tusk-20210930

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


☒			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2021


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO

Commission File No. 001-37917

Mammoth Energy Services, Inc.

(Exact name of registrant as specified in its charter)

Delaware

32-0498321

(State or other jurisdiction of
incorporation or organization)

(I.R.S. Employer
Identification No.)

14201 Caliber Drive,

Suite 300

Oklahoma City,

Oklahoma

(405)

608-6007

73134

(Address of principal executive offices)

(Registrant’s telephone number, including area code)

(Zip Code)

Securities registered pursuant to Section 12(b) of The Act:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock

TUSK

The Nasdaq Stock Market LLC

NASDAQ Global Select Market

______________________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer

☐

Accelerated filer

☐

Non-accelerated filer

☒

Smaller reporting company

☒

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

As of November 3, 2021, there were 46,684,065 shares of common stock, $0.01 par value, outstanding.

MAMMOTH ENERGY SERVICES, INC.

TABLE OF CONTENTS




		Page
	Glossary of Oil and Natural Gas and Electrical Infrastructure Terms	i
	Cautionary Note Regarding Forward-Looking Statements	iv

PART I. FINANCIAL INFORMATION		1
Item 1.	Condensed Consolidated Financial Statements (Unaudited)	1
	Condensed Consolidated Balance Sheets	1
	Condensed Consolidated Statements of Comprehensive Loss	2
	Condensed Consolidated Statements of Changes in Equity	3
	Condensed Consolidated Statements of Cash Flows	4
	Notes to Unaudited Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	52
Item 4.	Controls and Procedures	53

PART II. OTHER INFORMATION		54
Item 1.	Legal Proceedings	54
Item 1A.	Risk Factors	54
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	54
Item 4.	Mine Safety Disclosures	54
Item 5.	Other Information	54
Item 6.	Exhibits	56

SIGNATURES		57

GLOSSARY OF OIL AND NATURAL GAS AND ELECTRICAL INFRASTRUCTURE TERMS


The following is a glossary of certain oil and natural gas industry terms used in this Quarterly Report on Form 10-Q (this “report” or “Quarterly Report”):
Acidizing			To pump acid into a wellbore to improve a well’s productivity or injectivity.
Blowout			An uncontrolled flow of reservoir fluids into the wellbore, and sometimes catastrophically to the surface. A blowout may consist of salt water, oil, natural gas or a mixture of these. Blowouts can occur in all types of exploration and production operations, not just during drilling operations. If reservoir fluids flow into another formation and do not flow to the surface, the result is called an underground blowout. If the well experiencing a blowout has significant open-hole intervals, it is possible that the well will bridge over (or seal itself with rock fragments from collapsing formations) down-hole and intervention efforts will be averted.
Bottomhole assembly			The lower portion of the drillstring, consisting of (from the bottom up in a vertical well) the bit, bit sub, a mud motor (in certain cases), stabilizers, drill collar, heavy-weight drillpipe, jarring devices (“jars”) and crossovers for various threadforms. The bottomhole assembly must provide force for the bit to break the rock (weight on bit), survive a hostile mechanical environment and provide the driller with directional control of the well. Oftentimes the assembly includes a mud motor, directional drilling and measuring equipment, measurements-while-drilling tools, logging-while-drilling tools and other specialized devices.
Cementing			To prepare and pump cement into place in a wellbore.
Coiled tubing			A long, continuous length of pipe wound on a spool. The pipe is straightened prior to pushing into a wellbore and rewound to coil the pipe back onto the transport and storage spool. Depending on the pipe diameter (1 in. to 4 1/2 in.) and the spool size, coiled tubing can range from 2,000 ft. to 23,000 ft. (610 m to 6,096 m) or greater length.
Completion			A generic term used to describe the assembly of down-hole tubulars and equipment required to enable safe and efficient production from an oil or gas well. The point at which the completion process begins may depend on the type and design of the well.
Directional drilling			The intentional deviation of a wellbore from the path it would naturally take. This is accomplished through the use of whipstocks, bottomhole assembly (BHA) configurations, instruments to measure the path of the wellbore in three-dimensional space, data links to communicate measurements taken down-hole to the surface, mud motors and special BHA components and drill bits, including rotary steerable systems, and drill bits. The directional driller also exploits drilling parameters such as weight on bit and rotary speed to deflect the bit away from the axis of the existing wellbore. In some cases, such as drilling steeply dipping formations or unpredictable deviation in conventional drilling operations, directional-drilling techniques may be employed to ensure that the hole is drilled vertically. While many techniques can accomplish this, the general concept is simple: point the bit in the direction that one wants to drill. The most common way is through the use of a bend near the bit in a down-hole steerable mud motor. The bend points the bit in a direction different from the axis of the wellbore when the entire drillstring is not rotating. By pumping mud through the mud motor, the bit turns while the drillstring does not rotate, allowing the bit to drill in the direction it points. When a particular wellbore direction is achieved, that direction may be maintained by rotating the entire drillstring (including the bent section) so that the bit does not drill in a single direction off the wellbore axis, but instead sweeps around and its net direction coincides with the existing wellbore. Rotary steerable tools allow steering while rotating, usually with higher rates of penetration and ultimately smoother boreholes.
Down-hole			Pertaining to or in the wellbore (as opposed to being on the surface).
Down-hole motor			A drilling motor located in the drill string above the drilling bit powered by the flow of drilling mud. Down-hole motors are used to increase the speed and efficiency of the drill bit or can be used to steer the bit in directional drilling operations. Drilling motors have become very popular because of horizontal and directional drilling applications and the day rates for drilling rigs.
Drilling rig			The machine used to drill a wellbore.
Drillpipe or Drill pipe			Tubular steel conduit fitted with special threaded ends called tool joints. The drillpipe connects the rig surface equipment with the bottomhole assembly and the bit, both to pump drilling fluid to the bit and to be able to raise, lower and rotate the bottomhole assembly and bit.
Drillstring or Drill string			The combination of the drillpipe, the bottomhole assembly and any other tools used to make the drill bit turn at the bottom of the wellbore.
Flowback			The process of allowing fluids to flow from the well following a treatment, either in preparation for a subsequent phase of treatment or in preparation for cleanup and returning the well to production.
Horizontal drilling			A subset of the more general term “directional drilling,” used where the departure of the wellbore from vertical exceeds about 80 degrees. Note that some horizontal wells are designed such that after reaching true 90-degree horizontal, the wellbore may actually start drilling upward. In such cases, the angle past 90 degrees is continued, as in 95 degrees, rather than reporting it as deviation from vertical, which would then be 85 degrees. Because a horizontal well typically penetrates a greater length of the reservoir, it can offer significant production improvement over a vertical well.
Hydraulic fracturing			A stimulation treatment routinely performed on oil and gas wells in low permeability reservoirs. Specially engineered fluids are pumped at high pressure and rate into the reservoir interval to be treated, causing a vertical fracture to open. The wings of the fracture extend away from the wellbore in opposing directions according to the natural stresses within the formation. Proppant, such as grains of sand of a particular size, is mixed with the treatment fluid to keep the fracture open when the treatment is complete. Hydraulic fracturing creates high-conductivity communication with a large area of formation and bypasses any damage that may exist in the near-wellbore area.


Hydrocarbon			A naturally occurring organic compound comprising hydrogen and carbon. Hydrocarbons can be as simple as methane, but many are highly complex molecules, and can occur as gases, liquids or solids. Petroleum is a complex mixture of hydrocarbons. The most common hydrocarbons are natural gas, oil and coal.
Mesh size			The size of the proppant that is determined by sieving the proppant through screens with uniform openings corresponding to the desired size of the proppant. Each type of proppant comes in various sizes, categorized as mesh sizes, and the various mesh sizes are used in different applications in the oil and natural gas industry. The mesh number system is a measure of the number of equally sized openings per square inch of screen through which the proppant is sieved.
Mud motors			A positive displacement drilling motor that uses hydraulic horsepower of the drilling fluid to drive the drill bit. Mud motors are used extensively in directional drilling operations.
Natural gas liquids			Components of natural gas that are liquid at surface in field facilities or in gas processing plants. Natural gas liquids can be classified according to their vapor pressures as low (condensate), intermediate (natural gasoline) and high (liquefied petroleum gas) vapor pressure.
Nitrogen pumping unit			A high-pressure pump or compressor unit capable of delivering high-purity nitrogen gas for use in oil or gas wells. Two basic types of units are commonly available: a nitrogen converter unit that pumps liquid nitrogen at high pressure through a heat exchanger or converter to deliver high-pressure gas at ambient temperature, and a nitrogen generator unit that compresses and separates air to provide a supply of high pressure nitrogen gas.
Plugging			The process of permanently closing oil and gas wells no longer capable of producing in economic quantities. Plugging work can be performed with a well servicing rig along with wireline and cementing equipment; however, this service is typically provided by companies that specialize in plugging work.
Plug			A down-hole packer assembly used in a well to seal off or isolate a particular formation for testing, acidizing, cementing, etc.; also a type of plug used to seal off a well temporarily while the wellhead is removed.
Pounds per square inch			A unit of pressure. It is the pressure resulting from a one pound force applied to an area of one square inch.
Pressure pumping			Services that include the pumping of liquids under pressure.
Producing formation			An underground rock formation from which oil, natural gas or water is produced. Any porous rock will contain fluids of some sort, and all rocks at considerable distance below the Earth’s surface will initially be under pressure, often related to the hydrostatic column of ground waters above the reservoir. To produce, rocks must also have permeability, or the capacity to permit fluids to flow through them.
Proppant			Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment. In addition to naturally occurring sand grains, man-made or specially engineered proppants, such as resin-coated sand or high-strength ceramic materials like sintered bauxite, may also be used. Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore.
Resource play			Accumulation of hydrocarbons known to exist over a large area.
Shale			A fine-grained, fissile, sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers.
Tight oil			Conventional oil that is found within reservoirs with very low permeability. The oil contained within these reservoir rocks typically will not flow to the wellbore at economic rates without assistance from technologically advanced drilling and completion processes. Commonly, horizontal drilling coupled with multistage fracturing is used to access these difficult to produce reservoirs.
Tight sands			A type of unconventional tight reservoir. Tight reservoirs are those which have low permeability, often quantified as less than 0.1 millidarcies.
Tubulars			A generic term pertaining to any type of oilfield pipe, such as drill pipe, drill collars, pup joints, casing, production tubing and pipeline.
Unconventional resource			A term for the different manner by which resources are exploited as compared to the extraction of conventional resources. In unconventional drilling, the wellbore is generally drilled to specific objectives within narrow parameters, often across long, lateral intervals within narrow horizontal formations offering greater contact area with the producing formation. Typically, the well is then hydraulically fractured at multiple stages to optimize production.
Wellbore			The physical conduit from surface into the hydrocarbon reservoir.
Well stimulation			A treatment performed to restore or enhance the productivity of a well. Stimulation treatments fall into two main groups, hydraulic fracturing treatments and matrix treatments. Fracturing treatments are performed above the fracture pressure of the reservoir formation and create a highly conductive flow path between the reservoir and the wellbore. Matrix treatments are performed below the reservoir fracture pressure and generally are designed to restore the natural permeability of the reservoir following damage to the near wellbore area. Stimulation in shale gas reservoirs typically takes the form of hydraulic fracturing treatments.
Wireline			A general term used to describe well-intervention operations conducted using single-strand or multi-strand wire or cable for intervention in oil or gas wells. Although applied inconsistently, the term commonly is used in association with electric logging and cables incorporating electrical conductors.
Workover			The process of performing major maintenance or remedial treatments on an oil or gas well. In many cases, workover implies the removal and replacement of the production tubing string after the well has been killed and a workover rig has been placed on location. Through-tubing workover operations, using coiled tubing, snubbing or slickline equipment, are routinely conducted to complete treatments or well service activities that avoid a full workover where the tubing is removed. This operation saves considerable time and expense.


The following is a glossary of certain electrical infrastructure industry terms used in this report:
Distribution			The distribution of electricity from the transmission system to individual customers.
Substation			A part of an electrical transmission and distribution system that transforms voltage from high to low, or the reverse.
Transmission			The movement of electrical energy from a generating site, such as a power plant, to an electric substation.

iii

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, or the Exchange Act. In particular, the factors discussed in this report and detailed under Part II, Item 1A. Risk Factors in this report and our Annual Report on Form 10–K for the year ended December 31, 2020 could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or implied in such forward-looking statements.

Forward-looking statements may include statements about:

•the levels of capital expenditures by our customers and the impact of reduced drilling and completions activity on utilization and pricing for our oilfield services;

•the volatility of oil and natural gas prices and actions by OPEC members and other oil exporting nations, or OPEC+, affecting commodity price and production levels;

•the severity and duration of the COVID-19 pandemic, the related global and national health concerns and economic repercussions and the resulting negative impact on demand for Mammoth’s services;

•operational challenges relating to the COVID-19 pandemic and efforts to mitigate the spread of the virus, including logistical challenges, remote work arrangements and protecting the health, safety and well-being of Mammoth’s employees;

•the performance of contracts and supply chain disruptions during the COVID-19 pandemic;

•general economic, business or industry conditions;

•conditions in the capital, financial and credit markets;

•conditions of U.S. oil and natural gas industry and the effect of U.S. energy, monetary and trade policies;

•U.S. and global economic conditions and political and economic developments, including the effects of the recent U.S. presidential and congressional elections on energy and environmental policies;

•our ability to obtain capital or financing needed for our operations on favorable terms or at all;

•our ability to regain compliance with certain financial covenants and comply with other terms and conditions under our recently amended revolving credit facility;

•our ability to execute our business and financial strategies;

•our ability to continue to grow our infrastructure services segment, recommence certain of our suspended oilfield services or return our natural sand proppant services segment to profitability;

•any loss of one or more of our significant customers and its impact on our revenue, financial condition and results of operations;

•asset impairments;

•our ability to identify, complete and integrate acquisitions of assets or businesses;

•our ability to receive, or delays in receiving, permits and governmental approvals and/or payments, and to comply with applicable governmental laws and regulations;

•the outcome of a government investigation relating to the contracts awarded to one of our subsidiaries by the Puerto Rico Electric Power Authority and any resulting litigation;

•the outcome or settlement of our litigation matters discussed in this report, including the adverse impact of the recent settlements with Gulfport Energy Corporation and MasTec Renewables Puerto Rico, LLC, on our financial condition and results of operations;

•any future litigation, indemnity or other claims;

•regional supply and demand factors, delays or interruptions of production, and any governmental order, rule or regulation that may impose production limits on our customers;

•the availability of transportation, pipeline and storage facilities and any increase in related costs;

•extreme weather conditions, such as the severe winter storms in February 2021 in the Permian Basin where we provide well completion and drilling services;

•access to and restrictions on use of water;

•technology;

•civil unrest or terrorist attacks;

•cybersecurity issues as digital technologies may become more vulnerable and experience a higher rate of cyberattacks due to increased use of remote connectivity in the workplace;

•competition within the energy services industry;

•availability of equipment, materials or skilled personnel or other labor resources;

•payment of any future dividends;

•future operating results; and

•capital expenditures and other plans, objectives, expectations and intentions.

All of these types of statements, other than statements of historical fact included in this quarterly report, are forward-looking statements. These forward-looking statements may be found in the “Business,” “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and other sections of this quarterly report. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “could,” “should,” “would,” “expect,” “plan,” “project,” “budget,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “seek,” “objective,” “continue,” “will be,” “will benefit,” or “will continue,” the negative of such terms or other comparable terminology.

The forward-looking statements contained in this report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors, which are difficult to predict and many of which are beyond our control. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, our management’s assumptions about future events may prove to be inaccurate. Our management cautions all readers that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to many factors including those described in our Annual Report on Form 10–K for the year ended December 31, 2020 and Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this report. All forward-looking statements speak only as of the date of this report. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

MAMMOTH ENERGY SERVICES, INC.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

MAMMOTH ENERGY SERVICES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (unaudited)


ASSETS	September 30,		December 31,
	2021		2020
CURRENT ASSETS	(in thousands)
Cash and cash equivalents	$	7,953	$	14,822
Short-term investment	1,760		1,750
Accounts receivable, net	402,035		393,112
Receivables from related parties, net	238		28,461
Inventories	9,438		12,020
Prepaid expenses	3,859		13,825
Other current assets	754		758

Total current assets	426,037		464,748

Property, plant and equipment, net	194,478		251,262
Sand reserves	64,806		65,876
Operating lease right-of-use assets	14,766		20,179
Intangible assets, net - customer relationships	277		408
Intangible assets, net - trade names	3,194		4,366
Goodwill	12,608		12,608
Deferred income tax asset	8,094		—
Other non-current assets	4,247		5,115
Total assets	$	728,507	$	824,562
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	43,628	$	40,316
Payables to related parties	5		3
Accrued expenses and other current liabilities	54,724		44,408
Current operating lease liability	6,996		8,618
Current portion of long-term debt	1,449		1,165
Income taxes payable	39,283		34,088
Total current liabilities	146,085		128,598

Long-term debt, net of current portion	79,195		81,338
Deferred income tax liabilities	687		24,741
Long-term operating lease liability	7,591		11,377
Asset retirement obligations	3,682		4,746
Other liabilities	15,003		10,435
Total liabilities	252,243		261,235

COMMITMENTS AND CONTINGENCIES (Note 18)

EQUITY
Equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 46,684,065 and 45,769,283 issued and outstanding at September 30, 2021 and December 31, 2020	467		458
Additional paid in capital	537,980		537,039
Retained (deficit) earnings	(59,236)		28,895
Accumulated other comprehensive loss	(2,947)		(3,065)
Total equity	476,264		563,327
Total liabilities and equity	$	728,507	$	824,562

The accompanying notes are an integral part of these condensed consolidated financial statements.

MAMMOTH ENERGY SERVICES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS (unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
REVENUE	(in thousands, except per share amounts)
Services revenue	$	52,417	$	55,279	$	135,975	$	169,002
Services revenue - related parties	601		8,565		15,678		35,228
Product revenue	4,467		4,815		17,932		18,171
Product revenue - related parties	—		1,875		2,145		5,625
Total revenue	57,485		70,534		171,730		228,026

COST AND EXPENSES
Services cost of revenue (exclusive of depreciation, depletion, amortization and accretion of $35,587, $53,448, $20,424 and $65,728, respectively, for the three months and nine months ended September 30, 2021 and three and nine months ended September 30, 2020)	43,538		41,445		128,703		154,397
Services cost of revenue - related parties (exclusive of depreciation, depletion, amortization and accretion of $0, $0, $0 and $0, respectively, for the three and nine months ended September 30, 2021 and three and nine months ended September 30, 2020)	181		131		397		329
Product cost of revenue (exclusive of depreciation, depletion, amortization and accretion of $4,667, $7,051, $2,689 and $7,344, respectively, for the three and nine months ended September 30, 2021 and three and nine months ended September 30, 2020)	9,865		4,353		22,939		21,862

Selling, general and administrative (Note 11)	41,866		11,979		74,312		36,063
Selling, general and administrative - related parties (Note 11)	—		201		385		614
Depreciation, depletion, amortization and accretion	19,148		23,132		60,559		73,130
Impairment of goodwill	—		—		—		54,973
Impairment of other long-lived assets	547		—		547		12,897
Total cost and expenses	115,145		81,241		287,842		354,265
Operating loss	(57,660)		(10,707)		(116,112)		(126,239)

OTHER INCOME (EXPENSE)
Interest expense, net	(1,484)		(1,098)		(3,878)		(4,207)
Other income (expense), net	11,056		7,943		6,004		23,489
Other income (expense), net - related parties	—		1,099		(515)		2,232
Total other income (expense)	9,572		7,944		1,611		21,514
Loss before income taxes	(48,088)		(2,763)		(114,501)		(104,725)
Benefit for income taxes	(7,187)		(6,193)		(26,370)		(8,979)
Net (loss) income	$	(40,901)	$	3,430	$	(88,131)	$	(95,746)

OTHER COMPREHENSIVE INCOME (LOSS)
Foreign currency translation adjustment, net of tax of ($69), ($749), ($95) and $116, respectively, for the three and nine months ended September 30, 2021 and three and nine months ended September 30, 2020	(289)		324		118		(422)
Comprehensive (loss) income	$	(41,190)	$	3,754	$	(88,013)	$	(96,168)

Net (loss) income per share (basic) (Note 14)	$	(0.88)	$	0.07	$	(1.90)	$	(2.10)
Net (loss) income per share (diluted) (Note 14)	$	(0.88)	$	0.07	$	(1.90)	$	(2.10)
Weighted average number of shares outstanding (basic) (Note 14)	46,683		45,764		46,342		45,603
Weighted average number of shares outstanding (diluted) (Note 14)	46,683		46,571		46,342		45,603

The accompanying notes are an integral part of these condensed consolidated financial statements.

MAMMOTH ENERGY SERVICES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (unaudited)


	Three Months Ended September 30, 2021
								Accumulated
				Retained		Additional		Other
	Common Stock			(Deficit)		Paid-In		Comprehensive
	Shares	Amount		Earnings		Capital		Loss		Total
	(in thousands)
Balance at June 30, 2021	46,681	$	467	$	(18,335)	$	537,728	$	(2,658)	$	517,202
Stock based compensation	3	—		—		252		—		252
Net loss	—	—		(40,901)		—		—		(40,901)

Other comprehensive loss	—	—		—		—		(289)		(289)
Balance at September 30, 2021	46,684	$	467	$	(59,236)	$	537,980	$	(2,947)	$	476,264

	Three Months Ended September 30, 2020
								Accumulated
						Additional		Other
	Common Stock			Retained		Paid-In		Comprehensive
	Shares	Amount		Earnings		Capital		Loss		Total
	(in thousands)
Balance at June 30, 2020	45,762	$	458	$	37,326	$	536,333	$	(4,052)	$	570,065
Stock based compensation	3	—		—		352		—		352
Net income	—	—		3,430		—		—		3,430

Other comprehensive income	—	—		—		—		324		324
Balance at September 30, 2020	45,765	$	458	$	40,756	$	536,685	$	(3,728)	$	574,171

	Nine Months Ended September 30, 2021
								Accumulated
				Retained		Additional		Other
	Common Stock			(Deficit)		Paid-In		Comprehensive
	Shares	Amount		Earnings		Capital		Loss		Total
	(in thousands)
Balance at December 31, 2020	45,769	$	458	$	28,895	$	537,039	$	(3,065)	$	563,327
Stock based compensation	915	9		—		941		—		950
Net loss	—	—		(88,131)		—		—		(88,131)

Other comprehensive income	—	—		—		—		118		118
Balance at September 30, 2021	46,684	$	467	$	(59,236)	$	537,980	$	(2,947)	$	476,264

	Nine Months Ended September 30, 2020
								Accumulated
						Additional		Other
	Common Stock			Retained		Paid-In		Comprehensive
	Shares	Amount		Earnings		Capital		Loss		Total
	(in thousands)
Balance at December 31, 2019	45,109	$	451	$	136,502	$	535,094	$	(3,306)	$	668,741

Stock based compensation	656	7		—		1,591		—		1,598
Net loss	—	—		(95,746)		—		—		(95,746)

Other comprehensive loss	—	—		—		—		(422)		(422)
Balance at September 30, 2020	45,765	$	458	$	40,756	$	536,685	$	(3,728)	$	574,171

The accompanying notes are an integral part of these condensed consolidated financial statements.

