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 JUNE 30, ~~2017~~2018



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

FOR THE TRANSITION PERIOD FROM TO

Commission File No. 001-37917

Mammoth Energy Services, Inc.

(Exact name of registrant as specified in its charter)




Delaware		32-0498321
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

14201 Caliber Drive Suite 300 Oklahoma City, Oklahoma		73134
(Address of principal executive offices)		(Zip Code)

(405) 608-6007

(Registrant’s telephone number, including area code)

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, accelerated filer, non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.




Large accelerated filer	o	Accelerated filer	oý

Non-accelerated filer	o	Smaller reporting company	o

		Emerging growth company	ý

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 August ~~2, 2017,~~3, 2018, there were ~~44,502,223~~44,755,678 shares of common stock, $0.01 par value, outstanding.

MAMMOTH ENERGY SERVICES, INC.

TABLE OF CONTENTS





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

PART I. FINANCIAL INFORMATION		1
Item 1.	Condensed Consolidated Financial Statements (Unaudited)	1
	Condensed Consolidated Balance Sheets	1
	Condensed Consolidated Statements of Comprehensive ~~Loss~~Income (Loss)	2
	Condensed Consolidated Statements of Changes in Equity	3
	Condensed Consolidated Statements of Cash Flows	4
	Notes to Unaudited Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3231
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4952
Item 4.	Controls and Procedures	5054

PART II. OTHER INFORMATION		5155
Item 1.	Legal Proceedings	5155
Item 1A.	Risk Factors	5155
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	5255
Item 4.	Mine Safety Disclosures	5255
Item 5.	Other Information	5355
Item 6.	Exhibits	5456

SIGNATURES		5557

GLOSSARY OF OIL AND NATURAL GAS AND ELECTRICAL INFRASTRUCTURE TERMS



The following is a glossary of certain oil and natural gas industry terms used in this report:
Acidizing	To pump acid into a wellbore to improve a well's productivity or injectivity.
Blowout	An uncontrolled flow of reservoir fluids into the wellbore, and sometimes catastrophically to the surface. A blowout may consist of salt water, oil, natural gas or a mixture of these. Blowouts can occur in all types of exploration and production operations, not just during drilling operations. If reservoir fluids flow into another formation and do not flow to the surface, the result is called an underground blowout. If the well experiencing a blowout has significant open-hole intervals, it is possible that the well will bridge over (or seal itself with rock fragments from collapsing formations) down-hole and intervention efforts will be averted.
Bottomhole assembly	The lower portion of the drillstring, consisting of (from the bottom up in a vertical well) the bit, bit sub, a mud motor (in certain cases), stabilizers, drill collar, heavy-weight drillpipe, jarring devices (“jars”) and crossovers for various threadforms. The bottomhole assembly must provide force for the bit to break the rock (weight on bit), survive a hostile mechanical environment and provide the driller with directional control of the well. Oftentimes the assembly includes a mud motor, directional drilling and measuring equipment, measurements-while-drilling tools, logging-while-drilling tools and other specialized devices.
Cementing	To prepare and pump cement into place in a wellbore.
Coiled tubing	A long, continuous length of pipe wound on a spool. The pipe is straightened prior to pushing into a wellbore and rewound to coil the pipe back onto the transport and storage spool. Depending on the pipe diameter (1 in. to 4 1/2 in.) and the spool size, coiled tubing can range from 2,000 ft. to 23,000 ft. (610 m to ~~7,010~~6,096 m) or greater length.
Completion	A generic term used to describe the assembly of down-hole tubulars and equipment required to enable safe and efficient production from an oil or gas well. The point at which the completion process begins may depend on the type and design of the well.
Directional drilling	The intentional deviation of a wellbore from the path it would naturally take. This is accomplished through the use of whipstocks, bottomhole assembly (BHA) configurations, instruments to measure the path of the wellbore in three-dimensional space, data links to communicate measurements taken down-hole to the surface, mud motors and special BHA components and drill bits, including rotary steerable systems, and drill bits. The directional driller also exploits drilling parameters such as weight on bit and rotary speed to deflect the bit away from the axis of the existing wellbore. In some cases, such as drilling steeply dipping formations or unpredictable deviation in conventional drilling operations, directional-drilling techniques may be employed to ensure that the hole is drilled vertically. While many techniques can accomplish this, the general concept is simple: point the bit in the direction that one wants to drill. The most common way is through the use of a bend near the bit in a down-hole steerable mud motor. The bend points the bit in a direction different from the axis of the wellbore when the entire drillstring is not rotating. By pumping mud through the mud motor, the bit turns while the drillstring does not rotate, allowing the bit to drill in the direction it points. When a particular wellbore direction is achieved, that direction may be maintained by rotating the entire drillstring (including the bent section) so that the bit does not drill in a single direction off the wellbore axis, but instead sweeps around and its net direction coincides with the existing wellbore. Rotary steerable tools allow steering while rotating, usually with higher rates of penetration and ultimately smoother boreholes.
Down-hole	Pertaining to or in the wellbore (as opposed to being on the surface).
Down-hole motor	A drilling motor located in the drill string above the drilling bit powered by the flow of drilling mud. Down-hole motors are used to increase the speed and efficiency of the drill bit or can be used to steer the bit in directional drilling operations. Drilling motors have become very popular because of horizontal and directional drilling ~~applications.~~applications and the day rates for drilling rigs.
Drilling rig	The machine used to drill a wellbore.
Drillpipe or Drill pipe	Tubular steel conduit fitted with special threaded ends called tool joints. The drillpipe connects the rig surface equipment with the bottomhole assembly and the bit, both to pump drilling fluid to the bit and to be able to raise, lower and rotate the bottomhole assembly and bit.
Drillstring or Drill string	The combination of the drillpipe, the bottomhole assembly and any other tools used to make the drill bit turn at the bottom of the wellbore.
Horizontal drilling	A subset of the more general term “directional drilling,” used where the departure of the wellbore from vertical exceeds about 80 degrees. Note that some horizontal wells are designed such that after reaching true 90-degree horizontal, the wellbore may actually start drilling upward. In such cases, the angle past 90 degrees is continued, as in 95 degrees, rather than reporting it as deviation from vertical, which would then be 85 degrees. Because a horizontal well typically penetrates a greater length of the reservoir, it can offer significant production improvement over a vertical well.
Hydraulic fracturing	A stimulation treatment routinely performed on oil and gas wells in low permeability reservoirs. Specially engineered fluids are pumped at high pressure and rate into the reservoir interval to be treated, causing a vertical fracture to open. The wings of the fracture extend away from the wellbore in opposing directions according to the natural stresses within the formation. Proppant, such as grains of sand of a particular size, is mixed with the treatment fluid to keep the fracture open when the treatment is complete. Hydraulic fracturing creates high-conductivity communication with a large area of formation and bypasses any damage that may exist in the near-wellbore area.
Hydrocarbon	A naturally occurring organic compound comprising hydrogen and carbon. Hydrocarbons can be as simple as methane, but many are highly complex molecules, and can occur as gases, liquids or solids. Petroleum is a complex mixture of hydrocarbons. The most common hydrocarbons are natural gas, oil and coal.



Mesh size	The size of the proppant that is determined by sieving the proppant through screens with uniform openings corresponding to the desired size of the proppant. Each type of proppant comes in various sizes, categorized as mesh sizes, and the various mesh sizes are used in different applications in the oil and natural gas industry. The mesh number system is a measure of the number of equally sized openings per square inch of screen through which the proppant is sieved.
Mud motors	A positive displacement drilling motor that uses hydraulic horsepower of the drilling fluid to drive the drill bit. Mud motors are used extensively in directional drilling operations.
Natural gas liquids	Components of natural gas that are liquid at surface in field facilities or in gas processing plants. Natural gas liquids can be classified according to their vapor pressures as low (condensate), intermediate (natural gasoline) and high (liquefied petroleum gas) vapor pressure.



