 million and $6.6 million related to our unvested restricted stock units and our unvested Performance Units, respectively. The weighted-average remaining vesting periods for these awards were 1.66 years and 1.44 years, respectively as of December 31, 2021. See Note 12 of Notes to consolidated financial statements in Item 8 of this Report for additional discussion regarding our stock-based compensation.

Commitments — As of December 31, 2021, we had commitments to purchase major equipment totaling approximately $99.0 million for our drilling, pressure pumping, directional drilling and oilfield rentals businesses.

Our pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors. The remaining terms of the agreements are less than one year. In the event the required minimum quantities are not purchased during any contract year, we could be required to make a liquidated damages payment to the respective vendor for any shortfall. In 2017, we entered into a 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 recorded a charge of $9.2 million and $12.7 million in the second quarters of 2020 and 2019, respectively, to revalue the deposit to its expected realizable value. There is no value assigned to the capacity reservation contract subsequent to the charge recorded in the second quarter of 2020.

See Note 10 of Notes to consolidated financial statements in Item 8 of this Report for additional information on our current commitments and contingencies as of December 31, 2021.

Operating lease liabilities totaled $25.0 million at December 31, 2021. See Note 13 of Notes to consolidated financial statements in Item 8 of this Report for additional information on our operating leases as of December 31, 2021.

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.

41

Critical Accounting Estimates

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

Allowance for credit losses — We utilize an accounts receivable aging schedule and historical credit loss information to estimate expected credit losses. We evaluate our accounts receivable periodically through review of historical collection experience, current aging status of the customer accounts, financial condition of our customers, and the overall economic environment of the oil and gas industry. Any customers that have experienced a deterioration in credit quality are removed from the pool and evaluated individually. This process involves judgment and estimation. Accordingly, our results of operations can be affected by adjustments to the allowance due to actual write-offs that differ from estimated amounts. During 2021, we updated our expected credit loss rates for historical credit loss information associated with customers with accounts receivable acquired in the Pioneer acquisition. In applying our methodology of estimating credit losses, we determined no material changes to our credit loss rates. See Note 4 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report.

Depreciation and amortization — Property and equipment is carried at cost less accumulated depreciation and amortization. No provision for salvage value is considered in determining depreciation of our property and equipment. We calculate depreciation and amortization on our assets based on the estimated useful lives that we believe are reasonable. The estimated useful lives are subject to key assumptions such as maintenance, utilization and job variation. These estimates may change due to a number of factors such as changes in operating conditions or advances in technology. The method of depreciation does not change whenever equipment becomes idle. Maintenance and repairs are charged to expense when incurred. Renewals and betterments which extend the life or improve existing property and equipment are capitalized. See Note 1 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report.

Fair values of assets acquired and liabilities assumed in acquisitions — Assets acquired and liabilities assumed in a business combination are recorded at their estimated fair values on the date of acquisition. The difference between the purchase price amount and the net fair value of assets acquired and liabilities assumed is recognized as goodwill on the balance sheet if the purchase price exceeds the estimated net fair value or as a bargain purchase gain on the income statement if the purchase price is less than the estimated net fair value. We apply significant judgment in estimating the fair value of assets acquired and liabilities assumed, which involves the use of significant estimates and assumptions with respect to market day rates, direct operating costs, rig utilization percentages, expectations regarding the amount of future capital and operating costs, and discount rates. Changes in these judgments or estimates can have a material impact on the valuation of the respective assets and liabilities acquired and our results of operations in periods after acquisition, such as through depreciation and amortization expense. The allocation of the purchase price may be modified up to one year after the acquisition date as more information is obtained about the fair value of assets acquired and liabilities assumed. See Note 2 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report.

Impairment of long-lived assets — 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. If the carrying amount of the asset is not recoverable based on its estimated undiscounted cash flows expected to result from the use and eventual disposition, an impairment loss is recognized in an amount by which its carrying amount exceeds its estimated fair value. The inputs used to determine such fair value are primarily based upon internally developed cash flow models. Our cash flow models are based on a number of estimates regarding future operations that may be subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future. We determined no triggering events occurred in 2021. See Note 6 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report.

42

Accruals for self-insured levels of insurance coverage — We maintain insurance coverage for fire, windstorm and other risks of physical loss to our equipment and certain other assets, employers’ liability, automobile liability, commercial general liability, workers’ compensation and insurance for other specific risks. We also self-insure a number of other risks, including loss of earnings and business interruption and most cybersecurity risks, and do not carry a significant amount of insurance to cover risks of underground reservoir damage. Our insurance accruals are based on claims filed and estimates of claims incurred but not reported and are developed by our management with assistance from our third-party actuary and third-party claims administrator. The insurance accruals are influenced by our past claims experience factors, which have a limited history, and by published industry development factors. If we experience insurance claims or costs above or below our historically evaluated levels, our estimates could be materially affected. The frequency and number of claims or incidents could vary significantly over time, which could materially affect our self-insurance liabilities. Additionally, the actual costs to settle the self-insurance liabilities could materially differ from the original estimates and cause us to incur additional costs in future periods associated with prior year claims.