MAMMOTH ENERGY SERVICES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)


	Nine Months Ended September 30,
	2021		2020
	(in thousands)
Cash flows from operating activities:
Net loss	$	(88,131)	$	(95,746)
Adjustments to reconcile net loss to cash (used in) provided by operating activities:

Stock based compensation	950		1,598
Depreciation, depletion, accretion and amortization	60,559		73,130
Amortization of coil tubing strings	—		359
Amortization of debt origination costs	469		703
Bad debt expense	41,650		2,306
Gain on disposal of property and equipment	(4,632)		(927)
Impairment of goodwill	—		54,973
Impairment of other long-lived assets	547		12,897

Deferred income taxes	(32,183)		(7,334)
Other	502		581
Changes in assets and liabilities:
Accounts receivable, net	(50,666)		(11,707)
Receivables from related parties	28,224		(31,152)
Inventories	2,582		3,827
Prepaid expenses and other assets	9,947		8,803

Accounts payable	2,597		(5,211)
Payables to related parties	2		(508)
Accrued expenses and other liabilities	6,627		(3,166)
Income taxes payable	5,192		(1,644)
Net cash (used in) provided by operating activities	(15,764)		1,782

Cash flows from investing activities:
Purchases of property and equipment	(4,474)		(5,873)
Purchases of property and equipment from related parties	—		(76)


Proceeds from disposal of property and equipment	9,581		4,859

Net cash provided by (used in) investing activities	5,107		(1,090)

Cash flows from financing activities:
Borrowings on long-term debt	31,700		30,800
Repayments of long-term debt	(33,571)		(21,000)
Proceeds from sale leaseback transaction	9,473		—
Payments on sale leaseback transaction	(2,106)		—
Principal payments on financing leases and equipment financing notes	(1,716)		(1,423)

Debt issuance costs	—		(1,000)
Net cash provided by financing activities	3,780		7,377
Effect of foreign exchange rate on cash	8		(57)
Net change in cash and cash equivalents	(6,869)		8,012
Cash and cash equivalents at beginning of period	14,822		5,872
Cash and cash equivalents at end of period	$	7,953	$	13,884

Supplemental disclosure of cash flow information:
Cash paid for interest	$	3,236	$	3,637
Cash paid for income taxes, net of refunds received	$	978	$	13
Supplemental disclosure of non-cash transactions:
Purchases of property and equipment included in accounts payable and accrued expenses	$	2,028	$	2,032

The accompanying notes are an integral part of these condensed consolidated financial statements.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Nature of Business

Mammoth Energy Services, Inc. (“Mammoth Inc.” or the “Company”), together with its subsidiaries, is an integrated, growth-oriented company serving both the oil and gas and the electric utility industries in North America and US territories. Mammoth Inc.’s infrastructure division provides construction, upgrade, maintenance and repair services to various public and private owned utilities. Its oilfield services division provides a diversified set of services to the exploration and production industry including well completion, natural sand and proppant services and drilling services. Additionally, the Company provides aviation services, equipment rentals, crude oil hauling, remote accommodation services, equipment manufacturing and infrastructure engineering and design services.

Operations

The Company’s infrastructure services include construction, upgrade, maintenance and repair services to the electrical infrastructure industry as well as repair and restoration services in response to storms and other disasters. The Company’s well completion services include equipment and personnel used in connection with the completion and early production of oil and natural gas wells. The Company’s natural sand proppant services include the distribution and production of natural sand proppant that is used primarily for hydraulic fracturing in the oil and gas industry. The Company’s drilling services provide drilling rigs and directional tools for both vertical and horizontal drilling of oil and natural gas wells. The Company also provides other services, including aviation, equipment rentals, crude oil hauling, remote accommodations, equipment manufacturing and infrastructure engineering and design services.

All of the Company’s operations are in North America. During the periods presented in this report, the Company provided its infrastructure services primarily in the northeastern, southwestern, midwestern and western portions of the United States. The Company’s infrastructure business depends on infrastructure spending on maintenance, upgrade, expansion and repair and restoration. Any prolonged decrease in spending by electric utility companies, delays or reductions in government appropriations or the failure of customers to pay their receivables could have a material adverse effect on the Company’s results of operations and financial condition. During the periods presented, the Company has operated its oil and natural gas businesses in the Permian Basin, the Utica Shale, the Eagle Ford Shale, the Marcellus Shale, the Granite Wash, the SCOOP, the STACK, the Cana-Woodford Shale, the Cleveland Sand and the oil sands located in Northern Alberta, Canada. The Company’s oil and natural gas business depends in large part on the conditions in the oil and natural gas industry and, specifically, on the amount of capital spending by its customers. Any prolonged increase or decrease in oil and natural gas prices affects the levels of exploration, development and production activity, as well as the entire health of the oil and natural gas industry. Continuation of or further decreases in the commodity prices for oil and natural gas would have a material adverse effect on the Company’s results of operations and financial condition.

2. Basis of Presentation and Significant Accounting Policies

Basis of Presentation

The accompanying unaudited condensed consolidated interim financial statements include the accounts of the Company and its subsidiaries and the variable interest entities (“VIE”) for which the Company is the primary beneficiary. All material intercompany accounts and transactions have been eliminated.

This report has been prepared in accordance with the rules and regulations of the Securities and Exchange Commission, and reflects all adjustments, which in the opinion of management are necessary for the fair presentation of the results for the interim periods, on a basis consistent with the annual audited consolidated financial statements. All such adjustments are of a normal, recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles (“GAAP”) have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and the summary of significant accounting policies and notes thereto included in the Company’s most recent annual report on Form 10-K.

Accounts Receivable

Accounts receivable include amounts due from customers for services performed or goods sold. The Company grants credit to customers in the ordinary course of business and generally does not require collateral. Prior to granting credit to customers, the Company analyzes the potential customer’s risk profile by utilizing a credit report, analyzing macroeconomic factors and using its knowledge of the industry, among other factors. Most areas in the continental United

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

States in which the Company operates provide for a mechanic’s lien against the property on which the service is performed if the lien is filed within the statutorily specified time frame. Customer balances are generally considered delinquent if unpaid by the 30th day following the invoice date and credit privileges may be revoked if balances remain unpaid. Interest on delinquent accounts receivable is recognized in other income when chargeable and collectability is reasonably assured.

During the period October 2017 through March 2019, the Company provided infrastructure services in Puerto Rico under master services agreements entered into by Cobra Acquisitions LLC (“Cobra”), one of the Company’s subsidiaries, with the Puerto Rico Electric Power Authority (“PREPA”) to perform repairs to PREPA’s electrical grid as a result of Hurricane Maria. During the three and nine months ended September 30, 2021 and three and nine months ended September 30, 2020, the Company charged interest on delinquent accounts receivable pursuant to the terms of its agreements with PREPA totaling $9.3 million and $27.0 million, respectively, and $8.2 million and $23.8 million, respectively. These amounts are included in “other income (expense), net” on the unaudited condensed consolidated statement of comprehensive loss. Included in “accounts receivable, net” on the unaudited condensed consolidated balance sheets as of September 30, 2021 and December 31, 2020 were interest charges of $101.2 million and $74.3 million, respectively.

The Company regularly reviews receivables and provides for expected losses through an allowance for doubtful accounts. In evaluating the level of established reserves, the Company makes judgments regarding its customers’ ability to make required payments, economic events and other factors. As the financial condition of customers changes, circumstances develop, or additional information becomes available, adjustments to the allowance for doubtful accounts may be required. In the event the Company expects that a customer may not be able to make required payments, the Company would increase the allowance through a charge to income in the period in which that determination is made. If it is determined that previously reserved amounts are collectible, the Company would decrease the allowance through a credit to income in the period in which that determination is made. Uncollectible accounts receivable are periodically charged against the allowance for doubtful accounts once a final determination is made regarding their collectability.

Following is a roll forward of the allowance for doubtful accounts for the year ended December 31, 2020 and the nine months ended September 30, 2021 (in thousands):


Balance, January 1, 2020	$	5,154
Additions charged to bad debt expense	22,705
Additions charged to other selling, general and administrative expense	3,950
Additions charged to other (expense) income, net - related parties	1,427
Recoveries of receivables previously charged to bad debt expense	(747)
Deductions for uncollectible receivables written off	(2,350)
Balance, December 31, 2020	30,139
Additions charged to bad debt expense	41,799
Additions charged to revenue	27,071
Additions charged to other selling, general and administrative expense	273
Additions charged to other income (expense), net - related parties	515
Additions charged to other income (expense), net	1,394
Recoveries of receivables previously charged to bad debt expense	(149)
Deductions for uncollectible receivables written off	(82,426)
Balance, September 30, 2021	$	18,616

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The Company’s subsidiaries Stingray Pressure Pumping LLC (“Stingray Pressure Pumping”) and Muskie Proppant LLC (“Muskie”) were party to a pressure pumping contract and a sand supply contract, respectively, with Gulfport Energy Corporation (“Gulfport”). On November 13, 2020, Gulfport filed petitions for voluntary relief under chapter 11 of the Bankruptcy Code. On May 17, 2021, Gulfport emerged from bankruptcy. As of November 13, 2020, Gulfport owed the Company approximately $46.9 million, which included interest charges of $3.3 million and attorneys’ fees of $1.8 million. FASB ASC 326, Financial Instruments-Credit Losses, requires a company to reflect its current estimate of all expected credit losses. As a result, the Company recorded reserves on its pre-petition receivables due from Gulfport for products and services, interest and attorneys’ fees of $19.4 million, $1.4 million and $1.8 million, respectively, during the year ended December 31, 2020. On March 22, 2021, Gulfport listed the Stingray Pressure Pumping and Muskie contracts on its master rejection schedule filed with the bankruptcy court. During the first quarter of 2021, the Company recognized unliquidated damages of approximately $46.4 million and recorded reserves on these unliquidated damages as a reduction to revenue of $27.1 million and to bad debt expense of $3.8 million. Also during the first quarter of 2021, the Company recorded additional reserves on its pre-petition products and services and interest receivables of $6.1 million and $0.5 million, respectively. On September 21, 2021, the Company and Gulfport reached a settlement under which all litigation relating to the Stingray Pressure Pumping contract and the Muskie contract will be terminated, Stingray Pressure Pumping will release all claims against Gulfport and its subsidiaries with respect to Gulfport’s bankruptcy proceedings, each of the parties will release all claims they had against the others with respect to the litigation matters discussed in Note 18, and Muskie will have an allowed general unsecured claim against Gulfport of $3.1 million. The settlement remains subject to the final approval by the bankruptcy court overseeing Gulfport’s bankruptcy. As a result of the settlement, during the three months ended September 30, 2021, the Company wrote off its remaining receivable related to the Stingray Pressure Pumping claim resulting in bad debt expense and other expense of $31.0 million and $1.3 million, respectively, and recorded additional bad debt expense related to the Muskie claim totaling $0.2 million. The Company had net accounts receivable due from Gulfport totaling $0.1 million as of September 30, 2021, which is included in “accounts receivable, net” on the unaudited condensed consolidated balance sheets. See Note 3.

Additionally, the Company has made specific reserves consistent with Company policy which resulted in additions to allowance for doubtful accounts totaling $0.6 million and $3.3 million, respectively, for the nine months ended September 30, 2021 and year ended December 31, 2020. These additions were charged to bad debt expense based on the factors described above. Also, during the nine months ended September 30, 2021 and year ended December 31, 2020, the Company recorded additions to allowance for doubtful accounts of $0.3 million and $2.2 million, respectively, related to insurance claim receivables for its directors and officers liability policy. The Company will continue to pursue collection until such time as final determination is made consistent with Company policy.

As of September 30, 2021, PREPA owed Cobra approximately $227.0 million for services performed, excluding $101.2 million of interest charged on these delinquent balances as of September 30, 2021. The Company believes these receivables are collectible. PREPA, however, is currently subject to bankruptcy proceedings, which were filed in July 2017 and are currently pending in the U.S. District Court for the District of Puerto Rico. As a result, PREPA’s ability to meet its payment obligations is largely dependent upon funding from the Federal Emergency Management Agency (“FEMA”) or other sources. On September 30, 2019, Cobra filed a motion with the U.S. District Court for the District of Puerto Rico seeking recovery of the amounts owed to Cobra by PREPA, which motion was stayed by the court. On March 25, 2020, Cobra filed an urgent motion to modify the stay order and allow the recovery of approximately $61.7 million in claims related to a tax gross-up provision contained in the emergency master service agreement, as amended, that was entered into with PREPA on October 19, 2017. This emergency motion was denied on June 3, 2020 and the court extended the stay of our motion. On December 9, 2020, the Court again extended the stay of our motion and directed PREPA to file a status motion by June 7, 2021. On April 6, 2021, Cobra filed a motion to lift the stay order. Following this filing, PREPA initiated discussion with Cobra, which resulted in PREPA and Cobra filing a joint motion to adjourn all deadlines relative to the April 6, 2021 motion until the June 16, 2021 omnibus hearing as a result of PREPA’s understanding that FEMA would release a report in the near future relating to the emergency master service agreement between PREPA and Cobra that was executed on October 19, 2017. The joint motion was granted by the court on April 14, 2021. On May 26, 2021, FEMA issued a Determination Memorandum related to the first contract between Cobra and PREPA in which, among other things, FEMA raised two contract compliance issues and, as a result, concluded that approximately $47 million in costs were not authorized costs under the contract. On June 14, 2021, the Court issued an order adjourning Cobra’s motion to lift the stay order to a hearing on August 4, 2021 and directing Cobra and PREPA to meet and confer in good faith concerning, among other things, (i) the May 26, 2021 Determination Memorandum issued by FEMA and (ii) whether and when a second determination memorandum is expected. The parties were further directed to file an additional status report, which was filed on July 20, 2021. On July 23, 2021, with the aid of Mammoth, PREPA filed an appeal of the entire $47 million that FEMA de-obligated in the May 26, 2021 Determination Memorandum. On August 4, 2021, the Court denied Cobra’s April 6, 2021 motion to lift the stay order, extended the stay of Cobra’s motion

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

seeking recovery of amounts owed to Cobra and directed the parties to file a joint status report by January 19, 2022. In the event PREPA (i) does not have or does not obtain the funds necessary to satisfy its obligations to Cobra under the contracts, (ii) obtains the necessary funds but refuses to pay the amounts owed to the Company or (iii) otherwise does not pay amounts owed to the Company for services performed, the receivable may not be collectible.

Concentrations of Credit Risk and Significant Customers

Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents in excess of federally insured limits and trade receivables. Following is a summary of our significant customers based on percentages of total accounts receivable balances at September 30, 2021 and December 31, 2020 and percentages of total revenues derived for the three and nine months ended September 30, 2021 and 2020:


	REVENUES								ACCOUNTS RECEIVABLE
	Three Months Ended September 30,				Nine Months Ended September 30,				At September 30,		At December 31,
	2021		2020		2021		2020		2021		2020
Customer A(a)	—	%	—	%	—	%	—	%	82	%	71	%
Customer B(b)	—	%	15	%	10	%	18	%	—	%	9	%
Customer C(c)	24	%	—	%	8	%	—	%	3	%	—	%
Customer D(d)	7	%	8	%	9	%	10	%	1	%	2	%

a.Customer A is a third-party customer. The accounts receivable balances from Customer A were derived from the Company’s infrastructure services segment. Accounts receivable for Customer A also includes receivables due for interest charged on delinquent accounts receivable.

b.Customer B was a related-party customer until June 29, 2021. Revenues earned from this customer prior to June 29, 2021 are included in services revenue - related parties and product revenue - related parties on the unaudited condensed consolidated statements of comprehensive loss. The related accounts receivable are included in accounts receivable, net on the unaudited condensed consolidated balance sheet at September 30, 2021 and receivables due from related parties, net at December 31, 2020. Revenues and the related accounts receivable balances earned from Customer B were derived from the Company’s well completion services segment, natural sand proppant services segment and other businesses. Accounts receivable for Customer B also includes receivables due for interest charged on delinquent accounts receivable.

c.Customer C is a third-party customer. Revenues and the related accounts receivable balances earned from Customer C were derived from the Company’s well completion services segment.

d.Customer D is a third-party customer. Revenues and the related accounts receivable balances earned from Customer D were derived from the Company’s infrastructure services segment.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables, amounts receivable or payable to related parties and long-term debt. The carrying amount of cash and cash equivalents, trade receivables, receivables from related parties and trade payables approximates fair value because of the short-term nature of the instruments. The fair value of long-term debt approximates its carrying value because the cost of borrowing fluctuates based upon market conditions.

3. Revenue

The Company’s primary revenue streams include infrastructure services, well completion services, natural sand proppant services, drilling services and other services, which includes coil tubing, pressure control, flowback, cementing, acidizing, equipment rentals, full service transportation, crude oil hauling, remote accommodations, equipment manufacturing and infrastructure engineering and design services. See Note 19 for the Company’s revenue disaggregated by type.

Certain of the Company’s customer contracts include provisions entitling the Company to a termination penalty when the customer invokes its contractual right to terminate prior to the contract’s nominal end date. The termination penalties in the customer contracts vary, but are generally considered substantive for accounting purposes and create enforceable rights and obligations throughout the stated duration of the contract. The Company accounts for a contract cancellation as a contract modification in the period in which the customer invokes the termination provision. The determination of the contract termination penalty is based on the terms stated in the related customer agreement. As of the modification date, the Company updates its estimate of the transaction price using the expected value method, subject to constraints, and recognizes the amount over the remaining performance period.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Infrastructure Services

Infrastructure services are typically provided pursuant to master service agreements, repair and maintenance contracts or fixed price and non-fixed price installation contracts. Pricing under these contracts may be unit priced, cost-plus/hourly (or time and materials basis) or fixed price (or lump sum basis). Generally, the Company accounts for infrastructure services as a single performance obligation satisfied over time. In certain circumstances, the Company supplies materials that are utilized during the jobs as part of the agreement with the customer. The Company accounts for these infrastructure agreements as multiple performance obligations satisfied over time. Revenue is recognized over time as work progresses based on the days completed or as the contract is completed. Under certain customer contracts in our infrastructure services segment, the Company warranties equipment and labor performed for a specified period following substantial completion of the work.

Well Completion Services

Well completion services are typically provided based upon a purchase order, contract or on a spot market basis. Services are provided on a day rate, contracted or hourly basis. Generally, the Company accounts for well completion services as a single performance obligation satisfied over time. In certain circumstances, the Company supplies proppant that is utilized for pressure pumping as part of the agreement with the customer. The Company accounts for these pressure pumping agreements as multiple performance obligations satisfied over time. Jobs for these services are typically short-term in nature and range from a few hours to multiple days. Generally, revenue is recognized over time upon the completion of each segment of work based upon a completed field ticket, which includes the charges for the services performed, mobilization of the equipment to the location, consumable supplies and personnel.

Pursuant to a contract with Gulfport, Stingray Pressure Pumping agreed to provide Gulfport with use of up to two pressure pumping fleets for the period covered by the contract. Under this agreement, performance obligations were satisfied as services were rendered based on the passage of time rather than the completion of each segment of work. Stingray Pressure Pumping had the right to receive consideration from this customer even if circumstances prevent us from performing work. All consideration owed to Stingray Pressure Pumping for services performed during the contractual period is fixed and the right to receive it is unconditional. Gulfport has filed a legal action in Delaware state court seeking the termination of this contract and monetary damages. Further, on November 13, 2020, Gulfport filed petitions for voluntary relief under chapter 11 of the Bankruptcy Code. On March 22, 2021, Gulfport listed the Stingray Pressure Pumping contract on its master rejection schedule filed with the bankruptcy court. The Company determined that these factors changed the scope of the contract, accelerated the duration of, and otherwise changed the rights and obligations of each party to the contract. As a result, the Company accounted for this as a contract modification during the three months ended March 31, 2021. Stingray Pressure Pumping used the expected value method to estimate unliquidated damages totaling $37.9 million, which resulted in the recognition of net revenue totaling $14.8 million and bad debt expense of $2.9 million on previously recognized revenue during the three months ended March 31, 2021. On September 21, 2021, the Company and Gulfport reached a settlement under which all litigation relating to the Stingray Pressure Pumping contract will be terminated. Stingray Pressure Pumping will release all claims against Gulfport and its subsidiaries with respect to Gulfport’s bankruptcy proceedings and each of the parties will release all claims they had against the others with respect to the litigation matters discussed in Note 18. The settlement remains subject to the final approval by the bankruptcy court overseeing Gulfport’s bankruptcy. As a result of this settlement agreement, during the three months ended September 30, 2021, the Company wrote off its remaining receivable related to the Stingray Pressure Pumping claim resulting in bad debt expense and other expense of $31.0 million and $1.3 million, respectively. Gulfport was a related party until June 29, 2021. On June 29, 2021, pursuant to the terms of its plan of reorganization, all of the Company’s shares that Gulfport owned were transferred to a trust for the benefit of certain of Gulfport’s creditors. The revenue recognized related to this agreement is included in “services revenue - related parties” in the accompanying unaudited condensed consolidated statement of comprehensive loss and the related accounts receivable is included in “receivables due from related parties” as of December 31, 2020. See Notes 11 and 18 below.

Additional revenue is generated through labor charges and the sale of consumable supplies that are incidental to the service being performed. Such amounts are recognized ratably over the period during which the corresponding goods and services are consumed.

Natural Sand Proppant Services

The Company sells natural sand proppant through sand supply agreements with its customers. Under these agreements, sand is typically sold at a flat rate per ton or a flat rate per ton with an index-based adjustment. The Company recognizes revenue at the point in time when the customer obtains legal title to the product, which may occur at the production facility, rail origin or at the destination terminal.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Certain of the Company’s sand supply agreements contain a minimum volume commitment related to sand purchases whereby the Company charges a shortfall payment if the customer fails to meet the required minimum volume commitment. These agreements may also contain make-up provisions whereby shortfall payments can be applied in future periods against purchased volumes exceeding the minimum volume commitment. If a make-up right exists, the Company has future performance obligations to deliver excess volumes of product in subsequent months. In accordance with ASC 606, if the customer fails to meet the minimum volume commitment, the Company will assess whether it expects the customer to fulfill its unmet commitment during the contractually specified make-up period based on discussions with the customer and management’s knowledge of the business. If the Company expects the customer will make-up deficient volumes in future periods, revenue related to shortfall payments will be deferred and recognized on the earlier of the date on which the customer utilizes make-up volumes or the likelihood that the customer will exercise its right to make-up deficient volumes becomes remote. As of September 30, 2021, the Company had deferred revenue totaling $7.3 million related to shortfall payments. This amount is included in “accrued expenses and other current liabilities” on the unaudited condensed consolidated balance sheet. If the Company does not expect the customer will make-up deficient volumes in future periods, the breakage model will be applied and revenue related to shortfall payments will be recognized when the model indicates the customer’s inability to take delivery of excess volumes. The Company recognized revenue totaling $6.0 million during the nine months ended September 30, 2021, respectively, and $4.9 million and $14.7 million during the three and nine months ended September 30, 2020, respectively, related to shortfall payments. The Company did not recognize any shortfall revenue during the three months ended September 30, 2021.

In certain of the Company’s sand supply agreements, the customer obtains control of the product when it is loaded into rail cars and the customer reimburses the Company for all freight charges incurred. The Company has elected to account for shipping and handling as activities to fulfill the promise to transfer the sand. If revenue is recognized for the related product before the shipping and handling activities occur, the Company accrues the related costs of those shipping and handling activities.

Pursuant to its contract with Gulfport, Muskie agreed to sell and deliver specified amounts of sand to Gulfport. In September 2020, Muskie filed a lawsuit against Gulfport to recover delinquent payments due under this agreement. On November 13, 2020, Gulfport filed petitions for voluntary relief under chapter 11 of the Bankruptcy Code. On March 22, 2021, Gulfport listed the Muskie contract on its master rejection schedule filed with the bankruptcy court. The Company determined that these factors changed the scope of the contract, accelerated the duration of, and otherwise changed the rights and obligations of each party to the contract. As a result, the Company accounted for this as a contract modification during the three months ended March 31, 2021. Muskie used the expected value method to estimate unliquidated damages totaling $8.5 million, which resulted in the recognition of net revenue totaling $2.1 million and bad debt expense of $1.0 million on previously recognized revenue during the three months ended March 31, 2021. On September 21, 2021, the Company and Gulfport reached a settlement under which all litigation relating to the Muskie contract will be terminated, each of the parties will release all claims they had against the others with respect to the litigation matters discussed in Note 18 and Muskie’s contract claim against Gulfport will be allowed under Gulfport’s plan of reorganization in the amount of $3.1 million. The settlement remains subject to the final approval by the bankruptcy court overseeing Gulfport’s bankruptcy. As a result of this settlement agreement, Muskie recognized bad debt expense of $0.2 million during the three months ended September 30, 2021. As of September 30, 2021, Muskie had net accounts receivable due from Gulfport totaling $0.1 million, which includes a nominal amount of interest on delinquent accounts receivable. Gulfport was a related party until June 29, 2021. The revenue recognized related to this agreement is included in “product revenue - related parties” in the accompanying unaudited condensed consolidated statement of comprehensive loss and the related accounts receivable is included in “accounts receivable, net” in the unaudited condensed consolidated balance sheets as of September 30, 2021 and “receivables due from related parties” as of December 31, 2020. See Notes 11 and 18 below.