Nitrogen pumping unit	A high-pressure pump or compressor unit capable of delivering high-purity nitrogen gas for use in oil or gas wells. Two basic types of units are commonly available: a nitrogen converter unit that pumps liquid nitrogen at high pressure through a heat exchanger or converter to deliver high-pressure gas at ambient temperature, and a nitrogen generator unit that compresses and separates air to provide a supply of high pressure nitrogen gas.
Plugging	The process of permanently closing oil and gas wells no longer capable of producing in economic quantities. Plugging work can be performed with a well servicing rig along with wireline and cementing equipment; however, this service is typically provided by companies that specialize in plugging work.
Plug	A down-hole packer assembly used in a well to seal off or isolate a particular formation for testing, acidizing, cementing, etc.; also a type of plug used to seal off a well temporarily while the wellhead is removed.
Pounds per square inch	A unit of pressure. It is the pressure resulting from a one pound force applied to an area of one square inch.
Pressure pumping	Services that include the pumping of liquids under pressure.
Producing formation	An underground rock formation from which oil, natural gas or water is produced. Any porous rock will contain fluids of some sort, and all rocks at considerable distance below the Earth’s surface will initially be under pressure, often related to the hydrostatic column of ground waters above the reservoir. To produce, rocks must also have permeability, or the capacity to permit fluids to flow through them.
Proppant	Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment. In addition to naturally occurring sand grains, man-made or specially engineered proppants, such as resin-coated sand or high-strength ceramic materials like sintered bauxite, may also be used. Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore.
Resource play	Accumulation of hydrocarbons known to exist over a large area.
Shale	A fine-grained, fissile, sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers.
Tight oil	Conventional oil that is found within reservoirs with very low permeability. The oil contained within these reservoir rocks typically will not flow to the wellbore at economic rates without assistance from technologically advanced drilling and completion processes. Commonly, horizontal drilling coupled with multistage fracturing is used to access these difficult to produce reservoirs.
Tight sands	A type of unconventional tight reservoir. Tight reservoirs are those which have low permeability, often quantified as less than 0.1 millidarcies.
Tubulars	A generic term pertaining to any type of oilfield pipe, such as ~~drillpipe,~~drill pipe, drill collars, pup joints, casing, production tubing and pipeline.
Unconventional resource	An umbrella term for oil and natural gas that is produced by means that do not meet the criteria for conventional 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.
Wellbore	The physical conduit from surface into the hydrocarbon reservoir.
Well stimulation	A treatment performed to restore or enhance the productivity of a well. Stimulation treatments fall into two main groups, hydraulic fracturing treatments and matrix treatments. Fracturing treatments are performed above the fracture pressure of the reservoir formation and create a highly conductive flow path between the reservoir and the wellbore. Matrix treatments are performed below the reservoir fracture pressure and generally are designed to restore the natural permeability of the reservoir following damage to the near wellbore area. Stimulation in shale gas reservoirs typically takes the form of hydraulic fracturing treatments.
Wireline	A general term used to describe well-intervention operations conducted using single-strand or multi-strand wire or cable for intervention in oil or gas wells. Although applied inconsistently, the term commonly is used in association with electric logging and cables incorporating electrical conductors.
Workover	The process of performing major maintenance or remedial treatments on an oil or gas well. In many cases, workover implies the removal and replacement of the production tubing string after the well has been killed and a workover rig has been placed on location. Through-tubing workover operations, using coiled tubing, snubbing or slickline equipment, are routinely conducted to complete treatments or well service activities that avoid a full workover where the tubing is removed. This operation saves considerable time and expense.



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

iii

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, or the Exchange Act. In particular, the factors discussed in this report and detailed under Part II, Item 1A. Risk Factors in this report and our Annual Report on Form 10–K for the year ended December 31, ~~2016~~2017 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:

business strategy;

pending or future acquisitions and future capital expenditures;

ability to obtain permits and governmental approvals;

technology;

financial strategy;

future operating results; and

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 Part II, Item 1A. Risk Factors in this report and our Annual Report on Form 10–K for the year ended December 31, 2017 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~~iv

MAMMOTH ENERGY SERVICES, INC.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

MAMMOTH ENERGY SERVICES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (unaudited)


ASSETS	June 30,			December 31,			June 30,			December 31,
							2018			2017
CURRENT ASSETS	2017 (a)			2016 (b)			(in thousands)
Cash and cash equivalents	$	8,549,290		$	29,238,618		$	10,702		$	5,637
Accounts receivable, net	30,414,421			21,169,579			312,850			243,746
Receivables from related parties	45,686,985			27,589,283			30,674			33,788
Inventories	10,316,700			6,124,201			12,717			17,814
Prepaid expenses	3,647,227			4,425,872			13,811			12,552
Other current assets	341,555			391,599			816			886
Total current assets	98,956,178			88,939,152			381,570			314,423

Property, plant and equipment, net	327,080,164			242,119,663			423,315			351,017
Sand reserves	75,892,824			55,367,295			73,759			74,769
Intangible assets, net - customer relationships	13,962,772			15,949,772			6,204			9,623
Intangible assets, net - trade names	6,641,557			5,617,057			6,726			6,516
Goodwill	99,562,761			88,726,875			101,511			99,811
Deferred income tax asset							31,892			6,739
Other non-current assets	4,821,319			5,642,661			4,146			4,345
Total assets	$	626,917,575		$	502,362,475		$	1,029,123		$	867,243
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	53,864,660		$	20,469,542		$	177,353		$	141,306
Payables to related parties	120,183			203,209			1,916			1,378
Accrued expenses and other current liabilities	10,190,094			8,546,198			54,701			40,895
Income taxes payable	—			28,156			131,210			36,409
Total current liabilities	64,174,937			29,247,105			365,180			219,988

Long-term debt	65,000,000			—			—			99,900
Deferred income taxes	52,307,148			47,670,789
Deferred income tax liabilities							31,036			34,147
Asset retirement obligation	2,006,294			259,804			3,138			2,123
Other liabilities	3,018,937			2,404,422			4,100			3,289
Total liabilities	186,507,316			79,582,120			403,454			359,447

COMMITMENTS AND CONTINGENCIES (Note 14)
COMMITMENTS AND CONTINGENCIES (Note 18)

EQUITY
Equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 44,500,000 and	445,000			375,000
37,500,000 issued and outstanding at June 30, 2017 and December 31, 2016, respectively.
Common stock, $0.01 par value, 200,000,000 shares authorized, 44,752,765 and 44,589,306 issued and outstanding at June 30, 2018 and December 31, 2017, respectively							448			446
Additional paid in capital	505,245,742			400,205,921			528,421			508,010
Member's equity	—			81,738,675
Accumulated deficit	(62,473,672		)	(56,322,878		)
Retained earnings							100,247			2,001
Accumulated other comprehensive loss	(2,806,811		)	(3,216,363		)	(3,447		)	(2,661		)
Total equity	440,410,259			422,780,355			625,669			507,796
Total liabilities and equity	$	626,917,575		$	502,362,475		$	1,029,123		$	867,243

~~(a) Financial information includes the financial position and results attributable to Sturgeon Acquisitions LLC ("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.

