UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549


Form 10-Q
ý☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2017
For the quarterly period ended March 31, 2023
o☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


FOR THE TRANSITION PERIOD FROMTO


Commission File No. 001-37917

Mammoth Energy Services, Inc.


(Exact name of registrant as specified in its charter)
Delaware32-0498321
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
14201 Caliber Drive Suite 300
Oklahoma City, Oklahoma		73134
(Address of principal executive offices)(Zip Code)
(405) 608-6007
(Registrant’s telephone number, including area code)
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)608-600773134
(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 classTrading Symbol(s)Name of each exchange on which registered
Common StockTUSKThe 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  ý☒    No  ¨☐


Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).    Yes  ý☒    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 filero☐Accelerated filero☐
Non-accelerated filero☒Smaller reporting companyo☒
Emerging growth companyý☐


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. ý¨


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


As of November 7, 2017,April 26, 2023, there were 44,502,22347,713,342 shares of common stock, $0.01 par value, outstanding.



MAMMOTH ENERGY SERVICES, INC.





TABLE OF CONTENTS
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Item 1.
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5
Item 2.
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Item 3.
4941
Item 4.
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5144
Item 1.
5144
Item 1A.
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Item 2.
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Item 4.
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Item 5.
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Item 6.
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5447





GLOSSARY OF OIL AND NATURAL GAS AND ELECTRICAL INFRASTRUCTURE TERMS
The following is a glossary of certain oil and natural gas and natural sand proppant industry terms used in this report:Quarterly Report on Form 10-Q (this “report” or “Quarterly Report”):
BlowoutAcidizingTo pump acid into a wellbore to improve a well’s productivity or injectivity.
BlowoutAn 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 assemblyThe 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.
CementingTo prepare and pump cement into place in a wellbore.
Coiled tubingA 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 7,0106,096 m) or greater length.
CompletionA 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 drillingThe 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-holePertaining to or in the wellbore (as opposed to being on the surface).
Down-hole motorA 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.applications and the day rates for drilling rigs.
Drilling rigThe machine used to drill a wellbore.
Drillpipe or Drill pipeTubular 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 stringThe combination of the drillpipe, the bottomhole assembly and any other tools used to make the drill bit turn at the bottom of the wellbore.
FlowbackThe 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 drillingA 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 fracturingA 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.
i

HydrocarbonA 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 sizeThe 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 motorsA 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 liquidsComponents 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.

i

Nitrogen pumping unitA 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.
PluggingThe 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.
PlugA 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 inchA unit of pressure. It is the pressure resulting from a one pound force applied to an area of one square inch.
Pressure pumpingServices that include the pumping of liquids under pressure.
Producing formationAn 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.
ProppantSized 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 playAccumulation of hydrocarbons known to exist over a large area.
ShaleA fine-grained, fissile, sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers.
Tight oilConventional 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 sandsA type of unconventional tight reservoir. Tight reservoirs are those which have low permeability, often quantified as less than 0.1 millidarcies.
TubularsA generic term pertaining to any type of oilfield pipe, such as drillpipe,drill pipe, drill collars, pup joints, casing, production tubing and pipeline.
Unconventional resourceresource/unconventional wellAn umbrellaA term for oil and natural gas thatthe different manner by which resources are exploited as compared to the extraction of conventional resources. In unconventional drilling, the wellbore is produced by means that do not meetgenerally drilled to specific objectives within narrow parameters, often across long, lateral intervals within narrow horizontal formations offering greater contact area with the criteria for conventionalproducing formation. Typically, the well is then hydraulically fractured at multiple stages to optimize production. What has qualified as “unconventional” at any particular time is a complex function of resource characteristics, the available exploration and production technologies, the economic environment, and the scale, frequency and duration of production from the resource. Perceptions of these factors inevitably change over time and often differ among users of the term. At present, the term is used in reference to oil and gas resources whose porosity, permeability, fluid trapping mechanism, or other characteristics differ from conventional sandstone and carbonate reservoirs. Coalbed methane, gas hydrates, shale gas, fractured reservoirs and tight gas sands are considered unconventional resources.
WellboreThe physical conduit from surface into the hydrocarbon reservoir.
Well stimulationA 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.
WirelineA 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.
WorkoverThe 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.


ii


The following is a glossary of certain electrical infrastructure industry terms used in this report:
DistributionThe distribution of electricity from the transmission system to individual customers.
SubstationA part of an electrical transmission and distribution system that transforms voltage from high to low, or the reverse.
TransmissionThe 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, 20162022 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 our: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;
•any continuing impacts of the COVID-19 pandemic on Mammoth’s results of operations, financial condition or demand for Mammoth’s services;
•operational challenges relating to continuing efforts to prevent or mitigate the spread of COVID-19, including logistical challenges, remote work arrangements and protecting the health, safety and well-being of Mammoth’s employees;
•employee retention and increasingly competitive labor market;
•the performance of contracts and supply chain disruptions during or following the COVID-19 pandemic;
•general economic, business strategy;or industry conditions and concerns over a potential economic slowdown or recession;
pending or future acquisitions•conditions in the capital, financial and future capital expenditures;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 energy and environmental policies;
•inflationary pressure on the cost of services, equipment and other goods in our industries and other sectors;
•our ability to obtain capital or financing needed for our operations on favorable terms or at all;
•our ability to (i) continue to comply with or, if applicable, obtain a waiver of forecasted or actual non-compliance with certain financial covenants from our lenders and comply with other terms and conditions under our amended revolving credit facility, as amended, (ii) extend, repay or refinance our revolving credit facility at or prior to maturity on the terms acceptable to us or at all and (iii) meet our financial projections associated with reducing our debt;
•our ability to execute our business and financial strategies;
•our ability to continue to grow our infrastructure services segment or recommence certain of our suspended oilfield services;
•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;approvals and/or payments, and to comply with applicable governmental laws and regulations;
technology;•the results of litigation relating to the contracts awarded to our subsidiary Cobra Acquisitions LLC, or Cobra, by the Puerto Rico Electric Power Authority, or PREPA;
financial strategy;•the outcome of our ongoing efforts to collect the outstanding amounts owed to us by PREPA for electric grid restoration services performed by Cobra in Puerto Rico;
•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;
•shortages, delays in delivery and interruptions in supply of major components, replacement parts, or other equipment, supplies or materials;
•the availability of transportation, pipeline and storage facilities and any increase in related costs;
•extreme weather conditions in areas where we provide well completion, drilling and infrastructure services;
•access to and restrictions on use of sourced or produced water;
•technology;
•civil unrest, war, military conflicts 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;
iv

•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,"“will,” “could,” “should,” “would,” “expect,” “plan,” “project,” “budget,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “seek,” “objective”“objective,” “continue,” “will be,” “will benefit,” or “continue,“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.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.statements due to many factors including those described in our Annual Report on Form 10–K for the year ended December 31, 2022 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.



iii
v
MAMMOTH ENERGY SERVICES, INC.





PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
MAMMOTH ENERGY SERVICES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS (unaudited)
ASSETSMarch 31,December 31,
20232022
CURRENT ASSETS(in thousands)
Cash and cash equivalents$11,727 $17,282 
Accounts receivable, net475,582 456,465 
Receivables from related parties, net115 223 
Inventories10,230 8,883 
Prepaid expenses10,056 13,219 
Other current assets581 620 
Total current assets508,291 496,692 
Property, plant and equipment, net132,529 138,066 
Sand reserves61,830 61,830 
Operating lease right-of-use assets11,907 10,656 
Intangible assets, net1,587 1,782 
Goodwill11,717 11,717 
Other non-current assets3,635 3,935 
Total assets$731,496 $724,678 
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable$57,174 $47,391 
Accrued expenses and other current liabilities38,485 52,297 
Current operating lease liability5,858 5,447 
Current portion of long-term debt84,614 83,520 
Income taxes payable51,588 48,557 
Total current liabilities237,719 237,212 
Deferred income tax liabilities444 471 
Long-term operating lease liability5,772 4,913 
Asset retirement obligations4,017 3,981 
Other long-term liabilities12,846 15,485 
Total liabilities260,798 262,062 
COMMITMENTS AND CONTINGENCIES (Note 18)
EQUITY
Equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 47,713,342 and 47,312,270 issued and outstanding at March 31, 2023 and December 31, 2022477 473 
Additional paid in capital538,862 539,138 
Accumulated deficit(64,803)(73,154)
Accumulated other comprehensive loss(3,838)(3,841)
Total equity470,698 462,616 
Total liabilities and equity$731,496 $724,678 

ASSETS September 30, December 31,
CURRENT ASSETS 2017 2016 (a)
Cash and cash equivalents $14,278,328
 $29,238,618
Accounts receivable, net 65,490,189
 21,169,579
Receivables from related parties 44,772,661
 27,589,283
Inventories 12,164,225
 6,124,201
Prepaid expenses 2,753,800
 4,425,872
Other current assets 335,513
 391,599
Total current assets 139,794,716
 88,939,152
     
Property, plant and equipment, net 347,317,716
 242,119,663
Sand reserves 75,210,457
 55,367,295
Intangible assets, net - customer relationships 11,770,375
 15,949,772
Intangible assets, net - trade names 6,722,197
 5,617,057
Goodwill 99,810,819
 88,726,875
Other non-current assets 4,509,500
 5,642,661
Total assets $685,135,780
 $502,362,475
LIABILITIES AND EQUITY    
CURRENT LIABILITIES    
Accounts payable $70,229,349
 $20,469,542
Payables to related parties 211,352
 203,209
Accrued expenses and other current liabilities 21,556,542
 8,546,198
Income taxes payable —
 28,156
Total current liabilities 91,997,243
 29,247,105
     
Long-term debt 94,000,000
 —
Deferred income taxes 51,086,739
 47,670,789
Asset retirement obligation 2,031,119
 259,804
Other liabilities 4,755,414
 2,404,422
Total liabilities 243,870,515
 79,582,120
     
COMMITMENTS AND CONTINGENCIES (Note 14) 
 
    
EQUITY   
Equity:    
Common stock, $0.01 par value, 200,000,000 shares authorized, 44,502,223 and 445,022
 375,000
37,500,000 issued and outstanding at September 30, 2017 and December 31, 2016, respectively.    
Additional paid in capital 506,274,038
 400,205,921
Member's equity —
 81,738,675
Accumulated deficit (63,274,499) (56,322,878)
Accumulated other comprehensive loss (2,179,296) (3,216,363)
Total equity 441,265,265
 422,780,355
Total liabilities and equity $685,135,780
 $502,362,475

(a) Financial information has been recast to include the financial position and results attributable to Sturgeon Acquisitions LLC ("Sturgeon"). See Note 3.





The accompanying notes are an integral part of these condensed consolidated financial statements.
1
MAMMOTH ENERGY SERVICES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSSINCOME (LOSS) (unaudited)



Three Months Ended March 31,
20232022
REVENUE(in thousands, except per share amounts)
Services revenue$103,637 $53,667 
Services revenue - related parties220 274 
Product revenue12,463 8,357 
Total revenue116,320 62,298 
COST AND EXPENSES
Services cost of revenue (exclusive of depreciation, depletion, amortization and accretion of $11,762 and $15,355, respectively, for the three months ended March 31, 2023 and 2022)80,977 46,567 
Services cost of revenue - related parties (exclusive of depreciation, depletion, amortization and accretion of $0 and $0 , respectively, for the three months ended March 31, 2023 and 2022)31 135 
Product cost of revenue (exclusive of depreciation, depletion, amortization and accretion of $1,186 and $1,792, respectively, for the three months ended March 31, 2023 and 2022)7,985 7,778 
Selling, general and administrative (Note 11)8,383 8,668 
Depreciation, depletion, amortization and accretion12,956 17,167 
Gains on disposal of assets, net(361)(196)
Total cost and expenses109,971 80,119 
Operating income (loss)6,349 (17,821)
OTHER INCOME (EXPENSE)
Interest expense, net(3,289)(2,349)
Other income, net8,624 9,041 
Total other income, net5,335 6,692 
Income (loss) before income taxes11,684 (11,129)
Provision for income taxes3,333 3,688 
Net income (loss)$8,351 $(14,817)
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign currency translation adjustment, net of tax of $0 and $0, respectively, for the three months ended March 31, 2023 and 2022)3 198 
Comprehensive income (loss)$8,354 $(14,619)
Net income (loss) per share (basic) (Note 14)$0.18 $(0.32)
Net income (loss) per share (diluted) (Note 14)$0.17 $(0.32)
Weighted average number of shares outstanding (basic) (Note 14)47,443 46,845 
Weighted average number of shares outstanding (diluted) (Note 14)48,002 46,845 

 Three Months Ended
Nine Months Ended
 September 30,
September 30,
REVENUE2017 2016 (a) 2017 (b) 2016 (a)
Services revenue$63,112,621
 $19,077,680
 $119,863,654
 $65,964,774
Services revenue - related parties56,860,754
 36,028,399
 134,425,170
 76,679,011
Product revenue15,276,279
 1,675,230
 29,043,367
 4,651,673
Product revenue - related parties14,055,246
 6,557,237
 39,200,789
 17,788,581
Total revenue149,304,900
 63,338,546
 322,532,980
 165,084,039
        
COST AND EXPENSES       
Services cost of revenue (1)89,345,946
 35,850,660
 191,910,453
 102,113,120
Services cost of revenue - related parties8,899
 587,087
 701,008
 787,079
Product cost of revenue (2)25,177,849
 6,429,040
 57,759,173
 22,861,407
Selling, general and administrative7,667,419
 3,063,445
 21,473,039
 11,558,114
Selling, general and administrative - related parties355,242
 131,162
 986,126
 456,505
Depreciation, depletion, accretion and amortization27,223,733
 17,921,471
 64,354,383
 54,483,158
Impairment of long-lived assets—
 —
 —
 1,870,885
Total cost and expenses149,779,088
 63,982,865
 337,184,182
 194,130,268
Operating loss(474,188) (644,319) (14,651,202) (29,046,229)
        
OTHER (EXPENSE) INCOME       
Interest expense(1,420,067) (1,024,514) (2,928,859) (3,332,901)
Bargain purchase gain, net of tax—
 —
 4,011,512
 —
Other, net(319,252) (253,832) (705,894) 371,894
Total other (expense) income(1,739,319) (1,278,346) 376,759
 (2,961,007)
Loss before income taxes(2,213,507) (1,922,665) (14,274,443) (32,007,236)
(Benefit) provision for income taxes(1,412,680) 1,055,961
 (7,322,822) 2,739,696
Net loss$(800,827) $(2,978,626) $(6,951,621) $(34,746,932)
        
OTHER COMPREHENSIVE INCOME (LOSS)       
Foreign currency translation adjustment (3)627,515
 (386,265) 1,037,067
 1,583,593
Comprehensive loss$(173,312) $(3,364,891) $(5,914,554) $(33,163,339)
        
Net loss per share (basic and diluted) (Note 10)$(0.02) $(0.10) $(0.17) $(1.16)
Weighted average number of shares outstanding (Note 10)44,501,885
 30,000,000
 40,526,276
 30,000,000
        
Pro Forma C Corporation Data:       
Net loss, as reported

 (2,978,626) 

 (34,746,932)
Pro forma benefit for income taxes

 (3,896,035) 

 (9,701,517)
Pro forma net loss

 917,409
 

 (25,045,415)
Basic and Diluted (Note 10)

 $0.02
 

 $(0.58)
Weighted average pro forma shares outstanding—basic and diluted (Note 10)

 43,107,452
 

 43,107,452
        
(1) Exclusive of depreciation and amortization24,152,840
 16,115,125
 57,641,729
 49,658,528
(2) Exclusive of depreciation and amortization3,033,092
 1,783,439
 6,599,251
 4,729,620
(3) Net of tax357,594
 —
 811,906
 —

(a) Financial information has been recast to include the financial position and results attributable to Sturgeon. See Note 3.
(b) Financial information includes the financial position and results attributable to Sturgeon for the entire period presented. See Note 3.


















The accompanying notes are an integral part of these condensed consolidated financial statements.statements.
2
MAMMOTH ENERGY SERVICES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (unaudited)

Three Months Ended March 31, 2023
Accumulated
AdditionalOther
Common StockAccumulatedPaid-InComprehensive
SharesAmountDeficitCapitalLossTotal
(in thousands)
Balance at December 31, 202247,312 $473 $(73,154)$539,138 $(3,841)462,616 
Stock based compensation567 6 — 641 — 647 
Shares repurchased(166)(2)(917)(919)
Net income— — 8,351 — — 8,351 
Other comprehensive income— — — — 3 3 
Balance at March 31, 202347,713 $477 $(64,803)$538,862 $(3,838)$470,698 
Three Months Ended March 31, 2022
Accumulated
AdditionalOther
Common StockAccumulatedPaid-InComprehensive
SharesAmountDeficitCapitalLossTotal
(in thousands)
Balance at December 31, 202146,684 $467 $(72,535)$538,221 $(2,931)$463,222 
Stock based compensation500 5 — 236 — 241 
Net loss— — (14,817)— — (14,817)
Other comprehensive income— — — — 198 198 
Balance at March 31, 202247,184 $472 $(87,352)$538,457 $(2,733)$448,844 

         
      Additional  
 Common StockCommonMembers'AccumulatedPaid-In  
 SharesAmountPartnersEquityDeficitCapitalAOCLTotal
Balance at January 1, 2016 (a)—
$—
$329,090,230
$90,783,508
$—
$—
$(5,926,968)$413,946,770
Net loss prior to LLC conversion—
—
(32,085,117)—
—
—
—
(32,085,117)
Equity based compensation—
—
(18,683)—
—
—
—
(18,683)
LLC Conversion (Note 1)—
—
(296,986,430)—
—
296,986,430
—
—
Issuance of common stock at public offering, net of offering costs37,500,000
375,000
—
—
—
102,699,661
—
103,074,661
Stock-based compensation—
—
—
—
—
519,830
—
519,830
Net loss—
—
—
(4,044,833)—
—
—
(4,044,833)
Distributions—
—
—
(5,000,000)—
—
—
(5,000,000)
Net loss subsequent to LLC conversion—
—
—
—
(56,322,878)—
—
(56,322,878)
Other comprehensive income—
—
—
—
—
—
2,710,605
2,710,605
Balance at December 31, 2016 (a)37,500,000
375,000
—
81,738,675
(56,322,878)400,205,921
(3,216,363)422,780,355
Net loss—
—
—
—
(6,951,621)—
—
(6,951,621)
Stingray acquisition1,392,548
13,925
—
—
—
25,748,213
—
25,762,138
Sturgeon acquisition5,607,452
56,075
—
(81,738,675)—
77,671,715
—
(4,010,885)
Equity based compensation2,223
22
—
—
—
2,648,189
—
2,648,211
Other comprehensive income—
—
—
—
—
—
1,037,067
1,037,067
Balance at September 30, 201744,502,223
$445,022
$—
$—
$(63,274,499)$506,274,038
$(2,179,296)$441,265,265
























































(a) Financial information has been recast to include the financial position and results attributable to Sturgeon. See Note 3.


The accompanying notes are an integral part of these condensed consolidated financial statements.
3
MAMMOTH ENERGY SERVICES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)



Three Months Ended March 31,
20232022
(in thousands)
Cash flows from operating activities:
Net income (loss)$8,351 $(14,817)
Adjustments to reconcile net income (loss) to cash used in operating activities:
Stock based compensation647 241 
Depreciation, depletion, accretion and amortization12,956 17,167 
Amortization of debt origination costs188 186 
Bad debt recoveries(381)(99)
Gains on disposal of assets(361)(196)
Gains from sales of equipment damaged or lost down-hole— (397)
Deferred income taxes(27)3,481 
Other174 535 
Changes in assets and liabilities:
Accounts receivable, net(18,643)(3,898)
Receivables from related parties, net109 (225)
Inventories(1,347)(1,992)
Prepaid expenses and other assets3,203 3,404 
Accounts payable8,602 1,041 
Accrued expenses and other liabilities(13,262)(7,013)
Income taxes payable3,031 201 
Net cash provided by (used in) operating activities3,240 (2,381)
Cash flows from investing activities:
Purchases of property and equipment(6,036)(1,182)
Proceeds from disposal of property and equipment330 1,038 
Net cash used in investing activities(5,706)(144)
Cash flows from financing activities:
Borrowings on long-term debt66,700 37,550 
Repayments of long-term debt(65,606)(35,317)
Payments on sale leaseback transaction(1,214)(868)
Principal payments on financing leases and equipment financing notes(2,044)(629)
Other(919)— 
Net cash (used in) provided by financing activities(3,083)736 
Effect of foreign exchange rate on cash(6)8 
Net change in cash and cash equivalents(5,555)(1,781)
Cash and cash equivalents at beginning of period17,282 9,899 
Cash and cash equivalents at end of period$11,727 $8,118 
Supplemental disclosure of cash flow information:
Cash paid for interest$3,108 $1,754 
Cash paid for income taxes, net of refunds received$(26)$6 
Supplemental disclosure of non-cash transactions:
Purchases of property and equipment included in accounts payable and accrued expenses$5,917 $1,707 

 Nine Months Ended
 September 30,
Cash flows from operating activities2017 (a) 2016 (b)
Net loss$(6,951,621) $(34,746,932)
Adjustments to reconcile net loss to cash provided by operating activities:   
Equity based compensation2,648,211
 (18,683)
Depreciation, depletion, accretion and amortization64,354,383
 54,483,158
Amortization of coil tubing strings2,144,231
 1,386,856
Amortization of debt origination costs299,104
 452,343
Bad debt expense117,426
 1,779,870
(Gain) loss on disposal of property and equipment125,653
 (426,917)
Gain on bargain purchase(4,011,512) —
Impairment of long-lived assets—
 1,870,885
Deferred income taxes(8,151,410) (18,906)
Changes in assets and liabilities, net of acquisitions of businesses:   
Accounts receivable, net(37,439,781) (2,139,172)
Receivables from related parties(12,080,870) 167,964
Inventories(7,878,174) (119,260)
Prepaid expenses and other assets2,643,797
 59,940
Accounts payable30,444,904
 2,099,991
Payables to related parties7,934
 (394,292)
Accrued expenses and other liabilities14,392,715
 (1,292,176)
Income taxes payable(28,156) (4,052)
Net cash provided by operating activities40,636,834
 23,140,617
    
Cash flows from investing activities:   
Purchases of property and equipment(102,273,490) (4,108,047)
Business acquisitions(42,008,187) —
Proceeds from disposal of property and equipment782,432
 3,399,705
Business combination cash acquired (Note 3)2,671,558
 —
Net cash used in investing activities(140,827,687) (708,342)
    
Cash flows from financing activities:   
Borrowings from lines of credit118,850,000
 22,776,411
Repayments of lines of credit(24,850,000) (45,776,411)
Repayment of Stingray acquisition long-term debt(8,851,063) —
Net cash provided by (used in) financing activities85,148,937
 (23,000,000)
Effect of foreign exchange rate on cash81,626
 186,967
Net decrease in cash and cash equivalents(14,960,290) (380,758)
Cash and cash equivalents at beginning of period29,238,618
 4,038,899
Cash and cash equivalents at end of period$14,278,328
 $3,658,141
    
Supplemental disclosure of cash flow information:   
Cash paid for interest$2,300,250
 $2,972,072
Cash paid for income taxes$840,421
 $2,755,562
Supplemental disclosure of non-cash transactions:   
Purchases of property and equipment included in trade accounts payable$13,647,557
 $1,832,892
Acquisition of Sturgeon, Stingray Cementing LLC and Stingray Energy Services LLC (Note 3)$23,090,580
 $—

(a) Financial information includes the financial position and results attributable to Sturgeon for the entire period presented. See Note 3.
(b) Financial information has been recast to include the financial position and results attributable to Sturgeon. See Note 3.







The accompanying notes are an integral part of these condensed consolidated financial statements.
4
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



1.1.    Organization and Basis of Presentation
The accompanying unaudited condensed consolidated interim financial statements were prepared in accordance with the rules and regulationsNature of the Securities and Exchange Commission, and reflect 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. These condensed consolidated interim 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 2016 annual consolidated financial statements of Business
Mammoth Energy Services, Inc. (the "Company," "Mammoth(“Mammoth Inc."”, “Mammoth” or "Mammoth" ) in the Company's Annual Report on Form 10-K filed on February 24, 2017.

Mammoth,“Company”), together with its subsidiaries, is an integrated, growth-oriented energy services company serving companies engagedboth the oil and gas and the electric utility industries in North America and US territories. Mammoth Inc.’s infrastructure division provides engineering, design, 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 development of North American onshore unconventional oilproduction industry including well completion, natural sand and natural gas reservesproppant and energy infrastructure.drilling services. Additionally, the Company provides aviation services, equipment rentals, remote accommodation services and equipment manufacturing. The Company was incorporated in Delaware in June 2016 as a wholly-owned subsidiary of Mammoth Energy Partners LP, a Delaware limited partnership (the "Partnership" or the "Predecessor"). The Partnership was originally formed by Wexford Capital LP (“Wexford”) in February 2014 as a holding company under the name Redback Inc. and was converted to a Delaware limited partnership in August 2014. On November 24, 2014, Gulfport Energy Corporation (“Gulfport”), Rhino Resource Partners LP (“Rhino”) and Mammoth Energy Holdings LLC (“Mammoth Holdings”), an entity controlled by Wexford, contributed their interest in certain of the entities presented below to the Partnership in exchange for 20 million limited partner units. Mammoth Energy Partners GP, LLC (the “General Partner”) held a non-economic general partner interest.2016.

The following companies (the "Operating Entities”) are included in these condensed consolidated financial statements: Bison Drilling and Field Services, LLC (“Bison Drilling”), formed November 15, 2010; Bison Trucking LLC (“Bison Trucking”), formed August 9, 2013; White Wing Tubular Services LLC (“White Wing”), formed July 29, 2014; Barracuda Logistics LLC (“Barracuda”), formed October 24, 2014; Mr. Inspections LLC (“MRI”), formed January 25, 2015; Panther Drilling Systems LLC (“Panther”), formed December 11, 2012; Redback Energy Services, LLC (“Energy Services”), formed October 6, 2011; Redback Coil Tubing, LLC (“Coil Tubing”), formed May 15, 2012; Redback Pump Down Services LLC (“Pump Down”), formed January 16, 2015; Muskie Proppant LLC (“Muskie”), formed September 14, 2011; Stingray Pressure Pumping LLC (“Pressure Pumping”), formed March 20, 2012; Stingray Logistics LLC (“Logistics”), formed November 19, 2012; and Great White Sand Tiger Lodging Ltd. (“Lodging”), formed October 1, 2007, Silverback Energy Services LLC ("Silverback"), formed June 8, 2016; Mammoth Equipment Leasing LLC, formed on November 14, 2016; Cobra Acquisitions LLC ("Cobra Acquisitions"), formed January 9, 2017; Cobra Energy LLC ("Cobra"), formed January 24, 2017; Piranha Proppant LLC ("Piranha"), formed March 28, 2017; Mako Acquisitions LLC, (“Mako”) formed on March 28, 2017; Higher Power Electrical LLC ("Higher Power"), acquired April 21, 2017; Stingray Energy Services LLC ("SR Energy"), acquired June 5, 2017; Stingray Cementing LLC ("Cementing"), acquired June 5, 2017; Sturgeon Acquisitions LLC (“Sturgeon”), acquired June 5, 2017; Taylor Frac, LLC (“Taylor Frac”), acquired June 5, 2017; Taylor Real Estate Investments, LLC (“Taylor RE”), acquired June 5, 2017; South River Road, LLC (“South River”), acquired June 5, 2017; and 5 Star Electric, LLC ("5 Star"), acquired July 1, 2017.

The contribution to the Partnership on November 24, 2014 of all Operating Entities, except Pressure Pumping, Logistics and entities created or acquired after the date of such contribution to the Partnership, was treated as a combination of entities under common control. On November 24, 2014, the Partnership also acquired Pressure Pumping and Logistics (collectively, the “Stingray Entities”) in exchange for 10 million limited partner units. Prior to the contribution, the Partnership did not conduct any material business operations other than certain activities related to the preparation of the registration statement for a proposed initial public offering.