Drilling Services

Contract drilling services were provided under daywork contracts. Directional drilling services, including motor rentals, are provided on a day rate or hourly basis, and revenue is recognized as work progresses. Performance obligations are satisfied over time as the work progresses based on the measure of output. Mobilization revenue and costs were recognized over the days of actual drilling. As a result of market conditions, the Company temporarily shut down its contract land drilling operations beginning in December 2019 and rig hauling operations beginning in April 2020.

Other Services

During the periods presented, the Company also provided aviation, coil tubing, pressure control, equipment rentals, full service transportation, crude oil hauling, remote accommodations, equipment manufacturing and infrastructure engineering and design services, which are reported under other services. As a result of market conditions, the Company

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

has temporarily shut down its coil tubing and full service transportation operations beginning in July 2020 and its crude oil hauling operations beginning in July 2021. The Company’s other services are typically provided based upon a purchase order, contract or on a spot market basis. Services are provided on a day rate, contracted or hourly basis. Performance obligations for these services are satisfied over time and revenue is recognized as the work progresses based on the measure of output. Jobs for these services are typically short-term in nature and range from a few hours to multiple days.

Practical Expedients

The Company does not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less and (ii) contracts in which variable consideration is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied distinct good or service that forms part of a single performance obligation.

Contract Balances

Following is a rollforward of the Company’s contract liabilities (in thousands):


Balance, December 31, 2019	$	7,244
Deduction for recognition of revenue	(25,047)
Increase for deferral of shortfall payments	25,436
Increase for deferral of customer prepayments	648
Balance, December 31, 2020	8,281
Deduction for recognition of revenue	(5,308)
Increase for deferral of shortfall payments	4,338
Increase for deferral of customer prepayments	187
Balance, September 30, 2021	$	7,498

The Company did not have any contract assets as of September 30, 2021, December 31, 2020 or December 31, 2019.

Performance Obligations

Revenue recognized in the current period from performance obligations satisfied in previous periods was a nominal amount for the nine months ended September 30, 2021 and 2020. As of September 30, 2021, the Company had unsatisfied performance obligations totaling $3.8 million, which will be recognized over the next six months.

4. Inventories

Inventories consist of raw sand and processed sand available for sale, chemicals and other products sold as a bi-product of completion and production operations and supplies used in performing services. Inventory is stated at the lower of cost or net realizable value on an average cost basis. The Company assesses the valuation of its inventories based upon specific usage, future utility, obsolescence and other factors. A summary of the Company’s inventories is shown below (in thousands):


	September 30,		December 31,
	2021		2020
Supplies	$	5,165	$	6,312
Raw materials	731		613
Work in process	2,900		3,478
Finished goods	642		1,617
Total inventories	$	9,438	$	12,020

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

5. Property, Plant and Equipment

Property, plant and equipment include the following (in thousands):


		September 30,		December 31,
	Useful Life	2021		2020
Pressure pumping equipment	3-5 years	$	220,023	$	217,945
Drilling rigs and related equipment	3-15 years	112,223		113,146
Machinery and equipment	7-20 years	168,631		172,272
Buildings(a)	15-39 years	45,937		48,776
Vehicles, trucks and trailers	5-10 years	104,717		111,911
Coil tubing equipment	4-10 years	7,591		8,541
Land	N/A	13,417		13,417
Land improvements	15 years or life of lease	10,133		10,133
Rail improvements	10-20 years	13,793		13,793
Other property and equipment(b)	3-12 years	18,253		18,640
		714,718		728,574
Deposits on equipment and equipment in process of assembly(c)		3,857		3,191
		718,575		731,765
Less: accumulated depreciation(d)		524,097		480,503
Total property, plant and equipment, net		$	194,478	$	251,262

a. Included in Buildings at each of September 30, 2021 and December 31, 2020 are costs of $7.6 million related to assets under operating leases.

b. Included in Other property and equipment at each of September 30, 2021 and December 31, 2020 are costs of $6.0 million related to assets under operating leases.

c. Deposits on equipment and equipment in process of assembly represents deposits placed with vendors for equipment that is in the process of assembly and purchased equipment that is being outfitted for its intended use. The equipment is not yet placed in service.

d. Includes accumulated depreciation of $6.3 million and $5.0 million at September 30, 2021 and December 31, 2020, respectively, related to assets under operating leases.

Impairment


Water transfer equipment	$	4,203
Crude oil hauling equipment	3,275
Coil tubing equipment	2,160
Flowback equipment	1,514
Rental equipment	1,308
Other equipment	437
Total impairment of other long-lived assets	$	12,897

The Company measured the fair values of these assets using direct and indirect observable inputs (Level 2) based on a market approach. The Company did not record any impairment of other long-lived assets during the three and nine months ended September 30, 2021.

Disposals

Proceeds from customers for horizontal and directional drilling services equipment damaged or lost down-hole are reflected in revenue with the carrying value of the related equipment charged to cost of service revenues and are reported as cash inflows from investing activities in the unaudited condensed consolidated statement of cash flows. For the nine months ended September 30, 2020, proceeds and gains from the sale of equipment damaged or lost down-hole were a nominal amount and $0.7 million, respectively. The Company did not have any proceeds or gains from the sale of

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

equipment damaged or lost down-hole during the three and nine months ended September 30, 2021 and three months ended September 30, 2020.

Proceeds from assets sold or disposed of as well as the carrying value of the related equipment are reflected in “other income (expense), net” on the unaudited condensed consolidated statement of comprehensive loss. For the three and nine months ended September 30, 2021 and 2020, proceeds from the sale of equipment were $4.9 million, $9.5 million, $2.7 million and $4.9 million, respectively, and gains (losses) from the sale or disposal of equipment were $3.0 million, $4.6 million, ($0.6) million and $0.2 million, respectively.

Depreciation, depletion, amortization and accretion

A summary of depreciation, depletion, amortization and accretion expense is below (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Depreciation expense	$	18,179	$	22,305	$	58,625	$	71,645
Depletion expense	684		545		1,069		638
Amortization expense	249		253		756		761
Accretion expense	36		29		109		86
Depreciation, depletion, amortization and accretion	$	19,148	$	23,132	$	60,559	$	73,130

6. Goodwill and Intangible Assets

Goodwill

Changes in the net carrying amount of goodwill by reporting segment (see Note 19) for the nine months ended September 30, 2021 and year ended December 31, 2020 are presented below (in thousands):


	Infrastructure		Well Completion		Sand		Other		Total
Balance as of January 1, 2020
Goodwill	$	891	$	86,043	$	2,684	$	14,830	$	104,448
Accumulated impairment losses	—		(23,423)		(2,684)		(10,760)		(36,867)
	891		62,620		—		4,070		67,581
Acquisitions	—		—		—		—		—
Impairment losses	—		(53,406)		—		(1,567)		(54,973)
Balance as of December 31, 2020
Goodwill	891		86,043		2,684		14,830		104,448
Accumulated impairment losses	—		(76,829)		(2,684)		(12,327)		(91,840)
	891		9,214		—		2,503		12,608
Acquisitions	—		—		—		—		—
Impairment losses	—		—		—		—		—
Balance as of September 30, 2021
Goodwill	891		86,043		2,684		14,830		104,448
Accumulated impairment losses	—		(76,829)		(2,684)		(12,327)		(91,840)
	$	891	$	9,214	$	—	$	2,503	$	12,608

Oil prices declined significantly in March 2020 as a result of geopolitical events that increased the supply of oil in the market as well as effects of the COVID-19 pandemic. As a result, the Company determined that it was more likely than not that the fair value of certain of its reporting units were less than their carrying value. Therefore, the Company performed an interim goodwill impairment test. The Company impaired goodwill associated with Stingray Pressure Pumping, Silverback Energy and WTL Oil LLC, resulting in a $55.0 million impairment charge during the first quarter of 2020. To determine fair value, the Company used a combination of the income and market approaches. The income approach estimates the fair value based on anticipated cash flows that are discounted using a weighted average cost of

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

capital. The market approach estimates the fair value using comparative multiples, which involves significant judgment in the selection of the appropriate peer group companies and valuation multiples. The Company did not recognize any goodwill impairment during the three or nine months ended September 30, 2021.

Intangible Assets

The Company had the following definite lived intangible assets recorded (in thousands):


	September 30,		December 31,
	2021		2020
Customer relationships	$	1,050	$	1,050
Trade names	8,413		9,063
Less: accumulated amortization - customer relationships	(773)		(642)
Less: accumulated amortization - trade names	(5,219)		(4,697)
Intangible assets, net	$	3,471	$	4,774

Amortization expense for intangible assets was $0.2 million and $0.3 million for the three months ended September 30, 2021 and 2020, respectively, and $0.8 million for each of the nine months ended September 30, 2021 and 2020. The original life of customer relationships is six years as of September 30, 2021 with a remaining average useful life of 1.6 years. The original life of trade names ranges from 10 to 20 years as of September 30, 2021 with a remaining average useful life of 5.6 years.

Aggregated expected amortization expense for the future periods is expected to be as follows (in thousands):


Remainder of 2021	$	245
2022	982
2023	865
2024	739
2025	119
Thereafter	521
	$	3,471

Due to market conditions, the Company has temporarily shut down its crude oil hauling operations beginning in July 2021. As a result, the Company recognized impairment of trade names totaling $0.5 million, which is included in impairment of other long-lived assets on the unaudited condensed statements of comprehensive income (loss).

7. Equity Method Investment

On December 21, 2018, Cobra Aviation Services LLC (“Cobra Aviation”) and Wexford Partners Investment Co. LLC (“Wexford Investment”), a related party, formed a joint venture under the name of Brim Acquisitions LLC (“Brim Acquisitions”) to acquire all outstanding equity interest in Brim Equipment Leasing, Inc. (“Brim Equipment”) for a total purchase price of approximately $2.0 million. Cobra Aviation owns a 49% economic interest and Wexford Investment owns a 51% economic interest in Brim Acquisitions, and each member contributed its pro rata portion of Brim Acquisitions’ initial capital of $2.0 million. Brim Acquisitions, through Brim Equipment, owns four commercial helicopters and leases five commercial helicopters for operations, which it uses to provide a variety of services, including short haul, aerial ignition, hoist operations, aerial photography, fire suppression, construction services, animal/capture/survey, search and rescue, airborne law enforcement, power line construction, precision long line operations, pipeline construction and survey, mineral and seismic exploration, and aerial seeding and fertilization.

The Company uses the equity method of accounting to account for its investment in Brim Acquisitions, which had a carrying value of approximately $3.2 million and $3.7 million at September 30, 2021 and December 31, 2020, respectively. The investment is included in “other non-current assets” on the unaudited condensed consolidated balance sheets. The Company recorded equity method adjustments to its investment of a nominal amount and ($0.5) million for the three and nine months ended September 30, 2021, respectively, and $0.5 million and ($0.6) million for the three and nine months ended September 30, 2020, respectively. These amounts are included in “other income (expense), net” on the unaudited condensed consolidated statements of comprehensive loss.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

8. Accrued Expenses and Other Current Liabilities and Other Long-Term Liabilities

Accrued expenses and other current liabilities and other long-term liabilities included the following (in thousands):


	September 30,		December 31,
	2021		2020
Accrued legal settlement(a)	$	18,500	$	—
State and local taxes payable	14,169		13,838
Deferred revenue	7,498		8,281
Sale leaseback liability(b)	3,267		1,290
Accrued compensation and benefits	3,222		3,710
Payroll tax liability	1,897		1,816
Financing leases	1,817		1,499
Insurance reserves	1,637		1,941
Financed insurance premiums(c)	94		10,394
Other	2,623		1,639
Total accrued expenses and other current liabilities	$	54,724	$	44,408

Other Long-Term Liabilities
Sale leaseback liability(b)	$	8,203	$	3,348
Financing leases	4,840		4,618
Payroll tax liability	1,897		1,977
Other	63		492
Total other long-term liabilities	$	15,003	$	10,435

a.In June 2021, the Company reached an agreement to settle a certain legal matter. See Note 18 for additional detail.

b.On December 30, 2020, the Company entered into an agreement with First National Capital, LLC (“FNC”) whereby the Company agreed to sell certain assets from its infrastructure segment to FNC for aggregate proceeds of $5.0 million. Concurrent with the sale of assets, the Company entered into a 36 month lease agreement whereby the Company agreed to lease back the assets at a monthly rental rate of $0.1 million. On June 1, 2021, the Company entered into another agreement with FNC whereby the Company sold additional assets from its infrastructure segment to FNC for aggregate proceeds of $9.5 million and entered into a 42 month lease agreement whereby the Company agreed to lease back the assets at a monthly rental rate of $0.2 million. Under the agreements, the Company has the option to purchase the assets at the end of the lease terms. The Company recorded liabilities for the proceeds received and will continue to depreciate the assets. The Company has imputed an interest rate so that the carrying amount of the financial liabilities will be the expected repurchase price at the end of the initial lease terms.

c.Financed insurance premiums are due in monthly installments, are unsecured and mature within the twelve-month period following the close of the year. As of September 30, 2021 and December 31, 2020, the applicable interest rate associated with financed insurance premiums ranged from 3.45% to 3.75%.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

9. Debt

Long-term debt included the following (in thousands):


	September 30,		December 31,
	2021		2020
Revolving credit facility	$	76,951	$	78,000
Aviation note	3,730		4,551
Unamortized debt issuance costs	(37)		(48)
Total debt	80,644		82,503
Less: current portion	1,449		1,165
Total long-term debt	$	79,195	$	81,338

Mammoth Credit Facility

On October 19, 2018, Mammoth Inc. and certain of its direct and indirect subsidiaries, as borrowers, entered into an amended and restated revolving credit and security agreement with the lenders party thereto and PNC Bank, National Association, as a lender and as administrative agent for the lenders, as amended and restated (the “revolving credit facility”). The revolving credit facility matures on October 19, 2023. Borrowings under the revolving credit facility are secured by the assets of Mammoth Inc., inclusive of the subsidiary companies, and are subject to a borrowing base calculation prepared monthly.

The revolving credit facility also contains various customary affirmative and restrictive covenants. Among the covenants are two financial covenants, including a maximum leverage ratio (2.5 to 1.0) and a minimum fixed charges coverage ratio of at least 1.1 to 1.0.

At September 30, 2021, there were outstanding borrowings under the revolving credit facility of $77.0 million and $43.2 million of available borrowing capacity under the facility, after giving effect to $9.0 million of outstanding letters of credit. At December 31, 2020, there were outstanding borrowings under the revolving credit facility of $78.0 million and $38.7 million of borrowing capacity under the facility, after giving effect to $13.0 million of outstanding letters of credit.

As of December 31, 2020, the Company was in compliance with its financial covenants under the revolving credit facility. However, as a result of the lack of payment from PREPA, which owed Cobra approximately $328.2 million, including interest, as of September 30, 2021, the Company projected that it would likely breach the leverage ratio covenant contained in its revolving credit facility for the fiscal quarter ended September 30, 2021. On November 3, 2021, the Company entered into a third amendment to its revolving credit facility (the “Third Amendment”) to, among other things, (i) suspend the leverage ratio and fixed charges coverage ratio covenants for the quarters ending September 30, 2021 and December 31, 2021, (ii) permanently reduce the maximum revolving advance amount from $130 million to $120 million, (iii) add a minimum adjusted EBITDA financial covenant of $6.0 million for the quarter ending December 31, 2021, (iv) set the applicable margin on all loans at 3.50% during the limited covenant waiver period, (v) add a requirement to maintain revolver availability of not less than $10.0 million at all times during the limited covenant waiver period, (vi) permanently reduce the maximum revolving advance amount in an amount equal to fifty percent (50%) of any mandatory prepayments made with non-recurring proceeds that are received during the limited covenant waiver period, and (vii) eliminate the declaration of unrestricted subsidiaries during the limited covenant waiver period. The limited covenant waiver period commenced on the effective date of the Third Amendment and ends on the earlier to occur of (i) May 15, 2022, (ii) the Company reporting compliance with both the leverage ratio and the fixed charge coverage ratio covenants for either its fiscal quarter ending September 30, 2021 or December 31, 2021, and (iii) the occurrence of any event of default after the effective date of the Third Amendment. Under the Third Amendment, the Company also agreed to engage an advisor during the limited covenant waiver period to advise the Company and its subsidiaries with regard to, among other things, efforts to achieve certain operation efficiencies, improvement in results of operations, and general business strategy, and provide assistance to the Company and its subsidiaries in the preparation of the supplemental reporting and information required by the Third Amendment.

As of November 3, 2021, the Company had $76.1 million in borrowings outstanding under its revolving credit facility, leaving an aggregate of $24.1 million of available borrowing capacity under this facility, after giving effect to $9.0 million of outstanding letters of credit, the $10.0 million reduction in the borrowing base and the requirement to maintain a $10.0 million reserve out of the available borrowing capacity during the limited waiver period.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

If an event of default occurs under the revolving credit facility and remains uncured, it could have a material adverse effect on the Company’s business, financial condition, liquidity and results of operations. The lenders (i) would not be required to lend any additional amounts to the Company, (ii) could elect to increase the interest rate by 200 basis points, (iii) could elect to declare all outstanding borrowings, together with accrued and unpaid interest and fees, to be due and payable, (iv) may have the ability to require the Company to apply all of its available cash to repay outstanding borrowings, and (v) may foreclose on substantially all of the Company’s assets.

Aviation Note

On November 6, 2020, Leopard Aviation LLC (“Leopard”) and Cobra Aviation entered into a 39 month promissory note agreement with Bank7 (the “Aviation Note”) in an aggregate principal amount of $4.6 million and received net proceeds of $4.5 million. The Aviation Note bears interest at a rate based on the Wall Street Journal Prime Rate plus a margin of 1%. Principal and interest payments of $0.1 million are due monthly beginning on March 1, 2021, with a final payment of $0.2 million due on February 1, 2024. The Aviation Note is collateralized by Leopard and Cobra Aviation’s assets, including a $1.8 million certificate of deposit. The Aviation Note contains various customary affirmative and restrictive covenants. Included in the affirmative covenants is a minimum cash requirement, which requires Leopard and Cobra Aviation to maintain a minimum of $0.75 million of cash in accounts held by Bank7 until August 1, 2021.

As of September 30, 2021, the Company did not meet the minimum debt coverage ratio of 1.25 to 1.0 set forth in the Aviation Note. On November 3, 2021, Bank7 granted the Company a waiver of this event of default. The waiver extended the minimum cash requirement until February 15, 2022.

10. Variable Interest Entities

Dire Wolf Energy Services LLC (“Dire Wolf”) and Predator Aviation LLC (“Predator Aviation”), wholly owned subsidiaries of the Company, are party to Voting Trust Agreements with TVPX Aircraft Solutions Inc. (the “Voting Trustee”). Under the Voting Trust Agreements, Dire Wolf transferred 100% of its membership interest in Cobra Aviation and Predator Aviation transferred 100% of its membership interest in Leopard to the respective Voting Trustees in exchange for Voting Trust Certificates. Dire Wolf and Predator Aviation retained the obligation to absorb all expected returns or losses of Cobra Aviation and Leopard. Prior to the transfer of the membership interest to the Voting Trustee, Cobra Aviation was a wholly owned subsidiary of Dire Wolf and Leopard was a wholly owned subsidiary of Predator Aviation. Cobra Aviation owns two helicopters and support equipment, 100% of the equity interest in Air Rescue Systems Corporation (“ARS”) and 49% of the equity interest in Brim Acquisitions. Leopard owns one helicopter. Dire Wolf and Predator Aviation entered into the Voting Trust Agreements in order to meet certain registration requirements.

Dire Wolf’s and Predator Aviation’s voting rights are not proportional to their respective obligations to absorb expected returns or losses of Cobra Aviation and Leopard, respectively, and all of Cobra Aviation’s and Leopard’s activities are conducted on behalf of Dire Wolf and Predator Aviation, which have disproportionately fewer voting rights; therefore, Cobra Aviation and Leopard meet the criteria of a VIE. Cobra Aviation and Leopard’s operational activities are directed by Dire Wolf’s and Predator Aviation’s officers and Dire Wolf and Predator Aviation have the option to terminate the Voting Trust Agreements at any time. Therefore, the Company, through Dire Wolf and Predator Aviation, is considered the primary beneficiary of the VIEs and consolidates Cobra Aviation and Leopard at September 30, 2021.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

11. Selling, General and Administrative Expense

Selling, general and administrative (“SG&A”) expense includes of the following (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Cash expenses:
Compensation and benefits	$	3,353	$	3,449	$	11,379	$	11,138
Professional services	4,571		5,651		13,783		15,335
Other(a)	2,252		2,163		7,058		6,572
Total cash SG&A expense	10,176		11,263		32,220		33,045
Non-cash expenses:
Bad debt provision(b)	31,449		626		41,650		2,306

Stock based compensation	241		291		827		1,326
Total non-cash SG&A expense	31,690		917		42,477		3,632
Total SG&A expense	$	41,866	$	12,180	$	74,697	$	36,677

a. Includes travel-related costs, information technology expenses, rent, utilities and other general and administrative-related costs.

b. The bad debt provision for the three and nine months ended September 30, 2021, includes $31.2 million and $41.2 million, respectively, related to the Stingray Pressure Pumping and Muskie contracts with Gulfport. See Notes 2 and 18.

12. Income Taxes

The Company recorded income tax benefit of $26.4 million for the nine months ended September 30, 2021 compared to $9.0 million for the nine months ended September 30, 2020. The Company’s effective tax rate was 23% and 9% for the nine months ended September 30, 2021 and 2020, respectively.

The effective tax rate for the nine months ended September 30, 2021 differed from the statutory rate of 21% primarily due to the mix of earnings between the United States and Puerto Rico as well as changes in the valuation allowance. Additionally, the Company recorded an unrecognized tax benefit of $0.9 million during the nine months ended September 30, 2021 related to the 2020 tax year returns in Puerto Rico. It is the Company’s policy to recognize interest and applicable penalties, if any, related to uncertain tax positions in income tax expense.

On March 27, 2020, the Coronavirus Aid, Relief, and Economic Security (CARES) Act was enacted and signed into U.S. law in response to the COVID-19 pandemic, and among other things, permits the carryback of certain net operating losses. As a result of the enacted legislation, the Company recognized a $2.4 million net tax expense during the nine months ended September 30, 2020, which consisted of a $4.6 million deferred tax expense and a $7.0 million current tax benefit. This impact, along with the rate impact from non-deductible goodwill impairment, was the primary driver for the difference between the statutory rate of 21% and the effective tax rate for the nine months ended September 30, 2020.

13. Leases

Lessee Accounting

The Company recognized a lease liability equal to the present value of the lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term for all leases with a term in excess of 12 months. For operating leases, lease expense for lease payments is recognized on a straight-line basis over the lease term, while finance leases include both an operating expense and an interest expense component. For all leases with a term of 12 months or less, the Company has elected the practical expedient to not recognize lease assets and liabilities and recognizes lease expense for these short-term leases on a straight-line basis over the lease term.

The Company’s operating leases are primarily for rail cars, real estate, and equipment and its finance leases are primarily for machinery and equipment. Generally, the Company does not include renewal or termination options in its assessment of the leases unless extension or termination for certain assets is deemed to be reasonably certain. The accounting for some of the Company’s leases may require significant judgment, which includes determining whether a contract contains a lease, determining the incremental borrowing rates to utilize in the net present value calculation of lease payments for

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

lease agreements which do not provide an implicit rate and assessing the likelihood of renewal or termination options. Lease agreements that contain a lease and non-lease component are generally accounted for as a single lease component.

The rate implicit in the Company’s leases is not readily determinable. Therefore, the Company uses its incremental borrowing rate based on information available at the commencement date of its leases in determining the present value of lease payments. The Company’s incremental borrowing rate reflects the estimated rate of interest that it would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment.