MAMMOTH ENERGY SERVICES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE ~~LOSS~~INCOME (LOSS) (unaudited)

Three Months Ended
Six Months Ended
June 30,
June 30,
REVENUE 2017 (a) 2016 (b) 2017 (a) 2016 (b)
Services revenue $ 29,659,151
$ 18,650,612
$ 56,751,033
$ 46,887,094
Services revenue - related parties 44,602,759
39,504,058
77,564,416
40,650,612
Product revenue 10,395,025
1,694,698
13,767,088
2,976,443
Product revenue - related parties 13,605,124
9,313,266
25,145,543
11,231,344
Total revenue 98,262,059
69,162,634
173,228,080
101,745,493

COST AND EXPENSES
Services cost of revenue (c) 57,103,703
40,171,539
102,564,507
66,264,915
Services cost of revenue - related parties (c) 262,192
80,491
692,109
197,537
Product cost of revenue (c) 19,974,059
10,251,613
32,581,324
16,432,367
Selling, general and administrative 7,393,076
4,989,040
13,805,620
8,494,669
Selling, general and administrative - related parties 306,630
217,098
630,884
325,343
Depreciation, depletion, accretion and amortization 19,893,399
18,810,615
37,130,650
36,561,687
Impairment of long-lived assets —
1,870,885
—
1,870,885
Total cost and expenses 104,933,059
76,391,281
187,405,094
130,147,403
Operating loss (6,671,000 ) (7,228,647 ) (14,177,014 ) (28,401,910 )

OTHER (EXPENSE) INCOME
Interest expense (1,111,608 ) (1,012,031 ) (1,508,792 ) (2,308,387 )
Bargain purchase gain, net of tax 4,011,512
—
4,011,512
—
Other, net (202,496 ) 626,716
(386,642 ) 625,726
Total other income (expense) 2,697,408
(385,315 ) 2,116,078
(1,682,661 )
Loss before income taxes (3,973,592 ) (7,613,962 ) (12,060,936 ) (30,084,571 )
(Benefit) provision for income taxes (2,804,077 ) 789,375
(5,910,142 ) 1,683,735
Net loss $ (1,169,515 ) $ (8,403,337 ) $ (6,150,794 ) $ (31,768,306 )

OTHER COMPREHENSIVE INCOME (LOSS)
Foreign currency translation adjustment (1) 181,442
(5,493 ) 409,552
1,969,858
Comprehensive loss $ (988,073 ) $ (8,408,830 ) $ (5,741,242 ) $ (29,798,448 )

Net loss per share (basic and diluted) (Note 10) $ (0.03 ) $ (0.28 ) $ (0.16 ) $ (1.06 )
Weighted average number of shares outstanding (Note 10) 39,500,000
30,000,000
38,505,525
30,000,000

Pro Forma C Corporation Data:
Net loss, as reported

(7,613,962 )

(30,084,571 )
Pro forma benefit for income taxes

(2,342,467 )

(3,287,051 )
Pro forma net loss

(5,271,495 )

(26,797,520 )
Basic and Diluted (Note 10)

$ (0.14 )

$ (0.71 )
Weighted average pro forma shares outstanding—basic and diluted (Note 10)

37,500,000

37,500,000

(1) Net of tax 434,169
—
454,312
—



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
REVENUE	(in thousands, except per share amounts)
Services revenue	$	455,545		$	29,659		$	864,204		$	56,751
Services revenue - related parties	40,611			44,603			89,699			77,565
Product revenue	27,708			10,395			52,748			13,767
Product revenue - related parties	9,730			13,605			21,192			25,145
Total revenue	533,594			98,262			1,027,843			173,228

COST AND EXPENSES
Services cost of revenue (exclusive of depreciation, depletion, amortization and accretion of $26,898, $51,473, $17,651 and $33,489, respectively, for the three and six months ended June 30, 2018 and three and six months ended June 30, 2017)	302,283			57,104			593,262			102,565
Services cost of revenue - related parties (exclusive of depreciation, depletion, amortization and accretion of $0, $0, $0 and $0, respectively, for the three and six months ended June 30, 2018 and three and six months ended June 30, 2017)	2,428			262			4,220			692
Product cost of revenue (exclusive of depreciation, depletion, amortization and accretion of $3,879, $6,193, $2,204 and $3,566, respectively, for the three and six months ended June 30, 2018 and three and six months ended June 30, 2017)	35,117			19,974			68,447			32,581
Selling, general and administrative (Note 12)	64,595			7,393			102,677			13,806
Selling, general and administrative - related parties	532			307			961			631
Depreciation, depletion, amortization and accretion	30,795			19,893			57,703			37,130
Impairment of long-lived assets	187			—			187			—
Total cost and expenses	435,937			104,933			827,457			187,405
Operating income (loss)	97,657			(6,671		)	200,386			(14,177		)

OTHER (EXPENSE) INCOME
Interest expense, net	(959		)	(1,112		)	(2,196		)	(1,509		)
Bargain purchase gain, net of tax	—			4,012			—			4,012
Other, net	(486		)	(203		)	(514		)	(387		)
Total other (expense) income	(1,445		)	2,697			(2,710		)	2,116
Income (loss) before income taxes	96,212			(3,974		)	197,676			(12,061		)
Provision (benefit) for income taxes	53,512			(2,804		)	99,430			(5,910		)
Net income (loss)	$	42,700		$	(1,170	)	$	98,246		$	(6,151	)

OTHER COMPREHENSIVE INCOME (LOSS)
Foreign currency translation adjustment, net of tax of $86, $272, $434 and $454, respectively, for the three and six months ended June 30, 2018 and three and six months ended June 30, 2017	(325		)	181			(786		)	409
Comprehensive income (loss)	$	42,375		$	(989	)	$	97,460		$	(5,742	)

Net income (loss) per share (basic) (Note 14)	$	0.95		$	(0.03	)	$	2.20		$	(0.16	)
Net income (loss) per share (diluted) (Note 14)	$	0.95		$	(0.03	)	$	2.18		$	(0.16	)
Weighted average number of shares outstanding (basic) (Note 14)	44,737			39,500			44,700			38,506
Weighted average number of shares outstanding (diluted) (Note 14)	45,059			39,500			44,977			38,506

~~(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.~~

~~(c) Exclusive of depreciation, depletion, accretion and amortization~~

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

MAMMOTH ENERGY SERVICES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (unaudited)

Additional
Common Stock Common Members' Accumulated Paid-In
Shares Amount Partners Equity Deficit Capital AOCL Total
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 costs 37,500,000
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 —
—
—
—
(6,150,794 ) —
—
(6,150,794 )
Stingray acquisition 1,392,548
13,925
—
—
—
25,748,213
—
25,762,138
Sturgeon acquisition 5,607,452
56,075
—
(81,738,675 ) —
77,671,715
—
(4,010,885 )
Equity based compensation —
—
—
—
—
1,619,893
—
1,619,893
Other comprehensive income —
—
—
—
—
—
409,552
409,552
Balance at June 30, 2017 44,500,000
$ 445,000
$ —
$ —
$ (62,473,672 ) $ 505,245,742
$ (2,806,811 ) $ 440,410,259




							Retained			Additional
	Common Stock			Members'			Earnings			Paid-In
	Shares	Amount		Equity			(Deficit)			Capital		AOCL			Total
	(in thousands)
Balance at January 1, 2017	37,500	$	375	$	81,739		$	(56,323	)	$	400,206	$	(3,216	)	$	422,781
Net income of Sturgeon prior to acquisition	—	—		640			—			—		—			640
Stingray acquisition	1,393	14		—			—			25,748		—			25,762
Sturgeon acquisition	5,607	56		(82,379		)	—			78,313		—			(4,010		)
Stock based compensation	89	1		—			—			3,743		—			3,744
Net income	—	—		—			58,324			—		—			58,324
Other comprehensive income	—	—		—			—			—		555			555
Balance at December 31, 2017	44,589	$	446	$	—		$	2,001		$	508,010	$	(2,661	)	$	507,796
Equity based compensation (Note 15)	—	—		—			—			17,487		—			17,487
Stock based compensation	164	2		—			—			2,924		—			2,926
Net income	—	—		—			98,246			—		—			98,246
Other comprehensive loss	—	—		—			—			—		(786		)	(786		)
Balance at June 30, 2018	44,753	$	448	$	—		$	100,247		$	528,421	$	(3,447	)	$	625,669

~~(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.