On October 12, 2016, the Partnership was converted into a Delaware limited liability company named Mammoth Energy Partners LLC (“Mammoth LLC”), and then Mammoth Holdings, Gulfport and Rhino, as all the members of Mammoth LLC, contributed their member interests in Mammoth LLC to Mammoth Inc. Prior to the conversion and the contribution, Mammoth Inc. was a wholly-owned subsidiary of the Partnership. Following the conversion and the contribution, Mammoth LLC (as the converted successor to the Partnership) was a wholly-owned subsidiary of Mammoth Inc. Mammoth Inc. did not conduct any material business operations until Mammoth LLC was contributed to it. On October 19, 2016, Mammoth Inc. closed its initial public offering of  7,750,000 shares of common stock (the "IPO"), which included an aggregate of 250,000 shares that were offered by Mammoth Holdings, Gulfport and Rhino, at a price to the public of $15.00 per share.
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Net proceeds to Mammoth Inc. from its sale of 7,500,000 shares of common stock were approximately $103.1 million. On the closing date of the IPO, Mammoth Inc. repaid all outstanding borrowings under its revolving credit facility and the remaining net proceeds for general corporate purposes, which included the acquisition of additional equipment and complementary businesses that enhanced its existing service offerings, broadened its service offerings and expanded its customer relationships.

On March 27, 2017, the Company entered into a definitive asset purchase agreement, as amended as of May 24, 2017 (the “Purchase Agreement”), with Chieftain Sand and Proppant, LLC and Chieftain Sand and Proppant Barron, LLC, unrelated third party sellers (the “Chieftain Sellers”), following Mammoth’s successful bid in a bankruptcy court auction for substantially all of the assets of the Sellers (the “Chieftain Acquisition”). The Chieftain Acquisition closed on May 26, 2017 for the purchase price of $36.3 million, including closing adjustments. Mammoth funded the purchase price for the Chieftain Acquisition with cash on hand and borrowings under its revolving credit facility. Refer to Note 3 - Acquisitions for additional disclosure regarding the Chieftain Acquisition.

On June 5, 2017, the Company completed the acquisition of (1) Sturgeon, a Delaware limited liability company, which included the acquisition of Sturgeon's wholly-owned subsidiaries Taylor Frac, a Wisconsin limited liability company, Taylor RE, a Wisconsin limited liability company, and South River, a Wisconsin limited liability company, (2) SR Energy, a Delaware limited liability company; and (3) Cementing, a Delaware limited liability company (together with SR Energy, the “Stingray Acquisition”) in exchange for the issuance by Mammoth of an aggregate of 7,000,000 shares of its common stock.

Prior to its acquisition of Sturgeon, the Company and Sturgeon were under common control and it is required under accounting principles generally accepted in the Unites States of America ("GAAP") to account for this common control acquisition in a manner similar to the pooling of interest method of accounting. Therefore, the Company's historical financial information for all periods included in the accompanying financial statements has been recast to combine Sturgeon LLC with the Company as if the acquisition had been effective since the date Sturgeon commenced operations. Refer to Note 3 - Acquisitions for additional disclosure regarding the acquisition of Sturgeon LLC.

At September 30, 2017 and December 31, 2016, Mammoth Holdings, or its affiliates, Gulfport and Rhino owned the following share of outstanding common stock of Mammoth Inc.:
  At September 30, 2017 At December 31, 2016
  Share Count % Ownership Share Count % Ownership
Mammoth Holdings 25,009,319
 56.2% 20,443,903
 54.5%
Gulfport 11,171,887
 25.1% 9,073,750
 24.2%
Rhino 568,794
 1.3% 232,347
 0.6%
Outstanding shares owned by related parties 36,750,000
 82.6% 29,750,000
 79.3%
Total outstanding 44,502,223
 100.0% 37,500,000
 100.0%


Operations


The Company's pressure pumpingCompany’s well completion services include equipment and personnel used in connection with the completion and early production of oil and natural gas wells, wellwells. The Company’s infrastructure services include coil tubing units usedengineering, design, construction, upgrade, maintenance and repair services to enhance the flow of oil or natural gaselectrical infrastructure industry as well as repair and restoration services in response to storms and other disasters. 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 contract land and directionalCompany’s drilling services providesprovide drilling rigs and directional tools for both vertical and horizontal drilling of oil and natural gas wells. The Company also provides other energy services, which have historically consisted ofincluding aviation, equipment rentals, remote accommodations for people working in the oil sands located in Northern Alberta, Canada, but now include energy infrastructure services.and equipment manufacturing.


All of theThe Company’s operations are concentrated in North America. The Company operates 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'sCompany’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. 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. 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.

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.

Reclassifications    
Certain reclassifications have been made to prior period amounts to conform to the current period financial statement presentation. Previously, the Company included gains and losses on disposal of assets within Other income (expense), net
5
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

entire health of the oil and natural gas industry. Changes in the commodity prices for oil and natural gas could have a material effect on the Company’s results of operations and financial condition.

2.Summary of Significant Accounting Policies

(a) Principles of Consolidation
Theunaudited condensed consolidated financial statements are prepared in accordance with GAAP. All material intercompany accountsof comprehensive income (loss). The Company now presents gains and transactions between the entities within the Company have been eliminated.

(b) Use of Estimates     
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amountslosses on disposal of assets and liabilities, the disclosureas a separate line titled “Gains on disposal of contingent assets, and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include but are not limited to the Company's sand reserves and their impact on calculating the depletion expense, the allowance for doubtful accounts, asset retirement obligation, reserves for self-insurance, depreciation and amortization of property and equipment, business combination valuations, amortization of intangible assets, and future cash flows and fair values used to assess recoverability and impairment of long-lived assets, including goodwill.net”.


(c) Cash and Cash Equivalents
All highly liquid investments with an original maturity of three months or less are considered cash equivalents. The Company maintains its cash accounts in financial institutions that are insured by the Federal Deposit Insurance Corporation, with the exception of cash held by Lodging in a Canadian financial institution. At September 30, 2017, the Company had $3.0 million, in Canadian dollars, of cash in Canadian accounts. Cash balances from time to time may exceed the insured amounts; however the Company has not experienced any losses in such accounts and does not believe it is exposed to any significant credit risks on such accounts.
(d) Accounts Receivable
Accounts receivable include amounts due from customers for services performed and are recorded as the work progresses.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 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 months ended March 31, 2023 and 2022, the Company charged interest on delinquent accounts receivable pursuant to the terms of its agreements with PREPA totaling $11.2 million and $9.9 million, respectively. These amounts are included in “other income, net” on the unaudited condensed consolidated statements of comprehensive income (loss). Included in “accounts receivable, net” on the unaudited condensed consolidated balance sheets as of March 31, 2023 and December 31, 2022 were interest charges of $163.2 million and $152.0 million, respectively.

The Company regularly reviews receivables and provides for estimatedexpected 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 conditionscondition of customers change,changes, circumstances develop, or additional information becomes available, adjustments to the allowance for doubtful accounts may be required. In the event the Company was to determineexpects 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 ofregarding their uncollectability.collectability.


Following is a roll forward of the allowance for doubtful accounts for the year ended December 31, 20162022 and the ninethree months ended September 30, 2017:March 31, 2023 (in thousands):


Balance, January 1, 2022$18,085 
Additions charged to bad debt expense3,550 
Recoveries of receivables previously charged to bad debt expense(161)
Deductions for uncollectible receivables written off(17,887)
Balance, December 31, 20223,587 
Additions charged to bad debt expense33 
Additions charged to revenue39 
Deductions for uncollectible receivables written off(2)
Balance, March 31, 2023$3,657 

During the three months ended March 31, 2023 and 2022, the Company has made specific reserves consistent with Company policy which resulted in nominal additions to allowance for doubtful accounts. These additions were charged to bad debt expense based on the factors described above.

PREPA

As of March 31, 2023, PREPA owed Cobra approximately $227.0 million for services performed, excluding $163.2 million of interest charged on these delinquent balances. PREPA is currently subject to bankruptcy proceedings, which
6
Balance, January 1, 2016 $4,011,882
Additions charged to expense 1,968,001
Deductions for uncollectible receivables written off (602,967)
Balance, December 31, 2016 5,376,916
Additions charged to expense 117,426
Additions other 178,871
Balance, September 30, 2017 $5,673,213

MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

were filed in July 2017 and are currently pending in the U.S. District Court for the District of Puerto Rico. As discussed in Note 1, prolonged declines in pricing can impacta result, PREPA’s ability to meet its payment obligations is largely dependent upon funding from the overall healthFederal 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 oilamounts 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 natural gas industry.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 report 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 be releasing 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 year endedjoint 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. FEMA approved the appeal in part and denied the appeal in part. FEMA found that staffing costs of $24.4 million are eligible for funding. On August 4, 2021, the Court denied Cobra’s April 6, 2021 motion to lift the stay order, extended the stay of our motion seeking recovery of amounts owed to Cobra and directed the parties to file an additional joint status report, which was filed on January 22, 2022. On January 26, 2022, the Court extended the stay and directed the parties to file a further status report by July 25, 2022. On June 7, 2022, Cobra filed a motion to lift the stay order. On June 29, 2022 the Court denied Cobra’s motion and extended the stay to January 2023. On November 21, 2022, FEMA issued a Determination Memorandum related to the 100% federal funded portion of the second contract between Cobra and PREPA in which FEMA concluded that approximately $5.6 million in costs were not authorized costs under the contract. On December 21, 2022, FEMA issued a Determination Memorandum related to the 90% federal cost share portion of the second contract between Cobra and PREPA in which FEMA concluded that approximately $68.1 million in costs were not authorized costs under the contract. PREPA filed a first-level administrative appeal of the November 21, 2022 Determination Memorandum and has indicated that they will review the December 21, 2022 Determination Memorandums and, to the extent they feel plausible, file a first-level administrative appeal of the unauthorized amounts. On January 7, 2023, Cobra and PREPA filed a joint status report with the Court, in which PREPA requested that the Court continue the stay through July 31, 2016 contained such pricing conditions2023 and Cobra requested that the stay be lifted. On January 18, 2023, the Court entered an order extending the stay and directing the parties to file a further status report addressing (i) the status of any administrative appeals in connection with the November and December determination memorandums regarding the second contract, (ii) the status of the criminal case against the former Cobra president and the FEMA official that concluded in December 2022, and (iii) a summary of the outstanding and unpaid amounts arising from the first and second contracts and whether PREPA disputes Cobra’s entitlement to these amounts with the Court by July 31, 2023.

On January 20, 2023, Cobra submitted a certified claim for approximately $379 million to FEMA pursuant to the federal Contract Disputes Act. On February 1, 2023, FEMA notified Cobra that it had reviewed the claim and determined that no contract, expressed or implied, exists between FEMA and Cobra. On March 27, 2023, Cobra was notified that FEMA had approved $233 million in Cobra invoices related to the December 21, 2022 Determination Memorandum.The 90% federal cost share of this approved amount was $210 million, which may lead to enhanced risk of uncollectiblity on certain receivables. As such, the Company monitored its previously established reserveswas obligated and adjusted upward. The Company will continue to pursue collection until such time as final determination is made consistent with Company policy.

(e) Inventory
Inventory consists of raw sand and processed sand available for sale, chemicalsdraw down on March 27, 2023. Of this $210 million, approximately $99 million has been represented by both PREPA and other products soldFEMA as intended to pay Cobra for outstanding invoices and the remaining $111 million is a bi-productreimbursement to PREPA for payments already made on Cobra invoices. On March 29, 2023, Cobra filed a notice of completion and production operations, and supplies used in performing services. Inventory is stated atappeal with the lowerCivilian Board of cost or market (net realizable value) on an average cost basis. The Company assesses the valuation of its inventories based upon specific usage and future utility.

Inventory manufactured at the Company’s sand production facilities includes direct excavation costs, processing costs and overhead allocation. Stockpile tonnages are calculated by measuring the number of tons added and removed from the stockpile. Tonnages are verified periodically by an independent surveyor. Costs are calculated on a per ton basis and are appliedContract Appeals related to the stockpiles based on the numbercertified claim submitted in January 2023. On April 25, 2023, FEMA filed a motion to dismiss Cobra’s appeal alleging lack of tons in the stockpile. Inventory transported for sale at the Company’s terminal facility includes the cost of purchased or manufactured sand, plus transportation related charges.jurisdiction.

Coil tubing strings of various widths, diameters and lengths are included in inventory. The strings are used in providing specialized services to customers who are primarily operators of oil or gas wells and are used at various rates based on factors such as well conditions (i.e. pressure and friction), vertical and horizontal length of the well, running speed of the string in the well, and total running feet accumulated to the string. The Company obtains usage information from data acquisition software and other established assessment methods and attempts to amortize the strings over their estimated useful life. In no event will a string be amortized over a period longer than 12 months. Amortization of coil strings is included in services cost of revenue in the Condensed Consolidated Statements of Comprehensive Loss and totaled $2,144,231 and $1,386,856 for the nine months ended September 30, 2017 and 2016, respectively.

(f) Prepaid Expenses
Prepaid expenses primarily consist of insurance costs. Insurance costs are expensed over the periods that these costs benefit.

(g) Property and Equipment
Property and equipment, including renewals and betterments, are capitalized and stated at cost, while maintenance and repairs that do not increase the capacity, improve the efficiency or safety, or improve or extend the useful life are charged to operations as incurred. Disposals are removed at cost, less accumulated depreciation, and any resulting gain or loss is recorded in other, net. Depreciation is calculated using the straight-line method over the shorter of the estimated useful life, or the remaining lease term, as applicable. Depreciation does not begin until property and equipment is placed in service. Once placed in service, depreciation on property and equipment continues while being repaired, refurbished, or between periods of deployment. Sand reserves are depleted using the units-of-production method over the estimated sand reserves. 

(h) Sand reserves
Sand reserve costs include engineering, mineralogical studies and other related costs to develop the mine, the removal of overburden to initially expose the mineral and building access ways. Exploration costs are expensed as incurred and classified as product cost of revenue. Capitalization of mine development project costs begins once the deposit is classified as proven and probable reserves. Drilling and related costs are capitalized for deposits where proven and probable reserves exist and the activities are directed at obtaining additional information on the deposit or converting non-reserve minerals to proven and probable reserves and the benefit is to be realized over a period greater than one year. Mining property and development costs are amortized using the units-of-production method on estimated measured tons in in-place reserves. The impact of revisions to reserve estimates is recognized on a prospective basis.

(i) Long-Lived Assets
The Company reviews long-lived assets for recoverabilitybelieves all amounts charged to PREPA, including interest charged on delinquent accounts receivable, were in accordance with the provisionsterms of Financial Accounting Standards Board ("FASB") Accounting Standard Codification (“ASC”) Topic 360, Impairmentthe contracts. Further, there have been multiple reviews prepared by or Disposalon behalf of Long-Lived Assets, which requiresFEMA that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicatehave concluded that the carrying amount of the assets may not be recoverable. Recoverability of assets is measured by comparing the carrying amount of an assetamounts Cobra charged PREPA were reasonable, that PREPA adhered to future undiscounted net cash flows expected to be generated by the asset. These evaluations for impairment are significantly impacted by estimates of revenues, costsPuerto Rican legal statutes regarding emergency situations, and expenses, and other factors. Ifthat PREPA engaged in a reasonable procurement process. The
7
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Company believes these receivables are collectible and no allowance was deemed necessary at March 31, 2023 or December 31, 2022. 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 the Company or (iii) otherwise does not pay amounts owed to the Company for services performed, the receivable may not be collectible.
long-lived assets are considered
Concentrations of Credit Risk and Significant Customers
Financial instruments that potentially subject the Company to be impaired,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 March 31, 2023 and December 31, 2022 and percentages of total revenues derived for the impairment to be recognized is measured by the amount in which the carrying amount of the assets exceeds the fair value of the assets. For the ninethree months ended September 30, 2017March 31, 2023 and 2016, the Company recognized an impairment loss of $0 and $1,870,885, respectively, on various fixed assets included in property, plant and equipment, net in the Condensed Consolidated Balance Sheets.2022:

REVENUESACCOUNTS RECEIVABLE
Three Months Ended March 31,At March 31,At December 31,
2023202220232022
Customer A(a)
— %— %82 %83 %
Customer B(b)
16 %2 %3 %— %
Customer C(c)
9 %25 %2 %— %
(j) Goodwill
Goodwill is tested for impairment annually, or more frequently if events or changes in circumstances indicate that goodwill might be impaired. The impairment testa.Customer A is a two-step process. First,third-party customer. Revenues and the fair value of each reporting unitrelated accounts receivable balances earned 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 is compared to its carrying value to determine whether an indication of impairment exists. If impairmenta third-party customer. Revenues and the related accounts receivable balances earned from Customer B were derived from the Company’s well completion services segment.
c.Customer C is indicated, thena third-party customer. Revenues and the implied value ofrelated accounts receivable balances earned from Customer C were derived from the reporting unit’s goodwill is determined by allocating the unit’s fair value to its assets and liabilities as if the reporting unit had been acquired in a business combination. The fair value of the reporting unit is determined using the discounted cash flow approach, excluding interest. The impairment for goodwill is measured as the excess of its carrying value over its implied value. Goodwill was tested for impairment as of December 31, 2016. For the nine months ended September 30, 2017 and 2016, no impairment losses were recognized.Company’s well completion services segment.


(k) Other Non-Current Assets
Other non-current assets primarily consist of deferred financing costs on the credit facility (See Note 8) and sales tax receivables.

(l) Asset Retirement Obligation
Mine reclamation costs, future remediation costs for inactive mines or other contractual site remediation costs are accrued based on management’s best estimate at the end of each period of the costs expected to be incurred at a site. Such cost estimates include, where applicable, ongoing care, maintenance and monitoring costs. Changes in estimates at inactive mines are reflected in earnings in the period an estimate is revised. The nine months ended September 30, 2017 included recognition of $1,732,081 in asset retirement obligations as a result of the Chieftain acquisition (Note 3).

(m) Business Combinations
The Company accounts for its business acquisitions under the acquisition method of accounting as indicated in FASB ASC No. 805, “Business Combinations”, which requires the acquiring entity in a business combination to recognize the fair value of all assets acquired, liabilities assumed and any noncontrolling interest in the acquiree and establishes the acquisition date as the fair value measurement point. Accordingly, the Company recognizes assets acquired and liabilities assumed in business combinations, including contingent assets and liabilities and noncontrolling interest in the acquiree, based on fair value estimates as of the date of acquisition. In accordance with FASB ASC No. 805, the Company recognizes and measures goodwill, if any, as of the acquisition date, as the excess of the fair value of the consideration paid over the fair value of the identified net assets acquired.

When the Company acquires a business from an entity under common control, whereby the companies are ultimately controlled by the same party or parties both before and after the transaction, it is treated for accounting purposes in a manner similar to the pooling of interest method of accounting. The assets and liabilities are recorded at the transferring entity’s historical cost instead of reflecting the fair market value of assets and liabilities.

(n) Amortizable Intangible Assets
Intangible assets subject to amortization include customer relationships and trade names. Customer relationships are amortized based on an estimated attrition factor and trade names are amortized over their estimated useful lives. For the nine months ended September 30, 2017 and 2016, no impairment losses were recognized.

(o) Fair Value of Financial Instruments
The Company'sCompany’s financial instruments consist of cash and cash equivalents, trade receivables, long-term debt, trade payables, and amounts receivable or payable to related parties.parties and debt. The carrying amount of cash and cash equivalents, trade receivables, trade payables and 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.


(p)
3.     Revenue Recognition
The Company generatesCompany’s primary revenue from multiple sources within its operating segments. In all cases,streams include infrastructure services, well completion services, natural sand proppant services, drilling services and other services, which includes aviation, equipment rentals, remote accommodations and equipment manufacturing. See Note 19 for the Company’s revenue is recognized when services are performed, collectiondisaggregated by type.

Certain of the receivableCompany’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 probable, persuasive evidencebased on the terms stated in the related customer agreement. As of an arrangement exists,the modification date, the Company updates its estimate of the transaction price using the expected value method, subject to constraints, and recognizes the price is fixed and determinable.amount over the remaining performance period.

Well Completion Services are sold without warranty or right of return. Taxes assessed on revenue transactions are presented on a net basis and are not included in revenue.
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Pressure pumpingWell 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, and revenuebasis. 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 recognizedutilized for pressure pumping as part of the work progresses.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. RevenueGenerally, revenue is recognized over time upon the completion of each day’ssegment of work based upon a completed field ticket, which includes the charges for the services performed, mobilization of the equipment to the location and personnel.

8
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Additional revenue is generated through labor charges and the sale of consumable supplies that are incidental to the service being performed. The labor charges and the use of consumable supplies are reflected on the completed field tickets.

Natural sand proppant revenuesSuch amounts are recognized when legal title passes to the customer, which may occur at the production facility, rail origin or at the destination terminal. At that point, delivery has occurred, evidence of a contractual arrangement exists, the price is fixed and determinable, and collectability is reasonably assured. Amounts received from customers in advance of sand deliveries are recorded as deferred revenue. Customers have the ability to make up contractual short falls by achieving higher-than-contracted volumesratably over the shortfall window. Contractual shortfall revenue is deemed not probable untilperiod during which the end of the measurement period.

Wellcorresponding goods and services are typically provided based upon a purchase order, contract or on a spot market basis.consumed.

Infrastructure Services are provided on a day rate, contracted or hourly basis, and revenue is recognized as the work progresses. Jobs for these
Infrastructure services are typically short-term in nature and range from a few hours to multiple days. Our equipment rental services are recognized upon completion of each day's work based on a completed field ticket. 

Contract drilling services are provided under daywork or footage contracts, and revenue is recognized as the work progresses based on the days completed or the feet drilled, as applicable. Mobilization revenue and costs for daywork and footage contracts are recognized over the days of actual drilling.

Directional drilling services are provided on a day rate or hourly basis, and revenue is recognized as work progresses. Proceeds from customers for the cost of equipment that is damaged or lost down-hole are reflected as service revenues as this is deemed to be perfunctory or inconsequential to the underlying service being performed.

Revenue from remote accommodation services is recognized when rooms are occupied and services have been rendered. Advance deposits on rooms and special events are deferred until services are provided to the customer. For the nine months ended September 30, 2017, the Company recognized and collected $918,963 in business interruption insurance proceeds which is included in service revenue in the accompanying Condensed Consolidated Statements of Comprehensive Loss. The proceeds resulted from loss of revenue relating to wildfires that forced evacuation of personnel.

Revenue from energy infrastructure services, a component of the Company's other energy services segment, is recognized as the work progresses based on the days completed or as the contract is completed. These services may be 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), and. Generally, the final terms and pricesCompany 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 these contracts are frequently negotiatedthe 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 unit-basedcertain customer contracts in our infrastructure services segment, the utilizationCompany warranties equipment and labor performed for a specified period following substantial completion of the work. 

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 output-based measurement is appropriate for revenue recognition. Under our cost-plus/hourly and time and materials type contracts, theindex-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.

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 an input basis, as labor hours are incurreddiscussions with the customer and services are performed.

The timingmanagement’s knowledge of the business. If the Company expects the customer will make-up deficient volumes in future periods, revenue recognition may differ from contract billingrelated to shortfall payments will be deferred and recognized on the earlier of the date on which the customer utilizes make-up volumes or payment schedules, resultingthe likelihood that the customer will exercise its right to make-up deficient volumes becomes remote. If the Company does not expect the customer will make-up deficient volumes in revenues that have been earned but not billed (“unbilled revenue”).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 had $7,435,694did not recognize any shortfall revenue during the three months ended March 31, 2023 or 2022 and $2,744,986did not have any deferred revenue related to shortfall payments.

In certain of unbilled revenue included in accounts receivable, net in the Condensed Consolidated Balance Sheets at September 30, 2017Company’s sand supply agreements, the customer obtains control of the product when it is loaded into rail cars and December 31, 2016, respectively.the customer reimburses the Company for all freight charges incurred. The Company had $14,777,586has elected to account for shipping and $10,505,240handling 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 unbilledthose shipping and handling activities.

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 included in receivables from related parties inis recognized as work progresses. Performance obligations are satisfied over time as the Condensed Consolidated Balance Sheets at September 30, 2017 and December 31, 2016, respectively.

(q) Earnings per Share
Earnings per share is computed by dividing net loss by the weighted average number of outstanding shares. See Note 10.

(r) Unaudited Pro Forma Loss per Share
The Company’s pro forma basic loss per share amounts have been computedwork progresses based on the weighted-average numbermeasure of sharesoutput. Mobilization revenue and costs were recognized over the days of common stock outstandingactual 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
The Company also provided aviation, equipment rentals, remote accommodations and equipment manufacturing, which are reported under other services. 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 period, as ifwork progresses based on the common stock issuedmeasure of output. Jobs for these services are typically short-term in the October 12, 2016 contributionnature and the IPO was outstanding for the nine months ended September 30, 2016. Diluted earnings per share reflects therange from a few hours to multiple days.

9
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

potential dilution, using the treasury stock method. During periods in which the Company realizes a net loss, restricted stock awards would be anti-dilutive to net loss per share and conversion into common stock is assumed not to occur. See Note 10.

(s) Equity-based CompensationPractical Expedients
The Company records equity-based payments at fair value on the date of grant, and expensesdoes not disclose the value of these equity-based paymentsunsatisfied performance obligations for (i) contracts with an original expected length of one year or less and (ii) contracts in compensation expense overwhich 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 applicable vesting periods. See Note 11.Company’s contract liabilities (in thousands):
Balance, December 31, 2021$3,250 
Deduction for recognition of revenue(3,207)
Deduction for rebate credit recognized(140)
Increase for deferral of customer prepayments7,647 
Balance, December 31, 20227,550 
Deduction for recognition of revenue(7,042)
Deduction for rebate credit recognized— 
Increase for deferral of customer prepayments740 
Balance, March 31, 2023$1,248 

(t) Stock-based Compensation
The Company's stock-based compensation program consists of restricted stock units granted to employees and restricted stock units granted to non-employee directors under the Mammoth Energy Services, Inc. 2016 Incentive Plan (the "2016 Plan"). The Company recognizes in its financial statements the cost of employee services received in exchange for restricted stock based on the fair value of the equity instrumentsdid not have any contract assets as of the grant date. In general, this value is amortized over the vesting period; for grants with a non-substantive service condition, this value is recognized immediately. Amounts are recognized in selling, general and administrative expenses. See Note 12. March 31, 2023 or December 31, 2022.


(u) Income TaxesPerformance Obligations
On October 12, 2016, immediately prior to the IPO of Mammoth Inc., the Partnership converted into Mammoth LLC a limited liability company. All equity interests in Mammoth LLC were contributed to Mammoth Inc. and Mammoth LLC became a wholly owned subsidiary of Mammoth Inc. Mammoth Inc. is a C corporation under the Internal Revenue Code and is subject to income tax. Historically, each of Mammoth LLC and the Operating Entities other than Lodging were treated as a partnership for federal income tax purposes. As a result, essentially all taxable earnings and losses were passed through to its members, and Mammoth LLC did not pay any federal income taxes at the entity level. Mammoth Inc. owns the member interests in several single member limited liability companies. These LLCs are subject to taxation in Texas where the Company does business; therefore, the Company may provide for income taxes attributable to that state on a current basis. The income tax provision for the period before the IPO has been prepared on a separate return basis for Mammoth LLC and all of its subsidiaries that were treated as a partnership for federal income tax purposes.

Subsequent to the IPO, the Company's operations are included in a consolidated federal income tax return and other state returns. Accordingly, the Company has recognized deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases for all its subsidiaries as if each entity were a corporation, regardless of its actual characterization for U.S. federal income tax purposes. The Company's effective tax rate was 37.1% for the nine months ended September 30, 2017. The Company's effective tax rate can fluctuate as a result of the impact of state income taxes, permanent differences and changes in pre-tax income.

Under FASB ASC 740, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using statutory tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of deferred tax assets and liabilities as a result of a change in tax rate is recognized in the current period that includesfrom performance obligations satisfied in previous periods was a nominal amount for the statutory enactment date. A valuation allowancethree months ended March 31, 2023 and 2022. As of March 31, 2023, the Company had unsatisfied performance obligations totaling $19.3 million, which will be recognized over the next 22 months.

4.    Inventories
Inventories consist of raw sand and processed sand available for deferred tax assetssale, chemicals and other products sold as a bi-product of completion and production operations and supplies used in performing services. Inventory is recognized when it is more likely than not thatstated at the benefitlower of deferred tax assets will not be realized.

cost or net realizable value on an average cost basis. The Company has included a pro forma provision for income taxes assuming it had been taxed as a C corporation in all periods prior toassesses the conversion and contribution as partvaluation of its earnings per share calculation in Note 10. The unaudited pro forma data are presented for informational purposes only,inventories based upon specific usage, future utility, obsolescence and do not purport to projectother factors. A summary of the Company's results of operations for any future period or its financial position as of any future date.Company’s inventories is shown below (in thousands):
March 31,December 31,
20232022
Supplies$6,648 $5,167 
Raw materials1,816 974 
Work in process1,016 2,221 
Finished goods750 521 
Total inventories$10,230 $8,883 


Lodging is subject to foreign income taxes, and such taxes are provided in the financial statements pursuant to FASB ASC 740, Income Taxes.
10

The Company evaluates tax positions taken or expected to be taken in preparation of its tax returns and disallows the recognition of tax positions that do not meet a “more likely than not” threshold of being sustained upon examination by the taxing authorities. During the nine months ended September 30, 2017 and 2016, no uncertain tax positions existed. Penalties and interest, if any, are recognized in general and administrative expense. The Company's 2016, 2015, 2014 and 2013 income tax returns remain open to examination by the applicable taxing authorities.

MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

5.    Property, Plant and Equipment     
(v) Foreign Currency Translation
For foreign operations, assets and liabilities are translated at the period-end exchange rate, and income statement items are translated at the average exchange rate for the period. Resulting translation adjustments are recorded within accumulated other comprehensive loss. Assets and liabilities denominated in foreign currencies, if any, are re-measured at the balance sheet date. Transaction gains or losses are included as a component of current period earnings.

(w) Environmental Matters
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Company’s operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed as incurred. Liabilities are recorded when environmental costs are probable, and the costs can be reasonably estimated. The Company maintains insurance which may cover in whole or in part certain environmental expenditures. As of September 30, 2017 and December 31, 2016, there were no probable environmental matters.

(x) Comprehensive Loss
Comprehensive loss consists of net loss and other comprehensive loss. Other comprehensive income (loss) included certain changes in equity that are excluded from net loss. Specifically, cumulative foreign currency translation adjustments are included in accumulated other comprehensive loss.

(y) 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. The Company’s accounts receivable have a concentration in the oil and gas industry and the customer base consists primarily of independent oil and natural gas producers. At  September 30, 2017, one third-party customer accounted for 11% of the Company's trade accounts receivable and receivables from related parties balance combined. At September 30, 2017 and December 31, 2016, related party customers accounted for 41% and 57%, respectively, of the Company's trade accounts receivable and receivables from related parties balance combined. During the nine months ended September 30, 2017 and 2016, one related party customer accounted for 54% and 56%, respectively, of the Company's total revenue. One third-party customers accounted for greater than 10% of the Company's total revenue for nine months ended September 30, 2016, at 12%. No third-party customer accounted for greater than 10% for the nine months ended September 30, 2017.

(z) New Accounting Pronouncements
In July 2015, the FASB issued ASU No. 2015-11, “Inventory (Topic 330): Simplifying the Measurement of Inventory,” which changes inventory measured using any method other than last-in, first-out (LIFO) or the retail inventory method (for example, inventory measured using first-in, first-out (FIFO) or average cost) at the lower of cost and net realizable value. ASU 2015-11 is effective for annual and interim reporting periods beginning after December 15, 2016, with early adoption permitted. On January 1, 2017, the Company adopted the ASU and it did not impact our condensed consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers.” ASU 2014-09 supersedes existing revenue recognition requirements in GAAP and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. Additionally, it requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. The ASU was effective for annual and interim reporting periods beginning after December 15, 2016, using either a full or a modified retrospective application approach; however, in July 2015 the FASB decided to defer the effective date by one year (until 2018) by issuing ASU No. 2015-14, "Revenue From Contracts with Customers: Deferral of the Effective Date." The Company expects to adopt this new revenue guidance in the first quarter of 2018. The Company's review has indicated that the pressure pumping services and natural sand proppant segments contain contracts which could lead to changes in the timing of revenue recognition. Although the Company has not completed its review, the Company has made initial assessments of the impact on revenue and expenses. Based on these assessments, the Company currently does not expect a material impact to the Company’s results of operations, financial position and cash flowsas a result of this guidance. The Company expects to complete its review of all remaining customer contracts and will make a final assessment in the fourth quarter of 2017. The Company's services are primarily short-term in nature, and it does not expect that the new revenue recognition standard will have a material impact on its financial statements upon adoption. The Company will
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

adopt the new standard utilizing the modified retrospective method that will result in a cumulative effect adjustment as of January 1, 2018.

In February 2016, the FASB issued ASU No, 2016-2 “Leases” amending the current accounting for leases. Under the new provisions, all lessees will report a right-of-use asset and a liability for the obligation to make payments for all leases with the exception of those leases with a term of 12 months or less.  All other leases will fall into one of two categories: (i) a financing lease or (ii) an operating lease. Lessor accounting remains substantially unchanged with the exception that no leases entered into after the effective date will be classified as leveraged leases. For sale leaseback transactions, a sale will only be recognized if the criteria in the new revenue recognition standard are met. ASU 2016-2 is effective for fiscal years beginning after December 15, 2018, and interim periods within that fiscal year. Early adoption is permitted. Since a portion of the Company’s revenue may be subject to this new leasing guidance, it is evaluating the possibility of adopting this updated leasing guidance at the same time its adopts the new revenue guidance discussed above, utilizing the retrospective method of adoption. This new leasing guidance will also impact the Company in situations where it is the lessee, and in certain circumstances it will have a right-of-use asset and lease liability on its consolidated financial statements. The Company is currently evaluating the effect the new guidance will have on the Company's consolidated financial statements and results of operations.

3.Acquisitions

(a) Description of Stingray Acquisition

On March 20, 2017, and as amended on May 12, 2017, the Company entered into two definitive contribution agreements, one such agreement with MEH Sub LLC (“MEH Sub”), Wexford Offshore Stingray Energy Corp., Gulfport and Mammoth LLC and the other with MEH Sub, Wexford Offshore Stingray Pressure Pumping Corp., Gulfport and Mammoth LLC (collectively, the “Stingray Contribution Agreements”). Under the Stingray Contribution Agreements, the Company agreed to acquire all outstanding membership interests, through its wholly-owned subsidiary Mammoth LLC, in Cementing and SR Energy (the "2017 Stingray Acquisition"). Cementing and SR Energy are included in the Company's well services segment. The addition of their water transfer, equipment rentals and cementing services further expanded and vertically integrated Mammoth’s service offerings.

The 2017 Stingray Acquisition closed on June 5, 2017. Pursuant to the Stingray Contribution Agreements, Mammoth issued 1,392,548 shares of its common stock, par value $0.01 per share, for all outstanding equity interests in SR Energy and Cementing. Based upon a closing price of Mammoth's common stock of $18.50 per share on June 5, 2017, the total purchase price was $25,762,138.

At the acquisition date, the components of the consideration transferred were as follows:
Consideration attributable to Cementing (1)
 $12,975,123
Consideration attributable to SR Energy (1)
 12,787,015
Total consideration transferred $25,762,138
(1)See Summary of acquired assets and liabilities below



MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

  SR EnergyCementing Total
Cash and cash equivalents $1,611,791
$1,059,767
 $2,671,558
Accounts receivable, net 3,912,322
495,222
 4,407,544
Receivables from related parties 3,683,892
1,418,616
 5,102,508
Inventories —
306,081
 306,081
Prepaid expenses 35,322
31,980
 67,302
Property, plant and equipment(1)
 13,060,850
7,458,942
 20,519,792
Identifiable intangible assets - customer relationships(2)
 —
1,140,000
 1,140,000
Identifiable intangible assets - trade names(2)
 550,000
270,000
 820,000
Goodwill(3)
 3,928,508
6,263,978
 10,192,486
Other assets 6,532
—
 6,532
Total assets acquired $26,789,217
$18,444,586
 $45,233,803
      
Accounts payable and accrued liabilities $5,889,523
$2,063,443
 $7,952,966
Long-term debt (4)
 5,073,854
2,000,000
 7,073,854
Deferred tax liability 3,038,825
1,406,020
 4,444,845
Total liabilities assumed $14,002,202
$5,469,463
 $19,471,665
Net assets acquired $12,787,015
$12,975,123
 $25,762,138
(1)
Property, plant and equipment fair value measurements were prepared by utilizing a combined fair market value and cost approach. The market approach relies on comparability of assets using market data information. The cost approach places emphasis on the physical components and characteristics of the asset. It places reliance on estimated replacement cost, depreciation and economic obsolescence.
(2)
Identifiable intangible assets were measured using a combination of income approaches. Trade names were valued using a "Relief-from-Royalty" method. Non-contractual customer relationships were valued using a "Multi-period excess earnings" method. Identifiable intangible assets will be amortized over 5-10 years.
(3)
Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill recorded in connection with the acquisition is attributable to assembled workforces and future profitability based on the synergies expected to arise from the acquired entities.
(4)
Long-term debt assumed was paid off subsequent the acquisition.
Since the acquisition date, the businesses acquired have provided the following activity:
  2017
  SR EnergyCementing
Revenues $7,538,735
$4,121,051
Net loss (a) (1,284,347)(1,885,743)
a.Includes $1,961,179 and $2,370,569 in depreciation and amortization for SR Energy and Cementing, respectively.
The following table presents unaudited pro forma information as if the acquisition of SR Energy and Cementing had occurred on January 1, 2016:
  Nine Months Ended September 30, 2017Year Ended December 31, 2016
Revenues $27,481,890
$23,659,445
Net loss (2,550,270)(8,171,257)
The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the 2017 Stingray Acquisition. For the nine months ended September 30, 2017, there were $0.2 million transaction related costs expensed. The unaudited pro forma consolidated results are not necessarily indicative of what the consolidated results of operations actually would have been had the 2017 Stingray Acquisition been completed on January 1, 2017. In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations of the Company.
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(b) Description of Chieftain Acquisition

On March 27, 2017, as amended as of May 24, 2017, the Company entered into a the Purchase Agreement with the Chieftain Sellers, following the Company's successful bid in a bankruptcy court auction for substantially all of the assets of the Chieftain Sellers (the "Chieftain Assets"). The Chieftain Acquisition closed on May 26, 2017. Mammoth funded the purchase price for the Chieftain Assets with cash on hand and borrowings under its revolving credit facility. The Chieftain Assets are held by the Company's wholly owned subsidiary Piranha and are included in the Company's sand segment. The Chieftain Acquisition added sand reserves, increased our production capacity and provided access to the Union Pacific railroad, which affords access to both the Mid-Continent basin in support of the Company’s pressure pumping services as well as the Permian basin.

On the acquisition date, the $36,320,187 in cash consideration consisted of the following components:
  Total
Property, plant and equipment (1)
 $23,372,800
Sand reserves (2)
 20,910,000
Total assets acquired $44,282,800
   
Asset retirement obligation 1,732,081
Total liabilities assumed $1,732,081
Total allocation of purchase price $42,550,719
Bargain purchase price (3, 4)
 (6,230,532)
Total purchase price $36,320,187
(1)
Property, plant and equipment fair value measurements were prepared by utilizing a combined fair market value and cost approach. The market approach relies on comparability of assets using market data information. The cost approach places emphasis on the physical components and characteristics of the asset. It places reliance on estimated replacement cost, depreciation and economic obsolescence.
(2)
The fair value of the sand reserves was determined based on the excess cash flow method, a form of the income approach. The method provides a value based on the estimated remaining life of sand reserves, projected financial information and industry projections.
(3)
Amount reflected in Condensed Consolidated Statements of Comprehensive Loss reflected net of income taxes of $2,219,020.
(4)
The fair value of the business was determined based on the excess cash flow method, a form of the income approach.
Since the acquisition date, the Chieftain Assets have provided the following activity:
  2017
  Piranha
Revenues $3,131,408
Net loss (a) (5,354,907)
a.Includes $1,617,531 in depreciation and amortization
The following table presents unaudited pro forma information as if the acquisition of the Chieftain Assets had occurred as of January 1, 2016:
  Nine Months Ended September 30, 2017Year Ended December 31, 2016
Revenues $4,230,359
$7,690,032
Net (loss) income (2,458,402)34,127,344

The Company's historical financial information was adjusted to give pro forma effect to the events that were directly attributable to the Chieftain Acquisition. For the nine months ended September 30, 2017, $0.8 million of transaction related costs was expensed.




MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(c) Description of Sturgeon Acquisition

On March 20, 2017, and as amended on May 12, 2017, the Company entered into a definitive contribution agreement with MEH Sub, Wexford Offshore Sturgeon Corp., Gulfport, Rhino and Mammoth Energy Partners LLC (the “Sturgeon Contribution Agreement”). Under the Sturgeon Contribution Agreement, the Company agreed to acquire all outstanding membership interests, through its wholly-owned subsidiary Mammoth LLC, in Sturgeon, which owns all of the membership interests in Taylor Frac, Taylor RE and South River (collectively, the "Sturgeon subsidiaries"). The acquisition added sand reserves, increased our production capacity and provided access to the Canadian National Railway, which affords access to the Appalachian basin in support of the Company’s pressure pumping services as well as to western Canada.

The acquisition of Sturgeon closed on June 5, 2017. Pursuant to the Sturgeon Contribution Agreement, Mammoth issued 5,607,452 shares of its common stock, par value $0.01 per share, for all outstanding equity interests in Sturgeon. Based upon a closing price of Mammoth's common stock of $18.50 per share on June 5, 2017, the total purchase price was $103,737,862.

As a result of this transaction, the Company's historical financial information has been recast to combine the Condensed Consolidated Statements of Operations and the Condensed Consolidated Balance Sheets of the Company for all periods included in the accompanying financial statements with those of Sturgeon as if the combination had been in effect since Sturgeon commenced operations on September 13, 2014. Any material transactions between the Company and Sturgeon were eliminated. Sturgeon's financial results were incorporated into the Company's natural sand proppant services division.

For the nine months ended September 30, 2017, $1.3 million of transaction related costs was expensed.

The following table summarizes the carrying value of Sturgeon as of September 13, 2014, the date at which Sturgeon commenced operations with the acquisition of the Sturgeon subsidiaries:
  Sturgeon
Cash and cash equivalents $705,638
Accounts receivable 7,587,298
Inventories 2,221,073
Other current assets 555,939
Property, plant and equipment 20,424,087
Sand reserves 57,420,000
Goodwill 2,683,727
Total assets acquired $91,597,762
   
Accounts payable and accrued liabilities $2,878,072
Total liabilities assumed $2,878,072
Net assets acquired $88,719,690
   
Allocation of purchase price  
Carrying value of sponsor's non-controlling interest prior to Sturgeon contribution $81,738,675
Deferred tax liability assumed (4,010,885)
Members' equity conveyed $77,727,790

(d) Acquisition of Higher Power

On April 21, 2017, the Company completed its acquisition of Higher Power for total consideration of $3,250,000 in cash to the sellers plus up to $750,000 in contingent consideration to be paid in equal annual installments over the next three years subject to contractual conditions. As of September 30, 2017, $250,000 and $500,000 of the contingent consideration are reflected in the accrued expenses and other current liabilities and other liabilities, respectively. Mammoth funded the
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

purchase price for Higher Power with cash on hand and borrowings under its credit facility. The acquisition of Higher Power added an energy infrastructure component to the Company's other energy services segment, helping to diversify its service offerings.

For the nine months ended September 30, 2017, there was $0.1 million of transaction related costs expensed.

The following table summarizes the fair value of Higher Power as of April 21, 2017:
  Higher Power
Property, plant and equipment $1,743,600
Identifiable intangible assets - customer relationships 1,613,000
Goodwill (1)
 643,400
Total assets acquired $4,000,000
   
Long-term debt and other liabilities $750,000
Total liabilities assumed $750,000
Net assets acquired $3,250,000
(1)
Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill recorded in connection with the acquisition is attributable to assembled workforces and future profitability expected to arise from the acquired entity.
From its acquisition date through September 30, 2017, Higher Power has provided the following activity:
  2017
  Higher Power
Revenues $8,846,930
Net loss (a)
 (112,367)
a.Includes $1,052,020 in depreciation and amortization
The following table presents unaudited pro forma information as if the acquisition of Higher Power had occurred as of January 1, 2016:
  Nine Months Ended September 30, 2017Year Ended December 31, 2016
Revenues $11,618,913
$10,038,825
Net loss (236,055)(1,189,496)

(e) Acquisition of 5 Star

On July 1, 2017, the Company completed its acquisition of 5 Star for total consideration of $2,438,000 in cash to the sellers. Mammoth funded the purchase price for 5 Star with cash on hand and borrowings under its credit facility. The acquisition of 5 Star added to the infrastructure component of the Company's other energy services segment.

For the nine months ended September 30, 2017, there was $0.1 million of transaction related costs expensed.

The following table summarizes the fair value of 5 Star as of July 1, 2017:
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

  5 Star
Accounts receivable $2,440,440
Property, plant and equipment 1,862,500
Identifiable intangible assets - trade names (1)
 300,000
Goodwill (2)
 248,058
Total assets acquired $4,850,998
   
Long-term debt and other liabilities $2,412,998
Total liabilities assumed $2,412,998
Net assets acquired $2,438,000
(1)
Identifiable intangible assets were measured using a combination of income approaches. Trade names were valued using a "Relief-from-Royalty" method. Non-contractual customer relationships were valued using a "Multi-period excess earnings" method. Identifiable intangible assets will be amortized over 5-10 years.
(2)
Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill recorded in connection with the acquisition is attributable to assembled workforces and future profitability expected to arise from the acquired entity.
From its acquisition date through September 30, 2017, 5 Star has provided the following activity:
  2017
  5 Star
Revenues $6,348,734
Net income (a)
 776,182
a.Includes $327,351 in depreciation and amortization
The following table presents unaudited pro forma information as if the acquisition of 5 Star had occurred as of January 1, 2016:
  Nine Months Ended September 30, 2017Year Ended December 31, 2016
Revenues $12,680,853
$13,970,985
Net income (loss) 494,612
(839,125)

4.Inventories
A summary of the Company's inventories is shown below:
  September 30, December 31,
  2017 2016
Supplies $9,038,905
 $4,020,670
Raw materials 1,552,225
 75,971
Work in process 289,104
 205,450
Finished goods 1,283,991
 1,822,110
Total inventory $12,164,225
 $6,124,201

MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

5.Property, Plant and Equipment     
Property, plant and equipment include the following:following (in thousands):
March 31,December 31,
Useful Life20232022
Pressure pumping equipment3-5 years$244,680 $230,760 
Drilling rigs and related equipment3-15 years110,752 110,724 
Machinery and equipment7-20 years162,456 162,634 
Buildings(a)
15-39 years40,338 40,316 
Vehicles, trucks and trailers5-10 years101,191 101,580 
Coil tubing equipment4-10 years6,908 6,908 
LandN/A12,393 12,393 
Land improvements15 years or life of lease10,053 10,053 
Rail improvements10-20 years13,793 13,793 
Other property and equipment(b)
3-12 years18,310 18,296 
720,874 707,457 
Deposits on equipment and equipment in process of assembly(c)
7,126 13,885 
728,000 721,342 
Less: accumulated depreciation(d)
595,471 583,276 
Total property, plant and equipment, net$132,529 $138,066 
a.    Included in Buildings at each of March 31, 2023 and December 31, 2022 are costs of $7.6 million related to assets under operating leases.
   September 30, December 31,
 Useful Life 2017 2016
Land  $11,316,910
 $5,040,482
Land improvements15 years or life of lease 9,317,354
 3,640,976
Buildings15-39 years 58,814,815
 54,833,021
Drilling rigs and related equipment3-15 years 151,883,172
 138,526,519
Pressure pumping equipment3-5 years 174,609,203
 96,500,592
Coil tubing equipment4-10 years 28,006,153
 28,019,217
Rail improvements10-20 years 5,962,779
 4,276,928
Vehicles, trucks and trailers5-10 years 50,263,851
 33,140,599
Machinery and equipment7-20 years 52,866,319
 35,548,357
Other property and equipment3-12 years 14,208,936
 11,461,839
   557,249,492
 410,988,530
Deposits on equipment and equipment in process of assembly  22,225,520
 9,427,307
   579,475,012
 420,415,837
Less: accumulated depreciation  232,157,296
 178,296,174
Property, plant and equipment, net  $347,317,716
 $242,119,663
b.    Included in Other property and equipment at each of March 31, 2023 and December 31, 2022 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 $8.4 million and $8.0 million at March 31, 2023 and December 31, 2022, respectively, related to assets under operating leases.

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 statementunaudited condensed consolidated statements of cash flows. The Company did not have any proceeds or gains from the sale of equipment damaged or lost down-hole during the three months ended March 31, 2023. For the ninethree months ended September 30, 2017,March 31, 2022, proceeds and gains from the sale of equipment damaged or lost down-hole were $347,844a $0.4 million and gain$0.4 million, respectively.

Proceeds from assets sold or disposed of as well as the carrying value of the related equipment are reflected in “gains on salesdisposal of equipment damaged or lost down-hole was $221,779. There were noassets, net” on the unaudited condensed consolidated statements of comprehensive income (loss). For the three months ended March 31, 2023 and 2022, proceeds from the sale of equipment damagedwere $0.4 million and $0.6 million, respectively, and gains from the sale or lost down-hole for the nine months ended September 30, 2016.disposal of equipment were $0.4 million and $0.2 million, respectively.


Depreciation, depletion, amortization and accretion
A summary of depreciation, depletion, accretionamortization and amortizationaccretion expense is outlined below:below (in thousands):
Three Months Ended March 31,
20232022
Depreciation expense$12,726 $16,925 
Amortization expense195 195 
Accretion and depletion expense35 47 
Depreciation, depletion, amortization and accretion$12,956 $17,167 

11
  Three Months Ended September 30, Nine Months Ended September 30,
  2017 2016 2017 2016
Depreciation expense $24,104,784
 $15,223,767
 $56,301,053
 $47,030,398
Accretion expense (see Note 2) 24,825
 165
 39,234
 494
Depletion expense (see Note 2) 682,367
 431,706
 1,066,839
 650,933
Amortization expense (see Note 6) 2,411,757
 2,265,833
 6,947,257
 6,801,333
Depreciation, depletion, accretion and amortization $27,223,733
 $17,921,471
 $64,354,383
 $54,483,158

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.
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

6.    Goodwill and Intangible Assets
6.Goodwill and Intangible Assets
Goodwill
Changes in the net carrying amount of goodwill by reporting segment (see Note 19) for the three months ended March 31, 2023 and year ended December 31, 2022 are presented below (in thousands):

Well CompletionsOtherTotal
Balance as of January 1, 2022
Goodwill$86,043 $14,830 $100,873 
Accumulated impairment losses(76,829)(12,327)(89,156)
9,214 2,503 11,717 
Acquisitions— — — 
Impairment losses— — — 
Balance as of December 31, 2022
Goodwill86,043 14,830 100,873 
Accumulated impairment losses(76,829)(12,327)(89,156)
9,214 2,503 11,717 
Acquisitions— — — 
Impairment losses— — — 
Balance as of March 31, 2023
Goodwill86,043 14,830 100,873 
Accumulated impairment losses(76,829)(12,327)(89,156)
$9,214 $2,503 $11,717 

Intangible Assets

The Company had the following definite lived intangible assets recorded:recorded (in thousands):
March 31,December 31,
20232022
Trade names7,850 7,850 
Less: accumulated amortization - trade names(6,263)(6,068)
Intangible assets, net$1,587 $1,782 
  September 30, December 31,
  2017 2016
Customer relationships $35,798,000
 $33,605,000
Trade names 8,790,000
 7,110,000
Less: accumulated amortization - customer relationships 24,027,625
 17,655,228
Less: accumulated amortization - trade names 2,067,803
 1,492,943
Intangible assets, net $18,492,572
 $21,566,829


Amortization expense for intangible assets was $6,947,257 and $6,801,333$0.2 million for each of the ninethree months ended September 30, 2017March 31, 2023 and 2016,2022, respectively. The original life of customer relationships rangetrade names ranges from 410 to 1020 years as of March 31, 2023 with a remaining average useful life of 4.57 years. Trade names are amortized over a 10 year useful life and as of September 30, 2017 the remaining useful life was 9.043.1 years.


Aggregated expected amortization expense for the future periods is expected to be as follows:follows (in thousands):
Remainder of 2023$584 
2024710 
202591 
202691 
202745 
Thereafter66 
$1,587 


12
Year ended December 31: Amount
Remainder of 2017 $2,357,126
2018 8,581,505
2019 1,096,004
2020 1,096,004
2021 1,090,252
Thereafter 4,271,681
  $18,492,572

Goodwill was $99,810,819 and $88,726,875 at September 30, 2017 and December 31, 2016, respectively. Changes in the goodwill for the year ended December 31, 2016 and the nine months ended September 30, 2017 are set forth below:
Balance, January 1, 2016 $88,726,875
Additions —
Balance, December 31, 2016 88,726,875
Additions - 2017 Stingray Acquisition (Note 3) 10,192,486
Additions - Higher Power Acquisition (Note 3) 643,400
Additions - 5 Star Acquisition (Note 3) 248,058
Balance, September 30, 2017 $99,810,819










MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

7.Accrued Expenses and Other Current Liabilities
Accrued expense and other current liabilities included the following:
  September 30, December 31,
  2017 2016
Accrued compensation, benefits and related taxes $7,257,925
 $2,432,093
Financed insurance premiums —
 3,293,859
State & local taxes payable 1,519,073
 319,597
Insurance reserves 2,270,444
 971,351
Deferred revenue 6,051,796
 —
Other 4,457,304
 1,529,298
Total $21,556,542
 $8,546,198

Financed insurance premiums are due in monthly installments, bear interest at rates ranging from 1.79% to 5.00%, are unsecured, and mature within the twelve month period following the close of the year.
8.Debt
Mammoth Credit Facility

7.    Equity Method Investment
On November 25, 2014, Mammoth entered intoDecember 21, 2018, Cobra Aviation Services LLC (“Cobra Aviation”) and Wexford Partners Investment Co. LLC (“Wexford Investment”), a revolving creditrelated 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 security agreement withWexford Investment owns a syndicate51% economic interest in Brim Acquisitions, and each member contributed its pro rata portion of banks that providesBrim Acquisitions’ initial capital of $2.0 million. Brim Acquisitions, through Brim Equipment, owns four commercial helicopters and leases five commercial helicopters for maximum borrowingsoperations, which it uses to provide a variety of $170 million. The facility, as amended in connection with the IPO, matures on November 25, 2019. Borrowings under this facility are secured by the assets of Mammoth, inclusive of the subsidiary companies. The maximum availability of the facility is subject to a borrowing base calculation prepared monthly. Concurrent with the execution of the facility, the initial advance was used to repay all the debt of the Company then outstanding. Interest is payable monthly at a base rate set by the lead institution’s commercial lending group plus an applicable margin. Additionally, at the Company's request, outstanding balances are permitted to be converted to LIBOR rate plus applicable margin tranches at set increments of $500,000. The LIBOR rate option allows the Company to select interest periods from one, two, three or six months. The applicable margin for either the base rate or the LIBOR rate option can vary from 1.5% to 3.0%, based upon a calculation of the excess availability of theservices, including short haul, aerial ignition, hoist operations, aerial photography, fire suppression, construction services, animal/capture/survey, search and rescue, airborne law enforcement, power line as a percentage of the maximum credit limit. The deferred loan costs associated with this facility are classified in other non-current assets.construction, precision long line operations, pipeline construction and survey, mineral and seismic exploration, and aerial seeding and fertilization.

At September 30, 2017, all of the $94,000,000 outstanding balance of the facility was in a one month LIBOR rate option tranche with an interest rate of 3.99%. As of September 30, 2017, Mammoth had availability of $69,779,297, which is net of letters of credit of $5,454,187.

As of December 31, 2016, the facility was undrawn and had borrowing base availability of $146,181,002.


The Mammoth facility also contains various customary affirmativeCompany uses the equity method of accounting to account for its investment in Brim Acquisitions, which had a carrying value of approximately $3.3 million and restrictive covenants. Among the various covenants are specifically identified financial covenants placing requirements of a minimum interest coverage ratio (3.0 to 1.0), maximum leverage ratio (4.0 to 1.0), and minimum availability ($10 million). As of September 30, 2017$3.5 million at March 31, 2023 and December 31, 2016,2022, respectively. The investment is included in “other non-current assets” on the unaudited condensed consolidated balance sheets. The Company was in compliance withrecorded equity method adjustments to its covenants under the facility.

9.Income Taxes
As discussed in Note 1, the Partnership was converted into a limited liability company on October 12, 2016investment of $0.2 million and the membership interests in the limited liability company were contributed to the Company. As a result, the Company will file a consolidated return($0.5) million for the period October 12, 2016 through December 31, 2016. Prior to the conversion, the Partnership, other than Lodging, was not subject to corporate income taxes.

The components of income tax (benefit) expense attributable to the Company for the ninethree months ended September 30, 2017March 31, 2023 and 2016, are as follows:2022, respectively, which is included in “other income (expense), net” on the unaudited condensed consolidated statements of comprehensive income (loss).