Lease expense consisted of the following for the three and nine months ended September 30, 2021 and 2020 (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Operating lease expense	$	2,210	$	3,338	$	7,082	$	12,503
Short-term lease expense	113		36		477		323
Finance lease expense:
Amortization of right-of-use assets	412		318		1,179		952
Interest on lease liabilities	51		48		149		153
Total lease expense	$	2,786	$	3,740	$	8,887	$	13,931

Supplemental balance sheet information related to leases as of September 30, 2021 and December 31, 2020 is as follows (in thousands):


	September 30,		December 31,
	2021		2020
Operating leases:
Operating lease right-of-use assets	$	14,766	$	20,179
Current operating lease liability	6,996		8,618
Long-term operating lease liability	7,591		11,377
Finance leases:
Property, plant and equipment, net	$	6,468	$	6,065
Accrued expenses and other current liabilities	1,817		1,499
Other liabilities	4,840		4,618

Other supplemental information related to leases for the three and nine months ended September 30, 2021 and 2020 and as of September 30, 2021 and December 31, 2020 is as follows (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	2,159	$	3,277	$	7,079	$	12,207
Operating cash flows from finance leases	51		48		149		153
Financing cash flows from finance leases	426		344		1,229		940
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	697	$	(4,157)	$	879	$	(6,167)
Finance leases	1,822		237		1,822		210

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


	September 30,		December 31,
	2021		2020
Weighted-average remaining lease term:
Operating leases	3.0 years		3.2 years
Finance leases	3.5 years		4.2 years
Weighted-average discount rate:
Operating leases	3.5	%	3.5	%
Finance leases	3.4	%	3.5	%

Maturities of lease liabilities as of September 30, 2021 are as follows (in thousands):


	Operating Leases		Finance Leases
Remainder of 2021	$	2,235	$	501
2022	6,562		2,005
2023	3,927		2,261
2024	1,977		965
2025	305		524
Thereafter	419		795
Total lease payments	15,425		7,051
Less: Present value discount	838		394
Present value of lease payments	$	14,587	$	6,657

Lessor Accounting

Certain of the Company’s agreements with its customers for drilling services, aviation services and remote accommodation services contain an operating lease component under ASC 842 because (i) there are identified assets, (ii) the customer obtains substantially all of the economic benefits of the identified assets throughout the period of use and (iii) the customer directs the use of the identified assets throughout the period of use. The Company has elected to apply the practical expedient provided to lessors to combine the lease and non-lease components of a contract where the revenue recognition pattern is the same and where the lease component, when accounted for separately, would be considered an operating lease. The practical expedient also allows a lessor to account for the combined lease and non-lease components under ASC 606, Revenue from Contracts with Customers, when the non-lease component is the predominant element of the combined component.

The Company’s lease agreements are generally short-term in nature and lease revenue is recognized over time based on a monthly, daily or hourly rate basis. The Company does not provide an option for the lessee to purchase the rented assets at the end of the lease and the lessees do not provide residual value guarantees on the rented assets. The Company recognized lease revenue of $0.6 million and $0.4 million during the three months ended September 30, 2021 and 2020, respectively, and $1.7 million and $0.9 million during the nine months ended September 30, 2021 and 2020, respectively, which is included in “services revenue” and “services revenue - related parties” on the unaudited condensed consolidated statement of comprehensive loss.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

14. (Loss) Earnings Per Share

Reconciliations of the components of basic and diluted net (loss) income per common share are presented in the table below (in thousands, except per share data):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Basic (loss) earnings per share:
Allocation of (loss) earnings:
Net (loss) income	$	(40,901)	$	3,430	$	(88,131)	$	(95,746)
Weighted average common shares outstanding	46,683		45,764		46,342		45,603
Basic (loss) earnings per share	$	(0.88)	$	0.07	$	(1.90)	$	(2.10)

Diluted (loss) earnings per share:
Allocation of (loss) earnings:
Net (loss) income	$	(40,901)	$	3,430	$	(88,131)	$	(95,746)
Weighted average common shares, including dilutive effect(a)	46,683		46,571		46,342		45,603
Diluted (loss) earnings per share	$	(0.88)	$	0.07	$	(1.90)	$	(2.10)

a. No incremental shares of potentially dilutive restricted stock awards were included for the three and nine months ended September 30, 2021 and nine months ended September 30, 2020 as their effect was antidilutive under the treasury stock method.

15. Equity Based Compensation

Upon formation of certain operating entities by Wexford and Gulfport, specified members of management (the “Specified Members”) and certain non-employee members (the “Non-Employee Members”) were granted the right to receive distributions from the operating entities after the contribution member’s unreturned capital balance was recovered (referred to as “Payout” provision).

On November 24, 2014, the awards were modified in conjunction with the contribution of the operating entities to Mammoth. These awards were not granted in limited or general partner units. The awards are for interests in the distributable earnings of the members of MEH Sub, Mammoth’s majority equity holder.

On the closing date of Mammoth Inc.’s initial public offering (“IPO”), the unreturned capital balance of Mammoth’s majority equity holder was not fully recovered from its sale of common stock in the IPO. As a result, Payout did not occur and no compensation cost was recorded.

Payout for the remaining awards is expected to occur as the contribution member’s unreturned capital balance is recovered from additional sales by MEH Sub of its shares of the Company’s common stock or from dividend distributions, which is not considered probable until the event occurs. For the Specified Member awards, the unrecognized amount, which represents the fair value of the award as of the modification dates or grant date, was $5.6 million.

For the Company’s Non-Employee Member awards, the unrecognized amount, which represents the fair value of the awards as of the date of adoption of ASU 2018-07 was $18.9 million.

16. Stock Based Compensation

The 2016 Plan authorizes the Company’s Board of Directors or the compensation committee of the Company’s Board of Directors to grant restricted stock, restricted stock units, stock appreciation rights, stock options and performance awards. There are 4.5 million shares of common stock reserved for issuance under the 2016 Plan.

Restricted Stock Units

The fair value of restricted stock unit awards was determined based on the fair market value of the Company’s common stock on the date of the grant. This value is amortized over the vesting period.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

A summary of the status and changes of the unvested shares of restricted stock under the 2016 Plan is presented below.


	Number of Unvested Restricted Shares	Weighted Average Grant-Date Fair Value
Unvested shares as of January 1, 2020	221,241	$	22.43
Granted	2,401,446	0.98
Vested	(660,738)	5.32
Forfeited	(47,167)	3.28
Unvested shares as of December 31, 2020	1,914,782	1.21
Granted	128,205	3.90
Vested	(914,782)	1.52
Forfeited	—	—
Unvested shares as of September 30, 2021	1,128,205	$	1.27

As of September 30, 2021, there was $1.0 million of total unrecognized compensation cost related to the unvested restricted stock. The cost is expected to be recognized over a weighted average period of approximately 1.2 years.

Included in cost of revenue and selling, general and administrative expenses is stock based compensation expense of $0.9 million and $1.6 million, respectively, for the nine months ended September 30, 2021 and 2020.

17. Related Party Transactions

Transactions between the subsidiaries of the Company, including Stingray Pressure Pumping, Muskie, Stingray Energy Services LLC (“SR Energy”), Panther Drilling Systems LLC (“Panther Drilling”), Anaconda Manufacturing LLC (“Anaconda”), Cobra Aviation, ARS and Leopard and the following companies are included in Related Party Transactions: Gulfport, Wexford, Grizzly Oil Sands ULC (“Grizzly”), El Toro Resources LLC (“El Toro”), Everest Operations Management LLC (“Everest”); Elk City Yard LLC (“Elk City Yard”), Double Barrel Downhole Technologies LLC (“DBDHT”), Caliber Investment Group LLC (“Caliber”) and Brim Equipment.

Following is a summary of related party transactions (in thousands):


		Three Months Ended September 30,				Nine Months Ended September 30,				At September 30,		At December 31,
		2021		2020		2021		2020		2021		2020
		REVENUES								ACCOUNTS RECEIVABLE
Pressure Pumping and Gulfport	(a)	$	—	$	8,384	$	14,812	$	34,705	$	—	$	25,429
Muskie and Gulfport	(b)	—		1,875		2,145		5,625		—		1,127
SR Energy and Gulfport	(c)	—		—		—		113		—		8
Panther Drilling and El Toro	(d)	468		—		599		38		149		—
Cobra Aviation/ARS/Leopard and Brim Equipment	(e)	133		157		267		343		86		44
Other		—		24		—		29		3		9
		$	601	$	10,440	$	17,823	$	40,853	$	238	$	26,617

		OTHER								ACCOUNTS RECEIVABLE
Pressure Pumping and Gulfport	(a)	$	—	$	1,073	$	(514)	$	2,206	$	—	$	1,841
Muskie and Gulfport	(b)	—		26		(1)		26		—		3
		$	—	$	1,099	$	(515)	$	2,232	$	—	$	1,844
										$	238	$	28,461

a.Pressure Pumping provided pressure pumping, stimulation and related completion services to Gulfport. On June 29, 2021, Gulfport ceased to be a related party. See Note 3.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

b.Muskie agreed to sell and deliver, and Gulfport agreed to purchase, specified annual and monthly amounts of natural sand proppant, subject to certain exceptions specified in the agreement, and pay certain costs and expenses. On June 29, 2021, Gulfport ceased to be a related party. See Note 3.

c.SR Energy provided rental services to Gulfport. On June 29, 2021, Gulfport ceased to be a related party.

d.Panther provides directional drilling services for El Toro, an entity controlled by Wexford, pursuant to a master service agreement.

e.Cobra Aviation, ARS and Leopard lease helicopters to Brim Equipment pursuant to aircraft lease and management agreements.


		Three Months Ended September 30,				Nine Months Ended September 30,				At September 30,		At December 31,
		2021		2020		2021		2020		2021		2020
		COST OF REVENUE								ACCOUNTS PAYABLE
Cobra Aviation/ARS/Leopard and Brim Equipment	(a)	$	18	$	60	$	53	$	81	$	5	$	1
Anaconda and Caliber	(b)	136		62		263		186		—		—
Other		27		9		81		62		—		—
		$	181	$	131	$	397	$	329	$	5	$	1

		SELLING, GENERAL AND ADMINISTRATIVE COSTS
The Company and Caliber	(b)	$	—	$	199	$	374	$	582	$	—	$	—
Other		—		2		11		32		—		2
		$	—	$	201	$	385	$	614	$	—	$	2




										$	5	$	3

a.Cobra Aviation, ARS and Leopard lease helicopters to Brim Equipment pursuant to aircraft lease and management agreements.

b.Caliber leases office space to Anaconda and Mammoth.

On December 21, 2018, Cobra Aviation acquired all outstanding equity interest in ARS and purchased two commercial helicopters, spare parts, support equipment and aircraft documents from Brim Equipment. Following these transactions, and also on December 21, 2018, Cobra Aviation formed a joint venture with Wexford Investments named Brim Acquisitions to acquire all outstanding equity interests in Brim Equipment. Cobra Aviation owns a 49% economic interest and Wexford Investment owns a 51% economic interest in Brim Acquisitions, and each member contributed its pro rata portion of Brim Acquisitions’ initial capital of $2.0 million. Wexford Investments is an entity controlled by Wexford, which owns approximately 48% of the Company’s outstanding common stock.

18. Commitments and Contingencies

Commitments

The Company has entered into agreements with suppliers that contain minimum purchase obligations and agreements to purchase capital equipment. Aggregate future minimum payments under these obligations in effect at September 30, 2021 were approximately $1.5 million.

Letters of Credit

The Company has various letters of credit that were issued under the Company’s revolving credit agreement which is collateralized by substantially all of the assets of the Company. The letters of credit are categorized below (in thousands):


	September 30,		December 31,
	2021		2020
Bonding program	$	1,000	$	5,000
Environmental remediation	3,694		3,694
Insurance programs	3,890		3,890
Rail car commitments	455		455
Total letters of credit	$	9,039	$	13,039

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Insurance

The Company has insurance coverage for physical partial loss to its assets, employer’s liability, automobile liability, commercial general liability, workers’ compensation and insurance for other specific risks. The Company has also elected in some cases to accept a greater amount of risk through increased deductibles on certain insurance policies. As of September 30, 2021 and December 31, 2020, the workers’ compensation and automobile liability policies require a deductible per occurrence of up to $0.3 million and $0.1 million, respectively. As of September 30, 2021 and December 31, 2020, the workers’ compensation and auto liability policies contained an aggregate stop loss of $5.4 million. The Company establishes liabilities for the unpaid deductible portion of claims incurred based on estimates. As of September 30, 2021 and December 31, 2020, accrued claims were $1.6 million and $1.9 million, respectively.

The Company also has insurance coverage for directors and officers liability. As of September 30, 2021 and December 31, 2020, the directors and officers liability policy had a deductible per occurrence of $1.0 million and an aggregate deductible of $10.0 million. As of September 30, 2021 and December 31, 2020, the Company did not have any accrued claims for directors and officers liability.

The Company also self-insures its employee health insurance. The Company has coverage on its self-insurance program in the form of a stop loss of $0.2 million per participant and an aggregate stop-loss of $5.8 million for the calendar year ending December 31, 2021. As of September 30, 2021 and December 31, 2020, accrued claims were $1.2 million and $1.3 million, respectively. These estimates may change in the near term as actual claims continue to develop.

Warranty Guarantees

Pursuant to certain customer contracts in our infrastructure services segment, the Company warrants equipment and labor performed under the contracts for a specified period following substantial completion of the work. Generally, the warranty is for one year or less. No liabilities were accrued as of September 30, 2021 and December 31, 2020 and no expense was recognized during the nine months ended September 30, 2021 or 2020 related to warranty claims. However, if warranty claims occur, the Company could be required to repair or replace warrantied items, which in most cases are covered by warranties extended from the manufacturer of the equipment. In the event the manufacturer of equipment failed to perform on a warranty obligation or denied a warranty claim made by the Company, the Company could be required to pay for the cost of the repair or replacement.

Bonds

In the ordinary course of business, the Company is required to provide bid bonds to certain customers in the infrastructure services segment as part of the bidding process. These bonds provide a guarantee to the customer that the Company, if awarded the project, will perform under the terms of the contract. Bid bonds are typically provided for a percentage of the total contract value. Additionally, the Company may be required to provide performance and payment bonds for contractual commitments related to projects in process. These bonds provide a guarantee to the customer that the Company will perform under the terms of a contract and that the Company will pay subcontractors and vendors. If the Company fails to perform under a contract or to pay subcontractors and vendors, the customer may demand that the surety make payments or provide services under the bond. The Company must reimburse the surety for expenses or outlays it incurs. As of September 30, 2021 and December 31, 2020, outstanding bid bonds totaled $0.1 million and $1.0 million, respectively. As of September 30, 2021 and December 31, 2020, outstanding performance and payment bonds totaled $13.5 million and $18.1 million, respectively. The estimated cost to complete projects secured by the performance and payment bonds totaled $0.5 million as of September 30, 2021.

Litigation

The Company is routinely involved in state and local tax audits. During 2015, the State of Ohio assessed taxes on the purchase of equipment the Company believes is exempt under state law. The Company appealed the assessment and a hearing was held in 2017. As a result of the hearing, the Company received a decision from the State of Ohio. The Company is appealing the decision and while it is not able to predict the outcome of the appeal, this matter is not expected to have a material adverse effect on the Company’s financial position, results of operations or cash flows.

On June 19, 2018, Wendco of Puerto Rico Inc. filed a putative class action lawsuit in the Commonwealth of Puerto Rico styled Wendco of Puerto Rico Inc.; Multisystem Restaurant Inc.; Restaurant Operators Inc.; Apple Caribe, Inc.; on their own behalf and in representation of all businesses that conduct business in the Commonwealth of Puerto Rico vs. Mammoth Energy Services Inc.; Cobra Acquisitions, LLC; D. Grimm Puerto Rico, LLC, et al. The plaintiffs allege that the defendants caused power outages in Puerto Rico while performing restoration work on Puerto Rico’s electrical network following Hurricanes Irma and Maria in 2017, thereby interrupting commercial activities and causing economic loss. The Company believes these claims are without merit and will vigorously defend the action. However, at this time,

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

the Company is not able to predict the outcome of this lawsuit or whether it will have a material impact on the Company’s business, financial condition, results of operations or cash flows.

Cobra has been served with ten lawsuits from municipalities in Puerto Rico alleging failure to pay construction excise and volume of business taxes. The Government of Puerto Rico’s Central Recovery and Reconstruction Office (“COR3”) has noted the unique nature of work executed by entities such as Cobra in Puerto Rico and that taxes, such as those in these matters, may be eligible for reimbursement by the government. Further, COR3 indicated that it is working to develop a solution that will result in payment of taxes owed to the municipalities without placing an undue burden on entities such as Cobra. The Company continues to work with COR3 to resolve these matters. However, at this time, the Company is not able to predict the outcome of these matters or whether they will have a material impact on the Company’s business, financial condition, results of operations or cash flows.

On March 20, 2019, EJ LeJeune, a former employee of ESPADA Logistics and Security Group, LLC and ESPADA Caribbean LLC (together, “ESPADA”) filed a putative collective and class action complaint in LeJeune v. Mammoth Energy Services, Inc. d/b/a Cobra Energy & ESPADA Logistics and Security Group, LLC, Case No. 5:19-cv-00286-JKP-ESC, in the U.S. District Court for the Western District of Texas. On August 5, 2019, the court granted the plaintiff’s motion for leave to amend his complaint, dismissing Mammoth Energy Services, Inc. as a defendant, adding Cobra Acquisitions LLC (“Cobra”) as a defendant, and adding ESPADA Caribbean LLC and two officers of ESPADA—James Jorrie and Jennifer Gay Jorrie—as defendants. The amended complaint alleges that the defendants jointly employed the plaintiff and all similarly situated workers and failed to pay them overtime as required by the Fair Labor Standards Act and Puerto Rico law. The complaint also alleges the following violations of Puerto Rico law: illegal deductions from workers’ wages, failure to timely pay all wages owed, failure to pay a required severance when terminating workers without just cause, failure to pay for all hours worked, failure to provide required meal periods, and failure to pay a statutorily required bonus to eligible workers. Mr. LeJeune seeks to represent a class of workers allegedly employed by one or more defendants and paid a flat amount for each day worked regardless of how many hours were worked. The complaint seeks back wages, including overtime wages owed, liquidated damages equal to the overtime wages owed, attorneys’ fees, costs, and pre- and post-judgment interest. On June 16, 2020, Cobra answered Mr. LeJeune’s amended complaint, denying that it employed Mr. LeJeune and the putative class members and denying that they are entitled to relief from Cobra. All other defendants have also answered the amended complaint. The parties stipulated to conditional certification of a collective action, and on August 14, 2020, the Court ordered that notice be sent to all individuals engaged by ESPADA to provide services to Cobra in Puerto Rico between January 21, 2017 and the present who were paid a day-rate. Notice was sent to putative class members on September 15, 2020, and the opt-in period closed on November 14, 2020. The parties are in discovery. The Company believes these claims are without merit and will vigorously defend the action. However, at this time, the Company is not able to predict the outcome of this lawsuit or whether it will have a material impact on the Company’s business, financial condition, results of operations or cash flows.

On April 16, 2019, Christopher Williams, a former employee of Higher Power Electrical, LLC, filed a putative class and collective action complaint titled Christopher Williams, individually and on behalf of all others similarly situated v. Higher Power Electrical, LLC, Cobra Acquisitions LLC, and Cobra Energy LLC in the U.S. District Court for the District of Puerto Rico. On June 24, 2019, the complaint was amended to replace Mr. Williams with Matthew Zeisset as the named plaintiff. The plaintiff alleges that the Company failed to pay overtime wages to a class of workers in compliance with the Fair Labor Standards Act and Puerto Rico law. On August 21, 2019, upon request of the parties, the court stayed proceedings in the lawsuit pending completion of individual arbitration proceedings initiated by Mr. Zeisset and opt-in plaintiffs. The arbitrations remain pending. Other claimants have initiated individual arbitration proceedings asserting similar claims. In May 2020, six arbitrations were held in the related matters. The Company believes these claims are without merit and will vigorously defend the arbitrations. However, at this time, the Company is not able to predict the outcomes of these proceedings or whether they will have a material impact on the Company’s business, financial condition, results of operations or cash flows.

In June 2019 and August 2019, the Company was served with three class action lawsuits filed in the Western District of Oklahoma (the “Court”). On September 13, 2019, the court consolidated the three lawsuits under the case caption In re Mammoth Energy Services, Inc. Securities Litigation. On November 12, 2019, the plaintiffs filed their first amended complaint against Mammoth Energy Services, Inc., Arty Straehla, and Mark Layton. Pursuant to their first amended complaint, the plaintiffs brought a consolidated putative federal securities class action on behalf of all investors who purchased or otherwise acquired Mammoth Energy Services, Inc. common stock between October 19, 2017, and June 5, 2019, inclusive. On January 10, 2020, the defendants filed their motion to dismiss the first amended complaint. On March 9, 2020, the plaintiffs filed a second amended complaint for violation of federal securities laws which contains allegations substantially similar to those contained in the plaintiff’s first amended complaint. On March 30, 2020, the defendants filed their motion to dismiss the second amended complaint. On January 26, 2021, the court granted the motion to dismiss in

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

part and denied the motion to dismiss in part. In April 2021 a settlement was reached and motion for preliminary approval was filed, which the Court granted on May 4, 2021. On September 21, 2021, the Court issued a final judgment approving the settlement, which released the defendants from all claims asserted in the litigation, or that could have been asserted arising from the subject matter of the litigation and the purchase or acquisition of Mammoth common stock during the class period in return for a cash payment in the amount of $11.0 million for the benefit of the settlement class. The settlement amount is covered in full under Mammoth’s directors’ and officers’ insurance policy.

In September 2019, four derivative lawsuits were filed, two in the Western District of Oklahoma and two in the District of Delaware (the “Court”), purportedly on behalf of the Company against its officers and directors. In October 2019, the plaintiffs in the two Oklahoma actions voluntarily dismissed their respective cases, with one plaintiff refiling his action in the District of Delaware. On September 13, 2019, the Court consolidated the three actions under the case caption In re Mammoth Energy Services, Inc. Consolidated Shareholder Litigation. On January 17, 2020, the plaintiffs filed their consolidated amended shareholder derivative complaint on behalf of Nominal Defendant, Mammoth Energy Services, Inc., and against Arty Straehla, Mark Layton, Arthur Amron, Paul V. Heerwagen IV, Marc McCarthy, Jim Palm, Matthew Ross, Arthur Smith, Gulfport Energy Corporation, and Wexford Capital LP. On October 5, 2021, the plaintiffs and Nominal Defendant Mammoth entered into the Stipulation and Agreement of Settlement (the “Stipulation”) in the derivative action, which was preliminarily approved by the Court on October 28, 2021, and is subject to final approval by the Court. The terms of the Stipulation require that, in exchange for the full release, discharge and dismissal with prejudice of the claims asserted against the defendants in the derivative action, (1) the individual defendants will cause the insurers under Mammoth’s Directors’ and Officers’ (“D&O”) insurance policy (the “D&O insurers”) to pay $1.5 million to Mammoth, which Mammoth will use for general corporate purposes; and (2) Mammoth will adopt certain corporate governance reforms, which will further enhance Mammoth’s current corporate governance policies. Additionally, the Stipulation provides that the individual defendants will cause the D&O insurers to pay, subject to Court approval, a separate payment of $0.5 million to plaintiffs’ counsel for their attorneys’ fees and expenses. The Court has set a hearing date for January 7, 2022 to consider the final approval of the settlement. The final settlement amount is expected to be covered in full under Mammoth’s D&O insurance policy. However, until the Court issues a final order approving the settlement, Mammoth cannot assure you that the derivative action will be settled on the terms set forth herein or at all.

On September 10, 2019, the U.S. District Court for the District of Puerto Rico unsealed an indictment that charged the former president of Cobra Acquisitions LLC with conspiracy, wire fraud, false statements and disaster fraud. Two other individuals were also charged in the indictment. The indictment is focused on the interactions between a former FEMA official and the former president of Cobra. Neither the Company nor any of its subsidiaries were charged in the indictment. The Company is continuing to cooperate with the related investigation. Given the uncertainty inherent in the criminal litigation, it is not possible at this time to determine the potential outcome or other potential impacts that the criminal litigation could have on the Company. PREPA has stated in court filings that it may contend the alleged criminal activity affects Cobra’s entitlement to payment under its contracts with PREPA. Subsequent to the indictment, the Company received (i) a preservation request letter from the United States Securities and Exchange Commission (“SEC”) related to documents relevant to an ongoing investigation it is conducting and (ii) a civil investigative demand (“CID”) from the United States Department of Justice (“DOJ”), which requests certain documents and answers to specific interrogatories relevant to an ongoing investigation it is conducting. Both the aforementioned SEC and DOJ investigations are in connection with the issues raised in the criminal matter. Following the resignation of Jonathan Yellen from the Company’s board of directors and the matters raised in the Company’s Form 8-K filed on May 14, 2020, the Company received an expanded preservation request from the SEC. The Company is cooperating with both the SEC and DOJ and is not able to predict the outcome of these investigations or if either will have a material impact on the Company’s business, financial condition, results of operations or cash flows.