MAMMOTH ENERGY SERVICES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)



	Six Months Ended June 30,
	2018			2017
	(in thousands)
Cash flows from operating activities:
Net income (loss)	$	98,246		$	(6,151	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Equity based compensation (Note 15)	17,487			—
Stock based compensation	2,916			1,620
Depreciation, depletion, accretion and amortization	57,703			37,130
Amortization of coil tubing strings	1,120			1,046
Amortization of debt origination costs	199			199
Bad debt expense	53,790			19
(Gain) loss on disposal of property and equipment	(128		)	127
Gain on bargain purchase	—			(4,012		)
Impairment of long-lived assets	187			—
Deferred income taxes	(27,906		)	(6,529		)
Changes in assets and liabilities, net of acquisitions of businesses:
Accounts receivable, net	(122,908		)	(4,793		)
Receivables from related parties	3,114			(12,995		)
Inventories	4,156			(4,932		)
Prepaid expenses and other assets	(1,195		)	1,528
Accounts payable	34,186			20,557
Payables to related parties	538			(83		)
Accrued expenses and other liabilities	10,193			1,301
Income taxes payable	94,753			(28		)
Net cash provided by operating activities	226,451			24,004

Cash flows from investing activities:
Purchases of property and equipment	(105,349		)	(66,575		)
Purchases of property and equipment from related parties	(3,436		)	—
Business acquisitions	(13,356		)	(39,570		)
Proceeds from disposal of property and equipment	898			781
Business combination cash acquired (Note 4)	—			2,671
Net cash used in investing activities	(121,243		)	(102,693		)

Cash flows from financing activities:
Borrowings from lines of credit	52,000			79,150
Repayments of lines of credit	(151,900		)	(14,150		)
Repayments of equipment financing note	(145		)	—
Repayment of Stingray acquisition long-term debt	—			(7,074		)
Net cash (used in) provided by financing activities	(100,045		)	57,926
Effect of foreign exchange rate on cash	(98		)	73
Net change in cash and cash equivalents	5,065			(20,690		)
Cash and cash equivalents at beginning of period	5,637			29,239
Cash and cash equivalents at end of period	$	10,702		$	8,549

Supplemental disclosure of cash flow information:
Cash paid for interest	$	2,543		$	1,086
Cash paid for income taxes	$	32,584		$	912
Supplemental disclosure of non-cash transactions:
Purchases of property and equipment included in accounts payable and accrued expenses	$	20,897		$	7,836
Acquisition of Sturgeon, Stingray Cementing LLC and Stingray Energy Services LLC (Note 4)	$	—		$	23,091

Six Months Ended
June 30,
Cash flows from operating activities 2017 (a) 2016 (b)
Net loss $ (6,150,794 ) $ (31,768,306 )
Adjustments to reconcile net loss to cash provided by operating activities:
Equity based compensation 1,619,893
—
Depreciation, depletion, accretion and amortization 37,130,650
36,561,687
Amortization of coil tubing strings 1,045,233
962,302
Amortization of debt origination costs 199,403
199,403
Bad debt expense 18,980
1,764,218
(Gain) loss on disposal of property and equipment 127,153
(710,046 )
Gain on bargain purchase (4,011,512 ) —
Impairment of long-lived assets —
1,870,885
Deferred income taxes (6,529,406 ) 41,292
Changes in assets and liabilities, net of acquisitions of businesses:
Accounts receivable, net (4,792,555 ) (2,562,425 )
Receivables from related parties (12,995,194 ) (7,803,381 )
Inventories (4,931,651 ) 30,615
Prepaid expenses and other assets 1,528,346
(1,092,731 )
Accounts payable 20,557,001
8,008,632
Payables to related parties (83,079 ) (199,694 )
Accrued expenses and other liabilities 1,300,687
5,659,053
Income taxes payable (28,156 ) (15,387 )
Net cash provided by operating activities 24,004,999
10,946,117

Cash flows from investing activities:
Purchases of property and equipment (66,575,719 ) (2,174,209 )
Business acquisitions (39,570,187 ) —
Proceeds from disposal of property and equipment 780,932
3,165,519
Business combination cash acquired (Note 3) 2,671,558
—
Net cash (used in) provided by investing activities (102,693,416 ) 991,310

Cash flows from financing activities:
Borrowings from lines of credit 79,150,000
11,150,000
Repayments of lines of credit (14,150,000 ) (25,752,516 )
Repayment of Stingray acquisition long-term debt (7,073,854 ) —
Net cash provided by (used in) financing activities 57,926,146
(14,602,516 )
Effect of foreign exchange rate on cash 72,943
54,163
Net decrease in cash and cash equivalents (20,689,328 ) (2,610,926 )
Cash and cash equivalents at beginning of period 29,238,618
4,038,899
Cash and cash equivalents at end of period $ 8,549,290
$ 1,427,973

Supplemental disclosure of cash flow information:
Cash paid for interest $ 1,085,851
$ 2,056,581
Cash paid for income taxes $ 911,700
$ 2,035,015
Supplemental disclosure of non-cash transactions:
Purchases of property and equipment included in trade accounts payable $ 7,835,614
$ 414,795
Acquisition of Sturgeon, Stingray Cementing LLC and Stingray Energy Services LLC and (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.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


1.	Organization and ~~Basis~~Nature of ~~Presentation~~Business

The accompanying unaudited condensed consolidated interim financial statements were prepared in accordance with the rules and regulations 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 Mammoth Energy Services, Inc. (the ~~"Company," "Mammoth~~“Company,” “Mammoth Inc."” or ~~"Mammoth"~~ “Mammoth”) ~~in the Company's Annual Report on Form 10-K filed on February 24, 2017.~~

~~Mammoth,~~, together with its subsidiaries, is an integrated, growth-oriented ~~oilfield services~~ company serving ~~companies engaged~~both the oil and gas and the electric utility industries in North America and U.S. territories. Mammoth's subsidiaries provide a diversified set of drilling and completion services to the exploration and ~~development of North American onshore unconventional oil~~production industry and ~~natural gas reserves.~~its infrastructure division provides transmission, distribution and logistics services to various public and privately owned utilities throughout the U.S. and Puerto Rico. 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"~~“Partnership” or the ~~"Predecessor"~~“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, Mammoth Energy Holdings LLC (“Mammoth Holdings,” an entity controlled by Wexford), Gulfport Energy Corporation (“Gulfport”), and Rhino Resource Partners LP (“Rhino”) ~~and Mammoth Energy Holdings LLC (“Mammoth Holdings”~~(collectively known as the “Predecessor Interest”)~~, 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.

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; and South River Road, LLC (“South River”), acquired June 5, 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"~~“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~~On June 29, 2018, Gulfport and MEH Sub LLC ("MEH Sub"), an entity controlled by Wexford, (collectively, the "Selling Stockholders") completed an underwritten secondary public offering of 4,000,000 shares of the Company’s common stock at a purchase price to ~~Mammoth Inc. from its sale~~the Selling Stockholders of ~~7,500,000~~$38.01 per share. The Selling Stockholders granted the underwriters an option to purchase up to an aggregate of 600,000 additional shares of the Company's common stock at the same purchase price. This option was exercised, in part, and on July 30, 2018, the underwriters purchased an additional 385,000 shares of common stock ~~were approximately $103.1 million. On~~from the ~~closing date of~~Selling Stockholders at the ~~IPO, Mammoth Inc. repaid~~same price per share. The Selling Stockholders received 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 forfrom 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.offering.