13
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):
March 31,December 31,
20232022
State and local taxes payable$13,029 $13,336 
Financed insurance premiums(a)
6,522 10,136 
Deferred revenue1,248 7,550 
Accrued compensation and benefits4,087 6,743 
Sale-leaseback liability(b)
4,971 4,501 
Financing leases2,921 4,003 
Equipment financing note2,284 2,329 
Insurance reserves1,589 1,509 
Other1,834 2,190 
Total accrued expenses and other current liabilities$38,485 $52,297 
Other Long-Term Liabilities
Equipment financing note(c)
$5,489 $6,047 
Sale-leaseback liability(b)
5,166 6,836 
Financing leases2,191 $2,602 
Total other long-term liabilities$12,846 $15,485 
  Three Months Ended September 30, Nine Months Ended September 30,
  2017 2016 2017 2016
U.S. current income tax (benefit) expense $—

$44,232
 $—
 $31,352
U.S. deferred income tax (benefit) expense (1,330,254)
19,324
 (7,826,628) 29,110
Foreign current income tax expense (100,815)
998,663
 505,741
 2,652,847
Foreign deferred income tax (benefit) expense 18,389

(6,258) (1,935) 26,387
Total $(1,412,680) $1,055,961
 $(7,322,822) $2,739,696

A reconciliationa.Financed insurance premiums are due in monthly installments, are unsecured and mature within the twelve-month period following the close of the statutory federal income tax amountyear. As of March 31, 2023 and December 31, 2022, the applicable interest rate associated with financed insurance premiums ranged from 1.95% to the recorded expense is as follows:
5.13%.
  Nine Months Ended September 30,
  2017 2016
Loss before income taxes, as reported $(14,274,443) $(32,007,236)
Bargain purchase gain, net of tax (4,011,512) —
Loss before income taxes, as taxed (18,285,955) (32,007,236)
Statutory income tax rate 35% 35%
Expected income tax benefit (6,400,084) (11,202,533)
Non-taxable entity —
 14,763,650
Other permanent differences 40,287
 33,471
State tax benefit (301,569) 60,463
Foreign income tax rate differential (126,630) (820,580)
Other (534,826) (94,775)
Total $(7,322,822) $2,739,696

Deferred tax assets and liabilities attributable tob.On December 30, 2020, the Company consistedentered 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. On June 1, 2022, the Company entered into another agreement with FNC whereby the Company sold additional assets from its infrastructure segment to FNC for aggregate proceeds of $4.6 million and entered into a 42-month lease agreement whereby the Company agreed to lease back the assets at a monthly rental rate of $0.1 million. Under the agreements, the Company has the option to purchase the assets at the end of the following: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.In December 2022, the Company entered into a 42 month financing arrangement with FNC for the purchase of seven new pressure pumping units for an aggregate value of $9.7 million. Under this arrangement, the Company has agreed to make monthly principal and interest payments totaling $0.3 million over the term of the agreement. This note is secured by the seven pressure pumping units and bears interest at an imputed rate of approximately 15.0%.

9.    Debt
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 subsequently further amended (the “revolving credit facility”). The revolving credit facility matures on October 19, 2023 and currently provides for the maximum revolving advance amount of $120.0 million. 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 is a financial covenant, including a minimum fixed charges coverage ratio of at least 1.1 to 1.0.
14
  September 30, December 31,
  2017 2016
Deferred tax assets:    
Allowance for doubtful accounts $2,049,095
 $1,892,761
Net operating loss carryforward 4,653,055
 —
Deferred stock compensation 2,894,538
 1,686,671
Accrued liabilities 1,573,448
 746,132
Other 3,470,006
 1,785,999
Deferred tax assets 14,640,142
 6,111,563
    

Deferred tax liabilities:    
Property and equipment $(54,589,256) $(42,525,793)
Intangible assets (5,995,560) (7,662,590)
Unrepatriated foreign earnings (4,948,229) (3,451,110)
Other (193,836) (142,859)
Deferred tax liabilities (65,726,881) (53,782,352)
Net deferred tax liability $(51,086,739) $(47,670,789)
     
Reflected in accompanying balance sheet as:    
Deferred income taxes $(51,086,739) $(47,670,789)
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

10.Earnings Per Share
Common Stock Offering


On October 14, 2016, Mammoth Inc.’s common stock began tradingFebruary 28, 2022, the Company entered into a fourth amendment to the revolving credit facility (the “Fourth Amendment”) to, in relevant part, (i) amend the financial covenants as outlined below, (ii) provide for a conditional increase of the applicable interest margin, (iii) permit certain sale-leaseback transactions, and (iv) provide for a reduction in the maximum revolving advance amount in an amount equal to 50% of the PREPA claims proceeds, subject to a floor equal to the sum of eligible billed and unbilled accounts receivables.

The financial covenants under our revolving credit facility were amended as follows:

•the leverage ratio was eliminated;
•the fixed charge coverage ratio was reduced to .85 to 1.0 for the six months ended June 30, 2022 and increased to 1.1 to 1.0 for the periods thereafter;
•a minimum adjusted EBITDA covenant of $4.7 million, excluding interest on accounts receivable from PREPA, for the five months ending May 31, 2022 was added; and
•the minimum excess availability covenant was reduced to $7.5 million through March 31, 2022, after which the minimum excess availability covenant increased to $10.0 million.

The Nasdaq Global Select MarketCompany was in compliance with the applicable financial covenants under its revolving credit facility in effect as of March 31, 2023 and December 31, 2022.

At March 31, 2023, there were outstanding borrowings under the symbol “TUSK.” On October 19, 2016,revolving credit facility of $84.6 million and $17.4 million of available borrowing capacity under the Company closedfacility, after giving effect to $6.4 million of outstanding letters of credit and the IPO of 7,750,000 shares of common stock at $15.00 per share. Net proceedsrequirement to Mammoth Inc. from its sale of 7,500,000 shares of common stock were approximately $103.1 million.

The authorized capital stockmaintain a $10.0 million reserve out of the Company consistsavailable borrowing capacity. At December 31, 2022, there were outstanding borrowings under the revolving credit facility of 200$83.5 million sharesand $19.7 million of common stock, par value $0.01 per share,borrowing capacity under the facility, after giving effect to $6.5 million of outstanding letters of credit and 20the requirement to maintain a $10.0 million shares of preferred stock, par value $0.01 per share.

Earnings Per Share

In connection with the contribution of Operating Entities to the Partnership in November 2014, the Partnership issued an aggregate of 30,000,000 common units to Mammoth Holdings, Gulfport and Rhino. Upon the conversionreserve out of the Partnership into Mammoth LLC,available borrowing capacity.

If an event of default occurs under the revolving credit facility and remains uncured, it could have a limited liability company, in October 2016,material adverse effect on the common units were converted into an equal numberCompany’s business, financial condition, liquidity and results of membership interests in Mammoth LLC. Finally, when Mammoth Holdings, Gulfport and Rhino contributed their 30,000,000 membership interests in Mammoth LLCoperations. The lenders (i) would not be required to lend any additional amounts to the Company, in connection(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 IPO,ability to require the Company issued to themapply all of its available cash to repay outstanding borrowings, and (v) may foreclose on substantially all of the Company’s assets. The Company’s revolving credit facility is currently scheduled to mature on October 19, 2023. The Company continues to explore various strategic alternatives to extend, refinance or repay its revolving credit facility at or before the scheduled maturity date, which may include proceeds from any equity or debt transactions. There is no guarantee that such extension, refinancing or repayment will be secured. Additionally, any such extended or new credit facility could have terms that are less favorable to the Company than the terms of its existing revolving credit facility, which may significantly increase the Company’s cost of capital and may have a material adverse effect on the Company’s liquidity and financial condition.

Aviation Note

On November 6, 2020, Leopard and Cobra Aviation entered into a 39 month promissory note agreement with Bank7 (the “Aviation Note”) in an aggregate principal amount of 30,000,000 shares$4.6 million and received net proceeds of the Company's common stock.
  Three Months Ended September 30, Nine Months Ended September 30,
  2017 2016 2017 2016
Basic loss per share:        
Allocation of earnings:        
Net loss $(800,827) $(2,978,626) $(6,951,621) $(34,746,932)
Weighted average common shares outstanding 44,501,885
 30,000,000
 40,526,276
 30,000,000
Basic loss per share $(0.02) $(0.10) $(0.17) $(1.16)
         
Diluted loss per share:        
Allocation of earnings:        
Net loss $(800,827) $(2,978,626) $(6,951,621) $(34,746,932)
Weighted average common shares, including dilutive effect (a)
 44,501,885
 30,000,000
 40,526,276
 30,000,000
Diluted loss per share $(0.02) $(0.10) $(0.17) $(1.16)
a.
No incremental shares of potentially dilutive restricted stock awards were included for periods presented as their effect was antidulitive under the treasury stock method.

Unaudited Pro Forma Earnings Per Share

$4.5 million. The Company’s pro forma basic and diluted earnings per share amounts have been computedAviation Note bore interest at a rate based on the weighted-average numberWall Street Journal Prime Rate plus a margin of shares of common stock outstanding for the period, as if the shares of common stock issued upon the conversion and contribution of Mammoth LLC to Mammoth Inc. were outstanding for the entire year. A reconciliation of the components of pro forma basic and diluted earnings per common share is presented in the table below:1%. The Aviation Note was paid off on September 30, 2022.

15
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 March 31, 2023.

11.    Selling, General and Administrative Expense
Selling, general and administrative (“SG&A”) expense includes of the following (in thousands):
Three Months Ended March 31,
20232022
Cash expenses:
Compensation and benefits$4,277 $2,983 
Professional services1,929 3,637 
Other(a)
1,911 1,906 
Total cash SG&A expense8,117 8,526 
Non-cash expenses:
Bad debt recoveries(381)(99)
Stock based compensation647 241 
Total non-cash SG&A expense266 142 
Total SG&A expense$8,383 $8,668 
a.    Includes travel-related costs, information technology expenses, rent, utilities and other general and administrative-related costs.


12.    Income Taxes
The Company recorded income tax expense of $3.3 million for the three months ended March 31, 2023 compared to income tax expense of $3.7 million for the three months ended March 31, 2022. The Company’s effective tax rates were 29% and 33% for the three months ended March 31, 2023 and 2022, respectively.

The effective tax rates for the three months ended March 31, 2023 and 2022 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.

16
  Three Months Ended Nine Months Ended
  September 30, 2016 September 30, 2016
Pro Forma C Corporation Data (unaudited):    
Net loss, as reported $(2,978,626) $(34,746,932)
Pro forma benefit for income taxes (3,896,035) (9,701,517)
Pro forma net loss $917,409
 $(25,045,415)
     
Basic loss per share:    
Allocation of earnings:    
Net loss $917,409
 $(25,045,415)
Weighted average common shares outstanding 43,107,452
 43,107,452
Basic loss per share $0.02
 $(0.58)
     
Diluted loss per share:    
Allocation of earnings:    
Net loss $917,409
 $(25,045,415)
Weighted average common shares, including dilutive effect (a)
 43,107,452
 43,107,452
Diluted loss per share $0.02
 $(0.58)
(a)
No incremental shares of potentially dilutive restricted stock awards were included for periods presented as their effect was antidulitive under the treasury stock method.

MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
11.Equity Based Compensation
13.    Leases
Lessee Accounting

The Company recognizes 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 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 months ended March 31, 2023 and 2022 (in thousands):
Three Months Ended March 31,
20232022
Operating lease expense$1,768 $1,747 
Short-term lease expense420 36 
Finance lease expense:
Amortization of right-of-use assets565 403 
Interest on lease liabilities57 49 
Total lease expense$2,810 $2,235 

Supplemental balance sheet information related to leases as of March 31, 2023 and December 31, 2022 is as follows (in thousands):
March 31,December 31,
20232022
Operating leases:
Operating lease right-of-use assets$11,907 $10,656 
Current operating lease liability5,858 5,447 
Long-term operating lease liability5,772 4,913 
Finance leases:
Property, plant and equipment, net$6,703 $7,267 
Accrued expenses and other current liabilities2,921 4,003 
Other liabilities2,191 2,602 

17
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Other supplemental information related to leases for the three months ended March 31, 2023 and 2022 and as of March 31, 2023 and December 31, 2022 is as follows (in thousands):

Three Months Ended March 31,
20232022
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases$1,749 $1,672 
Operating cash flows from finance leases57 49 
Financing cash flows from finance leases1,493 452 
Right-of-use assets obtained in exchange for lease obligations:
Operating leases$2,917 $1,383 

March 31,December 31,
20232022
Weighted-average remaining lease term:
Operating leases2.7 years2.9 years
Finance leases2.1 years2.0 years
Weighted-average discount rate:
Operating leases6.3 %4.1 %
Finance leases3.9 %4.3 %

Maturities of lease liabilities as of March 31, 2023 are as follows (in thousands):
Operating LeasesFinance Leases
Remainder of 2023$4,974 $2,598 
20244,976 1,203 
20251,993 696 
2026374 795 
202714 — 
Thereafter449 — 
Total lease payments12,780 5,292 
Less: Present value discount1,150 180 
Present value of lease payments$11,630 $5,112 

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
18
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 $0.7 million during each of the three months ended March 31, 2023 and 2022, respectively, which is included in “services revenue” and “services revenue - related parties” on the unaudited condensed consolidated statements of comprehensive income (loss).

14.    Earnings (Loss) Per Share

Reconciliations of the components of basic and diluted net earnings (loss) per common share are presented in the table below (in thousands, except per share data):
Three Months Ended March 31,
20232022
Basic earnings (loss) per share:
Allocation of earnings (loss):
Net income (loss)$8,351 $(14,817)
Weighted average common shares outstanding47,443 46,845 
Basic earnings (loss) per share$0.18 $(0.32)
Diluted earnings (loss) per share:
Allocation of earnings (loss):
Net income (loss)$8,351 $(14,817)
Weighted average common shares, including dilutive effect(a)
48,002 46,845 
Diluted earnings (loss) per share$0.17 $(0.32)
a.    No incremental shares of potentially dilutive restricted stock awards were included for the three months ended March 31, 2022 as their effect was antidilutive under the treasury stock method.

15.    Equity Based Compensation
Upon formation of certain Operating Entities (including the acquired Stingray Entities),operating entities by Wexford and Gulfport, specified members of management (“Specified(the “Specified Members”) and certain non-employee members (the “Non-Employee Members”) were granted the right to receive distributions from their respective Operating Entity,the operating entities after the contribution member’s unreturned capital balance was recovered (referred to as “Payout” provision). Additionally, non-employee members were included in the award class (“Non-Employee Members”).


On November 24, 2014, the awards were modified in conjunction with the contribution of the Operating Entitiesoperating entities to Mammoth. Awards areThese awards were not granted in limited or general partner units. AgreementsThe awards are for interestinterests in the distributable earnings of Mammoth Holdings,the members of MEH Sub, Mammoth’s majority equity holder.


On the IPO closing date of Mammoth HoldingsInc.’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. Future offerings or sales of common stock to recover outstanding unreturned capital remain not probable.


Payout for the remaining awards is expected to occur followingas the salecontributing member’s unreturned capital balance is recovered from additional sales by Mammoth Holding'sMEH Sub of its shares of the Company'sCompany’s common stock or from dividend distributions, which is not considered not probable until the event occurs. Therefore, for the awards that contained the Payout provision, no compensation cost was recognized as the distribution rights do not vest until Payout is reached. 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 $5,618,552. $5.6 million.

For the Non-EmployeesCompany’s Non-Employee Member awards, the unrecognized cost,amount, which represents the fair value of the awards as of September 30, 2017the date of adoption of ASU 2018-07 was $41,040,779.$18.9 million.


12.Stock Based Compensation

16.    Stock Based Compensation
The 2016 Plan authorizes the Company'sCompany’s Board of Directors or the compensation committee of the Company'sCompany’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.




19

MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Restricted Stock Units


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


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 SharesWeighted Average Grant-Date Fair Value
Unvested shares as of January 1, 20221,128,205 $1.27 
Granted228,310 2.19 
Vested(628,205)1.54 
Forfeited— — 
Unvested shares as of December 31, 2022728,310 1.32 
Granted250,000 5.63 
Vested(566,667)1.48 
Forfeited— — 
Unvested shares as of March 31, 2023411,643 $3.72 

  Number of Unvested Restricted Shares Weighted Average Grant-Date Fair Value 
Unvested shares as of January 1, 2017 282,780
 $14.98
 
Granted 390,587
 21.19
 
Vested (2,233) (17.42) 
Forfeited (8,888) (15.00) 
Unvested shares as of September 30, 2017 662,246
 $18.63
 

As of September 30, 2017,March 31, 2023, there was $9,294,444$1.1 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 2.3 years.

2.4 years.

Included in cost of revenue and selling, general and administrative expenses is stock-based compensation expense of $1,028,318$0.6 million and $2,648,211$0.2 million for the three and nine months ended September 30, 2017,March 31, 2023 and 2022, respectively.


17.    Related Party Transactions
Transactions between the subsidiaries of the Company, including Panther Drilling Systems LLC (“Panther Drilling”), Cobra Aviation, ARS and Leopard and the following companies are included in Related Party Transactions: Wexford, Grizzly Oil Sands ULC (“Grizzly”), El Toro Resources LLC (“El Toro”), 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 March 31,At March 31,At December 31,
2023202220232022
REVENUESACCOUNTS RECEIVABLE
Cobra Aviation/ARS/Leopard and Brim Equipment(a)$220 $60 $107 $217 
Panther and El Toro(b)— 214 — — 
Other Relationships— — 8 6 
$220 $274 $115 $223 
a.Cobra Aviation, ARS and Leopard lease helicopters to Brim Equipment pursuant to aircraft lease and management agreements.
b.Panther provides directional drilling services for El Toro, an entity controlled by Wexford, pursuant to a master service agreement.

Three Months Ended March 31,At March 31,At December 31,
2023202220232022
COST OF REVENUEACCOUNTS PAYABLE
Cobra Aviation/ARS/Leopard and Brim Equipment(a)$7 $19 $25 $3 
The Company and Caliber(b)24 89 — — 
Other Relationships— 27 — — 
$31 $135 $25 $3 

20
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

a.Cobra Aviation, ARS and Leopard lease helicopters to Brim Equipment pursuant to aircraft lease and management agreements.
13.Related Party Transactions
Transactions betweenb.Caliber, an entity controlled by Wexford, leases office space to the subsidiariesCompany.

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 CompanyCompany’s outstanding common stock. ARS leases a helicopter to Brim Equipment and Cobra Aviation leases the following companies are included in Related Party Transactions: Gulfport; Grizzly Oil Sands ULC (“Grizzly”); El Toro Resources LLC ("El Toro"); Diamondback E&P, LLC ("Diamondback"); Cementingtwo helicopters purchased as part of these transactions to Brim Equipment under the terms of aircraft lease and SR Energy (collectively, prior to the 2017 Stingray Acquisition, the "2017 Stingray Companies"); Everest Operations Management LLC ("Everest"); Elk City Yard LLC ("Elk City Yard"); Double Barrel Downhole Technologies LLC ("DBDHT"); Orange Leaf Holdings LLC ("Orange Leaf"); Caliber Investment Group LLC ("Caliber");management agreements. See Note 7 for further discussion.

18.    Commitments and Dunvegan North Oilfield Services ULC (“Dunvegan”).Contingencies
  REVENUES ACCOUNTS RECEIVABLE
  Three Months Ended September 30,Nine Months Ended September 30, At September 30,At December 31,
  2017201620172016 20172016
Pressure Pumping and Gulfport(a)$46,701,582
$35,381,839
$119,546,973
$73,547,397
 $26,830,168
$19,094,509
Muskie and Gulfport(b)14,055,246
6,557,237
39,200,789
17,788,581
 9,464,076
5,373,007
Panther Drilling and Gulfport(c)944,177
464,850
2,937,993
1,685,872
 1,104,331
1,434,036
Cementing and Gulfport(d)3,178,512
—
4,081,829
—
 1,663,156
—
SR Energy and Gulfport(e)5,768,162
—
7,333,373
—
 5,448,130
—
Lodging and Grizzly(f)—
4,840
525
5,412
 —
274
Bison Drilling and El Toro(g)—
—
—
371,873
 —
—
Panther Drilling and El Toro(g)95,700
—
95,700
171,620
 95,700
—
Bison Trucking and El Toro(g)—
—
—
130,000
 —
—
White Wing and El Toro(g)—
—
—
20,431
 —
—
Energy Services and El Toro(h)25,872
155,855
183,617
405,047
 —
108,386
White Wing and Diamondback(i)—
—
—
1,650
 —
—
Coil Tubing and El Toro(j)133,305
—
133,305
318,694
 115,631
—
Panther and DBDHT(k)13,444
—
27,133
—
 25,416
100,450
The Company and 2017 Stingray Companies(l)—
21,015
84,722
21,015
 —
1,363,056
Other Relationships —
—
—
—
 26,053
115,565
  $70,916,000
$42,585,636
$173,625,959
$94,467,592
 $44,772,661
$27,589,283
a.Pressure Pumping provides pressure pumping, stimulation and related completion services to Gulfport.
b.Muskie has agreed to sell and deliver, and Gulfport has 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.
c.Panther Drilling performs drilling services for Gulfport pursuant to a master service agreement.
d.Cementing performs well cementing services for Gulfport.
e.SR Energy performs rental services for Gulfport.
f.Lodging provides remote accommodation and food services to Grizzly, an entity owned approximately 75% by affiliates of Wexford and approximately 25% by Gulfport.
g.The contract land and directional drilling segment provides services for El Toro, an entity controlled by Wexford, pursuant to a master service agreement.
h.Energy Services performs completion and production services for El Toro pursuant to a master service agreement.
i.White Wing provides rental services to Diamondback.
j.Coil Tubing provides to El Toro services in connection with completion and drilling activities.
k.Panther provides services and materials to DBDHT.
l.The Company provided certain services to the 2017 Stingray Companies.
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

  COST OF REVENUE ACCOUNTS PAYABLE
  Three Months Ended September 30,Nine Months Ended September 30, At September 30,At December 31,
  2017201620172016 20172016
Panther and DBDHT(a)$—
$—
$127,778
$48,998
 $—
$—
Bison Trucking and Diamondback(b)—
43,598
66,522
127,556
 —
—
Energy Services and Elk City Yard(c)8,899
26,700
62,299
80,100
 —
—
Lodging and Dunvegan(d)—
6,121
—
8,574
 —
3,199
Bison Trucking and El Toro(e)—
—
—
5,000
 93
—
The Company and 2017 Stingray Companies(f)—
510,668
444,409
516,851
 —
174,145
  $8,899
$587,087
$701,008
$787,079
 $93
$177,344
         
  SELLING, GENERAL AND ADMINISTRATIVE COSTS   
The Company and Everest(g)$32,255
$54,442
$140,372
$190,197
 $7,857
$12,668
The Company and Wexford(h)184,622
57,046
582,916
193,303
 158,386
13,197
Mammoth and Orange Leaf(i)—
19,674
45,786
73,005
 —
—
Mammoth and Caliber(j)137,258
—
209,256
—
 43,608
—
Sand Tiger and Grizzly(k)84
—
4,131
—
 722
—
Lodging and Dunvegan(d)1,023
—
3,665
—
 686
—
  $355,242
$131,162
$986,126
$456,505
 $211,259
$25,865
       $211,352
$203,209
a.Panther rents rotary steerable equipment in connection with its directional drilling services from DBDHT.
b.Bison Trucking leased office space from Diamondback in Midland, Texas.
c.Energy Services leases property from Elk City Yard.
d.Dunvegan provides technical and administrative services and pays for goods and services on behalf of the Company.
e.Bison Trucking leases space from El Toro for storage of a rig.
f.Prior to the 2017 Stingray Acquisition, the 2017 Stingray Companies provided certain services to the Company and, from time to time, the 2017 Stingray Companies paid for goods and services on behalf of the Company.
g.Everest has historically provided office space and certain technical, administrative and payroll services to the Company and the Company has reimbursed Everest in amounts determined by Everest based on estimates of the amount of office space provided and the amount of employees’ time spent performing services for the Company.
h.Wexford provides certain administrative and analytical services to the Company and, from time to time, the Company pays for goods and services on behalf of Wexford.
i.Orange Leaf leases office space to Mammoth.
j.Caliber leases office space to Mammoth.
k.Grizzly provides certain administrative and analytical services to the Company.

14.Commitments and Contingencies
Lease Obligations

The Company leases real estate, rail cars and other equipment under long-term operating leases with varying terms and expiration dates through 2025.

Minimum Purchase Commitments

We have enteredFrom time to time, the Company may enter into agreements with sand suppliers that contain minimum purchase obligations. Our failureobligations and agreements to purchase the minimum tonnage would require us to pay shortfall fees. However, the minimum quantities set forth in the agreements are not in excess of our currently expected future requirements.

Capital Spend Commitments

capital equipment. The Company has entered into agreements with suppliers to acquire capital equipment.did not have any unconditional purchase obligations as of March 31, 2023.


Aggregate future minimum payments under these obligations in effect at September 30, 2017 are as follows:
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Year ended December 31: Operating Leases Capital Spend Commitments Minimum Purchase Commitments
Remainder of 2017 $3,377,429
 $26,847,278
 $3,556,655
2018 13,047,020
 —
 10,866,000
2019 10,533,906
 —
 10,866,000
2020 8,085,194
 —
 —
2021 5,744,808
 —
 —
Thereafter 6,189,124
 —
 —
  $46,977,481
 $26,847,278
 $25,288,655

For the nine months ended September 30, 2017 and 2016, the Company recognized rent expenseLetters of$7,399,404 and $6,174,150, respectively.

Credit
The Company has various letters of credit totaling $454,560 to secure rail car lease payments. These letters of creditthat were issued under the Company'sCompany’s revolving credit agreement and arewhich is collateralized by substantially all of the assets of the Company. The letters of credit are categorized below (in thousands):

March 31,December 31,
20232022
Environmental remediation$3,569 $3,694 
Insurance programs2,800 2,800 
Total letters of credit$6,369 $6,494 

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. AsAt each of September 30, 2017March 31, 2023 and December 31, 2016,2022, the policy requiresworkers’ compensation and automobile liability policies require a per deductible per occurrence of up to $250,000.$0.3 million and $0.1 million, respectively. As of March 31, 2023 and December 31, 2022, 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 relating to workers’ compensation and auto liability based on estimates. As of September 30, 2017March 31, 2023 and December 31, 2016,2022, accrued claims were $1.6 million and $1.5 million, respectively.

The Company also has insurance coverage for directors and officers liability. As of March 31, 2023 and December 31, 2022, the policies containeddirectors and officers liability policy had a deductible per occurrence of $1.0 million and an aggregate stop lossdeductible of $2,000,000. $10.0 million. As of March 31, 2023 and December 31, 2022, 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 $150,000$0.2 million per participant and an aggregate stop-loss of $5,799,991$5.8 million for the calendar year ending December 31, 2017.2022. As of March 31, 2023 and December 31, 2022, accrued claims were $1.7 million and $1.5 million, respectively. These estimates may change in the near term as actual claims continue to develop. As

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 September 30, 2017the work. Generally, the warranty is for one year or less. No liabilities were accrued as of March 31, 2023 and December 31, 2016, accrued insurance2022 and no expense was recognized during the three months ended March 31, 2023 or 2022 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
21
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 each of March 31, 2023 and December 31, 2022, outstanding performance and payment bonds totaled $8.6 million, respectively. The estimated cost to complete projects secured by the performance and payment bonds totaled $1.2 million as of March 31, 2023. There were $2,270,444no outstanding bid bonds as of March 31, 2023 and $971,351, respectively. InDecember 31, 2022.

Litigation

As of March 31, 2023, PREPA owed the Company approximately $227.0 million for services performed, excluding $163.2 million of interest charged on these delinquent balances as of March 31, 2023. 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 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. FEMA approved the appeal in part and denied the appeal in part. FEMA found that staffing costs of $24.4 million are eligible for funding. On August 4, 2021, the Court extended the stay and directed that an additional status report be filed, which was done on January 22, 2022. On January 26, 2022, the Court extended the stay and directed the parties to file a further status report by July 25, 2022. On June 7, 2022, Cobra filed a motion to lift the stay order. On June 29, 2022 the Court denied Cobra’s motion and extended the stay to January 2023. On November 21, 2022, FEMA issued a Determination Memorandum related to the 100% federal funded portion of the second contract between Cobra and PREPA in which FEMA concluded that approximately $5.6 million in costs were not authorized costs under the contract. On December 21, 2022, FEMA issued a Determination Memorandum related to the 90% federal cost share portion of the second contract between Cobra and PREPA in which FEMA concluded that approximately $68.1 million in costs were not authorized costs under the contract. PREPA filed a first-level administrative appeal of the November 21, 2022 Determination Memorandum and has indicated that they will review the December 21, 2022 Determination Memorandums and, to the extent they feel plausible, file a first-level administrative appeal of the unauthorized amounts. On January 7, 2023, Cobra and PREPA filed a joint status report with the Court, in which PREPA requested that the Court continue the stay through July 31, 2023 and Cobra requested that the stay be lifted. On January 18, 2023, the Court entered an order extending the stay and directing the parties to file a further status report addressing (i) the status of any administrative appeals in connection with the insurance programs, letters of credit of $1,636,000 and $1,285,000 as of September 30, 2017November and December 31, 2016, respectively, have been issued supportingdetermination memorandums regarding the retained risk exposure. As of September 30, 2017, in connection with environmental remediation programs, letters of credit of $3,363,627 have been issued supportingsecond contract, (ii) the retained risk exposure. As of both September 30, 2017 and December 31, 2016, these letters of credit were collateralized by substantially allstatus of the assetscriminal case against the former Cobra president and
22
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
the FEMA official that concluded in December 2022, and (iii) a summary of the Company.outstanding and unpaid amounts arising from the first and second contracts and whether PREPA disputes Cobra’s entitlement to these amounts with the Court by July 31, 2023.