On September 12, 2019, AL Global Services, LLC (“Alpha Lobo”) filed a second amended third-party petition against the Company in an action styled Jim Jorrie v. Craig Charles, Julian Calderas, Jr., and AL Global Services, LLC v. Jim Jorrie v. Cobra Acquisitions LLC v. ESPADA Logistics & Security Group, LLC, ESPADA Caribbean LLC, Arty Straehla, Ken Kinsey, Jennifer Jorrie, and Mammoth Energy Services, Inc., in the 57th Judicial District in Bexar County, Texas. The petition alleges that the Company should be held vicariously liable under alter ego, agency and respondeat superior theories for Alpha Lobo’s alleged claims against Cobra and Arty Straehla for aiding and abetting, knowing participation in and conspiracy to breach fiduciary duty in connection with Cobra’s execution of an agreement with ESPADA Caribbean, LLC for security services related to Cobra’s work in Puerto Rico. The Company believes these claims are without merit and will vigorously defend the action. However, at this time, the Company is not able to predict the outcome of this lawsuit or whether it will have a material impact on the Company’s business, financial condition, results of operations or cash flows. Additionally, there was a parallel arbitration proceeding that was initiated in which certain

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Defendants sought a declaratory judgment regarding Cobra’s rights to terminate the Alpha Lobo contract and enter into a new contract with a third-party. On June 24, 2021, the arbitration panel ruled in favor of Cobra.

As of September 30, 2021, PREPA owed the Company approximately $227.0 million for services performed, excluding $101.2 million of interest charged on these delinquent balances as of September 30, 2021. The Company believes these receivables are collectible. PREPA, however, is currently subject to bankruptcy proceedings, which were filed in July 2017 and are currently pending in the U.S. District Court for the District of Puerto Rico. As a result, PREPA’s ability to meet its payment obligations is largely dependent upon funding from FEMA or other sources. On September 30, 2019, Cobra filed a motion with the U.S. District Court for the District of Puerto Rico seeking recovery of the amounts owed to Cobra by PREPA, which motion was stayed by the court. On March 25, 2020, Cobra filed an urgent motion to modify the stay order and allow the recovery of approximately $61.7 million in claims related to a tax gross-up provision contained in the emergency master service agreement, as amended, that was entered into with PREPA on October 19, 2017. This emergency motion was denied on June 3, 2020 and the court extended the stay of our motion. On December 9, 2020, the Court again extended the stay of our motion and directed PREPA to file a status motion by June 7, 2021. On April 6, 2021, Cobra filed a motion to lift the stay order. Following this filing, PREPA initiated discussion, which resulted in PREPA and Cobra filing a joint motion to adjourn all deadlines relative to the April 6, 2021 motion until the June 16, 2021 omnibus hearing as a result of PREPA’s understanding that FEMA will release a report in the near future relating to the emergency master service agreement between PREPA and Cobra that was executed on October 19, 2017. The joint motion was granted by the court on April 14, 2021. On May 26, 2021, FEMA issued a Determination Memorandum related to the first contract between Cobra and PREPA in which, among other things, FEMA raised two contract compliance issues and, as a result, concluded that approximately $47 million in costs were not authorized costs under the contract. On June 14, 2021, the Court issued an order adjourning Cobra’s motion to lift the stay order to a hearing on August 4, 2021 and directing Cobra and PREPA to meet and confer in good faith concerning (i) the May 26, 2021 Determination Memorandum issued by FEMA and (ii) whether and when a second determination memorandum is expected. The parties were further directed to file an additional status report, which was filed on July 20, 2021. On July 23, 2021, with the aid of Mammoth, PREPA filed an appeal of the entire $47 million that FEMA de-obligated in the May 26, 2021 Determination Memorandum. On August 4, 2021, the Court extended the stay and ordered a joint status report to be filed on January 19, 2022. In the event PREPA (i) does not have or does not obtain the funds necessary to satisfy its obligations to Cobra under the contracts, (ii) obtains the necessary funds but refuses to pay the amounts owed to the Company or (iii) otherwise does not pay amounts owed to the Company for services performed, the receivable may not be collectible.

On December 28, 2019, Gulfport filed a lawsuit against Stingray Pressure Pumping in the Superior Court of the State of Delaware. Pursuant to the complaint, Gulfport seeks to terminate the October 1, 2014, Amended and Restated Master Services Agreement for Pressure Pumping Services between Gulfport and Stingray Pressure Pumping (“MSA”). In addition, Gulfport alleges breach of contract and seeks damages for alleged overpayments and audit costs under the MSA and other fees and expenses associated with this lawsuit. On March 26, 2020, Stingray Pressure Pumping filed a counterclaim against Gulfport seeking to recover unpaid fees and expenses due to Stingray Pressure Pumping under the MSA. In September 2020, Muskie filed a lawsuit against Gulfport to recover delinquent payments due under a natural sand proppant supply contract. These matters were automatically stayed as a result of Gulfport’s bankruptcy filing. On November 13, 2020, Gulfport filed petitions for voluntary relief under chapter 11 of the Bankruptcy Code. Gulfport emerged from bankruptcy on May 17, 2021. As of November 13, 2020, Gulfport owed the Company approximately $46.9 million, which included interest charges of $3.3 million and $1.8 million in attorneys’ fees. FASB ASC 326, Financial Instruments-Credit Losses, requires companies to reflect its current estimate of all expected credit losses. As a result, the Company recorded reserves on its pre-petition receivables due from Gulfport for products and services, interest and attorneys’ fees of $19.4 million, $1.4 million and $1.8 million, respectively, during the year ended December 31, 2020. On March 22, 2021, Gulfport listed the Stingray Pressure Pumping and Muskie contracts on its master rejection schedule filed with the bankruptcy court. During the first quarter of 2021, the Company recognized unliquidated damages of approximately $46.4 million and recorded reserves on these unliquidated damages as a reduction to revenue of $27.1 million and to bad debt expense of $3.8 million. Also during the first quarter of 2021, the Company recorded additional reserves on its pre-petition products and services and interest receivables of $6.1 million and $0.5 million, respectively. On September 21, 2021, the Company and Gulfport reached a settlement under which all litigation relating to the Stingray Pressure Pumping contract and the Muskie contract will be terminated, Stingray Pressure Pumping will release all claims against Gulfport and its subsidiaries with respect to Gulfport’s bankruptcy proceedings, each of the parties will release all claims they had against the others with respect to the litigation matters discussed above and Muskie will have an allowed general unsecured claim against Gulfport of $3.1 million. The settlement remains subject to the final approval by the bankruptcy court overseeing Gulfport’s bankruptcy. As a result, during the three months ended September 30, 2021, the Company wrote off its remaining receivable related to the Stingray Pressure Pumping claim resulting in bad debt expense

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

and other expense of $31.0 million and $1.3 million, respectively, and recorded additional bad debt expense related to the Muskie claim totaling $0.2 million. The Company had net accounts receivable due from Gulfport totaling $0.1 million as of September 30, 2021, which is included in “accounts receivable, net” on the unaudited condensed consolidated balance sheets. See Note 3.

On January 21, 2020, MasTec Renewables Puerto Rico, LLC (“MasTec”) filed a lawsuit against Mammoth Inc. and Cobra, in the U.S. District Court for the Southern District of Florida. Pursuant to its complaint, MasTec asserts claims against the Company and Cobra for violations of the federal Racketeer Influenced and Corrupt Organizations Act (“RICO”), tortious interference and violations of a Puerto Rico statute. MasTec alleged that it sustained injuries to its business and property in an unspecified amount because it lost the opportunity to perform work in connection with rebuilding the energy infrastructure in Puerto Rico after Hurricane Maria under a services contract with a maximum value of $500 million due to the Company’s and Cobra’s wrongful interference, payment of bribes, and other inducements to a FEMA official. On April 1, 2020, the defendants filed a motion to dismiss the complaint. On October 14, 2020, the court dismissed the RICO claims, and on November 18, 2020, dismissed the claims arising under the Puerto Rico statute and the cause of action for tortious interference with MasTec’s contract (but not its business relations), and dismissed Mammoth Inc. from the litigation. On August 2, 2021, in order to avoid the risks of further litigation, and with no admission of wrongdoing whatsoever, the Company reached an agreement to settle this matter. Under the terms of the agreement, Cobra paid $6.5 million to MasTec on August 2, 2021 and the Company guaranteed payment, by Cobra, of $9.25 million on both August 1, 2022 and December 1, 2022. The agreement bears interest at rates between 6% and 12% and includes an acceleration clause that requires Cobra to pay within ten days all unpaid amounts if Cobra collects $100 million or more of specified receivables. These amounts are reflected in the accompanying unaudited condensed consolidated balance sheet and in “other income (expense), net” on the accompanying condensed consolidated statement of comprehensive loss.

On May 13, 2021, Foreman Electric Services, Inc. (“Foreman”) filed a petition against Mammoth Inc. and Cobra, in the U.S. District Court of Oklahoma County. Pursuant to its complaint, Foreman asserted claims against the Company and Cobra for violations of the federal RICO act, tortious interference and violations of Puerto Rico statutes. Foreman alleged that it sustained injuries to its business and property in the alleged amount of $250 million due to the Company’s and Cobra’s wrongful interference, payment of bribes and other inducements to a FEMA official. On May 18, 2021, the Company removed this action to the United States District Court for the Western District of Oklahoma. On July 29, 2021, Foreman voluntarily dismissed the action without prejudice.

The Company is involved in various other legal proceedings in the ordinary course of business. Although the Company cannot predict the outcome of these proceedings, legal matters are subject to inherent uncertainties and there exists the possibility that the ultimate resolution of these matters could have a material adverse effect on the Company’s business, financial condition, results of operations or cash flows.

Defined Contribution Plan

The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at their date of hire. The plan allows eligible employees to contribute up to 92% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes discretionary matching contributions of up to 3% of an employee’s compensation and may make additional discretionary contributions for eligible employees. For the nine months ended September 30, 2021 and 2020, the Company paid $1.3 million and $1.5 million, respectively, in contributions to the plan.

19. Reporting Segments

As of September 30, 2021, the Company’s revenues, income before income taxes and identifiable assets are primarily attributable to four reportable segments. The Company principally provides electric infrastructure services to private utilities, public investor-owned utilities and co-operative utilities and services in connection with on-shore drilling of oil and natural gas wells for small to large domestic independent oil and natural gas producers.

The Company’s Chief Executive Officer and Chief Financial Officer comprise the Company’s Chief Operating Decision Maker function (“CODM”). Segment information is prepared on the same basis that the CODM manages the segments, evaluates the segment financial statements and makes key operating and resource utilization decisions. Segment evaluation is determined on a quantitative basis based on a function of operating loss less impairment expense, as well as a qualitative basis, such as nature of the product and service offerings and types of customers.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

As of September 30, 2021, the Company’s four reportable segments include infrastructure services (“Infrastructure”), well completion services (“Well Completion”), natural sand proppant services (“Sand”) and drilling services (“Drilling”). Prior to the year ended December 31, 2020, the Company included Barracuda Logistics LLC in its Well Completion segment, Cobra Aviation, ARS and Leopard in its Infrastructure segment and Mako Acquisitions LLC in its Drilling segment. Based on its assessment of FASB ASC 280, Segment Reporting, guidance at December 31, 2020, the Company changed its presentation in 2020 to move Barracuda to the Sand segment and Cobra Aviation, ARS, Leopard and Mako to the reconciling column titled “All Other”. Additionally, the Company changed the name of its pressure pumping segment to the well completion segment in 2020. The results for the three and nine months ended September 30, 2020 have been retroactively adjusted to reflect this change in reportable segments.

The Infrastructure segment provides electric utility infrastructure services to government-funded utilities, private utilities, public investor-owned utilities and co-operative utilities in the northeastern, southwestern, midwestern and western portions of the United States. The Well Completion segment provides hydraulic fracturing and water transfer services primarily in the Utica Shale of Eastern Ohio, Marcellus Shale in Pennsylvania and the mid-continent region. The Sand segment mines, processes and sells sand for use in hydraulic fracturing. The Sand segment primarily services the Utica Shale, Permian Basin, SCOOP, STACK and Montney Shale in British Columbia and Alberta, Canada. During certain of the periods presented, the Drilling segment provided contract land and directional drilling services primarily in the Permian Basin and mid-continent region.

During certain of the periods presented, the Company also provided aviation services, coil tubing services, equipment rental services, full service transportation, crude oil hauling services, remote accommodation, equipment manufacturing and infrastructure engineering and design services. The businesses that provide these services are distinct operating segments, which the CODM reviews independently when making key operating and resource utilization decisions. None of these operating segments meet the quantitative thresholds of a reporting segment and do not meet the aggregation criteria set forth in ASC 280 Segment Reporting. Therefore, results for these operating segments are included in the column titled “All Other” in the tables below. Additionally, assets for corporate activities, which primarily include cash and cash equivalents, inter-segment accounts receivable, prepaid insurance and certain property and equipment, are included in the All Other column. Although Mammoth Energy Partners LLC, which holds these corporate assets, meets one of the quantitative thresholds of a reporting segment, it does not engage in business activities from which it may earn revenues and its results are not regularly reviewed by the Company’s CODM when making key operating and resource utilization decisions. Therefore, the Company does not include it as a reportable segment.

Sales from one segment to another are generally priced at estimated equivalent commercial selling prices. Total revenue and Total cost of revenue amounts included in the Eliminations column in the following tables include inter-segment transactions conducted between segments. Receivables due for sales from one segment to another and for corporate allocations to each segment are included in the Eliminations column for Total assets in the following tables. All transactions conducted between segments are eliminated in consolidation. Transactions conducted by companies within the same reporting segment are eliminated within each reporting segment. The following tables set forth certain financial information with respect to the Company’s reportable segments (in thousands):

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Three months ended September 30, 2021	Infrastructure		Well Completion		Sand		Drilling		All Other		Eliminations		Total
Revenue from external customers	$	23,489	$	22,702	$	4,439	$	1,184	$	5,671	$	—	$	57,485
Intersegment revenues	—		30		3,980		23		482		(4,515)		—
Total revenue	23,489		22,732		8,419		1,207		6,153		(4,515)		57,485
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion	20,541		18,125		9,368		1,566		4,917		—		54,517
Intersegment cost of revenues	54		3,204		—		—		324		(4,515)		(933)
Total cost of revenue	20,595		21,329		9,368		1,566		5,241		(4,515)		53,584
Selling, general and administrative	4,586		34,606		1,068		288		1,318		—		41,866
Depreciation, depletion, amortization and accretion	4,933		6,538		2,533		1,942		3,202		—		19,148

Impairment of other long-lived assets	—		—		—		—		547		—		547
Operating loss	(6,625)		(39,741)		(4,550)		(2,589)		(4,155)		—		(57,660)
Interest expense, net	971		215		107		56		135		—		1,484
Other (income) expense, net	(9,256)		755		(46)		(66)		(2,443)		—		(11,056)
Income (loss) before income taxes	$	1,660	$	(40,711)	$	(4,611)	$	(2,579)	$	(1,847)	$	—	$	(48,088)


Three months ended September 30, 2020	Infrastructure		Well Completion		Sand		Drilling		All Other		Eliminations		Total
Revenue from external customers	$	43,582	$	15,738	$	6,031	$	1,193	$	3,990	$	—	$	70,534
Intersegment revenues	—		27		—		11		687		(725)		—
Total revenue	43,582		15,765		6,031		1,204		4,677		(725)		70,534
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion	28,883		6,510		4,154		1,955		4,427		—		45,929
Intersegment cost of revenues	162		449		—		—		114		(725)		—
Total cost of revenue	29,045		6,959		4,154		1,955		4,541		(725)		45,929
Selling, general and administrative	7,227		1,721		1,056		382		1,794		—		12,180
Depreciation, depletion, amortization and accretion	7,294		7,189		2,700		2,294		3,655		—		23,132


Operating income (loss)	16		(104)		(1,879)		(3,427)		(5,313)		—		(10,707)
Interest expense, net	623		253		70		60		92		—		1,098
Other (income) expense, net	(8,375)		(1,156)		1,792		20		(1,323)		—		(9,042)
Income (loss) before income taxes	$	7,768	$	799	$	(3,741)	$	(3,507)	$	(4,082)	$	—	$	(2,763)


Nine months ended September 30, 2021	Infrastructure		Well Completion		Sand		Drilling		All Other		Eliminations		Total
Revenue from external customers	$	69,965	$	62,939	$	20,031	$	3,234	$	15,561	$	—	$	171,730
Intersegment revenues	—		120		3,980		54		1,804		(5,958)		—
Total revenue	69,965		63,059		24,011		3,288		17,365		(5,958)		171,730
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion	66,864		42,339		22,631		4,739		15,466		—		152,039
Intersegment cost of revenues	165		5,449		—		—		344		(5,958)		—
Total cost of revenue	67,029		47,788		22,631		4,739		15,810		(5,958)		152,039
Selling, general and administrative	18,222		47,111		4,108		1,105		4,151		—		74,697
Depreciation, depletion, amortization and accretion	17,499		19,668		7,059		6,185		10,148		—		60,559

Impairment of other long-lived assets	—		—		—		—		547		—		547
Operating loss	(32,785)		(51,508)		(9,787)		(8,741)		(13,291)		—		(116,112)
Interest expense, net	2,287		688		291		177		435		—		3,878
Other (income) expense, net	(2,663)		1,196		(892)		(201)		(2,929)		—		(5,489)
Loss before income taxes	$	(32,409)	$	(53,392)	$	(9,186)	$	(8,717)	$	(10,797)	$	—	$	(114,501)

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Nine months ended September 30, 2020	Infrastructure		Well Completion		Sand		Drilling		All Other		Eliminations		Total
Revenue from external customers	$	99,307	$	74,549	$	22,421	$	7,166	$	24,583	$	—	$	228,026
Intersegment revenues	—		1,080		95		16		2,046		(3,237)		—
Total revenue	99,307		75,629		22,516		7,182		26,629		(3,237)		228,026
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion	80,780		40,454		21,845		9,592		23,917		—		176,588
Intersegment cost of revenues	197		1,410		—		151		1,479		(3,237)		—
Total cost of revenue	80,977		41,864		21,845		9,743		25,396		(3,237)		176,588
Selling, general and administrative	19,001		5,347		3,737		2,776		5,816		—		36,677
Depreciation, depletion, amortization and accretion	22,416		23,346		7,380		7,814		12,174		—		73,130
Impairment of goodwill	—		53,406		—		—		1,567		—		54,973
Impairment of other long-lived assets	—		4,203		—		326		8,368		—		12,897
Operating loss	(23,087)		(52,537)		(10,446)		(13,477)		(26,692)		—		(126,239)
Interest expense, net	2,091		857		217		450		592		—		4,207
Other (income) expense, net	(24,082)		(2,444)		1,753		(251)		(697)		—		(25,721)
Loss before income taxes	$	(1,096)	$	(50,950)	$	(12,416)	$	(13,676)	$	(26,587)	$	—	$	(104,725)


	Infrastructure		Well Completion		Sand		Drilling		All Other		Eliminations		Total
As of September 30, 2021:
Total assets	$	423,267	$	70,335	$	159,215	$	29,295	$	111,434	$	(65,039)	$	728,507
As of December 31, 2020:
Total assets	$	436,604	$	99,247	$	172,927	$	36,252	$	135,194	$	(55,662)	$	824,562

20. Subsequent Events

As discussed above, on November 3, 2021, the Company entered into a third amendment to its revolving credit facility. See Note 9 above for details.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read in conjunction with the unaudited condensed consolidated financial statements and related notes thereto presented in this Quarterly Report and the consolidated financial statements and related notes thereto included in our Annual Report on Form 10-K. This discussion contains forward-looking statements reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in Item 1A. “Risk Factors” in our Form 10-K for the year ended December 31, 2020, filed with the Securities and Exchange Commission, or the SEC, on March 1, 2021 and the section entitled “Forward-Looking Statements” appearing elsewhere in this Quarterly Report.

Overview

We are an integrated, growth-oriented company serving both the electric utility and oil and gas industries in North America. Our primary business objective is to grow our operations and create value for stockholders through organic growth opportunities and accretive acquisitions. Our suite of services includes infrastructure services, well completion services, natural sand proppant services, drilling services and other services. Our infrastructure services division provides construction, upgrade, maintenance and repair services to the electrical infrastructure industry. Our well completion services division provides hydraulic fracturing, sand hauling and water transfer services. Our natural sand proppant services division mines, processes and sells natural sand proppant used for hydraulic fracturing. Our drilling services division currently provides rental equipment, such as mud motors and operational tools, for both vertical and horizontal drilling. In addition to these service divisions, we also provide aviation services, equipment rentals, crude oil hauling services, remote accommodations, equipment manufacturing and infrastructure engineering and design services. We believe that the services we offer play a critical role in maintaining and improving electrical infrastructure as well as in increasing the ultimate recovery and present value of production streams from unconventional resources. Our complementary suite of services provides us with the opportunity to cross-sell our services and expand our customer base and geographic positioning.

Our transformation towards an industrial based company is ongoing. We offer infrastructure engineering services focused on the transmission and distribution industry and also have equipment manufacturing operations as well as fiber optic services. Our equipment manufacturing operations provide us with the ability to repair much of our existing equipment in-house, as well as the option to manufacture certain new equipment we may need in the future. The equipment manufacturing operations have initially served the internal needs for our water transfer, equipment rental and infrastructure businesses, but we expect to expand into third party sales in the future. Our fiber optic services include the installation of both aerial and buried fiber. We are continuing to explore other opportunities to expand our business lines as we shift to a broader industrial focus.

Recent Developments

Impact of the COVID-19 Pandemic and Volatility in Commodity Prices

In March and April 2020, concurrent with the spread of COVID-19 and quarantine orders in the U.S. and worldwide, oil prices dropped sharply to below zero for the first time in history due to factors including significantly reduced demand and a shortage of storage facilities. Beginning in early March 2020, in response to the COVID-19 pandemic and the depressed commodity prices, many exploration and production companies, including our customers, immediately began to substantially reduce their capital expenditure budgets. As a result, demand for our oilfield services declined at the end of the first quarter of 2020 and continued to decline further throughout the remainder of 2020. Exploration and production companies set their 2021 budgets based on the prevailing prices for oil and gas at the time. Although demand for oil and natural gas and commodity prices have recently increased, these budgets have remained and are expected to remain relatively unchanged throughout the fourth quarter of 2021 with any excess cash flows used for debt repayment or return to shareholders rather than to increase production, as has been the case in the past. Despite the recent improvement in the U.S. economic activity, easing of the COVID-19 pandemic and rising energy use and commodity prices, the near term energy outlook remains subject to heightened levels of uncertainty related to the ongoing economic recovery. Further, on July 18, 2021, the OPEC+ reached an agreement to phase out 5.8 million barrels per day of oil production cuts by September 2022 as prices of crude oil reached their highest levels in more than two years. Coordinated increases in oil supply by OPEC+ began in August 2021, increasing overall oil production by 400,000 barrels per day on a monthly basis from that point forward. We cannot predict the impact of the gradual OPEC+ supply boost on commodity prices and expect a competitive and challenging market for oilfield services for the foreseeable future, which has had, and is likely to continue to have, an adverse effect on both pricing and utilization for our oilfield services and our financial condition and results of operations.

We have taken, and continue to take, responsible steps to protect the health and safety of our employees during the COVID-19 pandemic. We are also actively monitoring the recovery process from the COVID-19 pandemic and the adverse industry and market conditions and have taken mitigating steps in an effort to preserve liquidity, reduce costs and lower capital expenditures. These actions have included reducing headcount, adjusting pay and limiting spending. We will continue to take further actions that we deem to be in the best interest of the Company and our stockholders if the current conditions worsen. Given the dynamic nature of these events, we are unable to predict the ultimate impact of the COVID-19 pandemic, the volatility in commodity markets, the reduced demand for oil and oilfield services and uncertain macroeconomic conditions on our business, financial condition, results of operations, cash flows and stock price or the pace or extent of any subsequent recovery.