At June 30, ~~2017~~2018 and December 31, ~~2016, Mammoth Holdings, or its affiliates,~~2017, Wexford, Gulfport and Rhino beneficially owned the following ~~share~~shares of outstanding common stock of Mammoth Inc.:


	At June 30, 2017			At December 31, 2016			At June 30, 2018			At December 31, 2017
	Share Count	% Ownership		Share Count	% Ownership		Share Count	% Ownership		Share Count	% Ownership
Mammoth Holdings	25,009,319	56.2	%	20,443,903	54.5	%
Wexford							22,252,277	49.7	%	25,009,319	56.1	%
Gulfport	11,171,887	25.1	%	9,073,750	24.2	%	9,943,645	22.2	%	11,171,887	25.1	%
Rhino	568,794	1.3	%	232,347	0.6	%	104,100	0.2	%	568,794	1.3	%
Outstanding shares owned by related parties	36,750,000	82.6	%	29,750,000	79.3	%	32,300,022	72.1	%	36,750,000	82.5	%
Total outstanding	44,500,000	100.0	%	37,500,000	100.0	%	44,752,765	100.0	%	44,589,306	100.0	%

Operations

The Company's infrastructure services include electric utility contracting services focused on the repair, upgrade, maintenance and construction of transmission and distribution networks. The Company’s infrastructure services also provide storm repair and restoration services in response to natural disasters including hurricanes, ice or other storm-related damage. The Company's pressure pumping services include equipment and personnel used in connection with the completion and early production of oil and natural gas ~~wells, well services include coil tubing units used to enhance the flow of oil or natural gas and~~wells. The Company's natural sand proppant services include the distribution and production of natural sand proppant that is used primarily for hydraulic fracturing in the oil and gas industry. The Company's contract land and directional drilling services provides drilling rigs and directional tools for both

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

vertical and horizontal drilling of oil and natural gas wells and salt water disposal wells. The Company also provides other ~~energy~~ services, ~~which have historically consisted~~including coil tubing units used to enhance the flow of oil and natural gas, flowback, cementing, aciziding, equipment rentals, crude oil hauling and remote ~~accommodations for people working in the oil sands located in Northern Alberta, Canada, but recently have been expanded to include energy infrastructure services.~~accommodations.

All of the Company’s operations are in North ~~America.~~America and in the Caribbean. 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 operates its energy infrastructure services in the northeast, southwest and midwest portions of the United States and Puerto Rico. The Company's oil and natural gas business depends in large part on the conditions in the oil and natural gas industry and, specifically, on the amount of capital spending by its customers. Any prolonged increase or

~~MAMMOTH ENERGY SERVICES, INC.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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. 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. The Company’s business also depends on infrastructure spending on maintenance, upgrade, expansion and repair and restoration. Any prolonged decrease in spending by electric utility companies or delays or reductions in government appropriations could have a material adverse effect on the Company’s results of operations and financial condition.


2.	~~Summary~~Basis of Presentation and Significant Accounting Policies

~~(a) Principles~~Basis of ~~Consolidation~~Presentation

The accompanying unaudited condensed consolidated interim financial statements ~~are prepared in accordance with GAAP.~~include the accounts of the Company and its subsidiaries and the variable interest entity ("VIE") for which the Company is the primary beneficiary. All material intercompany accounts and transactions ~~between the entities within the Company~~ have been eliminated.

~~(b) Use~~This report has been prepared in accordance with the rules and regulations of ~~Estimates~~

~~The preparation~~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. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in ~~conformity~~accordance with ~~GAAP requires management~~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 ~~estimates and assumptions that affect~~ the ~~reported amounts of assets and liabilities,~~information presented not misleading. These unaudited condensed consolidated financial statements should be read in conjunction with the ~~disclosure of contingent assets and liabilities at the date of the~~consolidated financial statements and the ~~reported amounts~~summary of ~~revenues~~significant accounting policies and ~~expenses during~~notes thereto included in 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~~Company’s most recent annual report on calculating the depletion expense, the allowance for doubtful accounts, 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.Form 10-K.

~~(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. AtOn June ~~30,~~5, 2017, the Company ~~had $3.1 million, in Canadian dollars,~~acquired Sturgeon Acquisitions LLC ("Sturgeon") and Sturgeon's wholly owned subsidiaries Taylor Frac, LLC, Taylor Real Estate Investments, LLC and South River Road, LLC. Prior to its acquisition of ~~cash in Canadian accounts. Cash balances from time to time may exceed the insured amounts; however~~Sturgeon, the Company ~~has not experienced any losses in such accounts~~ and ~~does not believe~~Sturgeon were under common control and it is ~~exposed~~required under GAAP to ~~any significant credit risks on such accounts.~~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 with the Company as if the acquisition had been effective since the date Sturgeon commenced operations. Refer to Note 4 - Acquisitions for additional disclosure regarding the acquisition of Sturgeon.

~~(d)~~ Accounts Receivable

Accounts receivable include amounts due from customers for services performed and are recorded as the work progresses. The Company grants credit to customers in the ordinary course of business and generally does not require collateral. Most areas 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.

The Company regularly reviews receivables and provides for estimated 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 ~~conditions~~condition 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 determine 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. Uncollectible accounts receivable are periodically charged against the allowance for doubtful accounts once a final determination is made ofregarding their uncollectability.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Following is a roll forward of the allowance for doubtful accounts for the year ended December 31, ~~2016~~2017 and the six months ended June 30, ~~2017:~~2018 (in thousands):


Balance, January 1, 2016	$	4,011,882
Balance, January 1, 2017				$	5,377
Additions charged to expense				16,206
Additions other				179
Deductions for uncollectible receivables written off				(25		)
Balance, December 31, 2017				21,737
Additions charged to expense	1,968,001			53,790
Deductions for uncollectible receivables written off	(602,967		)	(1,758		)
Balance, December 31, 2016	5,376,916
Additions charged to expense	18,980
Additions other	178,871
Balance, June 30, 2017	$	5,574,767
Balance, June 30, 2018				$	73,769

~~MAMMOTH ENERGY SERVICES, INC.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~As discussed in Note 1, prolonged declines in pricing can impact the overall health~~In October 2017, Cobra Acquisitions LLC ("Cobra"), one of the ~~oil~~Company's subsidiaries, entered into a contract with the Puerto Rico Electric Power Authority ("PREPA") to perform repairs to PREPA’s electrical grid as a result of Hurricane Maria. At June 30, 2018 and ~~natural gas industry. The~~December 31, 2017, the Company reviewed receivables due from PREPA and made specific reserves consistent with Company policy which resulted in additions to the allowance for doubtful accounts totaling $53.6 million and $16.0 million, respectively, for the six months ended June 30, 2018 and year ended December 31, ~~2016 contained such pricing conditions which may lead to enhanced risk of uncollectiblity on certain receivables. As such,~~2017.

Additionally, the Company ~~monitored its previously established~~has made specific reserves consistent with Company policy which resulted in additions to allowance for doubtful accounts totaling $0.2 million and ~~adjusted upward.~~$0.2 million, respectively, for the six months ended June 30, 2018 and year ended December 31, 2017. The Company will continue to pursue collection until such time as final determination is made consistent with Company policy.