On January 20, 2023, Cobra submitted a certified claim for approximately $379 million to FEMA pursuant to the federal Contract Disputes Act. On February 1, 2023, FEMA notified Cobra that it had reviewed the claim and determined that no contract, expressed or implied, exists between FEMA and Cobra. On March 27, 2023, Cobra was notified that FEMA had approved $233 million in Cobra invoices related to the December 21, 2022 Determination Memorandum. The 90% federal cost share of this approved amount was $210 million, which was obligated and made available for draw down on March 27, 2023. Of this $210 million, approximately $99 million has been represented by both PREPA and FEMA as intended to pay Cobra for outstanding invoices and the remaining $111 million is a reimbursement to PREPA for payments already made on Cobra invoices. On March 29, 2023, Cobra filed a notice of appeal with the Civilian Board of Contract Appeals related to the certified claim submitted in January 2023. On April 25, 2023, FEMA filed a motion to dismiss Cobra’s appeal alleging lack of jurisdiction. 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 May 13, 2021, Foreman Electric Services, Inc. (“Foreman”) filed a petition against Mammoth Inc. and Cobra in the Oklahoma County District Court (Oklahoma State Court). The petition asserted claims against the Company and Cobra under federal RICO statutes and certain state-law causes of action. Foreman alleged that it sustained injuries to its business and property in the amount of $250 million due to the Company’s and Cobra’s alleged wrongful interference by means of 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 and filed a motion to dismiss on July 8, 2021. On July 29, 2021, Foreman voluntarily dismissed the action without prejudice. On December 14, 2021, Foreman re-filed its petition against Mammoth Inc. and Cobra in the Oklahoma County District Court (Oklahoma State Court). On December 16, 2021, the Company again removed this action to the United States District Court for the Western District of Oklahoma. Foreman filed a motion to remand this action back to Oklahoma County District Court, which was granted on May 5, 2022. The case will now proceed according to a schedule that will be set by the Oklahoma County District Court. In a related matter, on January 12, 2022, a Derivative Complaint on behalf of nominal defendant Machine Learning Integration, LLC (“MLI”), which alleges it would have served as a sub-contractor to Foreman in Puerto Rico, was filed against the Company and Cobra in the U.S. District Court for the District of Puerto Rico alleging essentially the same facts as Foreman’s action and asserting violations of federal RICO statutes and certain non-federal claims. MLI alleges it sustained injuries to its business and property in an unspecified amount because the Company’s and Cobra’s wrongful interference by means of inducements to a FEMA official prevented Foreman from obtaining work, and thereby prevented MLI, as Foreman’s subcontractor, from obtaining work. These matters are still in the early stages and at this time, the Company is not able to predict the outcome of these claims or whether they will have a material impact on the Company’s business, financial condition, results of operations or cash flows.

The Company is routinely involved in state and local tax audits. During the year ended December 31, 2016,2015, the State of Ohio assessed taxes on the purchase of equipment the Company believes is exempt under state law. The Company has appealed the assessment and a hearing was scheduled for November 30, 2016. In November 2016,held in 2017. As a result of the hearing, the Company received a decision from the State of Ohio, deferredwhich the hearing until 2017. WhileCompany appealed. On February 25, 2022, the Company received an unfavorable decision on the appeal. The Company appealed 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 business, financial position orcondition, 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. On November 14, 2022, the Court entered judgment against Cobra in connection with one of the Company.

lawsuits ordering payment of approximately $9.0 million. On June 3, 2015,January 9, 2023, Cobra appealed the judgment and, on March 20, 2023, the Court confirmed the imposition of approximately $8.5 million related to construction excise taxes. On April 10, 2023, Cobra appealed this judgment, and is currently awaiting a putative class and collective action lawsuit allegingdecision. To the extent Cobra receives an unfavorable judgment, the Company believes that Pressure Pumping failed to pay a class of workers overtime in compliance with the Fair Labor Standards Act and Ohio law was filed titled William Crigler, et al v. Stingray Pressure Pumping, LLCany such taxes in the U.S. District Court Southern Districtjudgement that relate to the Emergency Master Service Agreement with PREPA executed on October 19, 2017, would be reimbursable to Cobra. At this time, the Company is not able to predict the outcome of Ohio Eastern Division. The parties have reached a settlement of this matter which received final approval from the court in August 2017. This settlement is expected to be payable in 2017. This settlementthese matters or whether they will not have a material impact on the Company’s business, financial position,condition, results of operations or cash flows.


On December 2, 2015,April 16, 2019, Christopher Williams, a former employee of Higher Power Electrical, LLC, filed a putative class and collective action lawsuit alleging that Bison Drilling failed to pay a class of workers overtime in compliance with the Fair Labor Standards Act and Texas law was filedcomplaint titled John Talamantez,Christopher Williams, individually and on behalf of all others similarly situated v. Bison Drilling and Field Services, LLC in the U.S. District Court Western District of Texas Midland/Odessa Division. The Company is evaluating the background facts and at this time is not able to predict the outcome of this lawsuit or whether it will have a material impact on the Company’s financial position, results of operations or cash flows.

23
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

On June 22, 2016, a putative, Title VII discrimination,Higher Power Electrical, LLC, Cobra Acquisitions LLC, and Oklahoma anti-discrimination lawsuit alleging that RedbackCobra Energy Services was in violation of the previously mentioned federal and state laws. The lawsuit was filed titled Earl Richardson and Keary Johnson v. Redback Energy Services LLC in the U.S. District Court for the Western District of Oklahoma.Puerto Rico. On June 24, 2019, the complaint was amended to replace Mr. Williams with Matthew Zeisset as the named plaintiff. The Company is evaluatingplaintiff alleges the background facts at this time and is not able to predict the outcome of this lawsuit or whether it will have a material impact on the Company’s financial position, results of operations or cash flows.

On August 1, 2016, a putative class and collective action lawsuit alleging that Energy Servicesdefendant failed to pay a class of workers overtime in compliance with the Fair Labor Standards Act and Texas law was filed titled Michael Caffey, individually and on behalf of all others similarly situated v. Redback Energy Services LLC in the U.S. District Court for the Western District of Texas. The Company is evaluating the background facts and at this time is not ablewages to predict the outcome of this lawsuit or whether it will have a material impact on the Company’s financial position, results of operations or cash flows.

On September 27, 2016, a putative lawsuit alleging that Energy Services failed to pay a class of workers in compliance with the Fair Labor Standards Act was filed titled Michael Drake vs. Redback Coil Tubing LLC, et aland Puerto Rico law. On August 21, 2019, upon request of the parties, the Court stayed proceedings in the lawsuit and administratively closed the case pending completion of individual arbitration proceedings initiated by Mr. Zeisset and opt-in plaintiffs. Other claimants have subsequently initiated additional individual arbitration proceedings asserting similar claims. During and subsequent to the three months ended March 31, 2023, the Company agreed to settlements in principle with a portion of the claimants. Arbitrations remain pending for the remaining claimants. The Company will continue to vigorously defend the arbitrations. During the three months ended March 31, 2023, the Company recognized an estimated liability related to these complaints, which is included in “Accounts payable” in the unaudited condensed consolidated balance sheet at March 31, 2023. The amount to settle these matters may ultimately increase or decrease from our estimated amount as the matters progress.

On September 10, 2019, the U.S. District Court Westernfor 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 was 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. On May 18, 2022, the former FEMA official and the former president of Cobra each pled guilty to one-count information charging gratuities related to a project that Cobra never bid upon and was never awarded or received any monies for. On December 13, 2022, the Court sentenced the former Cobra president to custody of the Bureau of Prisons for six months and one day, a term of supervised release of six months and one day and a fine of $25,000. The Court sentenced the FEMA official to custody of the Bureau of Prisons for six months and one day, a term of supervised release of six months and a fine of $15,000. The Court also dismissed the indictment against the two defendants. The Company does not expect any additional activity in the criminal proceeding. Given the uncertainty inherent in criminal litigation, however, it is not possible at this time to determine the potential impacts that the sentencings 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. It is unclear what PREPA’s position will be going forward. Subsequent to the indictment, Cobra received 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. The aforementioned DOJ investigation is in connection with the issues raised in the criminal matter. Cobra is cooperating with the DOJ and is not able to predict the outcome of this investigation or if it will have a material impact on Cobra’s or the Company’s business, financial condition, results of operations or cash flows. With regard to the previously disclosed SEC investigation, on July 6, 2022, the SEC sent a letter saying that it had concluded its investigation as to the Company and that based on information the SEC has as of this date, it does not intend to recommend an enforcement action against the Company.

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 is evaluatingshould 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 trial court granted Cobra, Mammoth and Straehla’s motion to compel Alpha Lobo’s claims against them to arbitration. However, Alpha Lobo has not yet brought its claims in arbitration. Instead, on March 22, 2022, Alpha Lobo filed a Petition for Writ of Mandamus in the background factsFourth Court of Appeals, San Antonio, Texas, seeking to overturn the order compelling arbitration. The appellate court denied the Mandamus on May 4, 2022, without requesting a response. On June 28, 2022, Alpha Lobo filed a Petition for Writ of Mandamus in the Texas Supreme Court, seeking to overturn the order compelling arbitration. The Texas Supreme Court denied the Mandamus on August 5, 2022, without requesting a response. The Company believes these claims are without merit and will vigorously defend the action. However, at this time. The parties have agreed to stay discovery while they engage in settlement discussions. Thetime, 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 position,condition, results of operations or cash flows.

On January 26, 2017, Additionally, there was a collective action lawsuit alleging that Pressure Pumping failedparallel arbitration proceeding in which certain Defendants were seeking a declaratory judgment regarding Cobra’s rights to payterminate the Alpha Lobo contract and enter into a class of workers in compliancenew contract with the Fair Labor Standards Act was filed titled Ryan Crosby vs. Stingray Pressure Pumping, in the United Stated District Court for the Southern District of Ohio Eastern Division. The Company is evaluating the background facts at this time and is not able to predict the outcome of this lawsuit or whether it will have a material impact on the Company’s financial position, results of operations or cash flows.

third-party. On June 27, 2017, a complaint alleging negligence, as a result24, 2021, the arbitration panel ruled in favor of a motor vehicle accident, was filed titled Donnelle Banks, individually and as parent and next Friend for Leila Ann Hollis, a minor, vs. Redback Coil Tubing LLC and Mammoth Energy Services, Inc. in the District Court of Gregg County, Texas. The Company is evaluating the background facts and at this time is not able to predict the outcome of this lawsuit or whether it will have a material impact on the Company’s financial position, results of operations or cash flows.Cobra.


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
24
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
possibility that the ultimate resolution of these matters could have a material adverse effectimpact on the Company'sCompany’s business, financial condition, results of operations or cash flows.


Defined contribution plan

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 4%3% of an employee’s compensation and may make additional discretionary contributions for eligible employees. For the ninethree months ended September 30, 2017March 31, 2023 and 2016,2022, the Company paid $0$0.6 million and $102,230,$0.4 million, respectively, in contributions to the plan.


15.Operating Segments
The Company is organized into five19.    Reporting Segments
As of March 31, 2023, the Company’s revenues, income before income taxes and identifiable assets are primarily attributable to four reportable segments based on the nature of services provided and the basis in which management makes business and operating decisions. The Company principally provides oilfield services in connection with on-shore drilling of oil and natural gas wells for small to large domestic independent oil and nature gas producers.segments. The Company’s five segments consist of pressure pumping services ("Pressure Pumping Services"), well services ("Well Services"), natural sand proppant ("Sand"), contract land and directional drilling services ("Drilling") and other energy services ("Other Energy Services").

The Company's Chief Executive Officer and Chief Financial Officer comprise the Company'sCompany’s Chief Operating Decision Maker function ("CODM"(“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
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

evaluation is determined on a quantitative basis based on a function of revenue and earnings before interest, otheroperating loss less impairment expense, (income), impairment, taxes and depreciation and amortization as well as a qualitative basis, such as nature of the product and service offerings and types of customers.


Based onAs of March 31, 2023, the CODM's assessment, effective December 31, 2016, the Company reorganized theCompany’s four reportable segments include well completion services (“Well Completion”), infrastructure services (“Infrastructure”), natural sand proppant services (“Sand”) and drilling services (“Drilling”). 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 Infrastructure segment provides electric utility infrastructure services to align with its new management reporting structuregovernment-funded utilities, private utilities, public investor-owned utilities and business activities. Prior to this reorganization,co-operative utilities in the existing reportable segments were comprisednortheastern, southwestern, midwestern and western portions of four segmentsthe United States. The Sand segment mines, processes and sells sand for financial reporting purposes: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 completionprimarily in the Permian Basin and productionmid-continent region.

The Company also provided aviation services, completion and production - natural sand proppant andequipment rental services, crude oil hauling services, remote accommodation services. Asand equipment manufacturing. 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 resultreporting 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 this change, therethe quantitative thresholds of a reporting segment, it does not engage in business activities from which it may earn revenues and its results are fivenot 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 for financialare eliminated in consolidation. Transactions conducted by companies within the same reporting purposes as described above. Historical information in this Note to the financial statements has been revised to reflect the new reportablesegment are eliminated within each reporting segment.

The following table setstables set forth certain financial information with respect to the Company’s reportable segments:segments (in thousands):
25
 Completion and Production    
Nine Months Ended September 30, 2017Pressure Pumping ServicesWell ServicesSandDrillingOther Energy ServicesTotal
Revenue from external customers$46,511,384
$15,852,372
$29,043,367
$33,805,844
$23,694,054
$148,907,021
Revenue from related parties$119,570,520
$11,793,299
$39,200,789
$3,060,826
$525
$173,625,959
Cost of revenue$117,494,570
$24,288,693
$57,759,173
$34,584,336
$16,243,862
$250,370,634
Selling, general and administrative expenses$6,690,812
$2,789,881
$6,314,182
$4,103,053
$2,561,237
$22,459,165
Earnings before interest, other expense, impairment, taxes and depreciation and amortization$41,896,522
$567,097
$4,170,801
$(1,820,719)$4,889,480
$49,703,181
Other expense$126,650
$36,195
$251,520
$262,560
$28,969
$705,894
Bargain purchase gain$—
$—
$(4,011,512)$—
$—
$(4,011,512)
Interest expense (income)$1,023,519
$(14,019)$572,096
$1,227,422
$119,841
$2,928,859
Depreciation, depletion, accretion and amortization$31,823,408
$7,939,784
$6,603,001
$14,978,300
$3,009,890
$64,354,383
Income tax (benefit) provision$—
$(7,778,970)$32,326
$—
$423,822
$(7,322,822)
Net income (loss)$8,922,945
$384,107
$723,370
$(18,289,001)$1,306,958
$(6,951,621)
Total expenditures for property, plant and equipment$72,982,713
$1,121,873
$7,897,818
$8,257,702
$12,013,384
$102,273,490
Three Months Ended September 30, 2017      
Revenue from external customers$29,003,286
$7,055,718
$15,276,279
$12,590,622
$14,462,995
$78,388,900
Revenue from related parties$46,701,582
$9,105,851
$14,055,246
$1,053,321
$—
$70,916,000
Cost of revenue$52,960,761
$13,852,628
$25,177,849
$11,597,757
$10,943,699
$114,532,694
Selling, general and administrative expenses$2,511,147
$1,091,378
$1,840,746
$1,374,275
$1,205,115
$8,022,661
Earnings before interest, other expense, impairment, taxes and depreciation and amortization$20,232,960
$1,217,563
$2,312,930
$671,911
$2,314,181
$26,749,545
Other expense$120,261
$38,186
$97,744
$38,324
$24,737
$319,252
Interest expense$591,724
$94,357
$86,857
$570,364
$76,765
$1,420,067
Depreciation, depletion, accretion and amortization$13,038,962
$4,511,622
$3,034,342
$5,035,990
$1,602,817
$27,223,733
Income tax (benefit) provision$—
$(1,278,456)$23,824
$—
$(158,048)$(1,412,680)
Net income (loss)$6,482,013
$(2,148,146)$(929,837)$(4,972,767)$767,910
$(800,827)
Total expenditures for property, plant and equipment$19,580,804
$777,399
$4,927,935
$2,356,885
$8,054,748
$35,697,771
At September 30, 2017      
Goodwill$86,043,147
$10,192,486
$2,683,727
$—
$891,459
$99,810,819
Intangible assets, net$14,652,434
$2,022,430
$—
$—
$1,817,708
$18,492,572
Total assets$270,394,551
$93,523,385
$169,424,805
$94,661,601
$57,131,438
$685,135,780
MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three months ended March 31, 2023Well CompletionInfrastructureSandDrillingAll OtherEliminationsTotal
Revenue from external customers$67,179 $28,280 $12,442 $1,824 $6,595 $— $116,320 
Intersegment revenues121 — 25 1 437 (584)— 
Total revenue67,300 28,280 12,467 1,825 7,032 (584)116,320 
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion52,037 22,476 7,860 1,922 4,698 — 88,993 
Intersegment cost of revenues478 11 — 109 (14)(584)— 
Total cost of revenue52,515 22,487 7,860 2,031 4,684 (584)88,993 
Selling, general and administrative2,492 4,211 503 313 864 — 8,383 
Depreciation, depletion, amortization and accretion4,817 3,374 1,187 1,367 2,211 — 12,956 
Gains on disposal of assets, net— (127)(16)— (218)— (361)
Operating income (loss)7,476 (1,665)2,933 (1,886)(509)— 6,349 
Interest expense, net929 1,845 156 160 199 — 3,289 
Other (income) expense, net— (8,808)(2)— 186 — (8,624)
Income (loss) before income taxes$6,547 $5,298 $2,779 $(2,046)$(894)$— $11,684 
Three months ended March 31, 2022Well CompletionInfrastructureSandDrillingAll OtherEliminationsTotal
Revenue from external customers$23,630 $23,009 $8,347 $2,852 $4,460 $— $62,298 
Intersegment revenues244 — 832 3 272 (1,351)— 
Total revenue23,874 23,009 9,179 2,855 4,732 (1,351)62,298 
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion21,839 18,887 7,788 2,372 3,594 — 54,480 
Intersegment cost of revenues1,031 16 — 160 70 (1,277)— 
Total cost of revenue22,870 18,903 7,788 2,532 3,664 (1,277)54,480 
Selling, general and administrative2,039 4,645 828 292 864 — 8,668 
Depreciation, depletion, amortization and accretion6,444 4,314 1,795 1,680 2,934 — 17,167 
Gains on disposal of assets, net(49)(5)(75)— (67)— (196)
Operating loss(7,430)(4,848)(1,157)(1,649)(2,663)(74)(17,821)
Interest expense, net371 1,542 162 104 170 — 2,349 
Other (income) expense , net— (9,582)(4)— 545 — (9,041)
(Loss) income before income taxes$(7,801)$3,192 $(1,315)$(1,753)$(3,378)$(74)$(11,129)
Well CompletionInfrastructureSandDrillingAll OtherEliminationsTotal
As of March 31, 2023:
Total assets$89,795 $455,956 $131,790 $19,534 $114,942 $(80,521)$731,496 
As of December 31, 2022:
Total assets$82,897 $450,841 $129,467 $21,755 $120,164 $(80,446)$724,678 
26
 Completion and Production    
Nine Months Ended September 30, 2016Pressure Pumping ServicesWell ServicesSandDrillingOther Energy ServicesTotal
Revenue from external customers$18,294,739
$6,470,485
$4,651,673
$17,946,458
$23,253,092
$70,616,447
Revenue from related parties$73,559,413
$732,740
$17,788,581
$2,381,446
$5,412
$94,467,592
Cost of revenue$60,866,617
$10,030,214
$22,861,407
$22,010,295
$9,993,073
$125,761,606
Selling, general and administrative expenses$2,981,718
$1,512,824
$2,525,310
$3,353,243
$1,641,524
$12,014,619
Earnings before interest, other expense (income), impairment, taxes and depreciation and amortization$28,005,817
$(4,339,813)$(2,946,463)$(5,035,634)$11,623,907
$27,307,814
Other expense (income)$25,087
$(671,986)$82,422
$179,639
$12,944
$(371,894)
Interest expense$502,781
$178,584
$319,855
$2,272,913
$58,768
$3,332,901
Depreciation, depletion, accretion and amortization$27,964,092
$3,903,924
$4,734,540
$16,243,626
$1,636,976
$54,483,158
Impairment of long-lived assets$138,587
$1,384,751
$—
$347,547
$—
$1,870,885
Income tax provision$—
$2,835
$3,716
$—
$2,733,145
$2,739,696
Net (loss) income$(624,730)$(9,137,921)$(8,086,996)$(24,079,359)$7,182,074
$(34,746,932)
Total expenditures for property, plant and equipment$1,262,854
$404,612
$522,267
$1,492,476
$425,838
$4,108,047
Three Months Ended September 30, 2016      
Revenue from external customers$137,626
$2,109,874
$1,675,230
$8,230,625
$8,599,555
$20,752,910
Revenue from related parties$35,393,855
$164,854
$6,557,237
$464,850
$4,840
$42,585,636
Cost of revenue$20,782,936
$3,068,159
$6,429,040
$9,042,242
$3,544,410
$42,866,787
Selling, general and administrative expenses$916,176
$499,346
$415,505
$786,008
$577,572
$3,194,607
Earnings before interest, other expense, impairment, taxes and depreciation and amortization$13,832,369
$(1,292,777)$1,387,922
$(1,132,775)$4,482,413
$17,277,152
Other expense$1,262
$1,159
$9,439
$237,211
$4,761
$253,832
Interest expense$134,017
$29,489
$108,744
$718,706
$33,558
$1,024,514
Depreciation, depletion, accretion and amortization$9,050,605
$1,233,702
$1,784,689
$5,297,694
$554,781
$17,921,471
Impairment of long-lived assets$—
$—
$—
$—
$—
$—
Income tax provision$—
$5,929
$3,716
$—
$1,046,316
$1,055,961
Net income (loss)$4,646,485
$(2,563,056)$(518,666)$(7,386,386)$2,842,997
$(2,978,626)
Total expenditures for property, plant and equipment$335,312
$156,783
$359,656
$1,069,381
$12,706
$1,933,838
At September 30, 2016      
Goodwill$86,043,148
$—
$2,683,727
$—
$—
$88,726,875
Intangible assets, net$23,697,850
$138,646
$—
$—
$—
$23,836,496
Total assets$195,138,423
$41,263,250
$108,773,302
$103,882,141
$32,896,862
$481,953,978


The pressure pumping services segment provides hydraulic fracturing. The well services segment provides coil tubing, flowback and equipment rental services. The sand segment sells, distributes and produces sand for use in hydraulic fracturing. The contract land and directional drilling services segment provides vertical, horizontal and directional drilling services. The other energy services segment provides housing, kitchen and dining, and recreational service facilities for oilfield workers that are located in remote areas away from readily available lodging as well as energy infrastructure services. The pressure pumping and well service segments primarily services in the Utica Shale of Eastern Ohio, Marcellus Shale in Pennsylvania, Eagle Ford and Permian basin in Texas and the SCOOP/STACK in the mid-continent region. The natural sand proppant segment primarily services the Utica Shale and Montney Shale in British Columbia and Alberta, Canada. The contract land and directional drilling services segment primarily services the Permian Basin in West Texas. The other energy services segment provides service in Canada, Texas and New Mexico.
16.Subsequent Events
Subsequent to September 30, 2017, the Company entered into railcar lease agreements with aggregate commitments of $2.2 million.

Subsequent to September 30, 2017, the Company ordered additional capital equipment with aggregate commitments of $3.4 million.

MAMMOTH ENERGY SERVICES, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Subsequent to September 30, 2017, the Company entered into an agreement to purchase sand from an unrelated third party seller with aggregate commitments of $2.2 million.

On October 19, 2017, Cobra entered into a contract to aid in the restoration of utility infrastructure on the island of Puerto Rico. The contract provides for payments of up to $200.0 million, including an initial payment of $15.0 million at the time of signing. As of November 7, 2017, the Company had entered into $32.7 million of commitments related to this contract and made prepayments and deposits of $12.6 million with respect to these commitments.


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 reportQuarterly 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, 2016,2022, filed with the Securities and Exchange Commission, or the SEC, on February 24, 2017.2023 and the section entitled “Forward-Looking Statements” appearing elsewhere in this Quarterly Report.


Overview


We are an integrated, growth-oriented energy serviceservices company serving companies engaged infocused on providing products and services to enable the exploration and development of North American onshore unconventional oil and natural gas reservesreserve as well as the construction and energy infrastructure.repair of the electric grid for private utilities, public investor-owned utilities and co-operative utilities through our infrastructure services businesses. 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 pressure pumpingwell completion services, wellinfrastructure services, natural sand proppant services, contract land and directional drilling services and other energy services. Our pressure pumpingwell completion services division provides hydraulic fracturing, sand hauling and water transfer services. Our wellinfrastructure services division provides pressure controlengineering, design, construction, upgrade, maintenance and repair services cementing, flowback services and equipment rentals.to the electrical infrastructure industry. Our natural sand proppant services division mines, processes and sells distributes and producesnatural sand proppant used for hydraulic fracturing. Our contract land and directional drilling services division currently provides drilling rigs and crews for operators as well as rental equipment, such as mud motors and operational tools, for both vertical and horizontal drilling. Our other energyIn addition to these service divisions, we also provide aviation services, division has historically provided housing, kitchenequipment rentals, crude oil hauling services, remote accommodations and dining, and recreational service facilities for oilfield workers located in remote areas away from readily available lodging and now also includes energy infrastructure services.equipment manufacturing. We believe that the services we offer play a critical role in increasing the ultimate recovery and present value of production streams from unconventional resources.resources as well as in maintaining and improving electrical infrastructure. Our complementary suite of completion and production and drilling related services provides us with the opportunity to cross-sell our services and expand our customer base and geographic positioning.


On November 24, 2014, Mammoth Energy Holdings LLC, or Mammoth Holdings, Gulfport Energy Corporation, or Gulfport,    The growth of our industrial businesses is ongoing. We offer infrastructure engineering services focused on the transmission and Rhino Exploration LLC, or Rhino, contributeddistribution industry and also have equipment manufacturing operations and offer fiber optic services. Our equipment manufacturing operations provide us with the ability to Mammoth Energy Partners LP, orrepair much of our existing equipment in-house, as well as the Partnership, their respective interestsoption to manufacture certain new equipment we may need in the following entities: Bison Drillingfuture. Our fiber optic services include the installation of both aerial and Field Services, LLC, or Bison Drilling; Bison Trucking LLC, or Bison Trucking; White Wing Tubular Services LLC, or White Wing; Barracuda Logistics LLC, or Barracuda; Panther Drilling Systems LLC, or Panther Drilling; Redback Energy Services LLC, or Redback Energy Services; Redback Coil Tubing LLC, or Redback Coil Tubing; Muskie Proppant LLC, or Muskie Proppant; Stingray Pressure Pumping LLC, or Pressure Pumping; Stingray Logistics LLC, or Logistics;buried fiber. We are continuing to explore other opportunities to expand our industrial business lines.

Although demand across our three largest segments improved during 2022 and Great White Sand Tiger Lodging Ltd., or Lodging. Upon completion of these contributions, Mammoth Holdings, Gulfport and Rhino beneficially owned a 68.7%, 30.5% and 0.8% equity interest, respectively,remained strong during the three months ended March 31, 2023, we continue to address the external challenges in the Partnership.

On October 12, 2016, prior to and in connection with the IPO, the Partnership converted to a Delaware limited liability company named Mammoth Energy Partners LLC, or Mammoth LLC, and Mammoth Holdings, Gulfport and Rhino contributed their respective membership interests in Mammoth LLC to us in exchange for shares of our common stock, and Mammoth LLC became our wholly-owned subsidiary.