Third Quarter 2021 Financial Overview

•Reported a 21% increase in revenue for the third quarter of 2021, as compared to the second quarter of 2021, reflecting revenue increases in each of our operating segments.

•Net loss of $41 million, or $0.88 per diluted share for the three months ended September 30, 2021.

•Adjusted EBITDA of ($30) million for the three months ended September 30, 2021, which includes bad debt expense of $31 million. See “Non-GAAP Financial Measures” below for a reconciliation of net loss to Adjusted EBITDA.

Industry Overview

Energy Infrastructure Industry

In 2017, we expanded into the electric infrastructure business, offering both commercial and storm restoration services to government-funded utilities, private utilities, public investor owned utilities and cooperatives. Since we commenced operations in this line of business, a substantial portion of our infrastructure revenue has been generated from storm restoration work, primarily from the Puerto Rico Electric Power Authority, or PREPA, due to damage caused by Hurricane Maria. On October 19, 2017, Cobra Acquisitions LLC, or Cobra, and PREPA entered into an emergency master services agreement for repairs to PREPA’s electrical grid. The one-year contract, as amended, provided for payments of up to $945 million. On May 26, 2018, Cobra and PREPA entered into a new one-year, $900 million master services agreement to provide additional repair services and begin the initial phase of reconstruction of the electrical power system in Puerto Rico. Our work under each of the contracts with PREPA ended on March 31, 2019.

As of September 30, 2021, PREPA owed us approximately $227 million for services performed excluding approximately $101 million of interest charged on these delinquent balances as of September 30, 2021. See Note 2. Basis of Presentation and Significant Accounting Policies—Accounts Receivable of our unaudited condensed consolidated financial statements. PREPA is currently subject to bankruptcy proceedings, which were filed in July 2017 and are currently pending in the U.S. District Court for the District of Puerto Rico. As a result, PREPA’s ability to meet its payment obligations under the contracts is largely dependent upon funding from the Federal Emergency Management Agency, or FEMA, or other sources. On September 30, 2019, we filed a motion with the U.S. District Court for the District of Puerto Rico seeking recovery of the amounts owed to us by PREPA, which motion was stayed by the court. On March 25, 2020, we filed an urgent motion to modify the stay order and allow our recovery of approximately $62 million in claims related to a tax gross-up provision contained in the emergency master service agreement, as amended, that was entered into with PREPA on October 19, 2017. This emergency motion was denied on June 3, 2020 and the court extended the stay of our motion. On December 9, 2020, the Court again extended the stay of our motion and directed PREPA to file a status motion by June 7, 2021. On April 6, 2021, we filed a motion to lift the stay order. Following this filing, PREPA initiated discussion, which resulted in PREPA and Cobra filing a joint motion to adjourn all deadlines relative to the April 6, 2021 motion until the June 16, 2021 omnibus hearing as a result of PREPA’s understanding that FEMA will release a report in the near future relating to the emergency master service agreement between PREPA and Cobra that was executed on October 19, 2017. The joint motion was granted by the court on April 14, 2021. On May 26, 2021, FEMA issued a Determination Memorandum related to the first contract between Cobra and PREPA in which, among other things, FEMA raised two contract compliance issues and, as a result, concluded that approximately $47 million in costs were not authorized costs under the contract. On June 14, 2021, the Court issued an order adjourning Cobra’s motion to lift the stay order to a hearing on August 4, 2021 and directing Cobra and PREPA to meet and confer in good faith concerning (i) the May 26, 2021 Determination Memorandum issued by FEMA and (ii) whether and when a second determination memorandum is expected. The parties were further directed to file an additional status report, which was filed on July 20, 2021. On July 23, 2021, with our aid, PREPA filed an appeal of the entire $47 million that FEMA de-

obligated in the May 26, 2021 Determination Memorandum. In the event PREPA (i) does not have or does not obtain the funds necessary to satisfy its obligations to Cobra under the contracts, (ii) obtains the necessary funds but refuses to pay the amounts owed to us or (iii) otherwise does not pay amounts owed to us for services performed, the receivable may not be collected and our financial condition, results of operations and cash flows would be materially and adversely affected. In addition, government contracts are subject to various uncertainties, restrictions and regulations, including oversight audits and compliance reviews by government agencies and representatives. In this regard, on September 10, 2019, the U.S. District Court for the District of Puerto Rico unsealed an indictment that charged the former president of Cobra with conspiracy, wire fraud, false statements and disaster fraud. Two other individuals were also charged in the indictment. The indictment is focused on the interactions between a former FEMA official and the former President of Cobra. Neither we nor any of our subsidiaries were charged in the indictment. We are continuing to cooperate with the related investigation. We are also subject to investigations and legal proceedings related to our contracts with PREPA. Given the uncertainty inherent in the criminal litigation, investigations and legal proceedings, it is not possible at this time to determine the potential outcome or other potential impacts that they could have on us. See Note 18. Commitments and Contingencies to our unaudited condensed consolidated financial statements included elsewhere in this report for additional information regarding these investigations and proceedings. Further, as noted above, our contracts with PREPA have concluded and we have not obtained, and there can be no assurance that we will be able to obtain, one or more contracts with PREPA or other customers to replace the level of services that we provided to PREPA under our previous contracts.

Our crew count declined from approximately 100 crews as of December 31, 2020 to approximately 83 crews as of September 30, 2021. Although the COVID-19 pandemic and resulting economic conditions have not had a material impact on demand or pricing for our infrastructure services, revenues for our infrastructure services have declined in 2021 as a result of certain management changes, which resulted in crew departures. During the third quarter of 2021, we made leadership changes in our infrastructure group. We are focused on cutting costs and enhancing accountability across the division, both of which we have already seen improving.

Funding for projects in the infrastructure space remains strong with the added opportunity of a new federal infrastructure bill, which we are optimistic will occur in the near future. We continue to pursue opportunities within this sector as we strategically structure our service offerings for growth, intending to increase our infrastructure services activity and expand both our geographic footprint and depth of projects. During the third quarter of 2021, we won our first fiber installation job, which we expect to begin in November 2021. We work for multiple utilities primarily across the northeastern, southwestern, midwestern and western portions of the United States. Our infrastructure management team also has experience with both solar and wind projects and we believe that this experience, combined with our vertically integrated service offerings, positions us well to compete and win renewable projects. We believe we will be able to grow our customer base and increase our revenues in the continental United States over the coming years.

Oil and Natural Gas Industry

The oil and natural gas industry has traditionally been volatile and is influenced by a combination of long-term, short-term and cyclical trends, including the domestic and international supply and demand for oil and natural gas, current and expected future prices for oil and natural gas and the perceived stability and sustainability of those prices, production depletion rates and the resultant levels of cash flows generated and allocated by exploration and production companies to their drilling, completion and related services and products budgets. The oil and natural gas industry is also impacted by general domestic and international economic conditions, political instability in oil producing countries, government regulations (both in the United States and elsewhere), levels of customer demand, the availability of pipeline capacity, storage capacity and other conditions and factors that are beyond our control. See “Recent Developments—Impact of the COVID-19 Pandemic and Volatility in Commodity Prices” above.

Demand for most of our oil and natural gas products and services depends substantially on the level of expenditures by companies in the oil and natural gas industry. The levels of capital expenditures of our customers are predominantly driven by the prices of oil and natural gas. As discussed above, oil prices dropped sharply throughout March and April of 2020. While improved commodity pricing has contributed to positive industry movement and increased equipment utilization, oil and natural gas prices are expected to continue to be volatile and we cannot predict if, or at what levels, commodity prices will stabilize. We experienced a weakening in demand for our oilfield services during 2019 as a result of reductions in our customers’ capital expenditure budgets. The sharp decline in oil prices beginning in March 2020, the continued volatility and strategic operating decisions by producers to curtail drilling activity have adversely impacted the utilization and pricing of our oilfield services.

In response to market conditions, we have temporarily shut down our cementing and acidizing operations and flowback operations beginning in July 2019, our contract drilling operations beginning in December 2019, our rig hauling operations beginning in April 2020, our coil tubing and full service transportation operations beginning in July 2020 and our

crude oil hauling operations beginning in July 2021. We continue to monitor the market to determine if and when we can recommence these services. We are currently operating two of our six pressure pumping fleets. Based on feedback from our exploration and production customers, they are taking a cautious approach to activity levels for the remainder of 2021 given the recent volatility in oil prices and investor sentiment calling for activities to remain within or below cash flows. Market fundamentals are challenging for our oilfield businesses and we expect this trend to continue. Although we believe the reported retirement of equipment across the industry may, at some point, help the market, pricing and utilization for our oilfield services are expected to remain competitive for the foreseeable future. While the oilfield portion of our service offerings continue to experience significant challenges, we expect to be ready to ramp up our oilfield service offerings when oilfield demand, pricing and margins strengthen.

We continue to closely monitor our cost structure in response to market conditions and intend to pursue additional cost savings where possible. Further, a significant portion of our revenue from our pressure pumping business had been derived from Gulfport. On December 28, 2019, Gulfport filed a lawsuit alleging our breach of our pressure pumping contract with Gulfport and seeking to terminate the contract and recover damages for alleged overpayments, audit costs and legal fees. Gulfport did not make the payments owed to us under this contract for any periods subsequent to its alleged December 28, 2019 termination date. Further, on November 13, 2020, Gulfport filed petitions for voluntary relief under chapter 11 of the Bankruptcy Code. On September 21, 2021, we reached a settlement with Gulfport under which all litigation relating to the Stingray Pressure Pumping contract will be terminated, Stingray Pressure Pumping will release all claims against Gulfport and its subsidiaries with respect to Gulfport’s bankruptcy proceedings and each of the parties will release all claims they had against the others with respect to the litigation matters discussed above. We have not been able to obtain long-term contracts with other customers to replace our contract with Gulfport. See Note 18. Commitments and Contingencies to our unaudited condensed consolidated financial statements included elsewhere in this report for additional information.

Natural Sand Proppant Industry

In the natural sand proppant industry, demand growth for frac sand and other proppants is primarily driven by advancements in oil and natural gas drilling and well completion technology and techniques, such as horizontal drilling and hydraulic fracturing, as well as overall industry activity growth.

In 2018 and 2019, several new and existing suppliers completed planned capacity additions of frac sand supply, particularly in the Permian Basin. The industry expansion, coupled with increased capital discipline, budget exhaustion and the impact on oil demand from the COVID-19 pandemic, caused the frac sand market to become oversupplied, particularly in finer grades. With the frac sand market oversupplied, pricing for all grades has fallen significantly from the peaks experienced throughout 2018 and during the first half of 2019. This oversupply resulted in several industry participants idling and closing high cost mines in an attempt to restore the supply and demand balance and reduce the number of industry participants. Nevertheless, demand for our sand declined significantly in the second half of 2019 and throughout 2020 as a result of completion activity falling due to lower oil demand and pricing as discussed above, increased capital discipline by our customers, budget exhaustion and the COVID-19 pandemic. Activity has rebounded modestly in 2021 as we have seen an increase in the volume of sand sold, however the prices of frac sand have continued to be depressed compared to prior levels. We cannot predict if and when pricing and demand will recover sufficiently to return our natural sand proppant services segment to profitability.

Further, as a result of adverse market conditions, production at our Muskie sand facility in Pierce County, Wisconsin has been temporarily idled since September 2018. Our contracted capacity has provided a baseline of business, which has kept our Taylor and Piranha plants operating and our costs low.

A portion of our revenue from our natural sand proppant business had been derived from Gulfport pursuant to a contract. Gulfport did not made the payments owed to us under this contract for any periods subsequent to May 2020. In September 2020, we filed a lawsuit seeking to recover delinquent payments owed to us under this contract. On November 13, 2020, Gulfport filed petitions for voluntary relief under chapter 11 of the Bankruptcy Code. On September 21, 2021, the Company and Gulfport reached a settlement under which all litigation relating to the Muskie contract will be terminated and a portion of Muskie’s contract claim against Gulfport will be allowed under Gulfport’s plan of reorganization. The settlement remains subject to the final approval by the bankruptcy court overseeing Gulfport’s bankruptcy. See Note 18. Commitments and Contingencies to our unaudited condensed consolidated financial statements included elsewhere in this report for additional information.

Results of Operations

Three Months Ended September 30, 2021 Compared to Three Months Ended September 30, 2020


	Three Months Ended
	September 30, 2021		September 30, 2020
	(in thousands)
Revenue:
Infrastructure services	$	23,489	$	43,582
Well completion services	22,732		15,765
Natural sand proppant services	8,419		6,031
Drilling services	1,207		1,204
Other services	6,153		4,677
Eliminations	(4,515)		(725)
Total revenue	57,485		70,534

Cost of revenue:
Infrastructure services (exclusive of depreciation and amortization of $4,933 and $7,294, respectively, for the three months ended September 30, 2021 and 2020)	20,595		29,045
Well completion services (exclusive of depreciation and amortization of $6,538 and $7,189, respectively, for the three months ended September 30, 2021 and 2020)	21,329		6,959
Natural sand proppant services (exclusive of depreciation, depletion and accretion of $2,533 and $2,700, respectively, for the three months ended September 30, 2021 and 2020)	9,368		4,154
Drilling services (exclusive of depreciation and amortization of $1,942 and $2,294, respectively, for the three months ended September 30, 2021 and 2020)	1,566		1,955
Other services (exclusive of depreciation and amortization of $3,202 and $3,655, respectively, for the three months ended September 30, 2021 and 2020)	5,241		4,541
Eliminations	(4,515)		(725)
Total cost of revenue	53,584		45,929
Selling, general and administrative expenses	41,866		12,180
Depreciation, depletion, amortization and accretion	19,148		23,132

Impairment of other long-lived assets	547		—
Operating loss	(57,660)		(10,707)
Interest expense, net	(1,484)		(1,098)
Other income (expense), net	11,056		9,042
Loss before income taxes	(48,088)		(2,763)
Benefit for income taxes	(7,187)		(6,193)
Net (loss) income	$	(40,901)	$	3,430

Revenue. Revenue for the three months ended September 30, 2021 decreased $13.0 million, or 18%, to $57.5 million from $70.5 million for the three months ended September 30, 2020. The decrease in total revenue is primarily attributable to a decline in infrastructure services revenue of $20.1 million during the three months ended September 30, 2021, partially offset by an increase in well completion services revenue of $6.9 million. Revenue derived from related parties was a nominal amount for the three months ended September 30, 2021 and $10.4 million, or 15% of our total revenue, for the three months ended September 30, 2020. Substantially all of our related party revenue was derived from Gulfport under pressure pumping and sand contracts. For additional information regarding the status of these contracts and the litigation related to the pressure pumping contract, see “Industry Overview – Oil and Natural Gas Industry,” “Industry Overview – Natural Sand Proppant Industry” and Note 18. Commitments and Contingencies to our unaudited condensed consolidated financial statements included elsewhere in

this report. Following its emergence from bankruptcy, Gulfport is no longer a related party. Revenue by operating division was as follows:

Infrastructure Services. Infrastructure services division revenue decreased $20.1 million, or 46%, to $23.5 million for the three months ended September 30, 2021 from $43.6 million for the three months ended September 30, 2020 primarily due to a decline in storm activity during the three months ended September 30, 2021 compared to the three months ended September 30, 2020, resulting in a $20.4 million decline in storm restoration revenue.

Well Completion Services. Well completion services division revenue increased $6.9 million, or 44%, to $22.7 million for the three months ended September 30, 2021 from $15.8 million for the three months ended September 30, 2020. Revenue derived from related parties was $8.4 million, or 53% of total well completion revenue, for the three months ended September 30, 2020. We did not recognize any related party revenue for the three months ended September 30, 2021. All of our well completion related party revenue for the three months ended September 30, 2020 was derived from Gulfport under a pressure pumping contract. For additional information regarding the status of this contract and the litigation related to this contract, see “Industry Overview – Oil and Natural Gas Industry” above and Note 18 to our unaudited condensed consolidated financial statements included elsewhere in this report.

The increase in our well completion services revenue was primarily driven by a 53% increase in the number of stages completed from 449 for the three months ended September 30, 2020 to 688 for the three months ended September 30, 2021 as well as an increase in sand and chemical materials revenue. An average of 1.2 of our fleets were active for the three months ended September 30, 2021 as compared to an average of 0.9 fleets for the three months ended September 30, 2020.

Natural Sand Proppant Services. Natural sand proppant services division revenue increased $2.4 million, or 40%, to $8.4 million for the three months ended September 30, 2021, from $6.0 million for the three months ended September 30, 2020. Revenue derived from related parties was $1.9 million, or 32% of total sand revenue, for the three months ended September 30, 2020. We did not recognize any related party revenue for the three months ended September 30, 2021. All of our related party revenue for the three months ended September 30, 2020 was derived from Gulfport under a sand supply contract. For additional information regarding the status of this contract and the pending litigation related to this contract, see “Industry Overview – Natural Sand Proppant Industry” above and Note 18 to our unaudited condensed consolidated financial statements included elsewhere in this report. Inter-segment revenue, consisting primarily of revenue derived from our pressure pumping segment, was $4.0 million, or 47% of total sand revenue, for the three months ended September 30, 2021. The natural sand proppant services division did not have inter-segment revenues for the three months ended September 30, 2020.

The increase in our natural sand proppant services revenue was primarily attributable to a 365% increase in tons of sand sold from 67,715 tons for the three months ended September 30, 2020 to 315,066 tons for the three months ended September 30, 2021, and a 6% increase in the average price per ton of sand sold from $15.59 per ton during the three months ended September 30, 2020 to $16.58 per ton during the three months ended September 30, 2021. These increases were partially offset by a decrease in shortfall revenue by $4.9 million.

Drilling Services. Drilling services division revenue remained flat at $1.2 million for the three months ended September 30, 2021 as compared to the three months ended September 30, 2020. In response to market conditions, we have temporarily shut down our contract land drilling operations beginning in December 2019 and our rig hauling operations beginning in April 2020.

Other Services. Other services revenue, consisting of revenue derived from our aviation, coil tubing, pressure control, equipment rental, full service transportation, crude oil hauling, remote accommodation, equipment manufacturing and infrastructure engineering and design businesses, increased $1.5 million, or 32%, to $6.2 million for the three months ended September 30, 2021 from $4.7 million for the three months ended September 30, 2020. Inter-segment revenue, consisting primarily of revenue derived from our well completion segment, was $0.5 million and $0.7 million for the three months ended September 30, 2021 and 2020, respectively.

The increase in our other services revenue was primarily due to an increase in utilization for our equipment rental business. An average of 162 pieces of equipment was rented to customers during the three months ended September 30, 2021, an increase of 131% from an average of 70 pieces of equipment rented to customers during the three months ended September 30, 2020. Due to market conditions, we have temporarily shut down our coil tubing and full service transportation operations beginning in July 2020 and our crude oil hauling business beginning in July 2021.

Cost of Revenue (exclusive of depreciation, depletion, amortization and accretion expense). Cost of revenue, exclusive of depreciation, depletion, amortization and accretion expense, increased $7.7 million from $45.9 million, or 65% of total revenue, for the three months ended September 30, 2020 to $53.6 million, or 93% of total revenue, for the three months ended September 30, 2021. The increase is primarily due to an increase in cost of revenue for the well completion services division, partially offset by a decrease in cost of revenue for the infrastructure services division. Cost of revenue by operating division was as follows:

Infrastructure Services. Infrastructure services division cost of revenue, exclusive of depreciation and amortization expense, decreased $8.4 million, or 29%, to $20.6 million for the three months ended September 30, 2021 from $29.0 million for the three months ended September 30, 2020, primarily due to a decline in activity. As a percentage of revenue, cost of revenue, exclusive of depreciation and amortization expense of $4.9 million and $7.3 million for the three months ended September 30, 2021 and 2020, respectively, was 88% and 67% for the three months ended September 30, 2021 and 2020, respectively. The increase as a percentage of revenue is primarily due to increases in labor related costs and insurance costs as a percentage of revenue.

Well Completion Services. Well completion services division cost of revenue, exclusive of depreciation and amortization expense, increased $14.3 million, or 204%, to $21.3 million for the three months ended September 30, 2021 from $7.0 million for the three months ended September 30, 2020, primarily due to an increase in costs of goods sold as a result of providing sand and chemicals with our service package to customers during the three months ended September 30, 2021. As a percentage of revenue, our well completion services division cost of revenue, exclusive of depreciation and amortization expense of $6.5 million and $7.2 million for the three months ended September 30, 2021 and 2020, respectively, was 94% and 44% for the three months ended September 30, 2021 and 2020, respectively. The increase as a percentage of revenue is primarily due to the recognition of standby revenue during the three months ended September 30, 2020, of which there was a lower percentage of costs recognized compared to the three months ended September 30, 2021. Additionally, during the three months ended September 30, 2021, we provided sand and chemicals with our service package to customers, resulting in higher cost of goods sold as a percentage of revenue for this period in comparison to the three months ended September 30, 2020.

Natural Sand Proppant Services. Natural sand proppant services division cost of revenue, exclusive of depreciation, depletion and accretion expense, increased $5.2 million, or 124%, to $9.4 million for the three months ended September 30, 2021 from $4.2 million for the three months ended September 30, 2020. As a percentage of revenue, cost of revenue, exclusive of depreciation, depletion and accretion expense of $2.5 million and $2.7 million for the three months ended September 30, 2021 and 2020, respectively, was 112% and 70% for the three months ended September 30, 2021 and 2020, respectively. The increase is primarily due to the recognition of shortfall revenue during the three months ended September 30, 2020, for which there are no associated costs, compared to the three months ended September 30, 2021.

Drilling Services. Drilling services division cost of revenue, exclusive of depreciation and amortization expense, decreased $0.4 million, or 20%, to $1.6 million for the three months ended September 30, 2021 from $2.0 million for the three months ended September 30, 2020. As a percentage of revenue, our drilling services division cost of revenue, exclusive of depreciation and amortization expense of $1.9 million and $2.3 million for the three months ended September 30, 2021 and 2020, respectively, was 133% and 167% for the three months ended September 30, 2021 and 2020, respectively.

Other Services. Other services division cost of revenue, exclusive of depreciation and amortization expense, increased $0.7 million, or 16%, to $5.2 million for the three months ended September 30, 2021 from $4.5 million for the three months ended September 30, 2020, primarily due to increased activity. As a percentage of revenue, cost of revenue, exclusive of depreciation and amortization expense of $3.2 million and $3.7 million for the three months ended September 30, 2021 and 2020, respectively, was 84% and 96% for the three months ended September 30, 2021 and 2020, respectively. The decrease is primarily due to a decline in labor costs as a percentage of revenue.

Selling, General and Administrative Expenses. Selling, general and administrative, or SG&A, expenses represent the costs associated with managing and supporting our operations. The table below presents a breakdown of SG&A expenses for the periods indicated (in thousands):


	Three Months Ended
	September 30, 2021		September 30, 2020
Cash expenses:
Compensation and benefits	$	3,353	$	3,449
Professional services	4,571		5,651
Other(a)	2,252		2,163
Total cash SG&A expense	10,176		11,263
Non-cash expenses:
Bad debt provision(b)	31,449		626

Stock based compensation	241		291
Total non-cash SG&A expense	31,690		917
Total SG&A expense	$	41,866	$	12,180

a. Includes travel-related costs, information technology expenses, rent, utilities and other general and administrative-related costs.

b. The bad debt provision for the three months ended September 30, 2021 includes $31.2 million related to the Stingray Pressure Pumping and Muskie contracts with Gulfport. See “Industry Overview – Oil and Natural Gas Industry,” “Industry Overview – Natural Sand Proppant Industry” and Note 18. Commitments and Contingencies to our unaudited condensed consolidated financial statements included elsewhere in this report.

Depreciation, Depletion, Amortization and Accretion. Depreciation, depletion, amortization and accretion decreased $4.0 million, or 17%, to $19.1 million for the three months ended September 30, 2021 from $23.1 million for the three months ended September 30, 2020. The decrease is primarily attributable to a decline in property and equipment depreciation expense.