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. Please see “Risk Factors – We are Dependent on the Oil and Natural Gas Industry and Market Prices for Oil and Natural Gas. Declines in Customers’ Operating and Capital Expenditures and in Oil and Natural Gas Prices May Adversely Affect Our Operating Results” in Item 1A of this Report. Oil prices remain extremely volatile, as the closing price of oil (WTI-Cushing) reached a first quarter 2020 high of $63.27 per barrel on January 6, 2020, declined to negative $36.98 per barrel on April 20, 2020, and recovered to reach a 2021 high of $85.64 per barrel on October 26, 2021. 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 of 2020. While oil prices have recovered in 2021, and demand for our services has improved since the commodity price decline in 2020, our average number of rigs operating remains well below the number of our available rigs, and a significant portion of our pressure pumping horsepower remains stacked. Oil prices averaged $77.45 per barrel in the fourth quarter of 2021.

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.

Impact of Inflation

As previously disclosed within our Quarterly Reports on Form 10-Q for the periods ended June 30, 2021 and September 30, 2021, due to improving activity levels and increasing tightness in the overall labor market, we have seen general oilfield cost inflation across our segments during 2021, including increases in the cost of labor, services and supplies. This inflation, combined with the increasing challenge of attracting employees to the industry, is increasing the complexity of reactivating equipment. We believe this challenge, combined with the increasing market tightness for premium drilling and completion services, will support higher pricing for our services in 2022. However, to date, this general inflationary trend has not had a material effect on our operating margins as both revenues and costs are impacted in tandem.

Recently Issued Accounting Standards

For a discussion of recently issued accounting standards, see Note 1 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report.

43

Non-GAAP Measurements

Adjusted EBITDA

Adjusted earnings before interest, taxes, depreciation and amortization (“Adjusted EBITDA”) is not defined by U.S. GAAP. We define Adjusted EBITDA as loss from continuing operations plus income tax benefit, net interest expense, 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 loss from continuing operations 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 loss from continuing operations. 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 loss from continuing operations.

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2021","","","2020","","","2019"],["","","(in thousands)"],["Loss from continuing operations","","$","(657,079",")","","$","(803,692",")","","$","(425,703",")"],["Income tax benefit","","","(62,702",")","","","(127,326",")","","","(104,675",")"],["Net interest expense","","","41,756","","","","39,516","","","","69,191"],["Depreciation, depletion, amortization and impairment","","","849,178","","","","670,910","","","","1,003,873"],["Impairment of goodwill","","","\u2014","","","","395,060","","","","17,800"],["Adjusted EBITDA","","$","171,153","","","$","174,468","","","$","560,486"]]
[[/GREPCENT_TABLE]]

Adjusted Gross Margin

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

[[GREPCENT_TABLE]]
[["","Contract Drilling","","","Pressure Pumping","","","Directional Drilling","","","Other Operations"],["","(in thousands)"],["For the year ended December 31, 2021"],["Operating revenues","$","664,030","","","$","523,756","","","$","111,481","","","$","57,814"],["Less cost of sales","","(463,456",")","","","(475,953",")","","","(101,628",")","","","(40,911",")"],["Less depreciation, depletion, amortization and impairment","","(618,879",")","","","(159,305",")","","","(40,270",")","","","(24,865",")"],["GAAP gross margin","","(418,305",")","","","(111,502",")","","","(30,417",")","","","(7,962",")"],["Depreciation, depletion, amortization and impairment","","618,879","","","","159,305","","","","40,270","","","","24,865"],["Adjusted gross margin","$","200,574","","","$","47,803","","","$","9,853","","","$","16,903"],["For the year ended December 31, 2020"],["Operating revenues","$","669,126","","","$","336,111","","","$","73,356","","","$","45,656"],["Less cost of sales","","(380,822",")","","","(310,261",")","","","(69,050",")","","","(41,790",")"],["Less depreciation, depletion, amortization and impairment","","(433,771",")","","","(152,630",")","","","(36,504",")","","","(41,511",")"],["GAAP gross margin","","(145,467",")","","","(126,780",")","","","(32,198",")","","","(37,645",")"],["Depreciation, depletion, amortization and impairment","","433,771","","","","152,630","","","","36,504","","","","41,511"],["Adjusted gross margin","$","288,304","","","$","25,850","","","$","4,306","","","$","3,866"]]
[[/GREPCENT_TABLE]]