On October 19, 2016,today’s economic environment as we closed our IPO of 7,750,000 shares of common stock, of which 7,500,000 shares were sold by us and the remaining 250,000 shares were sold by certain selling stockholders, at a price to the public of $15.00 per share. Our common stock is traded on the Nasdaq Global Select Market under the symbol “TUSK.” Unless the context otherwise requires, references in this report to “we,” “our,” “us,” or like terms, when used in a historical context for periods prior to October 12, 2016 refer to the Partnership and its subsidiaries. References in this report to “we,” “our,” “us,” or like terms, when used in the present tense or for periods commencing on or after October 12, 2016 refer to Mammoth Energy Services, Inc., or Mammoth Inc., and its subsidiaries. Mammoth Inc. was formed in June 2016, and did not conduct any material business operations prior to the completion of the IPO and the contribution described above completed on October 12, 2016 immediately prior to the IPO. Prior to the IPO, Mammoth Inc. was a wholly-owned subsidiary of the Partnership.

On June 5, 2017, we acquired Sturgeon Acquisitions LLC, or Sturgeon, and Sturgeon's wholly owned subsidiaries Taylor Frac, LLC, Taylor Real Estate Investments, LLC and South River Road, LLC. Prior to the acquisition, we and Sturgeon were under common control and, in accordance with generally accepted accounting principles in the United States, or GAAP, we have accounted for this acquisition in a manner similar to the pooling of interest method of accounting. Therefore, our historical financial information for all periods included in this Quarterly Report on Form 10-Q has been recast to combine Sturgeon's financial resultsremain disciplined with our financial results as if the acquisition had been effective since Sturgeon commenced operations.spending and are focused on continuing to improve our operational efficiencies and cost structure and on enhancing value for our stockholders.



Overview of Our Industries
Third Quarter 2017 Highlights

Oil and Natural Gas Industry
Expansion of Services

During the third quarter of 2017, we expanded our pressure pumping, sand and last-mile trucking services into the SCOOP/STACK. The startup of our fifth pressure pumping fleet occurred in August 2017 with the startup of our sixth fleet occurring in October 2017, both of which were in the Mid-Continent.

5-Star Acquisition

On July 1, 2017, we completed our acquisition of 5 Star Electric, LLC, or 5 Star, from unrelated third party sellers. We funded the the acquisition of 5 Star with cash on hand and borrowings under our credit facility. The acquisition of 5 Star expanded the energy infrastructure component of our other energy services segment.

Industry Overview

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 budget.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, shortages of equipment and materials and other conditions and factors that are beyond our control.


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 significant declinelevels of capital expenditures of our customers are predominantly driven by the prices of oil and natural gas. 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 dollars per barrel for the first time in history due to factors including significantly reduced demand and a shortage of storage facilities. In 2021, U.S. oil production stabilized as
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commodity prices increased and demand for crude oil rebounded. We saw improvements in the oilfield services industry and in both pricing and utilization of our well completion and drilling services during 2022. During the first quarter of 2023, pricing for crude oil and natural gas prices that begandeclined from levels seen in the third quarter of 2014 continued into February 2016, when the closing price of oil reached a 12-year low of $26.19 per barrel on February 11, 2016. The low commodity price environment caused a reduction in the drilling,2022, which may slow down completion and other production activities of most offor our customers and, their spending on our products and services.

The reduction inas a result, reduce demand during the first part of 2016, and the resulting oversupply of many of the services and products we provide, substantially reduced the prices we could charge our customers for our productswell completion services. Further, the ongoing war and services, and had a negativerelated humanitarian crisis in Ukraine could continue to have an adverse impact on the utilizationglobal energy markets and volatility of commodity prices.

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, pressure control 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 three of our services. This overall trend with respectsix pressure pumping fleets. Subject to market conditions, supply chain constraints and liquidity requirements, we have plans to upgrade one spread to Tier 4 dual fuel as well as upgrade two fleets to Tier 2 dual fuel, giving us a total of four dual fuel fleets by year-end 2023. Continuing supply chain disruptions have resulted in backlogs of equipment and replacement parts for our customers’ activities and spending reversed in late 2016 as oil prices startedour competitors’ pressure pumping fleets, which we expect to rebound from the 12-year low recorded on February 11, 2016 of $26.21 per barrel, reaching a high of $54.06 per barrel on December 28, 2016. Duringpersist through at least the first nine monthshalf of 2017,2023. Any of these factors may result in the delay of our plans to activate, convert or upgrade our existing pressure pumping fleets in the second half of 2023, which may adversely impact our business, financial condition and cash flow.

Natural Sand Proppant Industry
    In our natural sand proppant services business, we experienced a significant decline in demand for our sand proppant in the second half of 2019 and throughout 2020 as a result of completion activity falling due to lower oil traded between a low of $42.53 per barrel recorded on June 21, 2017demand and a high of $54.45 per barrel on February 23, 2017, withpricing, increased capital discipline by our customers, budget exhaustion and the COVID-19 pandemic. Activity rebounded modestly in 2021 and continued to increase throughout 2022 as we saw an average of $49.40 per barrel. This increase in commodity prices from 2016 levels has spurred a significant increase in the land rig count with 918 rigs operating on September 29, 2017, up approximately 45%volume of sand sold. Supply constraints from labor shortages have negatively affected West Texas in-basin mine operations and increased demand for Northern White frac sand for the 635 rigs operating at year-end 2016. Asregion in 2022. Demand from oil and gas companies in Western Canada and the rig count increased, we experienced anMarcellus Shale was also strong in 2022. The increase in activity and pricing, mainly in our completion and production, natural sand proppant and contract land and directional drilling businesses. If near term commodity prices remain at current levels or recover further, we expect to continue to experience2022 resulted in an increase in demand and pricing for our services and products. Despitesand, which continued throughout the anticipated declines in remote accommodation services revenue, our other energy services revenue increased during the thirdfirst quarter of 20172023. However, as discussed above, pricing for crude oil and natural gas declined from levels seen in 2022, which may impact completion activities for our energycustomers and demand for our sand proppant services.

    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 competitive.

Energy Infrastructure Industry

    Our infrastructure services began to contribute to our financial results. Within this segment, subsequentbusiness provides engineering, design, construction, upgrade, maintenance and repair services to the endelectrical infrastructure industry. We offer a broad range of services on electric transmission and distribution, or T&D, networks and substation facilities, which include engineering, design, construction, upgrade, maintenance and repair of high voltage transmission lines, substations and lower voltage overhead and underground distribution systems. Our commercial services include the installation, maintenance and repair of commercial wiring. We also provide storm repair and restoration services in response to storms and other disasters. We provide infrastructure services primarily in the northeast, southwest, midwest and western portions of the thirdUnited States. We currently have agreements in place with private utilities, public IOUs and Co-Ops.

During 2022, operational improvements combined with increased crew count drove enhanced results in our infrastructure services division. Although our average crew count declined slightly from approximately 93 crews throughout the fourth quarter of 2017,2022 to approximately 88 crews throughout the first quarter of 2023, operational efficiencies drove improved results. Funding for projects in the infrastructure space remains strong with added opportunities expected from the Infrastructure Investment and Jobs Act, which was signed into law on November 15, 2021. We anticipate the federal spending to begin fueling additional projects in this sector beginning in late 2023. We continue to focus on operational execution and 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, especially in fiber maintenance and installation projects.

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We work for multiple utilities primarily across the northeastern, southwestern, midwestern and western portions of the United States. We believe that we are well-positioned to compete for new projects due to the experience of our infrastructure management team, combined with our vertically integrated service offerings. We are seeking to leverage this experience and our service offerings to grow our customer base and increase our revenues in the continental United States over the coming years.

Our infrastructure services business has been adversely impacted by the outstanding amounts owed to us by the Puerto Rico Electric Power Authority, or PREPA, for services performed by our subsidiary, Cobra Acquisitions LLC, or Cobra, signed a contract to aid in the restoration of the electric utility infrastructure in Puerto Rico to restore PREPA’s electrical grid damaged by Hurricane Maria. As of March 31, 2023, PREPA owed us approximately $227.0 million for services performed excluding approximately $163.2 million of interest charged on these delinquent balances. 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 first contract. 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 report by June 7, 2021. On April 6, 2021, we 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 providesFEMA would be releasing a report in the near future relating to the first contract. 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 our aid, PREPA filed an appeal of the entire $47 million that FEMA de-obligated in the May 26, 2021 Determination Memorandum. FEMA approved the appeal in part and denied the appeal in part. FEMA found that staffing costs of $24.4 million are eligible for funding. On August 4, 2021, the Court denied Cobra’s April 6, 2021 motion to lift the stay order, extended the stay of our motion seeking recovery of amounts owed to Cobra and directed the parties to file an additional joint status report, which was filed on January 22, 2022. On January 26, 2022, the Court extended the stay and directed the parties to file a further status report by July 25, 2022. On June 7, 2022, Cobra filed a motion to lift the stay order. On June 29, 2022 the Court denied Cobra’s motion and extended the stay to January 2023. On November 21, 2022, FEMA issued a Determination Memorandum related to the 100% federal funded portion of the second contract between Cobra and PREPA in which FEMA concluded that approximately $5.6 million in costs were not authorized costs under the contract. On December 21, 2022, FEMA issued a Determination Memorandum related to the 90% federal cost share portion of the second contract between Cobra and PREPA in which FEMA concluded that approximately $68.1 million in costs were not authorized costs under the contract. PREPA filed a first-level administrative appeal of the November 21, 2022 Determination Memorandum and has indicated that they will review the December 21, 2022 Determination Memorandums and, to the extent they feel plausible, file a first-level administrative appeal of the unauthorized amounts. On January 7, 2023, Cobra and PREPA filed a joint status report with the Court, in which PREPA requested that the Court continue the stay through July 31, 2023 and Cobra requested that the stay be lifted. On January 18, 2023, the Court entered an order extending the stay and directing the parties to file a further status report addressing (i) the status of any administrative appeals in connection with the November and December determination memorandums regarding the second contract, (ii) the status of the criminal proceedings against the former Cobra president and the FEMA official that concluded in December 2022, and (iii) a summary of the outstanding and unpaid amounts arising from the first and second contracts and whether PREPA disputes Cobra’s entitlement to these amounts with the Court by July 31, 2023.

On January 20, 2023, Cobra submitted a certified claim for approximately $379 million to FEMA pursuant to the federal Contract Disputes Act. On February 1, 2023, FEMA notified Cobra that it had reviewed the claim and determined that no contract, expressed or implied, exists between FEMA and Cobra. On March 27, 2023, Cobra was notified that FEMA had approved $233 million in Cobra invoices related to the December 21, 2022 Determination Memorandum. The 90% federal cost share of this approved amount was $210 million, which was obligated and made available for draw down on March 27, 2023. Of this $210 million, approximately $99 million has been represented by both PREPA and FEMA as intended to pay Cobra for outstanding invoices and the remaining $111 million is a reimbursement to PREPA for payments already made on Cobra invoices. On March 29, 2023, Cobra filed a notice of upappeal with the Civilian Board of Contract Appeals related to $200 million. Underthe certified
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claim submitted in January 2023. On April 25, 2023, FEMA filed a motion to dismiss Cobra’s appeal alleging lack of jurisdiction.

We believe all amounts charged to PREPA were in accordance with the terms of the contracts. Further, we believe these receivables are collectible. 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 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 contract, we intend to mobilize more than 500 peopleregard, 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 focused on the interactions between a former FEMA official and the necessary equipmentformer President of Cobra. Neither we nor any of our subsidiaries were charged in the indictment. On May 18, 2022, the former FEMA official and the former president of Cobra each pled guilty to Puerto Rico.one-count information charging gratuities related to a project that Cobra never bid upon and was never awarded or received any monies for. On December 13, 2022, the Court sentenced the former Cobra president to custody of the Bureau of Prisons for six months and one day, a term of supervised release of six months and a fine of $25,000. The Court sentenced the FEMA official to custody of the Bureau of Prisons for six months and one day, a term of supervised release of six months and a fine of $15,000. The Court also dismissed the indictment against the two defendants. We do not expect any additional activity in the criminal proceeding. Given the uncertainty inherent in the criminal litigation, however, it is not possible at this time to determine the potential impacts that the sentencings could have on us. 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. It is unclear what PREPA's position will be going forward. 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 other customers to replace the level of services that we provided to PREPA.



First Quarter 2023 Financial Overview

•Total revenue for the first quarter of 2023 increased by $54.0 million, or 87%, to $116.3 million from $62.3 million for the first quarter of 2022. The increase in total revenue is primarily due to an increase in well completions, driven primarily by increased utilization and pricing for our services.

•Net income for the first quarter of 2023 was $8.4 million, or $0.17 per diluted share, as compared to net loss of $14.8 million, or $0.32 loss per diluted share, for the first quarter of 2022.

•Net cash flow provided by operating activities for the first quarter of 2023 was $3.2 million, as compared to net cash flow used in operating activities of $2.4 million for the first quarter of 2022.

•Adjusted EBITDA (as defined and reconciled below) for the first quarter of 2023 increased by $21.4 million, or 230%, to $30.7 million from $9.3 million for the first quarter of 2022. See “Non-GAAP Financial Measures” below for a reconciliation of net income to Adjusted EBITDA.






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Results of Operations

Three Months Ended September 30, 2017March 31, 2023 Compared to Three Months Ended September 30, 2016March 31, 2022
Three Months Ended
March 31, 2023March 31, 2022
(in thousands)
Revenue:
Well completion services$67,300 $23,874 
Infrastructure services28,280 23,009 
Natural sand proppant services12,467 9,179 
Drilling services1,825 2,855 
Other services7,032 4,732 
Eliminations(584)(1,351)
Total revenue116,320 62,298 
Cost of revenue:
Well completion services (exclusive of depreciation and amortization of $4,813 and $6,437, respectively, for the three months ended March 31, 2023 and 2022)52,515 22,870 
Infrastructure services (exclusive of depreciation and amortization of $3,372 and $4,306, respectively, for the three months ended March 31, 2023 and 2022)22,487 18,903 
Natural sand proppant services (exclusive of depreciation, depletion and accretion of $1,186 and $1,792, respectively, for the three months ended March 31, 2023 and 2022)7,860 7,788 
Drilling services (exclusive of depreciation and amortization of $1,367 and $1,680, respectively, for the three months ended March 31, 2023 and 2022)2,031 2,532 
Other services (exclusive of depreciation and amortization of $2,210 and $2,933, respectively, for the three months ended March 31, 2023 and 2022)4,684 3,664 
Eliminations(584)(1,277)
Total cost of revenue88,993 54,480 
Selling, general and administrative expenses8,383 8,668 
Depreciation, depletion, amortization and accretion12,956 17,167 
Gains on disposal of assets, net(361)(196)
Operating income (loss)6,349 (17,821)
Interest expense, net(3,289)(2,349)
Other income, net8,624 9,041 
Income (loss) before income taxes11,684 (11,129)
Provision for income taxes3,333 3,688 
Net income (loss)$8,351 $(14,817)

 Three Months Ended
 September 30, 2017 September 30, 2016
Revenue:   
Pressure pumping services$75,704,868
 $35,531,481
Well services16,161,569
 2,274,728
Natural sand proppant services29,331,525
 8,232,467
Contract land and directional drilling services13,643,943
 8,695,475
Other energy services14,462,995
 8,604,395
Total revenue149,304,900
 63,338,546
    
Cost of revenue:   
Pressure pumping services52,960,761
 20,782,936
Well services13,852,628
 3,068,159
Natural sand proppant services25,177,849
 6,429,040
Contract land and directional drilling services11,597,757
 9,042,242
Other energy services10,943,699
 3,544,410
Total cost of revenue114,532,694
 42,866,787
Selling, general and administrative expenses8,022,661
 3,194,607
Depreciation and amortization27,223,733
 17,921,471
Operating loss(474,188) (644,319)
Interest expense, net(1,420,067) (1,024,514)
Other expense, net(319,252) (253,832)
Loss before income taxes(2,213,507) (1,922,665)
(Benefit) provision for income taxes(1,412,680) 1,055,961
Net loss$(800,827) $(2,978,626)

Revenue. Revenue for the three months ended September 30, 2017March 31, 2023 increased $86.0$54.0 million, or 136%87%, to $149.3$116.3 million from $63.3$62.3 million for the three months ended September 30, 2016.March 31, 2022. The increase in total revenue is primarily attributable to an increase in well completions revenue during the three months ended March 31, 2023 primarily due to increased utilization and pricing. Revenue derived from related parties was $0.2 million for the three months ended March 31, 2023 and $0.3 million for the three months ended March 31, 2022. Revenue by operating division was as follows:


Pressure Pumping    Well Completion Services. Pressure pumpingWell completion services division revenueincreased $40.2$43.4 million, or 113%182%, to $75.7$67.3 million for the three months ended September 30, 2017March 31, 2023 from $35.5$23.9 million for the three months ended September 30, 2016.March 31, 2022. The increase in our well completion services revenue was primarily driven by ana 189% increase in fleet utilizationthe number of stages completed from two active fleets, averaging 36% utilization,699 for the three months ended September 30, 2016March 31, 2022 to 82%, on2,018 for the three months ended March 31,
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2023 as well as an increase in both pricing for our services and sand and chemical materials revenue. An average of 3.6 of our fleets were active for the three months ended March 31, 2023 as compared to an average of five active1.6 fleets for the three months ended September 30, 2017. Our fourth and fifth fleets began working in June and August 2017, respectively. Additionally, the number of stages completed increased to 1,617 for the three months ended September 30, 2017 from 511 for the three months ended September 30, 2016.March 31, 2022.


Well Services. Well    Infrastructure Services. Infrastructure services division revenue increased $13.9$5.3 million, or 604%23%, to $16.2$28.3 million for the three months ended September 30, 2017March 31, 2023 from $2.3$23.0 million for the three months ended September 30, 2016. Cementing and energyMarch 31, 2022 primarily due to operational execution, an increase in crew count, improved pricing for our services accounted for $9.1 million of the increase as a result of our Stingray Cementing and Stingray Energy acquisitions. Our coil tubing services accounted for $4.1 million of our operating division increase, as a result of increased utilization and an increase in average day rates from approximately $16,800storm restoration activity. Average crew count was 88 crews for the three months ended September 30, 2016March 31, 2023, as compared to approximately $30,20085 crews for the three months ended September 30, 2017. Our flowback services accounted for $0.7 million of our operating division increase, as a result of an increase in utilization.March 31, 2022.


Natural Sand Proppant Services. Natural sand proppant services division revenue increased $21.1$3.3 million, or 257%36%, to $29.3$12.5 million for the three months ended September 30, 2017,March 31, 2023, from $8.2$9.2 million for the three months ended September 30, 2016. TheMarch 31, 2022 primarily due to an 45% increase was primarily attributablein the average price per ton of sand sold from $21.44 per ton during the three months ended March 31, 2022 to an$31.02 per ton during the three months ended March 31, 2023, and a 19% increase in tons of sand sold from 188,018328,591 tons for the three months ended September 30, 2016March 31, 2022 to 438,800391,439 tons for the three months ended September 30, 2017. InMarch 31, 2023.


addition, the price per ton of sand sold increased from $44 to $67, from the three months ended September 30, 2016 to the three months ended September 30, 2017.

Contract Land and Directional Drilling Services. Contract land and directional drillingServices. Drilling services division revenue increased $4.9decreased $1.1 million, or 56%38%, from $8.7to $1.8 million for the three months ended September 30, 2016March 31, 2023 as compared to $13.6$2.9 million for the three months ended September 30, 2017.March 31, 2022. The increase wasdecrease is primarily attributabledue to a decline utilization for our landdirectional drilling services, which accounted for $2.0 million, or 41%, of the operating division increase as a result of an increase in average day ratesbusiness from approximately $12,200 to approximately $14,80048% for the three months ended September 30, 2016 and 2017, respectively. The average rig count remained consistent at an average of five rigs for each respective period. Our directional drilling services accounted for $1.5 million, orMarch 31, 2022 to 30%, of the operating division increase as a result of utilization increasing from 25% for the three months ended September 30, 2016 to 32% for the three months ended September 30, 2017. Our rig movingMarch 31, 2023.

    Other Services. Other services accounted for $1.4revenue, consisting of revenue derived from our aviation, equipment rental, remote accommodation and equipment manufacturing businesses, increased approximately $2.3 million, or 29%, of the operating division increase. The increase in our rig moving services was driven by the increase in drilling activity.

Other Energy Services. Other energy services division revenue, which has historically included only remote accommodation services but now also includes energy infrastructure services, increased $5.9 million, or 69%49%, to $14.5$7.0 million for the three months ended September 30, 2017March 31, 2023, from $8.6$4.7 million for the three months ended September 30, 2016. The increase was a resultMarch 31, 2022. Inter-segment revenue, consisting primarily of revenue derived from our energy infrastructure services of $13.5 million. The increase from energy infrastructure serviceswell completion segment, was partially offset by a decrease in total rooms nights rented from 65,455 to 5,569$0.4 million and $0.3 million for the three months ended September 30, 2016March 31, 2023 and 2017, respectively, partially offset by2022, respectively.

Revenue from our accommodations business increased $1.9 million primarily due to an increase in revenue per room night, in Canadian dollars, from $172 forrooms rented during the three months ended September 30, 2016March 31, 2023 compared to $187 for the three months ended September 30, 2017.March 31, 2022. Additionally, an average of 287 pieces of equipment were rented to customers during the three months ended March 31, 2023, anincrease of 29% from an average of 222 pieces of equipment rented to customers during the three months ended March 31, 2022, resulting in an increase to revenue of $0.3 million.


Cost of Revenue (exclusive of depreciation, depletion, amortization and accretion expense). Cost of revenue, exclusive of depreciation, depletion, amortization and accretion expense, increased $71.6$34.5 million from $42.9$54.5 million, or 68%87% of total revenue, for the three months ended September 30, 2016March 31, 2022 to $114.5$89.0 million, or 77%of total revenue, for the three months ended September 30, 2017.March 31, 2023. The increase is primarily due to an increase in activity in our well completions divisions. Cost of revenue by operating division was as follows:


Pressure PumpingWell Completion Services. Pressure pumpingWell completion services division cost of revenue, exclusive of depreciation and amortization expense, increased $32.2$29.6 million, or 155%130%, to $53.0$52.5 million for the three months ended September 30, 2017March 31, 2023 from $20.8$22.9 million for the three months ended September 30, 2016. The increase wasMarch 31, 2022, primarily due to thean increase in active fleets, which resulted in increases in proppant costs, repairsutilization and maintenance expense and labor-related costs. The labor-related costs were primarily as a result of staffing our third, fourth and fifth pressure pumping fleets during 2017. As a percentage of revenue, our pressure pumping services divisionthe cost of revenue was 70% and 58% for the three months ended September 30, 2017 and September 30, 2016, respectively.

Well Services. Well services division cost of revenue increased $10.8 million, or 348%, from $3.1 million for the three months ended September 30, 2016 to $13.9 million for the three months ended September 30, 2017. The increase was primarily due to increases in labor-related costs and the acquisition of Stingray Cementing and Stingray Energy.consumables. As a percentage of revenue, our well completion services division cost of revenue, was 86%exclusive of depreciation and 135%amortization expense of $4.8 million and $6.4 million for the three months ended September 30, 2017March 31, 2023 and September 30, 2016,2022, respectively, was 78% and 96% for the three months ended March 31, 2023 and 2022, respectively. The decrease in cost of revenue as a percentage of revenue wasis primarily due to thean increase in utilization as well as improved pricing.

    Infrastructure Services. Infrastructure services division cost of revenue, exclusive of depreciation and average day ratesamortization expense, increased $3.6 million, or 19%, to $22.5 million for the three months ended March 31, 2023 from $18.9 million for the three months ended March 31, 2022, primarily due to an increase in activity. As a percentage of revenue, cost of revenue, exclusive of depreciation and amortization expense of $3.4 million and $4.3 million for the three months ended March 31, 2023 and 2022, respectively, was 80% and 82% for the three months ended March 31, 2023 and 2022, respectively. The decline as a percentage of revenue is primarily due to improved pricing, an increase in storm restoration activity as well as a decline in labor related costs as a result of improved efficiency of our coil tubing division.crews.


Natural Sand Proppant Services. Natural sand proppant services division cost of revenue, exclusive of depreciation, depletion and accretion expense, increased $18.8$0.1 million, or 294%, from $6.4to $7.9 million for the three months ended September 30, 2016 to $25.2
32


March 31, 2023 from $7.8 million for the three months ended September 30, 2017, primarily due to an increase in tons of sand sold.March 31, 2022. As a percentage of revenue, cost of revenue, was 86%exclusive of depreciation, depletion and 78%accretion expense of $1.2 million and $1.8 million for the three months ended September 30, 2017March 31, 2023 and September 30, 2016,2022, respectively, was 63% and 85% for the three months ended March 31, 2023 and 2022, respectively. The increase wasdecrease as a percentage of revenue is primarily due to increasesan 45% increase in salesprice per ton of sand sold.

Drilling Services. Drilling services division cost of revenue, exclusive of depreciation and amortization expense, decreased $0.5 million, or 20%, to $2.0 million for the pressure pumping division which are eliminated in consolidation.

Contract Land and Directional Drilling Services. Contract land and directionalthree months ended March 31, 2023 from $2.5 million for the three months ended March 31, 2022. As a percentage of revenue, our drilling services division cost of revenue, increased $2.6exclusive of depreciation and amortization expense of $1.4 million or 29%, from $9.0and $1.7 million for the three months ended September 30, 2016March 31, 2023 and 2022, respectively, was 111% and 86% for the three months ended March 31, 2023 and 2022, respectively. The increase is primarily due to $11.6a decline in utilization.

    Other Services. Other services division cost of revenue, exclusive of depreciation and amortization expense, increased $1.0 million, or 27%, to $4.7 million for the three months ended September 30, 2017, primarily due to an increase in labor-related costs, repairs and maintenance and increased utilization. As a percentage of revenue, our contract land and directional drilling services division cost of revenue was 85% and 104% for the three months ended September 30, 2017 and September 30, 2016, respectively. The decrease was primarily due to higher day rates and utilization.

Other Energy Services. Other energy services division cost of revenue increased $7.4 million, or 211%,March 31, 2023 from $3.5$3.7 million for the three months ended September 30, 2016March 31, 2022 primarily due to $10.9 million for the three months ended

September 30, 2017.increased activity. As a percentage of revenue, cost of revenue, was 76%exclusive of depreciation and 41%amortization expense of $2.2 million and $2.9 million for the three months ended September 30, 2017March 31, 2023 and 2016,2022, respectively, was 67% and 77% for the three months ended March 31, 2023 and 2022, respectively. The decrease is primarily due to an increase attributable to costs from our energy infrastructure services was partially offset by decreases in costs attributable to our remote accommodation services.utilization.


Selling, General and Administrative Expenses. Selling, general and administrative, or SG&A, expenses represent the costs associated with managing and supporting our operations. TheseThe table below presents a breakdown of SG&A expenses increased $4.8for the periods indicated (in thousands):
Three Months Ended
March 31, 2023March 31, 2022
Cash expenses:
Compensation and benefits$4,277 $2,983 
Professional services1,929 3,637 
Other(a)
1,911 1,906 
Total cash SG&A expense8,117 8,526 
Non-cash expenses:
Bad debt provision(381)(99)
Stock based compensation647 241 
Total non-cash SG&A expense266 142 
Total SG&A expense$8,383 $8,668 
a.    Includes travel-related costs, IT expenses, rent, utilities and other general and administrative-related costs.


    Depreciation, Depletion, Amortization and Accretion. Depreciation, depletion, amortization and accretion decreased $4.2 million, or 150%24%, to $8.0$13.0 million for the three months ended September 30, 2017,March 31, 2023 from $3.2$17.2 million for the three months ended September 30, 2016.March 31, 2022. The increase in expenses wasdecrease is primarily attributable to a $1.5decline in property and equipment depreciation expense as a result of existing assets being fully depreciated.

Gains on Disposal of Assets, Net. Gains on the disposal of assets were $0.4 million increase in compensation, of which $1.0 million was related to equity based compensation, a $3.4 million increase in professional fees and services, of which $0.3 million was related to acquisition-related costs, and a $0.1 million reduction in bad debt expense for the three months ended September 30, 2017, compared to the three months ended September 30, 2016.

Depreciation and Amortization. Depreciation and amortization increased $9.3 million, or 52%, to $27.2$0.2 million for the three months ended September 30, 2017 from $17.9March 31, 2023 and 2022, respectively.