Impairment of Long-Lived Assets. During the three months ended September 30, 2021, we began the temporary shut down of our crude oil hauling operations, resulting in impairment of trade names of $0.5 million.

Operating Loss. We reported an operating loss of $57.7 million for the three months ended September 30, 2021 compared to an operating loss of $10.7 million for the three months ended September 30, 2020. The increase in operating loss is primarily due to the recognition of $31.4 million in bad debt expense attributable to our contracts with Gulfport, as well as an increase in costs of revenue as a percentage of revenue.

Interest Expense, Net. Interest expense, net increased $0.4 million, or 36%, to $1.5 million for the three months ended September 30, 2021 from $1.1 million for the three months ended September 30, 2020. The increase is primarily due to an increase in average borrowings outstanding under our revolving credit facility.

Other Income (Expense), Net. Other income increased $2.0 million during the three months ended September 30, 2021 compared to the three months ended September 30, 2020 primarily due to an increase in interest on trade accounts receivable.

Income Taxes. We recorded an income tax benefit of $7.2 million on pre-tax losses of $48.1 million for the three months ended September 30, 2021 compared to an income tax expense of $6.2 million on pre-tax losses of $2.8 million for the three months ended September 30, 2020. During the three months ended September 30, 2020, we recorded a benefit of $8 million related to provisions in the Coronavirus Aid, Relief, and Economic Security (CARES) Act.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020


	Nine Months Ended
	September 30, 2021		September 30, 2020
	(in thousands)
Revenue:
Infrastructure services	$	69,965	$	99,307
Well completion services	63,059		75,629
Natural sand proppant services	24,011		22,516
Drilling services	3,288		7,182
Other services	17,365		26,629
Eliminations	(5,958)		(3,237)
Total revenue	171,730		228,026

Cost of revenue:
Infrastructure services (exclusive of depreciation and amortization of $17,499 and $22,416, respectively, for the nine months ended September 30, 2021 and 2020)	67,029		80,977
Well completion services (exclusive of depreciation and amortization of $19,668 and $23,346, respectively, for the nine months ended September 30, 2021 and 2020)	47,788		41,864
Natural sand proppant services (exclusive of depreciation, depletion and accretion of $7,059 and $7,380, respectively, for the nine months ended September 30, 2021 and 2020)	22,631		21,845
Drilling services (exclusive of depreciation of $6,185 and $7,814, respectively, for the nine months ended September 30, 2021 and 2020)	4,739		9,743
Other services (exclusive of depreciation and amortization of $10,148 and $12,174, respectively, for the nine months ended September 30, 2021 and 2020)	15,810		25,396
Eliminations	(5,958)		(3,237)
Total cost of revenue	152,039		176,588
Selling, general and administrative expenses	74,697		36,677
Depreciation, depletion, amortization and accretion	60,559		73,130
Impairment of goodwill	—		54,973
Impairment of long-lived assets	547		12,897
Operating loss	(116,112)		(126,239)
Interest expense, net	(3,878)		(4,207)
Other income, net	5,489		25,721
Loss before income taxes	(114,501)		(104,725)
Benefit for income taxes	(26,370)		(8,979)
Net loss	$	(88,131)	$	(95,746)

Revenue. Revenue for the nine months ended September 30, 2021 decreased $56.3 million, or 25%, to $171.7 million from $228.0 million for the nine months ended September 30, 2020. The decrease in total revenue is primarily attributable to declines in revenue across most business lines. Revenue derived from related parties was $17.8 million, or 10% of our total revenue, for the nine months ended September 30, 2021 and $40.9 million, or 18% of our total revenue, for the nine months ended September 30, 2020. Substantially all of our related party revenue was derived from Gulfport under pressure pumping and sand contracts. For additional information regarding the status of these contracts and the pending litigation related to the pressure pumping contract, see “Industry Overview – Oil and Natural Gas Industry,” “Industry Overview – Natural Sand Proppant Industry” and Note 18. Commitments and Contingencies to our unaudited condensed consolidated financial statements included elsewhere in this report. Revenue by operating division was as follows:

Infrastructure Services. Infrastructure services division revenue decreased $29.3 million, or 30%, to $70.0 million for the nine months ended September 30, 2021 from $99.3 million for the nine months ended September 30, 2020 primarily due to crew departures as a result of certain changes in management. Additionally, there was less storm activity during the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020, resulting in an $11.5 million decline in storm restoration revenue.

Well Completion Services. Well completion services division revenue decreased $12.5 million, or 17%, to $63.1 million for the nine months ended September 30, 2021 from $75.6 million for the nine months ended September 30, 2020. Revenue derived from related parties was $14.8 million, or 23% of total well completion, for the nine months ended September 30, 2021 compared to $35.0 million, or 46% of total well completion revenue, for the nine months ended September 30, 2020. All of our well completion related party revenue was derived from Gulfport under a pressure pumping contract. On November 13, 2020, Gulfport filed petitions for voluntary relief under chapter 11 of the Bankruptcy Code. During the nine months ended September 30, 2021, we recognized revenue totaling $15 million related to the modification of our pressure pumping contract with Gulfport. For additional information regarding the status of this contract and the pending litigation related to this contract, see “Industry Overview – Oil and Natural Gas Industry” above and notes 2 and 3 to our unaudited condensed consolidated financial statements included elsewhere in this report. Inter-segment revenues, consisting primarily of revenue derived from our sand segment, was $0.1 million and $1.1 million for the nine months ended September 30, 2021 and 2020, respectively.

The decrease in our well completion services revenue was primarily driven by a declines in pressure pumping services utilization and pricing. The number of stages completed decreased 36% to 1,653 for the nine months ended September 30, 2021 from 2,589 for the nine months ended September 30, 2020. An average of 1.0 of our six fleets were active for the nine months ended September 30, 2021 as compared to an average of 1.8 fleets for the nine months ended September 30, 2020.

Natural Sand Proppant Services. Natural sand proppant services division revenue increased $1.5 million, or 7%, to $24.0 million for the nine months ended September 30, 2021, from $22.5 million for the nine months ended September 30, 2020. Revenue derived from related parties was $2.1 million, or 9% of total sand revenue, for the nine months ended September 30, 2021 and $6.0 million, or 27% of total sand revenue, for the nine months ended September 30, 2020. All of our related party revenue was derived from Gulfport under a sand supply contract. On November 13, 2020, Gulfport filed petitions for voluntary relief under chapter 11 of the Bankruptcy Code. During the three months ended March 31, 2021, we recognized revenue totaling $2 million related to the modification of our sand supply contract with Gulfport. For additional information regarding the status of this contract and the pending litigation related to this contract, see “Industry Overview – Natural Sand Proppant Industry” above and notes 2 and 3 to our unaudited condensed consolidated financial statements included elsewhere in this report. Inter-segment revenue, consisting primarily of revenue derived from our pressure pumping segment, was $4.0 million, or 17% of total sand revenue, for the nine months ended September 30, 2021. The natural sand proppant services division did not have inter-segment revenues for the nine months ended September 30, 2020.

The increase in our natural sand proppant services revenue was primarily attributable to a 90% increase in tons of sand sold from approximately 389,436 tons for the nine months ended September 30, 2020 to approximately 741,458 tons for the nine months ended September 30, 2021 and a 14% increase in the average sales price per ton of sand sold from $14.32 per ton during the nine months ended September 30, 2020 to $16.37 per ton during the nine months ended September 30, 2021. This increase was partially offset by an $8.7 million decline in shortfall revenue for the nine months ended September 30, 2021.

Drilling Services. Drilling services division revenue decreased $3.9 million, or 54%, to $3.3 million for the nine months ended September 30, 2021 from $7.2 million for the nine months ended September 30, 2020. The decline in our drilling services revenue was primarily attributable to declines in directional drilling and rig hauling revenue. In response to market conditions, we have temporarily shut down our contract land drilling operations beginning in December 2019 and our rig hauling operations beginning in April 2020.

Other Services. Other services revenue, consisting of revenue derived from our coil tubing, equipment rental, full service transportation, crude oil hauling, remote accommodation, equipment manufacturing and infrastructure engineering businesses, decreased $9.2 million, or 35%, to $17.4 million for the nine months ended September 30, 2021 from $26.6 million for the nine months ended September 30, 2020. Inter-segment revenue, consisting primarily of revenue derived from our infrastructure and well completion segments, totaled $1.8 million and $2.0 million for the nine months ended September 30, 2021 and 2020, respectively.

The decrease in our other services revenue was primarily due to a decline in utilization for our equipment rental business. An average of 117 pieces of equipment was rented to customers during the nine months ended September 30, 2021, a decrease of 52% from an average of 245 pieces of equipment rented to customers during the nine months ended September 30, 2020. Additionally, utilization for remote accommodations business declined. Due to market conditions, we have temporarily shut down our coil tubing and full service transportation operations beginning in July 2020. These decreases were partially offset by increases in revenue from our infrastructure engineering business.

Cost of Revenue (exclusive of depreciation, depletion, amortization and accretion expense). Cost of revenue, exclusive of depreciation, depletion, amortization and accretion expense, decreased $24.6 million from $176.6 million, or 77% of total revenue, for the nine months ended September 30, 2020 to $152.0 million, or 89% of total revenue, for the nine months ended September 30, 2021. The decrease in cost of revenue was primarily due to a decline in activity for our infrastructure services and other services divisions. Cost of revenue by operating division was as follows:

Infrastructure Services. Infrastructure services division cost of revenue, exclusive of depreciation and amortization expense, decreased $14.0 million, or 17%, to $67.0 million for the nine months ended September 30, 2021 from $81.0 million for the nine months ended September 30, 2020, primarily due to a decline in activity. As a percentage of revenue, cost of revenue, exclusive of depreciation and amortization expense of $17.5 million and $22.4 million, respectively, for the nine months ended September 30, 2021 and 2020 was 96% and 82% for the nine months ended September 30, 2021 and 2020, respectively. The increase as a percentage of revenue is primarily due to increased labor costs as a percentage of revenue.

Well Completion Services. Well completion services division cost of revenue, exclusive of depreciation and amortization expense, increased $5.9 million, or 14%, to $47.8 million for the nine months ended September 30, 2021 from $41.9 million for the nine months ended September 30, 2020, primarily due to an increase in cost of goods sold as a result of providing sand and chemicals with our service package to customers during the nine months ended September 30, 2021. As a percentage of revenue, our well completion services division cost of revenue, exclusive of depreciation and amortization expense of $19.7 million and $23.3 million for the nine months ended September 30, 2021 and 2020, respectively, was 76% and 55% for the nine months ended September 30, 2021 and 2020, respectively. The increase as a percentage of revenue is primarily due to the recognition of more pressure pumping services standby revenue during the nine months ended September 30, 2020, of which there was a lower percentage of costs recognized compared to the nine months ended September 30, 2021. Additionally, during the nine months ended September 30, 2021, we provided sand and chemicals with our service package to customers, resulting in higher cost of goods sold as a percentage of revenue for this period in comparison to the nine months ended September 30, 2020.

Natural Sand Proppant Services. Natural sand proppant services division cost of revenue, exclusive of depreciation, depletion and accretion expense, increased $0.8 million, or 4%, from $21.8 million for the nine months ended September 30, 2020 to $22.6 million for the nine months ended September 30, 2021. As a percentage of revenue, cost of revenue, exclusive of depreciation, depletion and accretion expense of $7.1 million and $7.4 million for each of the nine months ended September 30, 2021 and 2020, respectively, was 94% and 97% for the nine months ended September 30, 2021 and 2020, respectively. The decrease in cost as a percentage of revenue is primarily due to a 14% increase is average sales price.

Drilling Services. Drilling services division cost of revenue, exclusive of depreciation and amortization expense, decreased $5.0 million, or 52%, from $9.7 million for the nine months ended September 30, 2020 to $4.7 million for the nine months ended September 30, 2021, as a result of reduced activity. In response to market conditions, we have temporarily shut down our contract land drilling operations beginning in December 2019 and our rig hauling operations beginning in April 2020. As a percentage of revenue, our drilling services division cost of revenue, exclusive of depreciation and amortization expense of $6.2 million and $7.8 million, for the nine months ended September 30, 2021 and 2020, respectively, was 142% and 135% for the nine months ended September 30, 2021 and 2020, respectively. The increase as a percentage of revenue is primarily due to a decline in utilization.

Other Services. Other services division cost of revenue, exclusive of depreciation and amortization expense, decreased $9.6 million, or 38%, from $25.4 million for the nine months ended September 30, 2020 to $15.8 million for the nine months ended September 30, 2021, primarily due to a decline in costs for our equipment rental, coil tubing and full service transportation businesses as a result of reduced activity. Due to market conditions, we have temporarily shut down our coil tubing and full service transportation operations beginning in July 2020. These declines were partially offset by an increase in costs for our infrastructure engineering business. As a percentage of revenue, cost of revenue, exclusive of depreciation and amortization expense of $10.1 million and $12.2 million for the nine

months ended September 30, 2021 and 2020, respectively, was 91% and 95% for the nine months ended September 30, 2021 and 2020, respectively.

Selling, General and Administrative Expenses. Selling, general and administrative expenses represent the costs associated with managing and supporting our operations. The table below presents a breakdown of SG&A expenses for the periods indicated (in thousands):


	Nine Months Ended
	September 30, 2021		September 30, 2020
Cash expenses:
Compensation and benefits	$	11,379	$	11,138
Professional services	13,783		15,335
Other(a)	7,058		6,572
Total cash SG&A expenses	32,220		33,045
Non-cash expenses:
Bad debt provision	41,650		2,306

Stock based compensation	827		1,326
Total non-cash SG&A expenses	42,477		3,632
Total SG&A expenses	$	74,697	$	36,677

a. Includes travel-related costs, IT expenses, rent, utilities and other general and administrative-related costs.

b. The bad debt provision for the nine months ended September 30, 2021 includes $41.2 million related to the Stingray Pressure Pumping and Muskie contracts with Gulfport. See “Industry Overview – Oil and Natural Gas Industry,” “Industry Overview – Natural Sand Proppant Industry” and Note 18. Commitments and Contingencies to our unaudited condensed consolidated financial statements included elsewhere in this report.

Depreciation, Depletion, Amortization and Accretion. Depreciation, depletion, amortization and accretion decreased $12.5 million to $60.6 million for the nine months ended September 30, 2021 from $73.1 million for the nine months ended September 30, 2020. The decrease is primarily attributable to a decline in property and equipment depreciation expense.

Impairment of Goodwill. As a result of market conditions, we performed an impairment assessment of our goodwill as of March 31, 2020. We determined that the carrying value of goodwill for certain of our entities exceeded their fair values, resulting in impairment expense of $55.0 million.

Impairment of Other Long-Lived Assets. During the three months ended September 30, 2021, we temporarily shut down our crude oil hauling operations, resulting in impairment of trade names of $0.5 million. During the nine months ended September 30, 2020, we recorded impairment of property and equipment, including water transfer, crude oil hauling, coil tubing and equipment rental assets, totaling $12.9 million.

Operating Loss. We reported an operating loss of $116.1 million for the nine months ended September 30, 2021 compared to an operating loss of $126.2 million for the nine months ended September 30, 2020. The reduced operating loss was primarily due to the recognition of $67.9 million in impairment expense during the nine months ended September 30, 2020, partially offset by a $39.3 million increase in bad debt expense.

Interest Expense, Net. Interest expense, net decreased $0.3 million during the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020 primarily due to a decrease in average borrowings outstanding.

Other Income (Expense), Net. We recognized other income, net of $5.5 million during the nine months ended September 30, 2021 compared to $25.7 million for the nine months ended September 30, 2020. During the nine months ended September 30, 2021 we recognized expense of $25.0 million related to an agreement to settle a legal matter. We recognized interest on trade accounts receivable of $25.1 million for the nine months ended September 30, 2021 compared to $26.1 million for nine months ended September 30, 2020.

Income Taxes. We recorded an income tax benefit of $26.4 million on pre-tax losses of $114.5 million for the nine months ended September 30, 2021 compared to an income tax benefit of $9.0 million on pre-tax loss of $104.7 million for the nine months ended September 30, 2020. Our effective tax rate was 23% for the nine months ended September 30, 2021 compared to 9% for the nine months ended September 30, 2020. The increase compared to the nine months ended September 30, 2020 was partially due to the mix of earnings between the United States and Puerto Rico as well as changes in

the valuation allowance. Additionally, during the nine months ended September 30, 2020, we recorded a benefit of $2 million related to provisions in the Coronavirus Aid, Relief, and Economic Security (CARES) Act, which was enacted on March 27, 2020. Our effective tax rate was also impacted by permanent differences such as goodwill impairment for the nine months ended September 30, 2020.

Non-GAAP Financial Measures

Adjusted EBITDA

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as net (loss) income before depreciation, depletion, amortization and accretion, impairment of goodwill, impairment of other long-lived assets, public offering costs, stock based compensation, interest expense, net, other (income) expense, net (which is comprised of the (gain) or loss on disposal of long-lived assets and interest on trade accounts receivable) and (benefit) provision for income taxes, further adjusted to add back interest on trade accounts receivable. We exclude the items listed above from net (loss) income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industries 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 considered as an alternative to, or more meaningful than, net (loss) income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

The following tables provide a reconciliation of Adjusted EBITDA to the GAAP financial measure of net income or (loss) for each of our operating segments for the specified periods (in thousands).

Consolidated


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Reconciliation of Adjusted EBITDA to net (loss) income:	2021		2020		2021		2020
Net (loss) income	$	(40,901)	$	3,430	$	(88,131)	$	(95,746)
Depreciation, depletion, amortization and accretion expense	19,148		23,132		60,559		73,130
Impairment of goodwill	—		—		—		54,973
Impairment of other long-lived assets	547		—		547		12,897


Public offering costs	13		—		91		—

Stock based compensation	252		353		950		1,598
Interest expense, net	1,484		1,098		3,878		4,207
Other income, net	(11,056)		(9,042)		(5,489)		(25,721)
Benefit for income taxes	(7,187)		(6,193)		(26,370)		(8,979)
Interest on trade accounts receivable	7,963		9,285		25,138		26,052
Adjusted EBITDA	$	(29,737)	$	22,063	$	(28,827)	$	42,411

Infrastructure Services


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Reconciliation of Adjusted EBITDA to net income (loss):	2021		2020		2021		2020
Net income (loss)	$	(2,288)	$	6,123	$	(29,946)	$	(6,182)
Depreciation and amortization expense	4,933		7,294		17,499		22,416


Public offering costs	(7)		—		37		—
Stock based compensation	96		139		388		424
Interest expense	971		623		2,287		2,091
Other income, net	(9,256)		(8,375)		(2,663)		(24,082)
Provision (benefit) for income taxes	3,947		1,645		(2,463)		5,085
Interest on trade accounts receivable	9,290		8,170		26,980		23,796
Adjusted EBITDA	$	7,686	$	15,619	$	12,119	$	23,548

Well Completion Services


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Reconciliation of Adjusted EBITDA to net (loss) income:	2021		2020		2021		2020
Net (loss) income	$	(40,711)	$	799	$	(53,391)	$	(50,951)
Depreciation and amortization expense	6,538		7,189		19,668		23,346
Impairment of goodwill	—		—		—		53,406
Impairment of other long-lived assets	—		—		—		4,203

Public offering costs	19		—		31		—

Stock based compensation	95		76		253		458
Interest expense	215		253		688		857
Other expense (income), net	755		(1,156)		1,196		(2,444)

Interest on trade accounts receivable	(1,327)		1,073		(1,841)		2,206
Adjusted EBITDA	$	(34,416)	$	8,234	$	(33,396)	$	31,081

Natural Sand Proppant Services


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Reconciliation of Adjusted EBITDA to net loss:	2021		2020		2021		2020
Net loss	$	(4,611)	$	(3,741)	$	(9,186)	$	(12,415)
Depreciation, depletion, amortization and accretion expense	2,533		2,700		7,059		7,380


Public offering costs	—		—		12		—
Stock based compensation	32		77		163		354
Interest expense	107		70		291		217
Other (income) expense, net	(46)		1,792		(892)		1,753

Interest on trade accounts receivable	—		26		(1)		26
Adjusted EBITDA	$	(1,985)	$	924	$	(2,554)	$	(2,685)

Drilling Services


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Reconciliation of Adjusted EBITDA to net loss:	2021		2020		2021		2020
Net loss	$	(2,579)	$	(3,508)	$	(8,717)	$	(13,676)
Depreciation expense	1,942		2,294		6,185		7,814

Impairment of other long-lived assets	—		—		—		326

Public offering costs	—		—		2		—
Stock based compensation	6		38		71		166
Interest expense	56		60		177		450
Other (income) expense, net	(66)		20		(201)		(251)

Adjusted EBITDA	$	(641)	$	(1,096)	$	(2,483)	$	(5,171)

Other Services(a)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Reconciliation of Adjusted EBITDA to net income (loss):	2021		2020		2021		2020
Net income (loss)	$	9,288	$	3,756	$	13,109	$	(12,522)
Depreciation, amortization and accretion expense	3,202		3,655		10,148		12,174
Impairment of goodwill	—		—		—		1,567
Impairment of other long-lived assets	547		—		547		8,368


Public offering costs	1		—		9		—
Stock based compensation	23		23		75		196
Interest expense, net	135		92		435		592
Other income, net	(2,443)		(1,323)		(2,929)		(697)
Benefit for income taxes	(11,134)		(7,838)		(23,907)		(14,064)
Interest on trade accounts receivable	—		16		—		25
Adjusted EBITDA	$	(381)	$	(1,619)	$	(2,513)	$	(4,361)

a. Includes results for our aviation, coil tubing, pressure control, equipment rentals, full service transportation, crude oil hauling, remote accommodations, equipment manufacturing and infrastructure engineering and design services and corporate related activities. Our corporate related activities do not generate revenue.

Adjusted Net Loss and Adjusted Loss per Share

Adjusted net loss and adjusted loss per share are supplemental non-GAAP financial measures that are used by management to evaluate our operating and financial performance. Management believes these measures provide meaningful information about the Company’s performance by excluding certain non-cash charges, such as impairment of goodwill and impairment of other long-lived assets, that may not be indicative of the Company’s ongoing operating results. Adjusted net loss and adjusted loss per share should not be considered in isolation or as a substitute for net loss and loss per share prepared in accordance with GAAP and may not be comparable to other similarly titled measures of other companies. The following tables provide a reconciliation of adjusted net loss and adjusted loss per share to the GAAP financial measures of net loss and loss per share for the periods specified.


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2021		2020		2021		2020
	(in thousands, except per share amounts)
Net loss, as reported	$	(40,901)	$	3,430	$	(88,131)	$	(95,746)
Impairment of goodwill	—		—		—		54,973
Impairment of other long-lived assets	547		—		547		12,897
Adjusted net loss	$	(40,354)	$	3,430	$	(87,584)	$	(27,876)

Basic loss per share, as reported	$	(0.88)	$	0.07	$	(1.90)	$	(2.10)
Impairment of goodwill	—		—		—		1.21
Impairment of other long-lived assets	0.01		—		0.01		0.28
Adjusted basic loss per share	$	(0.87)	$	0.07	$	(1.89)	$	(0.61)

Diluted loss per share, as reported	$	(0.88)	$	0.07	$	(1.90)	$	(2.10)
Impairment of goodwill	—		—		—		1.21
Impairment of other long-lived assets	0.01		—		0.01		0.28
Adjusted diluted loss per share	$	(0.87)	$	0.07	$	(1.89)	$	(0.61)

Liquidity and Capital Resources

We require capital to fund ongoing operations including maintenance expenditures on our existing fleet of equipment, organic growth initiatives, investments and acquisitions, and the litigation settlement obligations described in Note 18 “Commitments and Contingencies” of the Notes to the Unaudited Condensed Consolidated Financial Statements. Our primary sources of liquidity have been cash on hand, borrowings under our revolving credit facility and cash flows from operations. Our primary uses of capital have been for investing in property and equipment used to provide our services and to acquire complementary businesses.