~~(e) Inventory~~Concentrations of Credit Risk and Significant Customers

~~Inventory consists~~Financial instruments that potentially subject the Company to concentrations of ~~raw sand~~credit risk consist of cash and ~~processed sand available for sale, chemicals~~cash equivalents in excess of federally insured limits and ~~other products sold as~~trade receivables. Following is a ~~bi-product~~summary of completion and production operations, and supplies used in performing services. Inventory is stated at the lower 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 applied to the stockpilesour significant customers based on ~~the number~~percentages of ~~tons in the stockpile. Inventory transported for sale~~total accounts receivable balances at ~~the Company’s terminal facility includes the cost~~June 30, 2018 and December 31, 2017 and percentages of ~~purchased or manufactured sand, plus transportation related charges.~~

Inventory also consists of coil tubing strings of various widths, diameters and lengths that are used in providing specialized services to customers who are primarily operators of oil or gas wells. The strings 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 $1,045,233 and $962,302revenues derived for the three and six months ended June 30, ~~2017~~2018 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 operations. 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) Long-Lived Assets~~

The Company reviews long-lived assets for recoverability in accordance with the provisions of Financial Accounting Standards Board ("FASB") Accounting Standard Codification (“ASC”) Topic 360, Impairment or Disposal of Long-Lived Assets, which requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. Recoverability of assets is measured by comparing the carrying amount of an asset to future undiscounted net cash flows expected to be generated by the asset. These evaluations for impairment are significantly impacted by estimates of revenues, costs and expenses, and other factors. If long-lived assets are considered to be impaired, 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 six months ended June 30, 2017 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.

~~(i) Goodwill~~

Goodwill is tested for impairment annually, or more frequently if events or changes in circumstances indicate that goodwill might be impaired. The impairment test is a two-step process. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. If impairment is indicated, then the implied value of the reporting unit’s goodwill is determined by allocating the unit’s fair value to its assets and

~~MAMMOTH ENERGY SERVICES, INC.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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 six months ended June 30, 2017 and 2016, no impairment losses were recognized.

~~(j) 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.~~

~~(k) 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.

~~Changes in the asset retirement obligation for the year ended December 31, 2016 and the six months ended June 30, 2017 are set forth below:~~2017:

Balance, January 1, 2016 $ 94,904
Accretion expense 164,900
Balance, December 31, 2016 259,804
Accretion expense 14,409
Additions - Chieftain Acquisition (Note 3) 1,732,081
Balance, June 30, 2017 $ 2,006,294



	REVENUES								ACCOUNTS RECEIVABLE
	Three Months Ended June 30,				Six Months Ended June 30,				At June 30,		At December 31,
	2018		2017		2018		2017		2018		2017
Customer A^(a)	65	%	—	%	65	%	—	%	59	%	56	%
Customer B^(b)	9	%	59	%	11	%	59	%	9	%	12	%


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


b.	Customer B is a related party customer. Revenues and the related accounts receivable balances earned from Customer B were derived from the Company's pressure pumping services segment, natural sand proppant services segment, contract land and directional drilling services segment and other businesses.

~~(l) 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.

~~(m) 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 six months ended June 30, 2017 and 2016, no impairment losses were recognized.

~~(n)~~ Fair Value of Financial Instruments

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

~~(o) Revenue Recognition~~

The Company generates revenue from multiple sources within its operating segments. In all cases, revenue is recognized when services are performed, collection of the receivable is probable, persuasive evidence of an arrangement exists, and

~~MAMMOTH ENERGY SERVICES, INC.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~the price is fixed and determinable. 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.~~

Pressure pumping 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 revenue is recognized as the work progresses. Jobs for these services are typically short-term in nature and range from a few hours to multiple days. Revenue is recognized upon the completion of each day’s work based upon a completed field ticket, which includes the charges for the services performed, mobilization of the equipment to the location, and personnel. 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 revenues 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 volumes over the shortfall window. Contractual shortfall revenue is deemed not probable until the end of the measurement period.

Well 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 revenue is recognized as the work progresses. Jobs for these 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 six months ended June 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 the final terms and prices of these contracts are frequently negotiated with the customer. Under unit-based contracts, the utilization of an output-based measurement is appropriate for revenue recognition. Under our cost-plus/hourly and time and materials type contracts, the Company recognizes revenue on an input basis, as labor hours are incurred and services are performed.

The timing of revenue recognition may differ from contract billing or payment schedules, resulting in revenues that have been earned but not billed (“unbilled revenue”). The Company had $3,017,892 and $2,732,993 of unbilled revenue included in accounts receivable, net in the Condensed Consolidated Balance Sheets at June 30, 2017 and December 31, 2016, respectively. The Company had $13,662,077 and $10,506,958 of unbilled revenue included in receivables from related parties in the Condensed Consolidated Balance Sheets at June 30, 2017 and December 31, 2016, respectively.

~~(p) Earnings per Share~~

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

~~(q) Unaudited Pro Forma Loss per Share~~

The Company’s pro forma basic loss per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period, as if the common stock issued in the October 12, 2016 contribution

~~MAMMOTH ENERGY SERVICES, INC.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

and the IPO was outstanding for the six months ended June 30, 2016. Diluted earnings per share reflects the 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.

~~(r) Equity-based Compensation~~

The Company records equity-based payments at fair value on the date of grant, and expenses the value of these equity-based payments in compensation expense over the applicable vesting periods. See Note 11.

~~(s) 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 instruments 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.

~~(t) Income Taxes~~

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 was 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 36.8% for the six months ended June 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 period that includes the statutory enactment date. A valuation allowance for deferred tax assets is recognized when it is more likely than not that the benefit of deferred tax assets will not be realized.

The Company has included a pro forma provision for income taxes assuming it had been taxed as a C corporation in all periods prior to the conversion and contribution as part of its earnings per share calculation in Note 10. The unaudited pro forma data are presented for informational purposes only, and do not purport to project the Company's results of operations for any future period or its financial position as of any future date.

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

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 six months ended June 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~~

~~(u) 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.

~~(v) 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 June 30, 2017 and December 31, 2016, there were no probable environmental matters.

~~(w) 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.

~~(x) 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 June 30, 2017, no third-party customer accounted for 10% of the Company's trade accounts receivable and receivables from related parties balance combined. At June 30, 2017 and December 31, 2016, related party customers accounted for 60% and 58%, respectively, of the Company's trade accounts receivable and receivables from related parties balance combined. During the six months ended June 30, 2017 and 2016, one related party customer accounted for 59% and 50%, respectively, of the Company's total revenue. Two third-party customers accounted for greater than 10% of the Company's total revenue for six months ended June 30, 2016, at 12% for each respective parties. No third-party customer accounted for greater than 10% for the six months ended June 30, 2017.

~~(y)~~ 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 utilizing the full retrospective method of adoption in the first quarter of 2018, and because the Company is still evaluating the portion of its revenues that may be subject to the new leasing guidance discussed below, it is unable to quantify the impact that the new revenue standard will have on the Company’s consolidated financial statements upon adoption. Remaining implementation matters include establishing new policies, procedures, and controls and quantifying any adoption date adjustments.

~~MAMMOTH ENERGY SERVICES, INC.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

In February 2016, the ~~FASB~~Financial Accounting Standards Board (“FASB”) issued ~~ASU No,~~Accounting Standards Update (“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,

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 expects~~The Company plans to adopt this ~~updated leasing guidance at~~ASU effective January 1, 2019 utilizing the ~~same time its adopts the new revenue guidance discussed above, utilizing the~~modified 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~~may have on the Company's consolidated financial statements and results of operations.