    Operating Income (Loss). We reported operating income of $6.3 million for the three months ended September 30, 2016. The increase was primarily attributable to placing in service of $162.6 million of capital additions during 2017 partially offset by $26.2 million and $14.9 million of assets that fully depreciated during 2016 and 2017, respectively.

Interest Expense, Net. Interest expense increased $0.4 million, or 40%, to $1.4 million during the three months ended September 30, 2017, from $1.0 million during the three months ended September 30, 2016. The increase in interest expense was attributable to an increase in average borrowings during the three months ended September 30, 2017.

Other Expense, Net. Non-operating expense resulted in expense of $0.3 million for both the three months ended September 30, 2016 and 2017. Both periods were primarily comprised of loss recognition on assets disposed of during the period.

Income Taxes. Prior to our initial public offering in October 2016, we were treated as a pass-through entity for federal income tax and most state income tax purposes. For the three months ended September 30, 2017, we recognized income tax benefit of $1.4 millionMarch 31, 2023 compared to an income tax expenseoperating loss of $1.1$17.8 million for the three months ended September 30, 2016. The provision for the three months ended September 30, 2016 was primarily attributable to our subsidiary, Lodging, which provides our remote accommodation services.



Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
 Nine Months Ended September 30,
 2017 2016
Revenue:   
Pressure pumping services$166,081,904
 $91,854,152
Well services27,645,671
 7,203,225
Natural sand proppant services68,244,156
 22,440,254
Contract land and directional drilling services36,866,670
 20,327,904
Other energy services23,694,579
 23,258,504
Total revenue322,532,980
 165,084,039
    
Cost of revenue:   
Pressure pumping services117,494,570
 60,866,617
Well services24,288,693
 10,030,214
Natural sand proppant services57,759,173
 22,861,407
Contract land and directional drilling services34,584,336
 22,010,295
Other energy services16,243,862
 9,993,073
Total cost of revenue250,370,634
 125,761,606
Selling, general and administrative expenses22,459,165
 12,014,619
Depreciation and amortization64,354,383
 54,483,158
Impairment of long-lived assets—
 1,870,885
Operating loss(14,651,202) (29,046,229)
Interest expense, net(2,928,859) (3,332,901)
Bargain purchase gain, net of tax4,011,512
 —
Other (expense) income, net(705,894) 371,894
Loss before income taxes(14,274,443) (32,007,236)
(Benefit) provision for income taxes(7,322,822) 2,739,696
Net loss$(6,951,621) $(34,746,932)

Revenue. Revenue for the nine months ended September 30, 2017 increased $157.4 million, or 95%, to $322.5 million from $165.1 million for the nine months ended September 30, 2016. Revenue by operating division was as follows:

Pressure Pumping Services. Pressure pumping services division revenue increased $74.2 million, or 81%, to $166.1 million for the nine months ended September 30, 2017 from $91.9 million for the nine months ended September 30, 2016. The increase was primarily driven by an increase in fleet utilization of 45%, on an average of two active fleets, for the nine months ended September 30, 2016 to 84%, on an average of 3.3 active fleets, for the nine months ended September 30, 2017. Additionally, the number of stages completed increased to 3,764 for the nine months ended September 30, 2017 from 1,678 for the nine months ended September 30, 2016.

Well Services. Well services division revenue increased $20.4 million, or 283%, to $27.6 million for the nine months ended September 30, 2017 from $7.2 million for the nine months ended September 30, 2016. The cementing and energy services divisions accounted for $11.7 million of the increase as a result of our Stingray Cementing and Stingray Energy acquisitions. Our coil tubing services accounted for $7.9 million of our operating division increase, as a result of increased utilization and an increase in average day rates from approximately $17,933 for the nine months ended September 30, 2016 to approximately $26,933 for the nine months ended September 30, 2017. Our flowback services accounted for $0.8 million of our operating division increase, as a result of increased utilization.

Natural Sand Proppant Services. Natural sand proppant services division revenue increased $45.8 million, or 204%, to $68.2 million for the nine months ended September 30, 2017, from $22.4 million for the nine months ended September 30, 2016. The increase was primarily attributable to an increase in tons sold from approximately

447,908 for the nine months ended September 30, 2016 to approximately 1,035,506 in the nine months ended September 30, 2017, in addition to an increase in price per ton of of sand sold from $50 to $66, for the nine months ended September 30, 2016 and 2017, respectively.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division revenue increased $16.6 million, or 82%, from $20.3 million for the nine months ended September 30, 2016 to $36.9 million for the nine months ended September 30, 2017. The increase was primarily attributable to our land drilling services, which accounted for $9.0 million, or 55%, of the operating division increase.March 31, 2022. The increase in our land drilling services was driven by a increase in average active rigs from four for the nine months ended September 30, 2016 to five for the nine months ended September 30, 2017 as well as a increase in average day rates from approximately $12,667 to approximately $14,433 during those same periods. Our directional drilling services accounted for $4.0 million, or 24%, of the operating division increase as a result of utilization declining from 18% for the nine months ended September 30, 2016 to 28% for the nine months ended September 30, 2017. Our rig moving services accounted for $3.7 million, or 22%, of the operating division increase primarily driven by the increase in drilling activity. Our drill pipe inspection services accounted for a decline of $0.2 million, or (1)%, of the operating division.

Other Energy Services. Other energy services division revenue increased $0.4 million, or 2%, to $23.7 million for the nine months ended September 30, 2017 from $23.3 million for the nine months ended September 30, 2016. The increase in attributable to $15.2 million of revenue from our energy infrastructure services during the nine months ended September 30, 2017. We did not not provide infrastructure services during the same period in 2016. The increase from our infrastructure services was offset by a decrease in our remote accommodation services due to a decrease in total room nights rented from 174,684 for the nine months ended September 30, 2016 to 55,007 for the nine months ended September 30, 2017 partially offset by an increase in revenue per room night, in Canadian dollars, from $176 for the nine months ended September 30, 2016 to $202 for the nine months ended September 30, 2017. The decrease in revenue from our remote accommodation services was partially offset by approximately $0.9 million of business interruption insurance proceeds we collected and recognized for the nine months ended September 30, 2017.

Cost of revenue. Cost of revenue increased $124.6 million from $125.8 million, or 76% of total revenue, for the nine months ended September 30, 2016 to $250.4 million, or 78%of total revenue, for the nine months ended September 30, 2017. Cost of revenue by operating division was as follows:

Pressure Pumping Services. Pressure pumping services division cost of revenue increased $56.6 million, or 93%, to $117.5 million for the nine months ended September 30, 2017 from $60.9 million for the nine months ended September 30, 2016. The increase was primarily due to our additional fleets, which resulted in increases in proppant costs, repairs and maintenance expense and labor-related costs. The labor-related costs increased primarily as a result of staffing our third, fourth and fifth pressure pumping fleets which came online during 2017. As a percentage of revenue, our pressure pumping services division cost of revenue was 71% and 66% for the nine months ended September 30, 2017 and 2016, respectively.

Well Services. Well services division cost of revenue increased $14.3 million, or 143%, from $10.0 million for the nine months ended September 30, 2016 to $24.3 million for the nine months ended September 30, 2017. The increase wasincome is primarily due to an increase in labor-related costs. As a percentage of revenue,activity and pricing for our well services division cost of revenue was 88% and 139% for the nine months ended September 30, 2017 and September 30, 2016, respectively. The decrease in cost of revenue as a percentage of revenue was primarily due to increases in utilization as well as pricing in our coil tubing services.completions division.


Natural Sand Proppant Services. Natural sand proppant services division cost of revenue    Interest Expense, Net. Interest expense, net increased $34.9$1.0 million, or 152%43%, from $22.9to $3.3 million for the ninethree months ended September 30, 2016 to $57.8March 31, 2023 from $2.3 million for the ninethree months ended September 30, 2017,March 31, 2022. The increase is primarily due to an increase in tons sold. As a percentage of revenue, cost of revenue was 85% and 102% for the nine months ended September 30, 2017 and 2016, respectively. The decrease in cost of revenue as a percentage of revenue was primarily dueinterest rate under our revolving credit facility.

    Other Income, Net. Other income decreased $0.4 million to an increase in price per ton sold.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division cost of revenue increased $12.6 million, or 57%, from $22.0$8.6 million for the ninethree months ended September 30, 2016March 31, 2023 compared to $34.6$9.0 million for the ninethree months ended September 30, 2017, primarily due to an increase in labor-related costs, repairs and maintenance and increased utilization. As a percentageMarch 31, 2022.
33


    Income Taxes. We recorded income tax expense of revenue, our contract land and directional drilling services division cost$3.3 million on pre-tax income of revenue was 94% and 108% for the nine months ended September 30, 2017 and 2016, respectively. The decrease was primarily due to higher day rates and utilization.

Other Energy Services. Other energy services division cost of revenue increased $6.2 million, or 62%, from $10.0 million the nine months ended September 30, 2016 to $16.2$11.7 million for the ninethree months ended September 30, 2017, primarily dueMarch 31, 2023 compared to costs associated with our energy infrastructure services$3.7 million on pre-tax losses of $11.8$11.1 million which were offset by decreases in costs associated with our remote accommodation services. As a percentage of revenue, cost of revenue was 69% and 43% for the ninethree months ended September 30, 2017March 31, 2022. Our effective tax rates were 29% and 2016,33% for the three months ended March 31, 2023 and 2022, respectively. The increase waseffective tax rates for the three months ended March 31, 2023 and 2022 differed from the statutory rate of 21% primarily due to the decrease in total room nights rented from 174,684 formix of earnings between the nine months ended September 30, 2016 to 55,007 for the nine months ended September 30, 2017.

Selling, GeneralUnited States and Administrative expenses. Selling, general and administrative expenses represent the costs associated with managing and supporting our operations. These expenses increased $10.5 million, or 88%, to $22.5 million for the nine months ended September 30, 2017, from $12.0 million for the nine months ended September 30, 2016. The increase in expenses was primarily attributable to a $6.5 million increase in compensation and benefits, of which $2.5 million was related to equity based compensation, and a $5.0 million increase in professional fees, of which $2.6 million was related to acquisition-related costs, partially offset by a decrease in bad debt expense of $1.1 million.

Depreciation and Amortization. Depreciation and amortization increased $9.9 million, or 18%, to $64.4 million for the nine months ended September 30, 2017 from $54.5 million for the nine months ended September 30, 2016. The increase was primarily attributable to placing in service of $162.6 million of capital additions during 2017, partially offset by $26.2 million and $14.9 million of assets that fully depreciated during 2016 and 2017, respectively.

Impairment of Long-lived Assets. The nine months ended September 30, 2016 included impairment charges of $1.9 million attributable to various fixed assetsPuerto Rico as well as changes in the amount of $0.4 million, $0.1 million and $1.4 million for the contract land and directional drilling services, pressure pumping and well service segments, respectively.valuation allowance.


Interest Expense, Net. Interest expense decreased $0.4 million, or 12%, to $2.9 million during the nine months ended September 30, 2017, from $3.3 million during the nine months ended September 30, 2016. The decrease in interest expense was attributable to a decrease in average borrowings during the nine months ended September 30, 2017.

Bargain Purchase Gain. Bargain purchase resulted in a gain of $4.0 million for the nine months ended September 30, 2017 on the purchase of Chieftain (see Note 3 of Part I of this Report).

Other (Expense) Income, Net. Non-operating (charges) income resulted in expense of $0.7 million for the nine months ended September 30, 2017, compared to other income, net of $0.4 million for the nine months ended September 30, 2016. Both periods were primarily comprised of income/loss recognition on assets disposed during the period.

Income Taxes. Prior to our initial public offering in October 2016, we were treated as a pass-through entity for federal income tax and most state income tax purposes. For the nine months ended September 30, 2017, we recognized income tax benefit of $7.3 million compared to an income tax expense of $2.7 million for the nine months ended September 30, 2016. The provision for the nine months ended September 30, 2016 was primarily attributable to our subsidiary, Lodging, which provides our remote accommodation services.

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 income (loss) before depreciation, depletion, amortization and accretion, and amortization, impairmentgains on disposal of long-lived assets, acquisition related costs, equitystock based compensation, interest expense, net, other (income) expense,income (expense), net (which is comprised of the (gain) or lossinterest on disposal of long-lived assets), bargain purchase gaintrade accounts receivable and certain legal expenses) and provision (benefit) for income taxes.taxes, further adjusted to add back interest on trade accounts receivable. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industryindustries 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 income (loss)loss 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 measuremeasures 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 also 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.periods (in thousands).


Consolidated
Three Months Ended
March 31,
Reconciliation of Adjusted EBITDA to net income (loss):20232022
Net income (loss)$8,351 $(14,817)
Depreciation, depletion, amortization and accretion expense12,956 17,167 
Gains on disposal of assets, net(361)(196)
Stock based compensation647 241 
Interest expense, net3,289 2,349 
Other income, net(8,624)(9,041)
Provision for income taxes3,333 3,688 
Interest on trade accounts receivable11,112 9,862 
Adjusted EBITDA$30,703 $9,253 


34


 Three Months Ended Nine Months Ended
 September 30, September 30,
Reconciliation of Adjusted EBITDA to net income (loss):2017 2016 2017 2016
Net loss$(800,827) $(2,978,626) $(6,951,621) $(34,746,932)
Depreciation, depletion, accretion and amortization expense27,223,733
 17,921,471
 64,354,383
 54,483,158
Impairment of long-lived assets—
 —
 —
 1,870,885
Acquisition related costs264,091
 —
 2,454,840
 —
Equity based compensation1,028,317
 (18,683) 2,648,210
 (18,683)
Bargain purchase gain—
 —
 (4,011,512) —
Interest expense1,420,067
 1,024,514
 2,928,859
 3,332,901
Other expense (income), net319,252
 253,832
 705,894
 (371,894)
(Benefit) provision for income taxes(1,412,680) 1,055,961
 (7,322,822) 2,739,696
Adjusted EBITDA$28,041,953
 $17,258,469
 $54,806,231
 $27,289,131


Pressure PumpingWell Completion Services
Three Months Ended
March 31,
Reconciliation of Adjusted EBITDA to net income (loss):20232022
Net income (loss)$6,547 $(7,801)
Depreciation and amortization expense4,817 6,444 
Gains on disposal of assets, net— (49)
Stock based compensation291 87 
Interest expense929 371 
Adjusted EBITDA$12,584 $(948)
 Three Months EndedNine Months Ended
 September 30, September 30,
Reconciliation of Adjusted EBITDA to net income (loss):2017 2016 2017 2016
Net income (loss)$6,482,013
 $4,646,485
 $8,922,945
 $(624,730)
Depreciation and amortization expense13,038,962
 9,050,605
 31,823,408
 27,964,092
Impairment of long-lived assets—
 —
 —
 138,587
Acquisition related costs500
 —
 500
 —
Equity based compensation428,398
 —
 1,202,687
 —
Interest expense591,724
 134,017
 1,023,519
 502,781
Other expense, net120,261
 1,262
 126,650
 25,087
Adjusted EBITDA$20,661,858
 $13,832,369
 $43,099,709
 $28,005,817


Infrastructure Services
Three Months Ended
March 31,
Reconciliation of Adjusted EBITDA to net income:20232022
Net income$2,452 $125 
Depreciation and amortization expense3,374 4,314 
Gains on disposal of assets(127)(5)
Stock based compensation230 98 
Interest expense1,845 1,542 
Other income, net(8,808)(9,582)
Provision for income taxes2,847 3,067 
Interest on trade accounts receivable11,112 9,862 
Adjusted EBITDA$12,925 $9,421 




Other Well Services
 Three Months EndedNine Months Ended
 September 30, September 30,
Reconciliation of Adjusted EBITDA to net income (loss):2017 2016 2017 2016
Net (loss) income$(2,148,146) $(2,563,056) $384,107
 $(9,137,921)
Depreciation and amortization expense4,511,622
 1,233,702
 7,939,784
 3,903,924
Impairment of long-lived assets—
 —
 —
 1,384,751
Acquisition related costs65,394
 —
 235,526
 —
Equity based compensation127,930
 (18,683) 265,380
 (18,683)
Interest expense, net94,357
 29,489
 (14,019) 178,584
Other expense (income), net38,186
 1,159
 36,195
 (671,986)
(Benefit) provision for income taxes(1,278,456) 5,929
 (7,778,970) 2,835
Adjusted EBITDA$1,410,887
 $(1,311,460) $1,068,003
 $(4,358,496)

Natural Sand Proppant Services
Three Months Ended
March 31,
Reconciliation of Adjusted EBITDA to net income (loss):20232022
Net income (loss)$2,779 $(1,315)
Depreciation, depletion, amortization and accretion expense1,187 1,795 
Gains on disposal of assets(16)(75)
Stock based compensation77 34 
Interest expense156 162 
Other income, net(2)(4)
Adjusted EBITDA$4,181 $597 

35


 Three Months EndedNine Months Ended
 September 30, September 30,
Reconciliation of Adjusted EBITDA to net income (loss):2017 2016 2017 2016
Net (loss) income$(929,837) $(518,666) $723,370
 $(8,086,996)
Depreciation, depletion, accretion and amortization expense3,034,342
 1,784,689
 6,603,001
 4,734,540
Acquisition related costs166,654
 —
 2,120,733
 —
Equity based compensation271,762
 —
 524,223
 —
Bargain purchase gain—
 —
 (4,011,512) —
Interest expense86,857
 108,744
 572,096
 319,855
Other expense, net97,744
 9,439
 251,520
 82,422
Provision for income taxes23,824
 3,716
 32,326
 3,716
Adjusted EBITDA$2,751,346
 $1,387,922
 $6,815,757
 $(2,946,463)


Contract Land and Directional Drilling Services
Three Months Ended
March 31,
Reconciliation of Adjusted EBITDA to net loss:20232022
Net loss$(2,046)$(1,753)
Depreciation expense1,367 1,680 
Stock based compensation11 5 
Interest expense160 104 
Adjusted EBITDA$(508)$36 
 Three Months EndedNine Months Ended
 September 30, September 30,
Reconciliation of Adjusted EBITDA to net income (loss):2017 2016 2017 2016
Net loss$(4,972,767) $(7,386,386) $(18,289,001) $(24,079,359)
Depreciation and amortization expense5,035,990
 5,297,694
 14,978,300
 16,243,626
Impairment of long-lived assets—
 —
 —
 347,547
Acquisition related costs(16,328) —
 8,187
 —
Equity based compensation137,637
 —
 429,901
 —
Interest expense570,364
 718,706
 1,227,422
 2,272,913
Other expense, net38,324
 237,211
 262,560
 179,639
Adjusted EBITDA$793,220
 $(1,132,775) $(1,382,631) $(5,035,634)




Other Services(a)
Three Months Ended
March 31,
Reconciliation of Adjusted EBITDA to net loss:20232022
Net loss$(1,381)$(3,999)
Depreciation, amortization and accretion expense2,211 2,934 
Gains on disposal of assets, net(218)(67)
Stock based compensation38 17 
Interest expense, net199 170 
Other expense, net186 545 
Provision for income taxes486 621 
Adjusted EBITDA$1,521 $221 

a.    Includes results for our aviation, equipment rentals, remote accommodations and equipment manufacturing and corporate related activities. Our corporate related activities do not generate revenue.





Other Energy Services
 Three Months EndedNine Months Ended
 September 30, September 30,
Reconciliation of Adjusted EBITDA to net income (loss):2017 2016 2017 2016
Net income$767,910
 $2,842,997
 $1,306,958
 $7,182,074
Depreciation and amortization expense1,602,817
 554,781
 3,009,890
 1,636,976
Impairment of long-lived assets—
 —
 —
 —
Acquisition related costs47,871
 —
 89,894
 —
Equity based compensation62,590
 —
 226,019
 —
Interest expense76,765
 33,558
 119,841
 58,768
Other expense, net24,737
 4,761
 28,969
 12,944
(Benefit) provision for income taxes(158,048) 1,046,316
 423,822
 2,733,145
Adjusted EBITDA$2,424,642
 $4,482,413
 $5,205,393
 $11,623,907


Liquidity and Capital Resources


We require capital to fund ongoing operations including maintenance expenditures on our existing fleet andof equipment, organic growth initiatives, investments and acquisitions. Since November 2014, ouracquisitions, and the litigation settlement obligations described in Note 18 “Commitments and Contingencies” of the Notes to the Unaudited Condensed Consolidated Financial Statements and under “Capital Requirements and Sources of Liquidity” below. Our primary sources of liquidity have been cash on hand, borrowings under our revolving credit facility and cash flows from operations. Our primary useuses of capital hashave been for investing in property and equipment used to provide our services and to acquire complimentarycomplementary businesses.


Liquidity

    The following table summarizes our liquidity as of the dates indicated (in thousands):
March 31,December 31,
20232022
Cash and cash equivalents$11,727 $17,282 
Revolving credit facility availability118,399 119,756 
Less current and long-term debt(84,614)(83,520)
Less available borrowing capacity reserve(10,000)(10,000)
Less letter of credit facilities (insurance programs)(2,800)(2,800)
Less letter of credit facilities (environmental remediation)(3,569)(3,694)
Net working capital (less cash and current portion of long-term debt)(a)
343,459 325,719 
Total$372,602 $362,743 
a.Net working capital (less cash and current portion of long-term debt) is a non-GAAP measure and, as of March 31, 2023, is calculated by subtracting total current liabilities of $237.7 million and cash and cash equivalents of $11.7 million from total current assets of $508.3 million,
36


further adjusted to add current portion of long-term debt of $84.6 million. As of September 30, 2017,December 31, 2022, net working capital (less cash and current portion of long-term debt) is calculated by subtracting total current liabilities of $237.2 million and cash and cash equivalents of $17.3 million from total current assets of $496.7 million, further adjusted to add current portion of long-term debt of $83.5 million. Amounts include receivables due from PREPA of $390.2 million at March 31, 2023 and $379.0 million at December 31, 2022 and corresponding liabilities of $50.5 million at March 31, 2023 and $47.6 million at December 31, 2022.

    As of April 26, 2023, we had an aggregatecash on hand of $94.0$9.5 million inand outstanding borrowings outstanding under our revolving credit facility of $76.0 million, leaving an aggregate of $69.8$26.0 million of available borrowing capacity under this facility, which is netafter giving effect to $6.4 million of outstanding letters of credit and the requirement to maintain a $10.0 million reserve out of $5.5 million.the available borrowing capacity.

The following table summarizesContinued prolonged volatility in the capital, financial and/or credit markets due to the COVID-19 pandemic, inflationary pressures or otherwise and volatility in commodity prices and/or adverse macroeconomic conditions may further limit our liquidity foraccess 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 periods indicated:
 September 30, December 31,
 2017 2016
Cash and cash equivalents$14,278,328
 $29,238,618
Revolving credit facilities availability169,233,484
 164,354,373
Less long-term debt(94,000,000) —
Less letter of credit facilities (rail car commitments)(454,560) (454,560)
Less letter of credit facilities (insurance programs)(1,636,000) (1,636,000)
Less letter of credit facilities (environmental remediation)(3,363,627) (1,375,342)
Net working capital (less cash)33,519,145
 30,453,429
Total$117,576,770
 $220,580,518
At November 7, 2017, we had an aggregate of $110.2 million in borrowings outstandingfinancial covenants under our amended revolving credit facility, leavingor obtain a waiver of forecasted or actual non-compliance with any such financial covenants from our lenders, and an aggregateevent of $53.2 milliondefault 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 borrowing capacity under thiscash to repay our outstanding borrowings and may foreclose on substantially all of our assets. Further, we may not be able to extend, repay or refinance our existing revolving credit facility, which is net of letters of credit of $5.5 million.currently scheduled to mature on October 19, 2023, at or prior to maturity on the terms acceptable to us or at all.


Liquidity and Cash Flows
    
The following table sets forth our cash flows at the dates indicated:indicated (in thousands):
Three Months Ended
March 31,
20232022
Net cash provided by (used in) operating activities$3,240 $(2,381)
Net cash used in investing activities(5,706)(144)
Net cash (used in) provided by financing activities(3,083)736 
Effect of foreign exchange rate on cash(6)8 
Net change in cash$(5,555)$(1,781)
 Three Months Ended Nine Months Ended
 September 30, September 30,
 20172016 20172016
Net cash provided by operating activities$16,631,835
$14,101,540
 $40,636,834
$23,140,617
Net cash used in investing activities(38,134,271)(1,699,652) (140,827,687)(708,342)
Net cash provided by (used in) financing activities27,222,791
(10,300,000) 85,148,937
(23,000,000)
Effect of foreign exchange rate on cash8,683
128,280
 81,626
186,967
Net change in cash$5,729,038
$2,230,168
 $(14,960,290)$(380,758)


Operating Activities


Net cash provided by operating activities was $40.6$3.2 million for the ninethree months ended September 30, 2017,March 31, 2023, compared to $23.1cash used in operating activities of $2.4 million for the ninethree months ended September 30, 2016.March 31, 2022. The increase in operating cash flows was primarily attributable to thean increase in revenue.utilization and pricing for our well completions division.

Net cash provided by operating activities was $16.6 million for the three months ended September 30, 2017, compared to $14.1 million for the three months ended September 30, 2016. The increase in operating cash flows was primarily attributable to timing of receivable collections with related parties.






Investing Activities
    
Net cash used in investing activities was $140.8 million for the nine months ended September 30, 2017, compared to $0.7 million for the nine months ended September 30, 2016. Net cash used in investing activities was $38.1$5.7 million for the three months ended September 30, 2017,March 31, 2023, compared to $1.7$0.1 million for the three months ended September 30, 2016. With the exception of the businesses acquired, substantially all cashMarch 31, 2022. Cash used in investing activities was used to purchaseis primarily comprised of purchases of property and equipment that is utilized to provide our services.and proceeds from the disposal of property and equipment.


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The following table summarizes our capital expenditures by operating division for the periods indicated:indicated (in thousands):
Three Months Ended
March 31,
20232022
Well completion services(a)
$5,772 $801 
Infrastructure services(b)
203 398 
Drilling services(c)
— 2 
Other(d)
— 60 
Eliminations61 (79)
Total capital expenditures$6,036 $1,182 
a.     Capital expenditures primarily for upgrades to our pressure pumping fleet to reduce greenhouse gas emissions and maintenance for the three months ended March 31, 2023 and 2022.
 Three Months Ended Nine Months Ended
 September 30, September 30,
 2017 2016 2017 2016
Pressure pumping services (a)$19,580,804
 $335,312
 $72,982,713
 $1,262,854
Well services (b)777,399
 156,783
 1,121,873
 404,612
Natural sand proppant production (c)4,927,935
 359,656
 7,897,818
 522,267
Contract and directional drilling services (d)2,356,885
 1,069,381
 8,257,702
 1,492,476
Other energy services (e)8,054,748
 12,706
 12,013,384
 425,838
Net change in cash$35,697,771
 $1,933,838
 $102,273,490
 $4,108,047
b.     Capital expenditures primarily for tooling and other equipment for the three months ended March 31, 2023 and 2022.
(a).Capital expenditures primarily for pressure pumping equipment for the three and nine months ended September 30, 2017 and 2016.
(b).Capital expenditures primarily for equipment upgrades for the three and nine months ended September 30, 2017 and 2016.
(c).Capital expenditures included a conveyor and plant additions for the three and nine months ended September 30, 2017 and 2016.
(d).Capital expenditures primarily for upgrades to our rig fleet for the three and nine months ended September 30, 2017 and 2016.
(e).Capital expenditures primarily for an intersection upgrade for the nine months ended September 30, 2016. Capital expenditures for the nine months ended September 30, 2017 represent property and equipment for energy infrastructure services.

c.    Capital expenditures primarily for maintenance for the three months ended March 31, 2022.
d.    Capital expenditures primarily for equipment for our rental business for the three months ended March 31, 2022.

Financing Activities


    Net cash used in financing activities was $3.1 million for the three months ended March 31, 2023, compared to net cash provided by financing activities of $0.7 million for the three months ended March 31, 2022. Net cash used in financing activities for the three months ended March 31, 2023 was primarily attributable to principal payment on financing leases and equipment financing notes of $2.0 million, principal payments on sale leaseback arrangements of $1.2 million and share repurchases used to satisfy tax withholding obligations of $0.9 million in connection with the vesting and settlement of certain executive restricted stock unit awards. These were partially offset by net borrowings under our revolving credit facility of $1.1 million during the three months ended March 31, 2023. Net cash provided by financing activities was $85.1 million for the nine months ended September 30, 2017, compared to cash used in financing activities of $23.0 million for the nine months ended September 30, 2016. Net cash provided by financing activities was $27.2 million for the three months ended September 30, 2017, comparedMarch 31, 2022 was primarily attributable to cash used in financing activities of $10.3 million for the three months ended September 30, 2016. For the nine months ended September 30, 2017, cash provided by financing activities were used to fund the Chieftain, 5 Star and Higher Power Electrical, LLC acquisitions and to purchase property and equipment. For the nine months ended September 30, 2016, substantially all cash used in financing activities was used to pay down net borrowings under our revolving credit facility.facility of $2.2 million, partially offset by principal payments on financing leases and equipment financing notes totaling $1.5 million.