Liquidity

The following table summarizes our liquidity as of the dates indicated (in thousands):


	September 30,		December 31,
	2021		2020
Cash and cash equivalents	$	7,953	$	14,822
Revolving credit facility availability	129,184		129,787
Less outstanding borrowings on credit facility	(76,951)		(78,000)
Less letter of credit facilities (bonding program)	(1,000)		(5,000)
Less letter of credit facilities (insurance programs)	(3,889)		(3,890)
Less letter of credit facilities (environmental remediation)	(3,694)		(3,694)
Less letter of credit facilities (rail car commitments)	(455)		(455)
Net working capital (less cash)(a)	271,999		321,328
Total	$	323,147	$	374,898

a.Net working capital (less cash) is a non-GAAP measure and is calculated by subtracting total current liabilities of $146 million and cash and cash equivalents of $8 million from total current assets of $426 million as of September 30, 2021. As of December 31, 2020, net working capital (less cash) is calculated by subtracting total current liabilities of $129 million and cash and cash equivalents of $15 million from total current assets of $465 million. Amounts include receivables due from PREPA and Gulfport of $328 million and a nominal amount, respectively, at September 30, 2021 and $301 million and $28 million, respectively, at December 31, 2020.

As of November 3, 2021, we had cash on hand of $7 million and outstanding borrowings under our revolving credit facility of $76 million, leaving an aggregate of $24 million of available borrowing capacity under this facility, after giving effect to $9 million of outstanding letters of credit, the $10 million reduction in the borrowing base and the requirement to maintain a $10 million reserve out of the available borrowing capacity during the limited waiver period as described below.

Continued prolonged volatility in the capital, financial and/or credit markets due to the COVID-19 pandemic, volatility in commodity prices and/or adverse macroeconomic conditions may further limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all. In addition, if we are unable to comply with the covenants under our amended revolving credit facility following the expiration of the waiver period contemplated thereunder, as discussed below, and an event of default occurs and remains uncured, our lenders would not be required to lend any additional amounts to us, could elect to increase our interest rate by 200 basis points, could elect to declare all outstanding borrowings, together with accrued and unpaid interest and fees, to be due and payable, may have the ability to require us to apply all of our available cash to repay our outstanding borrowings and may foreclose on substantially all of our assets.

Cash Flows

The following table sets forth our cash flows at the dates indicated (in thousands):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2021		2020		2021		2020
Net cash (used in) provided by operating activities	$	(20,235)	$	(5,051)	$	(15,764)	$	1,782
Net cash provided by (used in) investing activities	2,184		791		5,107		(1,090)
Net cash provided by financing activities	14,994		41		3,780		7,377
Effect of foreign exchange rate on cash	(28)		80		8		(57)
Net change in cash	$	(3,085)	$	(4,139)	$	(6,869)	$	8,012

Operating Activities

Net cash used in operating activities was $16 million for the nine months ended September 30, 2021, compared to net cash provided by operating activities of $2 million for the nine months ended September 30, 2020. Net cash used in operating activities was $20 million for the three months ended September 30, 2021, compared to net cash used in operating activities of $5 million for the three months ended September 30, 2020. The change in operating cash flows was primarily attributable to the timing of cash inflows for accounts receivable during the three and nine months ended September 30, 2021.

Investing Activities

Net cash provided by investing activities was $5 million for the nine months ended September 30, 2021, compared to net cash used in investing activities of $1 million for the nine months ended September 30, 2020. Net cash provided by investing activities was $2 million for the three months ended September 30, 2021, compared to net cash provided by investing activities of $1 million for the three months ended September 30, 2020. Cash used in investing activities was primarily used to purchase property and equipment that is utilized to provide our services, which was offset by proceeds from the disposal of property and equipment.

The following table summarizes our capital expenditures by operating division for the periods indicated (in thousands):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2021		2020		2021		2020
Infrastructure services(a)	$	181	$	178	$	474	$	221
Well completion services(b)	2,392		698		3,192		3,752
Natural sand proppant services(c)	16		194		429		1,069
Drilling services(d)	4		132		42		199
Other(e)	172		323		337		708
Total capital expenditures	$	2,765	$	1,525	$	4,474	$	5,949

a. Capital expenditures primarily for tooling and other equipment for the three and nine months ended September 30, 2021.

b. Capital expenditures primarily for upgrades to our pressure pumping fleet to reduce greenhouse gas emissions and water transfer equipment for the three and nine months ended September 30, 2021 and 2020.

c. Capital expenditures primarily for maintenance for the three and nine months ended September 30, 2021 and 2020.

d. Capital expenditures primarily for equipment for our rig fleet for the three and nine months ended September 30, 2021.

e. Capital expenditures primarily for equipment for our rental business for the three and nine months ended September 30, 2021 and 2020.

Financing Activities

Net cash provided by financing activities was $3.8 million for the nine months ended September 30, 2021, compared to $7.4 million for the nine months ended September 30, 2020. Net cash provided by financing activities for the nine months ended September 30, 2021 was primarily attributable to net proceeds received from sale leaseback transactions of $7.4 million, which was partially offset by net payments on long-term debt totaling $1.9 million and principal payments on financing leases and equipment financing notes totaling $1.7 million. Net cash provided by financing activities for nine months ended September 30, 2020 was primarily attributable to net borrowings under our revolving credit facility of $9.8 million, which was partially offset by debt issuance costs of $1.0 million.

Net cash provided by financing activities was $15 million for the three months ended September 30, 2021, compared to a nominal amount for the three months ended September 30, 2020. Net cash provided by financing activities for the three months ended September 30, 2021 was primarily attributable to net borrowings of long-term debt totaling $16.4 million, which was partially offset by payment on sale leaseback transactions of $0.8 million and principal payments on financing leases and equipment financing notes totaling $0.6 million. Net cash provided by financing activities for the three months ended September 30, 2020 was primarily attributable to net borrowings under our revolving credit facility of $0.6 million.

Effect of Foreign Exchange Rate on Cash

The effect of foreign exchange rate on cash was $0.01 million and ($0.1) million, respectively, for the nine months ended September 30, 2021 and 2020. The change was driven primarily by a favorable (unfavorable) shift in the weakness (strength) of the Canadian dollar relative to the U.S. dollar for the cash held in Canadian accounts.

Working Capital

Our working capital totaled $280 million and $336 million, respectively, at September 30, 2021 and December 31, 2020. Our cash balances were $8 million and $15 million, respectively, at September 30, 2021 and December 31, 2020.

Our Revolving Credit Facility

On October 19, 2018, we and certain of our direct and indirect subsidiaries, as borrowers, entered into an amended and restated revolving credit facility, as subsequently amended, with the lenders party thereto and PNC Bank, National Association, as a lender and as administrative agent for the lenders. At September 30, 2021, we had outstanding borrowings under our revolving credit facility of $77 million and $43 million of available borrowing capacity under this facility, after giving effect to $9 million of outstanding letters of credit. As a result of the lack of payment from PREPA, which owed Cobra approximately $328.2 million, including interest, as of September 30, 2021, we projected that we would likely breach the leverage ratio covenant contained in our revolving credit facility for the fiscal quarter ended on September 30, 2021. On November 3, 2021, we entered into a third amendment to the revolving credit facility (the “Third Amendment”) to, among other things, (i) suspend the leverage ratio and fixed charges coverage ratio covenants for the quarters ending September 30, 2021 and December 31, 2021, (ii) permanently reduce the maximum revolving advance amount from $130 million to $120 million, (iii) add a minimum adjusted EBITDA financial covenant of $6.0 million for the quarter ending December 31, 2021, (iv) set the applicable margin on all loans at 3.50% during the limited covenant waiver period, (v) add a requirement to maintain revolver availability of not less than $10.0 million at all times during the limited covenant waiver period, (vi) permanently reduce the maximum revolving advance amount in an amount equal to fifty percent (50%) of any mandatory prepayments made with non-recurring proceeds that are received during the limited covenant waiver period, and (vii) eliminate the declaration of unrestricted subsidiaries during the limited covenant waiver period. The limited covenant waiver period commenced on the effective date of the Third Amendment and ends on the earlier to occur of (i) May 15, 2022, (ii) our reporting compliance with both the leverage ratio and the fixed charge coverage ratio covenants for either its fiscal quarter ending September 30, 2021 or December 31, 2021, and (iii) the occurrence of any event of default after the effective date of the Third Amendment. Under the Third Amendment, we also agreed to engage an advisor during the limited covenant waiver period to advise us and our subsidiaries with regard to, among other things, efforts to achieve certain operational efficiencies, improvement in results of operations, and general business strategy, and provide assistance to us and our subsidiaries in the preparation of the supplemental reporting and information required by the Third Amendment.

As of November 3, 2021, our outstanding borrowings under our amended credit facility were $76 million, leaving an aggregate of $24 million of available borrowing capacity, after giving effect to $9 million of outstanding letters of credit, the $10 million reduction in the borrowing base and the requirement to maintain a $10 million reserve out of the available borrowing capacity during the limited waiver period. If we fail to comply with the financial covenants following the expiration of the waiver period contemplated by the amended revolving credit facility and fail to cure such an event of default, it will have a material adverse effect on our business, financial condition, liquidity and results of operations. For additional information regarding our revolving credit facility, see Note 9. Debt to our unaudited condensed consolidated financial statements included elsewhere in this report.

Sale Leaseback Transactions

On December 30, 2020, we entered into an agreement with First National Capital, LLC, or FNC, whereby we agreed to sell certain assets from our infrastructure segment to FNC for aggregate proceeds of $5.0 million. Concurrent with the sale of assets, we entered into a 36 month lease agreement whereby we lease back the assets at a monthly rental rate of $0.1 million. On June 1, 2021, we entered into another agreement with FNC whereby we sold additional assets from our infrastructure segment to FNC for aggregate proceeds of $9.5 million and entered into a 42 month lease agreement whereby we lease back the assets at a monthly rental rate of $0.2 million. Under the agreements, we have the option to purchase the assets at the end of the lease term. We recorded a liability for the proceeds received and will continue to depreciate the assets. We imputed an interest rate so that the carrying amount of the financial liabilities will be the expected repurchase price at the end of the initial lease terms.

Aviation Note

On November 6, 2020, Leopard and Cobra Aviation entered into a 39 month promissory note agreement with Bank7, or the Aviation Note, in an aggregate principal amount of $4.6 million and received net proceeds of $4.5 million. The Aviation Note bears interest at a rate based on the Wall Street Journal Prime Rate plus a margin of 1%. Principal and interest payments of $0.1 million are due monthly beginning on March 1, 2021, with a final payment of $0.2 million due on February 1, 2024. The Aviation Note is collateralized by Leopard and Cobra Aviation’s assets, including a $1.8 million certificate of deposit. The Aviation Note contains various customary affirmative and restrictive covenants. As of September 30, 2021, we did not meet the minimum debt coverage ratio of 1.25 to 1.0 set forth in the Aviation Note. On November 3, 2021, Bank7 granted us a waiver of this event of default.

Capital Requirements and Sources of Liquidity

We believe that our cash on hand, operating cash flow and available borrowings under our credit facility will be sufficient to fund our operations, including our litigation settlement obligations, for at least the next twelve months. However, future cash flows are subject to a number of variables (including receipt of payments from our customers, including PREPA). As of September 30, 2021, PREPA owed Cobra approximately $328.2 million for services performed, including $101.2 million of interest charges. Throughout 2021, we have released significant data obtained through the Freedom of Information Act that affirms the work performed by Cobra in Puerto Rico. We believe these documents in conjunction with the current Administration’s focus on the recovery of Puerto Rico and enhanced lobbying efforts will aid in collecting the outstanding amounts owed to us by PREPA. However, in the event PREPA (i) does not have or does not obtain the funds necessary to satisfy its obligations to Cobra under the contracts, (ii) obtains the necessary funds but refuses to pay the amounts owed to Cobra or (iii) otherwise does not pay amounts owed to Cobra for services performed, the receivable may not be collectible.

We now estimate that during 2021 our aggregate capital expenditures will be up to $5.0 million depending upon industry conditions and our financial results. These capital expenditures include $0.7 million in our infrastructure segment for assets for additional crews, $3.5 million in our well completion segment for conversion of a portion of our fleet to include dynamic gas blending capabilities and maintenance to our existing pressure pumping fleet and $0.8 million for our other divisions, primarily for additional equipment for our rental business and upgrades to our sand facilities. During the nine months ended September 30, 2021, our capital expenditures totaled $4.5 million. Significant additional capital expenditures could be required to conduct our operations. Accordingly, there can be no assurance that operations and other capital resources, including potential sales of assets or businesses, will provide cash in sufficient amounts to meet our operating needs and/or maintain planned or future levels of capital expenditures.

In addition, while we regularly evaluate acquisition opportunities, we do not have a specific acquisition budget for 2021 since the timing and size of acquisitions cannot be accurately forecasted. We continue to evaluate acquisition opportunities, including those in the renewable energy sector as well as transactions involving entities controlled by Wexford. Our acquisitions may be undertaken with cash, our common stock or a combination of cash, common stock and/or other consideration. In the event we make one or more acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures and/or seek additional capital. If we seek additional capital for that or other reasons, we may do so through borrowings under our revolving credit facility, joint venture partnerships, sale-leaseback transactions, asset sales, offerings of debt or equity securities or other means. We cannot assure you that this additional capital will be available on acceptable terms or at all. If we are unable to obtain funds we need, our ability to conduct operations, make capital expenditures and/or complete acquisitions that may be favorable to us will be impaired.

Off-Balance Sheet Arrangements

We have entered into agreements with suppliers that contain minimum purchase obligations and agreements to purchase capital equipment. Aggregate future minimum payments under these obligations in effect at September 30, 2021 were approximately $1.5 million.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The demand, pricing and terms for our products and services are largely dependent upon the level of activity for the U.S. oil and natural gas industry, energy infrastructure industry and natural sand proppant industry. Industry conditions are influenced by numerous factors over which we have no control, including, but not limited to: the supply of and demand for oil and natural gas services, energy infrastructure services and natural sand proppant; demand for repair and construction of transmission lines, substations and distribution networks in the energy infrastructure industry and the level of expenditures of utility companies; the level of prices of, and expectations about future prices for, oil and natural gas and natural sand proppant, as well as energy infrastructure services; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; the discovery rates of new oil and natural gas reserves and frac sand reserves meeting industry specifications and consisting of the mesh size in demand; access to pipeline, transloading and other transportation facilities and their capacity; weather conditions; domestic and worldwide economic conditions; political instability in oil-producing countries; environmental regulations; technical advances affecting energy consumption; the price and availability of alternative fuels; the ability of oil and natural gas producers and other users of our services to raise equity capital and debt financing; and merger and divestiture activity in industries in which we operate.

In March and April 2020, concurrent with the COVID-19 pandemic and quarantine orders in the U.S. and worldwide, oil prices dropped sharply to below zero for the first time in history due to factors including significantly reduced demand and a shortage of storage facilities. In the third quarter of 2020, many U.S. producers resumed completion activities to stem production declines and stabilize their production base as demand for crude oil rebounded. Despite the recent improvement in the U.S. economic activity, easing of the COVID-19 pandemic and rising energy use and commodity prices, the near term energy outlook remains subject to heightened levels of uncertainty related to the ongoing economic recovery. As a result, we expect to see the challenging market for oilfield services continue for the foreseeable future, which has had, and is likely to continue to have, an adverse effect on both pricing and utilization for our oilfield services and our financial condition and results of operations.

The levels of activity in the U.S. oil and natural gas exploration and production, energy infrastructure and natural sand proppant industries have been and continue to be volatile. We are unable to predict the ultimate impact of the COVID-19 pandemic, the continued volatility in commodity markets, uncertainty in the demand for oil and oilfield services and current macroeconomic conditions on our business, financial condition, liquidity, results of operations, cash flows and stock price.

Interest Rate Risk

We had a cash and cash equivalents balance of $8.0 million at September 30, 2021. We do not enter into investments for trading or speculative purposes. We do not believe that we have any material exposure to changes in the fair value of these investments as a result of changes in interest rates. Declines in interest rates, however, will reduce future income.

Interest under our credit facility is payable at a base rate plus an applicable margin. Additionally, at our request, outstanding balances are permitted to be converted to LIBOR rate plus applicable margin tranches. The applicable margin for either the base rate or the LIBOR rate option can vary from 2.0% to 3.5%, based upon a calculation of the excess availability of the line as a percentage of the maximum credit limit. At September 30, 2021, we had outstanding borrowings under our revolving credit facility of $77.0 million with a weighted average interest rate of 3.32%. A 1% increase or decrease in the interest rate at that time would increase or decrease our interest expense by approximately $0.8 million per year. We do not currently hedge our interest rate exposure.

Foreign Currency Risk

Our remote accommodation business, which is included in our other services division, generates revenue and incurs expenses that are denominated in the Canadian dollar. These transactions could be materially affected by currency fluctuations. Changes in currency exchange rates could adversely affect our consolidated results of operations or financial position. We also maintain cash balances denominated in the Canadian dollar. At September 30, 2021, we had $1.5 million of cash, in Canadian dollars, in Canadian accounts. A 10% increase in the strength of the Canadian dollar versus the U.S. dollar would have resulted in an increase in pre-tax income of approximately $0.08 million as of September 30, 2021. Conversely, a corresponding decrease in the strength of the Canadian dollar would have resulted in a comparable decrease in pre-tax income. We have not hedged our exposure to changes in foreign currency exchange rates and, as a result, could incur unanticipated translation gains and losses.

Customer Credit Risk

We are also subject to credit risk due to concentration of our receivables from several significant customers. We generally do not require our customers to post collateral. The inability, delay or failure of our customers to meet their obligations to us due to customer liquidity issues or their insolvency or liquidation may adversely affect our business, financial condition, results of operations and cash flows. This risk may be further enhanced by the impact of the COVID-19 pandemic, the volatility in commodity price environment, the uncertainty in the levels of demand for oil and oilfield services and adverse macroeconomic conditions. See Note 2. Basis of Presentation and Significant Accounting Policies—Accounts Receivable and —Concentrations of Credit Risk and Significant Customers and Note 18. Commitments and Contingencies—Litigation of our unaudited condensed consolidated financial statements.

Seasonality

We provide completion and production services as well as contract land and drilling services primarily in the Utica, Permian Basin, Eagle Ford, Marcellus, Granite Wash, Cana Woodford and Cleveland sand resource plays located in the continental U.S. We provide infrastructure services primarily in the northeastern, southwestern, midwestern and western portions of the United States. We provide remote accommodation services in the oil sands in Alberta, Canada. We serve these markets through our facilities and service centers that are strategically located to serve our customers in Ohio, Texas, Oklahoma, Wisconsin, Minnesota, Kentucky and Alberta, Canada. A portion of our revenues are generated in Ohio, Wisconsin, Minnesota, North Dakota, Pennsylvania, West Virginia and Canada where weather conditions may be severe. As a result, our operations may be limited or disrupted, particularly during winter and spring months, in these geographic regions, which would have a material adverse effect on our financial condition and results of operations. Our operations in Oklahoma and Texas are generally not affected by seasonal weather conditions.

Item 4. Controls and Procedures

Evaluation of Disclosure Control and Procedures

Under the direction of our Chief Executive Officer and Chief Financial Officer, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and d under the Exchange Act, that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

As of September 30, 2021, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that as of September 30, 2021, our disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There was no change in our internal control over financial reporting (as defined in Rules 13a-15(d) and 15d-15(d) under the Exchange Act) that occurred during the quarter ended September 30, 2021 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Due to the nature of our business, we are, from time to time, involved in litigation or subject to disputes or claims related to our business activities, including breaches of contractual obligations, workers’ compensation claims and employment related disputes. In the opinion of our management, none of the pending litigation, disputes or claims against us is expected to have a material adverse effect on our financial condition, cash flows or results of operations, except as disclosed in Note 18 “Commitments and Contingencies,” of the Notes to Unaudited Condensed Consolidated Financial Statements.

Item 1A. Risk Factors

As of the date of this filing, our Company and operations continue to be subject to the risk factors previously disclosed in Item 1A. Risk Factors in our Annual Report on Form 10-K filed with the SEC on March 1, 2021, except that the Company has identified additional risk factors set forth below. For a discussion of the recent trends and uncertainties impacting our business, see also “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Impact of the COVID-19 Pandemic and Volatility in Commodity Prices” and “—Industry Overview.”

The U.S. presidential executive order concerning mandatory COVID-19 vaccination for certain U.S. government contractors and the new OSHA vaccine mandate for employers with more than 100 employees could have a material adverse impact on our business and results of operations.

On September 9, 2021, President Biden issued an executive order requiring all employers with U.S. government contracts to ensure that their U.S.-based employees, contractors and subcontractors that work on or in support of U.S. government contracts are fully vaccinated by December 8, 2021, which deadline is expected to be extended to January 4, 2022. The executive order includes on-site and remote U.S.-based employees, contractors and subcontractors and it only permits limited exceptions for medical and religious reasons. In addition, on September 9, 2021, President Biden announced plans for the federal Occupational Safety and Health Administration (OSHA) to issue an “Emergency Temporary Standard” (ETS) mandating that all employers with more than 100 employees ensure their workers are either fully vaccinated against COVID-19 or produce, on a weekly basis, a negative COVID test (the "vaccine mandate"). OSHA issued the ETS on November 4, 2021, requiring covered employers to comply with the vaccine mandate beginning with January 4, 2022 or face substantial penalties for non-compliance. Additional, more protective vaccine mandates may be announced by the state or local jurisdictions in which our businesses operate. Although it is not possible to predict with certainty the impact of these measures on our business and workforce, these requirements may result in attrition, including attrition of critically skilled labor, and difficulty securing future labor needs, and may further disrupt the national supply chain, all of which could have a material adverse effect on our business, financial condition and results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.

Item 4. Mine Safety Disclosures

Our operations are subject to the Federal Mine Safety and Health Act of 1977, as amended by the Mine Improvement and New Emergency Response Act of 2006, which imposes stringent health and safety standards on numerous aspects of mineral extraction and processing operations, including the training of personnel, operating procedures, operating equipment and other matters. Our failure to comply with such standards, or changes in such standards or the interpretation or enforcement thereof, could have a material adverse effect on our business and financial condition or otherwise impose significant restrictions on our ability to conduct mineral extraction and processing operations. Following passage of The Mine Improvement and New Emergency Response Act of 2006, MSHA significantly increased the numbers of citations and orders charged against mining operations. The dollar penalties assessed for citations issued has also increased in recent years. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 to this Report.

Item 5. Other Information

On November 3, 2021, we entered into the Third Amendment to Amended and Restated Credit Agreement, dated as of November 3, 2021, by and among us, certain of our subsidiaries, PNC Bank, National Association, as lender and administrative agent for the lenders, and other lenders party thereto. For a description of the Third Amendment, please see Note 9—Debt—Mammoth Credit Agreement.

MAMMOTH ENERGY SERVICES, INC.

Item 6. Exhibits

The following exhibits are filed as a part of this report:

Incorporated By Reference

Exhibit Number

Exhibit Description

Form

Commission File No.

Filing Date

Exhibit No.

Filed Herewith

Furnished Herewith

3.1

Amended and Restated Certificate of Incorporation of the Company

8-K

001-37917

11/15/2016

3.1

3.2

Amended and Restated Bylaws of the Company

8-K

001-37917

11/15/2016

3.2

3.3

First Amendment to Amended and Restated Bylaws of the Company

8-K

001-37917

6/9/2020

3.1

4.1

Specimen Certificate for shares of common stock, par value $0.01 per share, of the Company

S-1/A

333-213504

10/3/2016

4.1

4.2

Registration Rights Agreement, dated October 12, 2016, by and between the Company and Mammoth Energy Holdings, LLC

8-K

001-37917

11/15/2016

4.1

10.1

Third Amendment to Amended and Restated Credit Agreement, dated as of November 3, 2021, by and among the Company, certain of its subsidiaries, PNC Bank, National Association, as a lender and administrative agent for the lender, and other lenders party thereto

31.1

Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.

31.2

Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.

32.1

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

95.1

Mine Safety Disclosure Exhibit

101.INS

XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH

XBRL Taxonomy Extension Schema Document.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB

XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document.

104

Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

MAMMOTH ENERGY SERVICES, INC.

Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

MAMMOTH ENERGY SERVICES, INC.

Date:

November 5, 2021

By:

/s/ Arty Straehla

Arty Straehla

Chief Executive Officer

Date:

November 5, 2021

By:

/s/ Mark Layton

Mark Layton

Chief Financial Officer