In June 2018, the FASB issued ASU No. 2018-07, “Compensation - Stock Compensation (Topic 718): Improvements to Non-employee Share-Based Accounting,” which simplifies the accounting for share-based payments granted to non-employees by aligning the accounting with requirements for employee share-based compensation. Upon transition, this ASU requires non-employee awards to be measured at fair value as of the adoption date. This ASU is effective for fiscal years beginning after December 15, 2018, and interim periods within that fiscal year. Early adoption is permitted. Currently, the Company has not elected to early adopt this ASU and is evaluating the impact it will have on the Company's consolidated financial statements.


3.	~~Acquisitions~~Revenues

~~(a) Description~~Adoption of ~~Stingray Acquisition~~ASC 606 "Revenues from Contracts with Customers"

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers,” which supersedes the revenue recognition requirements in ASC 605, Revenue Recognition, and most industry-specific guidance. The new guidance requires entities to recognize revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services.

On ~~March 20, 2017, and as amended on May 12, 2017,~~January 1, 2018, the Company ~~entered into two definitive contribution agreements, one such agreement~~adopted ASU 2014-09 and its related amendments (collectively, "ASC 606") using the modified retrospective method applied to contracts which were not completed as of January 1, 2018. Revenues for reporting periods beginning after January 1, 2018 are presented under ASC 606, while prior period amounts continue to be reported under previous revenue recognition guidance. While ASC 606 requires additional disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with ~~MEH Sub LLC (“MEH Sub”), Wexford Offshore Stingray Energy Corp., Gulfport and Mammoth LLC and~~customers, its adoption has not had a material impact on 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 inmeasurement or recognition of 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.~~revenues.

The ~~2017 Stingray Acquisition closed on June 5, 2017. Pursuant~~adoption of ASC 606 represents a change in accounting principle. After evaluation of all contracts not completed as of January 1, 2018, the Company determined the cumulative effect of adopting ASC 606 was immaterial, and as such, has not recorded an adjustment to the ~~Stingray Contribution Agreements, Mammoth issued 1,392,548 shares~~opening balance 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~~retained earnings on ~~June 5, 2017, the total purchase price was $25,762,138.~~January 1, 2018.

~~At the acquisition date, the components of the consideration transferred were as follows:~~Revenue Recognition

The following table presents revenues disaggregated by service line (in thousands):

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~~



	Three Months Ended						Six Months Ended
	June 30, 2018			June 30, 2017			June 30, 2018			June 30, 2017
Revenue:
Pressure pumping services	$	101,406		$	50,196		$	202,544		$	90,836
Infrastructure services	360,250			1,709			685,709			1,709
Natural sand proppant services	52,845			24,762			103,860			40,359
Contract land and directional drilling services	17,210			12,472			32,440			23,223
Other services	20,167			10,242			43,062			19,092
Eliminations	(18,284		)	(1,119		)	(39,772		)	(1,991		)
Total revenue	$	533,594		$	98,262		$	1,027,843		$	173,228

Pressure Pumping Services

Pressure pumping services are typically provided based upon a purchase order, contract or on a spot market basis. Services are provided on a day rate, contracted or hourly basis. Generally, the Company accounts for pressure pumping services as a single performance obligation satisfied over time. In certain circumstances, the Company supplies proppant that is utilized for pressure pumping as part of the agreement with the customer. The Company accounts for these pressure pumping agreements as multiple performance obligations satisfied over time. Jobs for these services are typically short-term in nature and range from a few hours to multiple days. Generally, revenue is recognized over time upon the

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

completion of each segment of work based upon a completed field ticket, which includes the charges for the services performed, mobilization of the equipment to the location and personnel.

Pursuant to a contract with one of its customers, the Company has agreed to provide that customer with use of two pressure pumping fleets for the period covered by the contract. Under this agreement, performance obligations are satisfied as services are rendered based on the passage of time rather than the completion of each segment of work. The Company has the right to receive consideration from this customer even if circumstances prevent us from performing work. All consideration owed to the Company for services performed during the contractual period is fixed and the right to receive it is unconditional.

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

Infrastructure Services

Infrastructure services are typically provided pursuant to master service agreements, repair and maintenance contracts or fixed price and non-fixed price installation contracts. Pricing under these contracts may be unit priced, cost-plus/hourly (or time and materials basis) or fixed price (or lump sum basis). The Company accounts for infrastructure services as a single performance obligation satisfied over time. Revenue is recognized over time as work progresses based on the days completed or as the contract is completed.

Natural Sand Proppant Services

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

Certain of the Company's sand supply agreements contain a minimum volume commitment related to sand purchases whereby the Company charges a shortfall payment if the customer fails to meet the required minimum volume commitment. These agreements may also contain make-up provisions whereby shortfall payments can be applied in future periods against purchased volumes exceeding the minimum volume commitment. If a make-up right exists, the Company has future performance obligations to deliver excess volumes of product in subsequent months. In accordance with ASC 606, if the customer fails to meet the minimum volume commitment, the Company will assess whether it expects the customer to fulfill its unmet commitment during the contractually specified make-up period based on discussions with the customer and management's knowledge of the business. If the Company expects the customer will make-up deficient volumes in future periods, revenue related to shortfall payments will be deferred and recognized on the earlier of the date on which the customer utilizes make-up volumes or the likelihood that the customer will exercise its right to make-up deficient volumes becomes remote. If the Company does not expect the customer will make-up deficient volumes in future periods, the breakage model will be applied and revenue related to shortfall payments will be recognized when the model indicates the customer's inability to take delivery of excess volumes. During the three and six months ended June 30, 2018, the Company recognized $0.3 million in revenue related to shortfall payments.

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

Contract Land and Directional Drilling Services

Contract drilling services are provided under daywork contracts. Directional drilling services, including motor rentals, are provided on a day rate or hourly basis, and revenue is recognized as work progresses. Performance obligations are satisfied over time as the work progresses based on the measure of output. Mobilization revenue and costs are recognized over the days of actual drilling.

Other Services

The Company also provides coil tubing, pressure control, flowback, cementing, acidizing, equipment rentals, crude oil hauling and remote accommodations services, which are reported under other services. These services are typically provided based upon a purchase order, contract or on a spot market basis. Services are provided on a day rate, contracted or hourly basis. Performance obligations for these services are satisfied over time and revenue is recognized as the work

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SR Energy Cementing 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

progresses based on the measure of output. Jobs for these services are typically short-term in nature and range from a few hours to multiple days.

Practical Expedients

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

Performance Obligations and Contract Balances

As of June 30, 2018 and January 1, 2018, the Company had contract liabilities totaling $15.0 million, which are included in accrued expenses and other current liabilities in the unaudited condensed consolidated balance sheets, and did not have any contract assets. Revenue recognized in the current period from performance obligations satisfied in previous periods was a nominal amount for the three and six months ended June 30, 2018. As of June 30, 2018, the Company had unsatisfied performance obligations totaling $68.5 million, which will be recognized over the next 2.5 years.

⁽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.Acquisitions

(a) Acquisition of WTL Oil

On May 31, 2018, the Company completed its acquisition of WTL Oil LLC ("WTL") for total consideration of $5.5 million in cash to the sellers plus $0.6 million in consideration to be paid upon completion of certain contractual obligations. As of June 30, 2018, the $0.6 million of contingent consideration is reflected in accrued expenses and other current liabilities on the unaudited condensed consolidated balance sheet. The seller completed these obligations and the Company paid the additional $0.6 million to the seller in July 2018.

The Company used cash on hand and borrowings under its credit facility to fund the acquisition. The acquisition of WTL expanded the Company's service offerings into the crude oil hauling business.