Effect of Foreign Exchange Rate on Cash


The effect of foreign exchange rate on cash was $0.1 million and $0.2 milliona nominal amount for the nine months ended September 30, 2017 and 2016, respectively. The effecteach of foreign rate on cash was $8.7 thousand for the three months ended September 30, 2017, compared to $0.1 million for the three months ended September 30, 2016.March 31, 2023 and 2022. The year-over-year effectchange 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 $47.8$270.6 million and $59.7$259.5 million at September 30, 2017March 31, 2023 and December 31, 2016, respectively.2022, respectively, including receivables due from PREPA of $390.2 million at March 31, 2023 and $379.0 million at December 31, 2022 and corresponding liabilities of $50.5 million at March 31, 2023 and $47.6 million at December 31, 2022. Our cash balances totaled $14.3were $11.7 million and $29.2$17.3 million at September 30, 2017March 31, 2023 and December 31, 2016,2022, respectively.


Our Revolving Credit Facility


On November 25, 2014,October 19, 2018, we and certain of our direct and indirect subsidiaries, as borrowers, entered into a $170.0 millionan amended and restated revolving credit and security agreementfacility, as subsequently amended, with PNC Capital Markets LLC, as lead arranger,the lenders party thereto and PNC Bank, National Association, as a lender and as administrative agent for the administrative and collateral agent, and the lenders from time-to-time party thereto. Our revolving credit facility, as amended in connection with the IPO, matures on November 25, 2019. Borrowings under our revolving credit facility are secured by our and our subsidiaries’ assets. The maximum

availability for futurelenders. At March 31, 2023, we had outstanding borrowings under our revolving credit facility isof $84.6 million and $17.4 million of available borrowing capacity under this facility, after giving effect to $6.4 million of outstanding letters of credit and the requirement to maintain a $10.0 million reserve out of the available borrowing capacity.

On February 28, 2022, we entered into a fourth amendment to the revolving credit facility (the “Fourth Amendment”) to, in relevant part, (i) amend our financial covenants as outlined below, (ii) provide for a conditional increase of the applicable interest margin, (iii) permit certain sale-leaseback transactions, and (iv) provide for a reduction in the maximum revolving advance amount in an amount equal to 50% of the PREPA claims proceeds, subject to a borrowing base calculation prepared monthly.

Effective as of July 12, 2017, our revolving credit facility was amended, providing us with greater flexibility for permitted acquisitions and permitted indebtedness, increasing the maximum amount creditedfloor equal to the borrowing base for sand inventorysum of eligible billed and for in-transit inventory and increasing certain default thresholds from $5 million to $15 million.unbilled accounts receivables.
Interest is payable monthly at a base rate set by the lead institution’s commercial lending group plus an applicable margin. Additionally, at our request, outstanding balances are permitted to be converted to LIBOR rate plus applicable margin tranches at set increments of $500,000.
The LIBOR rate option allows us to select interest periods from one, two, three or six months. The applicable margin for either the base rate or the LIBOR rate option can vary from 1.5% to 3.0%, based upon a calculation of the excess availability of the line as a percentage of the maximum credit limit.

At September 30, 2017, $94.0 million of the total outstanding balance of $94.0 million under the facility was in a one month LIBOR rate option tranche with an interest rate of 3.99%. As of September 30, 2017, we had availability of $69.8 millionfinancial covenants under our revolving credit facility which is net of letters of credit of $5.5 million.were amended as follows:

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Our revolving credit facility contains various customary affirmative

•the leverage ratio was eliminated;
•the fixed charge coverage ratio was reduced to 0.85 to 1.0 for the six months ended June 30, 2022 and restrictive covenants. Amongincreases to 1.1 to 1.0 for the covenants are two financial covenants, including periods thereafter;
•a minimum adjusted EBITDA covenant of $4.7 million, excluding interest coverage ratio (3.0on the accounts receivable from PREPA, for the five months ending May 31, 2022 was added; and
•the minimum excess availability covenant was reduced to 1.0), and a maximum leverage ratio (4.0$7.5 million through March 31, 2022, after which the minimum excess availability covenant increased to 1.0), and minimum availability ($10.0 million). As of September 30, 2017 and December 31, 2016, we$10.0 million.

We were in compliance with these covenants.the applicable financial covenants under our amended revolving credit facility in effect as of March 31, 2023. For additional information regarding our revolving credit facility, see Note 9. Debt to our unaudited condensed consolidated financial statements included elsewhere in this report.


As of April 26, 2023, our outstanding borrowings under our amended revolving credit facility were $76.0 million, leaving an aggregate of $26.0 million of available borrowing capacity, after giving effect to $6.4 million of outstanding letters of credit and the requirement to maintain a $10.0 million reserve out of the available borrowing capacity. If we fail to comply with the financial covenants contemplated by our amended revolving credit facility, or obtain a waiver of forecasted or actual non-compliance with any such financial covenants from our lenders, and an event of default occurs and remains uncured, it will have a material adverse effect on our business, financial condition, liquidity and results of operations. In addition, our revolving credit facility is currently scheduled to mature on October 19, 2023. Although we continue to explore various strategic alternatives to extend, refinance, or repay our revolving credit facility on or before the scheduled maturity date, which may include proceeds from any equity or debt transactions, there is no guarantee that such extension, refinancing or repayment will be secured. Additionally, any such extended or new credit facility could have terms that are less favorable to us than the terms of our existing revolving credit facility, which may significantly increase our cost of capital and may have a material adverse effect on our liquidity and financial condition. For additional information regarding our amended revolving credit facility and financial covenants thereunder, 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. On June 1, 2022, we entered into another agreement with FNC whereby we sold additional assets from our infrastructure segment to FNC for aggregate proceeds of $4.6 million and entered into a 42-month lease agreement whereby we lease back the assets at a monthly rental rate of $0.1 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.

Equipment Financing Note

In December 2022, we entered into a 42 month financing arrangement with FNC for the purchase of seven new pressure pumping units for an aggregate value of $9.7 million. Under this arrangement, we have agreed to make monthly principal and interest payments totaling $0.3 million over the term of the agreement. This note is secured by the seven pressure pumping units and bears interest at an imputed rate of approximately 15.0%.

Capital Requirements and Sources of Liquidity


With commodity prices beginning    As we pursue our business and financial strategy, we regularly consider which capital resources are available to increase in the second half of 2016meet our future financial obligations and then stabilizing within their current range, we have seen an increase in customer demand, particularly in our pressure pumping and natural sand proppant services divisions. Our capital budget for 2017 increased substantially from our 2016 capital budget of approximately $11.3 million. Our expected 2017 full-year capital budget currently includes expenditures of $64.0 million in our pressure pumping services division for the acquisition of 132,500 horsepower of new high pressure hydraulic pumps and related equipment, $8.0 million in our pressure pumping service division for tractors, pneumatic trailers to enhance our last mile solutions, $25.0 million in our sand segment for plant capacity expansion projects, and $33.0 million for rig upgrades and additional equipment for our well services, contract and direction drilling services and other energy services divisions. During the first nine months ended September 30, 2017, we spent approximately $102.3 million on such capital expenditures, including $35.7 million during the third quarter of 2017, and an additional $42.0 million to complete business acquisitions. Due to the anticipated 120-day duration of the initial work to be performed under the contract signed by Cobra to aid in the restoration of the electric utility infrastructure in Puerto Rico, we intend to lease a majority of the equipment required to fulfill the contract. As a result, we do not anticipate a material increase in our announced $143.0 million capital expenditure budget for 2017.

liquidity requirement. We believe that our cash on hand, operating cash flow and available borrowings under our revolving credit facility will be sufficient to fundmeet our short-term and long-term funding requirements, including funding our current operations, for at least the next twelve months. However,planned capital expenditures, debt service obligations and known contingencies.

39


Our liquidity and future cash flows, however, are subject to a number of variables, including receipt of payments from our customers, including PREPA, and our ability to extend, refinance or repay our revolving credit facility at or prior to its scheduled maturity date of October 19, 2023. As of March 31, 2023, PREPA owed Cobra approximately $390.2 million for services performed, including $163.2 million of interest charges. Throughout 2021, we released significant additionaldata that we obtained through Freedom of Information Act requests that affirm 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 our 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, which may adversely impact our liquidity.

We have revised our 2023 capital expenditure estimate down to approximately $24.0 million from the previously planned 2023 capital budget of $64 million primarily due to lower commodity prices, softer demand for oilfield services and volatility in market conditions. During the first quarter of 2023, pricing for crude oil and natural gas declined from levels seen in 2022, which may slow down completion activities for our customers and, as a result, reduce demand for our oilfield services. Capital expenditures will ultimately be dependent upon industry conditions and our financial results.These capital expenditures could be requiredinclude $21 million for our well completions segment, $1 million for our infrastructure segment, $1 million for our natural sand proppant segment, and $1 million for our other businesses. During the three months ended March 31, 2023, our capital expenditures totaled $6.0 million.

Also, as noted above in this report, in response to conductmarket conditions we have (i) temporarily shut down certain of our oilfield service offerings, including coil tubing, pressure control, flowback, crude oil hauling, cementing, acidizing and land drilling services, (ii) idled certain facilities, including our sand processing plant in Pierce County, Wisconsin and (iii) reduced our workforce across all of our operations. There can be no assurance thatWe continue to monitor market conditions to determine if and when we will recommence these services and operations and other capital resourcesincrease our workforce. Any such recommencement and expansion will provide cashfurther increase our liquidity requirements in sufficient amounts to maintain planned or future levelsadvance of capital expenditures. Further,revenue generation.

    In addition, while we continue to pursue our previously announced acquisition strategy to enhance our portfolio of products and services, market positioning and/or geographic presence. We regularly evaluate acquisition opportunities, and the number of opportunities coming to our attention has increased substantially since the IPO. However, we do not have a specific acquisition budget for 2017 since2023. We intend to continue to evaluate acquisition opportunities, including those in the timing and size of acquisitions cannot be accurately forecasted.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 additional 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 thatany of the above or other reasons, we may do so through borrowings under oura revolving credit facility, joint venture partnerships, sale-leaseback transactions, asset sales, offerings of debt or equity securities or other means. WeAlthough we expect that our sources of capital will be adequate to fund our short-term and long-term liquidity requirements, 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, we may not be ableour ability to conduct operations, make capital expenditures, satisfy debt services obligations, pay litigation settlement obligations, fund contingencies and/or complete acquisitions that may be favorable to us or finance the capital expenditures necessary to conduct our operations.


Off-Balance Sheet Arrangements
Lease Obligations

We lease real estate, rail cars and other equipment under long-term operating leases with varying terms and expiration dates through 2025.

Minimum Purchase Commitments

Wewill be impaired, which would have entered into agreements with sand suppliers that contain minimum purchase obligations. Our failure to purchase the minimum tonnage specified would require us to pay shortfall fees. However, the minimum quantities set forth in the agreements are not in excess of our current expected future requirements.

Capital Spend Commitments

We have entered into agreements with suppliers to acquire capital equipment. These commitments are included in our 2017 capital budget discussed under the heading "Capital Requirements and Sources of Liquidity."

Aggregate future minimum lease payments under these agreements in effect at September 30, 2017 are as follows:
Year ended December 31: Operating Leases Capital Spend Commitments Minimum Purchase Commitments
Remainder of 2017 $3,377,429
 $26,847,278
 $3,556,655
2018 13,047,020
 —
 10,866,000
2019 10,533,906
 —
 10,866,000
2020 8,085,194
 —
 —
2021 5,744,808
 —
 —
Thereafter 6,189,124
 —
 —
  $46,977,481
 $26,847,278
 $25,288,655

Other Commitments

Subsequent to September 30, 2017, we entered into railcar lease agreements with aggregate commitments of $2.2 million.

Subsequent to September 30, 2017, we entered into a lease agreement for capital equipment with aggregate commitments of $3.4 million.

Subsequent to September 30, 2017, we entered into an agreement to purchase sand from an unrelated third party seller with aggregate commitments of $2.2 million.

On October 19, 2017, Cobra entered into a contract to aid in the restoration of utility infrastructure on the island of Puerto Rico. The contract provides for payments of up to $200.0 million, including an initial payment of $15.0 million at the time of signing. As of November 7, 2017, Cobra had entered into $32.7 million of commitments related to this contract and made prepayments and deposits of $12.6 million with respect to these commitments.


New Accounting Pronouncements
In July 2015, the FASB issued ASU No. 2015-11, “Inventory (Topic 330): Simplifying the Measurement of Inventory,” which changes inventory measured using any method other than last-in, first-out (LIFO) or the retail inventory method (for example, inventory measured using first-in, first-out (FIFO) or average cost) at the lower of cost and net realizable value. ASU 2015-11 is effective for annual and interim reporting periods beginning after December 15, 2016, with early adoption permitted. On January 1, 2017, we adopted the ASU and it did not impact our condensed consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers.” ASU 2014-09 supersedes existing revenue recognition requirements in GAAP and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. Additionally, it requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. The ASU was effective for annual and interim reporting periods beginning after December 15, 2016, using either a full or a modified retrospective application approach; however, in July 2015 the FASB decided to defer the effective date by one year (until 2018) by issuing ASU No. 2015-14, "Revenue From Contracts with Customers: Deferral of the Effective Date." We expect to adopt this new revenue guidance in the first quarter of 2018. Our review has indicated that the pressure pumping services and natural sand proppant segments contain contracts which could lead to changes in the timing of revenue recognition. Although we have not completed our review, we have made initial assessments of the impact on revenue and expenses. Based on these assessments, we currently do not expect a material impact to theadverse effect on our business, financial condition, results of operations financial position and cash flowsas a result of this guidance. We expect to complete our review of all remaining customer contracts and will make a final assessment in the fourth quarter of 2017. Our services are primarily short-term in nature, and we do not expect that the new revenue recognition standard will have a material impact on our financial statements upon adoption. We will adopt the new standard utilizing the modified retrospective method that will result in a cumulative effect adjustment as of January 1, 2018.flows.


In February 2016, the FASB issued ASU No, 2016-2 “Leases” amending the current accounting for leases. Under the new provisions, all lessees will report a right-of-use asset and a liability for the obligation to make payments for all leases with the exception of those leases with a term of 12 months or less.  All other leases will fall into one of two categories: (i) a financing lease or (ii) an operating lease. Lessor accounting remains substantially unchanged with the exception that no leases entered into after the effective date will be classified as leveraged leases. For sale leaseback transactions, a sale will only be recognized if the criteria in the new revenue recognition standard are met. ASU 2016-2 is effective for fiscal years beginning after December 15, 2018, and interim periods within that fiscal year. Early adoption is permitted. Since a portion of our revenue may be subject to this new leasing guidance, we are evaluating the possibility of adopting this updated leasing guidance at the same time we adopt the new revenue standard discussed above, utilizing the retrospective method of adoption. This new leasing guidance will also impact us in situations where we are the lessee, and in certain circumstances we will have a right-of-use asset and lease liability on our consolidated financial statements. We are currently evaluating the effect the new guidance will have on our consolidated financial statements and results of operations.







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Item 3. Quantitative and Qualitative Disclosures About Market Risk


The demand, pricing and terms for oilour products and gas services provided by us 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;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 offor, oil and natural gas;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; availablereserves 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 amongin 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 dollars per barrel for the first time in history due to factors including significantly reduced demand and a shortage of storage facilities. In 2021, U.S. oil production stabilized as commodity prices increased and demand for crude oil rebounded, many exploration and production companies set their operating budgets based on the prevailing prices for oil and natural gas producers.at the time. Despite improvement in the U.S. and global economic activity, easing of the COVID-19 pandemic and related restrictions, rising energy use and improved commodity prices, the budgets for the publicly traded exploration and production companies remained relatively flat throughout 2021, with any excess cash flows used for debt repayment and shareholder returns, rather than to increase production. We saw improvements in the oilfield services industry and in both pricing and utilization of our well completion and drilling services throughout 2022. During the first quarter of 2023, pricing for crude oil and natural gas declined from levels seen in 2022, which may slow down completion activities for our customers and, as a result, reduce demand for our well completion services. Further, the ongoing war and related humanitarian crisis in Ukraine could continue to have an adverse effect on the global supply chain and volatility of commodity prices.


The levelAlthough the levels of activity in the U.S. oil and natural gas exploration and production, industry is volatile. Expected trends in oilenergy infrastructure and natural gas production activities may notsand proppant industries improved throughout 2022, they have historically been and continue and demandto be volatile. We are unable to predict the ultimate impact of the COVID-19 pandemic, the volatility in commodity prices, any changes in the near-term or long-term outlook for our services may not reflect the level of activity in the industry. Any prolonged substantial reduction in oil and natural gas prices would likely affect oil and natural gas production levels and therefore affect demand for our services. A material decline in oil and natural gas pricesindustries or U.S. activity levels could have a material adverse effectoverall macroeconomic conditions on our business, financial condition, results of operations, cash flows and cash flows. Recently, demand for our services has been strong and we are continuing our past practice of committing our equipment on a short-term or day-to-day basis.stock price.


Interest Rate Risk


We had a cash and cash equivalents balance of $14.3$11.7 million at September 30, 2017.March 31, 2023. We do not enter into investments for trading or speculative purposes. We do not believe that we have any material exposure

    Interest under our credit facility is payable at a base rate, which can fluctuate based on multiple facts, including rates set by the U.S. Federal Reserve (which increased its benchmark interest rate by an aggregate of 4.75 percentage points throughout 2022 and 2023, and may continue to changes in the fair value of these investments as a result of changes in interest rates. Declines inincrease interest rates however, will reduce future income.

in an effort to counter the persistent inflation), the supply and demand for credit and general economic conditions, plus an applicable margin. The applicable margin is currently set at 4.0%, which can be reduced to 3.5% under certain circumstances specified in our credit facility. At September 30, 2017,March 31, 2023, we had $94.0outstanding borrowings under our revolving credit facility of $84.6 million outstanding under this facility with a weighted average interest rate of 3.99%11.5%. A 1% increase or decrease in the interest rate at that time would have increasedincrease or decreaseddecrease our interest expense by approximately $0.9$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 energy services segment,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, 2017,March 31, 2023, we had $3.0$2.4 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 $0.2$0.1 million as of September 30, 2017.March 31, 2023. Conversely, a corresponding decrease in
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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 COVID-19 pandemic, the volatility in commodity prices, the reduction in demand for our services and challenging macroeconomic conditions.

Specifically, we had receivables due from PREPA totaling $390.2 million, including $163.2 million of interest charges, as of March 31, 2023. PREPA is currently subject to bankruptcy proceedings 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 FEMA or other sources. 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 infrastructure services in the northeastern, southwestern, midwestern and western portions of the United States. We provide well completion and productiondrilling services primarily in the Utica, Permian Basin, Eagle Ford, Marcellus, SCOOP, STACK, Granite Wash, Cana Woodford and Cleveland sand resource plays located in the continental U.S. We also 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 resource playsour customers in Ohio, Texas, Oklahoma, Wisconsin, Minnesota,Kentucky, Colorado, California, Indiana and Alberta, Canada. For the nine months ended September 30, 2017 and 2016, we generated approximately 81% and 85%, respectively,A portion of our revenue from our operationsrevenues are generated in Ohio, Wisconsin, Minnesota, 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.



Inflation

    Although the impact of inflation has been insignificant on our operations in prior years, inflation in the U.S. has been at some of the highest levels in over 40 years, creating inflationary pressure on the cost of services, equipment and other goods in our industries and other sectors and contributing to labor and materials shortages across the supply-chain. Throughout 2022 and early 2023, the Federal Reserve increased its benchmark interest rates by an aggregate of 4.75 percentage points, and may continue increasing benchmark interest rates in the future. If the efforts to control inflation are not successful and inflationary pressures persist, our business, results of operations and financial condition may be adversely affected.


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 d15d-15(e) 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, 2017,March 31, 2023, 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
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Executive Officer and Chief Financial Officer have concluded that as of September 30, 2017,March 31, 2023, 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, 2017March 31, 2023 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION
Item 1. Legal Proceedings

We are routinely involved in state and local tax audits. During 2015, the State of Ohio assessed taxes on the purchase of equipment we believe is exempt under state law. We have appealed the assessment and a hearing was scheduled for November 30, 2016. In November 2016, the State of Ohio deferred the hearing until April 2017. While we are not able to predict the outcome of the appeal, this matter is not expected to have a material adverse effect on our financial position or results of operations.


Due to the nature of our business, we are, from time to time, involved in other routine litigation or subject to disputes or claims related to our business activities, including breaches of contractual obligations, workers’ compensation claims, and employment related disputes.disputes, arbitrations, class actions and other litigation. We are also involved, from time to time, in reviews, investigations, subpoenas and other proceedings (both formal and informal) by governmental agencies regarding our business (collectively, “regulatory matters”), which regulatory matters, if determined adversely to us, could subject us to significant fines, penalties, obligations to change our business practices or other requirements resulting in increased expenses, diminished income and damage to our reputation. In the opinion of our management, none of the pending litigation, disputes or claims against us if decided adversely, willis expected to have a material adverse effect on our financial condition, cash flows or results of operations.operations, except as disclosed in Note 18 “Commitments and Contingencies,” of the Notes to Unaudited Condensed Consolidated Financial Statements.


See Part I, Item 1. Note 13 of this Report.

Item 1A. Risk Factors


Security holdersAs of the date of this filing, our Company and potential investors in our securities should carefully consideroperations continue to be subject to the risk factors set forth below andpreviously disclosed in Item 1A. Risk Factors in our Annual Report on Form 10-K (Commission File No. 001-37917) filed with the SEC on February 24, 2017, together with the information set forth in our subsequent Quarterly Reports on Form 10-Q, current reports on Form 8-K and other materials we file with the SEC. 

Other than set forth below, there have been no material changes to the Risk Factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016 or our subsequent quarterly reports on Form 10-Q.

One of our energy services subsidiaries recently entered into2023. For a contract with the Puerto Rico Electric Power Authority, or PREPA, which provides for payments to us of up to $200.0 million.  PREPA is currently subject to pending bankruptcy proceeding.  In the event that PREPA does not have or does not obtain the funds necessary to satisfy its payment obligations to our subsidiary under the contract or terminates the contract prior to the enddiscussion of the contract term,recent trends and uncertainties impacting our financial condition, resultsbusiness, see also “Management’s Discussion and Analysis of operationsFinancial Condition and cash flows could be materiallyResults of Operations—Recent Developments—Overview of Our Services and adversely affected.Industry Conditions”


On October 19, 2017, our energy services subsidiary Cobra Acquisitions LLC, or Cobra, and PREPA entered into an energy master services agreement for repairs to PREPA's electrical grid as a result of Hurricane Maria.  The one-year contract provides for payments of up to $200.0 million, including an initial payment of $15.0 million.  As of November 7, 2017, Cobra had entered into $32.7 million of commitments related to this contract and made prepayments and deposits of $12.6 million with respect to these commitments.  PREPA is currently subject to bankruptcy proceedings 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 contract will be largely dependent upon funding from the Federal Emergency Management Agency, or FEMA, or other sources.  PREPA's contracting practices in connection with restoration and repair of PREPA's electrical grid in Puerto Rico, and the terms of certain of those contracts, have been subject to critical comment and are the subject of review and hearings by U.S. federal and Puerto Rican governmental entities. Recently, a contract for restoration and repair services entered into by PREPA with an unrelated third party was terminated by PREPA.   In the event that PREPA does not have or does not obtain the funds necessary to satisfy its obligations to Cobra under the contract or terminates the contract prior to the end of the contract term, our financial condition, results of operations and cash flows could be materially and adversely affected.


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


On June 5, 2017, we issued an aggregateUnregistered Sales of 7.0 millionEquity Securities

None.

Issuer Repurchases of Equity Securities

Our common stock repurchase activity for the three months ended March 31, 2023 was as follows:

Period
Total number of shares repurchased(a)
Average price paid per shareTotal number of shares purchased as part of publicly announced plans or programs
January— $— — 
February— $— — 
March165,595 $5.55 — 
Total165,595 $5.55 — 

a.Represents 165,595 shares of our common stock repurchased from the Company’s executive officers in order to the contributors under the Contribution Agreements as consideration for all outstanding membership interests in Sturgeon, Stingray Energy and Stingray Cementing acquired. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations —— Second Quarter 2017 Highlights.” These shares of our common stock were issued in reliancesatisfy tax withholding requirements upon the exemption from the registration requirementsvesting and settlement of the Securities Act provided by Section 4(2)certain of the Securities Act as sales by an issuer not involving any public offeringtheir restricted stock unit awards. Such shares are cancelled and retired immediately upon repurchase.


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.




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Item 5. Other Information


Not applicable.

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MAMMOTH ENERGY SERVICES, INC.





Item 6. Exhibits


The following exhibits are filed as a part of this report:
Incorporated By Reference
Exhibit NumberExhibit DescriptionFormCommission File No.Filing DateExhibit No.Filed HerewithFurnished Herewith
3.1
8-K001-3791711/15/20163.1
3.2
8-K001-3791711/15/20163.2
3.3
 8-K001-379176/9/20203.1
4.1
S-1/A333-21350410/3/20164.1
4.2
8-K001-3791711/15/20164.1
31.1
X
31.2
X
32.1
X
32.2
X
95.1
X
101.INSXBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.X
101.SCHXBRL Taxonomy Extension Schema Document.X
101.CALXBRL Taxonomy Extension Calculation Linkbase Document.X
101.DEFXBRL Taxonomy Extension Definition Linkbase Document.X
101.LABXBRL Taxonomy Extension Labels Linkbase Document.X
101.PREXBRL Taxonomy Extension Presentation Linkbase Document.X
104Cover 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.X




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    Incorporated By Reference   
Exhibit Number Exhibit Description Form Commission File No. Filing Date Exhibit No. Filed HerewithFurnished Herewith
2.1# Amended and Restated Contribution Agreement by and among MEH Sub LLC, Gulfport Energy Corporation, Rhino Exploration LLC, Mammoth Energy Partners LLC and Mammoth Energy Services, Inc. dated as of May 12, 2017 DEF
14C		 001-37917 5/15/2017 A-1   
2.2# Amended and Restated Contribution Agreement by and among MEH Sub LLC, Gulfport Energy Corporation, Mammoth Energy Partners LLC and Mammoth Energy Services, Inc. dated as of May 12, 2017 DEF
14C		 001-37917 5/15/2017 A-2   
2.3# Amended and Restated Contribution Agreement by and among MEH Sub LLC, Gulfport Energy Corporation, Mammoth Energy Partners LLC and Mammoth Energy Services, Inc. dated as of May 12, 2017 DEF
14C		 001-37917 5/15/2017 A-3   
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   
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   
4.3 Investor Rights Agreement, dated October 12, 2016, by and between the Company and Gulfport Energy Corporation 8-K 001-37917 11/15/2016 4.2   
4.4 Registration Rights Agreement, dated October 12, 2016, by and between the Company and Rhino Exploration LLC 8-K 001-37917 11/15/2016 4.3   
10.1 Second Amendment to Revolving Credit and Security Agreement, dated as of July 12, 2017 among Mammoth Energy Services, Inc. and its subsidiaries.         X 
10.2
 Emergency Master Service Agreement for PREPA’s Electrical Grid Repairs-Hurricane Maria, executed on October 19, 2017, by the Puerto Rico Electric Power Authority (PREPA) and Cobra Acquisitions LLC.         X 
10.3
 Amendment No. 1 to Emergency Master Service Agreement for PREPA’s Electrical Grid Repairs-Hurricane Maria, executed on November 1, 2017, by the Puerto Rico Electric Power Authority (PREPA) and Cobra Acquisitions LLC.         X 
31.1
 Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.         X 
31.2
 Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.         X 
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.         X 
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.         X 
95.1
 Mine Safety Disclosure Exhibit         X 
101.1 Interactive data files pursuant to Rule 405 of Regulation S-T.           

#The schedules (or similar attachments) referenced in this agreement have been omitted in accordance with Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule (or similar attachment) will be furnished supplementally to the Securities and Exchange Commission.


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:April 28, 2023By:/s/ Arty Straehla
Arty Straehla
Chief Executive Officer
Date:April 28, 2023By:MAMMOTH ENERGY SERVICES, INC.
Date:November 13, 2017By:/s/ Arty Straehla
Arty Straehla
Chief Executive Officer
Date:November 13, 2017By:/s/ Mark Layton
Mark Layton
Chief Financial Officer



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