The following table summarizes the fair value of WTL as of May 31, 2018 (in thousands):



	WTL
Property, plant and equipment	$	2,960
Identifiable intangible assets - customer relationships^(a)	930
Identifiable intangible assets - trade name^(a)	650
Goodwill^(b)	1,567
Total assets acquired	$	6,107


⁽²⁾ a.	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~~10-20 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 the assembled ~~workforces~~workforce and future profitability ~~based on the synergies~~ expected to arise from the acquired ~~entities.~~


⁽⁴⁾	~~Long-term debt assumed was paid off during the three months ended June 30, 2017.~~entity.

~~Since~~

From the acquisition date ~~the businesses acquired have~~through June 30, 2018, WTL provided the following ~~activity:~~activity (in thousands):


	2017
	SR Energy			Cementing			2018
Revenues	$	1,692,239		$	903,317		$	595
Net loss (a)	(251,908		)	(422,295		)
Net income^(a)							5

a.Includes ~~$503,997 and $512,656 in~~ depreciation and amortization ~~for SR Energy and Cementing, respectively.~~expense of $0.1 million.

The following table presents unaudited pro forma information ~~for the Company~~ as if the acquisition of ~~SR Energy and Cementing~~WTL had occurred onas of January 1, ~~2016:~~2017 (in thousands):

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


							Six Months Ended
	Six Months Ended June 30, 2017			Year Ended December 31, 2016			June 30, 2018		June 30, 2017
Revenues	$	18,333,453		$	23,659,445		$	3,354	$	1,553
Net loss	(1,612,175		)	(8,171,257		)
Net income							90		62

The ~~historical financial information was adjusted to give effect to~~Company recognized $0.1 million of transaction related costs during the ~~pro forma events that were directly attributable to the 2017 Stingray Acquisition. For the six~~three months ended June 30, 2018 related to this acquisition.

(b) Acquisition of RTS Energy Services

On June 15, 2018, the Company completed its acquisition of RTS Energy Services LLC ("RTS") for total consideration of $7.6 million in cash to the sellers plus $0.5 million to be paid 90 days after closing subject to contractual conditions. As of June 30, 2018, the $0.5 million of contingent consideration is reflected in accrued expenses and other current liabilities on the unaudited condensed consolidated balance sheet. The Company used cash on hand and borrowings under its credit facility to fund the acquisition. The acquisition of RTS expanded Mammoth's cementing services into the Permian Basin and added acidizing to the Company's service offerings.

The following table summarizes the fair value of RTS as of June 15, 2018 (in thousands):



	RTS
Inventory	$	180
Property, plant and equipment	7,787
Goodwill^(a)	133
Total assets acquired	$	8,100

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 the assembled workforce and future profitability expected to arise from the acquired entity.

From the acquisition date through June 30, 2018, RTS provided the following activity (in thousands):



	2018
Revenues	$	630
Net income^(a)	7

a. Includes depreciation expense of $0.1 million.

The following table presents unaudited pro forma information as if the acquisition of RTS had occurred as of January 1, 2017 ~~there were $0.2 million~~(in thousands):



	Six Months Ended
	June 30, 2018			June 30, 2017
Revenues	$	10,160		$	8,326
Net income (loss)	(848		)	653

The Company recognized a nominal amount of transaction related costs ~~expensed.~~during the three months ended June 30, 2018 related to this acquisition.

On July 1, 2017, the Company completed its acquisition of 5 Star for total consideration of $2.4 million in cash to the sellers. Mammoth funded the purchase price for 5 Star with cash on hand and borrowings under its credit facility. The ~~unaudited pro forma consolidated results are not necessarily indicative~~acquisition of ~~what~~5 Star added to 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 operationsinfrastructure component of the ~~Company.~~Company's business.

The Company recognized $0.1 million of transaction related costs during the year ended December 31, 2017 related to this acquisition.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~(b) Description~~The following table summarizes the fair value of ~~Chieftain Acquisition~~

~~On March 27, 2017, as amended~~5 Star as of ~~May 24,~~July 1, 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:~~(in thousands):

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



	5 Star
Accounts receivable	$	2,440
Property, plant and equipment	1,863
Identifiable intangible assets - trade names ^(a)	300
Goodwill ^(b)	248
Total assets acquired	$	4,851

Long-term debt and other liabilities	$	2,413
Total liabilities assumed	$	2,413
Net assets acquired	$	2,438


a.	⁽¹⁾Identifiable intangible assets were measured using a combination of income approaches. Trade names were valued using a "Relief-from-Royalty" method. Identifiable intangible assets will be amortized over 10 years.	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~~Goodwill was the excess of the ~~sand reserves was determined based on~~consideration transferred over the ~~excess cash flow method, a form of~~net assets recognized and represents the ~~income approach. The method provides a value based on~~future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill recorded in connection with the ~~estimated remaining life of sand reserves, projected financial information~~acquisition is attributable to the assembled workforce 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~~future profitability expected to arise from the ~~business was determined based on the excess cash flow method, a form of the income approach.~~acquired entity.

~~Since~~From the acquisition date ~~the Chieftain Assets have~~through June 30, 2018, 5 Star provided the following ~~activity:~~activity (in thousands):

2017
Piranha
Revenues $ 1,311,768
Net loss (a) (206,644 )



	2018		2017
Revenues^(a)	$	86,720	$	25,216
Net income^(b)	12,903		4,191

a.Includes ~~$429,821 in~~ intercompany revenues of $77.5 million and $16.0 million, respectively, for 2018 and 2017.

b.Includes depreciation and amortization expense of $1.0 million and $0.8 million, respectively, for 2018 and 2017.

The following table presents unaudited pro forma information ~~for the Company~~ as if the acquisition of ~~the Chieftain Assets~~5 Star had occurred as of January 1, ~~2016:~~2017 (in thousands):


	Six Months Ended June 30, 2017			Year Ended December 31, 2016		Six Months Ended June 30, 2017
Revenues	$	1,311,768		$	7,690,032	$	6,332
Net (loss) income	(72,455		)	34,127,344
Net loss						(282		)

(d) Acquisition of Higher Power

On April 21, 2017, the Company completed its acquisition of Higher Power for total consideration of $3.3 million in cash to the sellers plus up to $0.8 million in contingent consideration to be paid in equal annual installments over the next three years subject to contractual conditions. As of June 30, 2018, $0.3 million and $0.3 million, respectively, of the contingent consideration are reflected in accrued expenses and other current liabilities and other liabilities on the unaudited condensed consolidated balance sheet. Mammoth funded the 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 business, helping to diversify its service offerings.

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 six months ended June 30, 2017, $0.7Company recognized $0.1 million of transaction related costs ~~was expensed.~~

during the year ended December 31, 2017 related to this acquisition.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the fair value of Higher Power as of April 21, 2017 (in thousands):



	Higher Power
Property, plant and equipment	$	1,744
Identifiable intangible assets - customer relationships	1,613
Goodwill ^(a)	643
Total assets acquired	$	4,000

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 the assembled workforce and future profitability expected to arise from the acquired entity.

From the acquisition date through June 30, 2018, Higher Power provided the following activity (in thousands):



	2018		2017
Revenues^(a)	$	122,734	$	39,571
Net income^(b)	16,205		5,127

a.Includes intercompany revenues of $111.4 million and $27.4 million, respectively for 2018 and 2017.

b.Includes depreciation and amortization expense of $2.3 million and $2.0 million, respectively, for 2018 and 2017.

The following table presents unaudited pro forma information as if the acquisition of Higher Power had occurred as of January 1, 2017 (in thousands):



	Six Months Ended June 30, 2017
Revenues	$	4,481
Net loss	(411		)

~~(c) Description~~(e) Acquisition 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, all outstanding membership interests 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.~~$103.7 million.

As a result of this transaction, the Company's historical financial information has been recast to combine the ~~Condensed Consolidated Statements~~unaudited condensed consolidated statements of ~~Operations~~operations and the ~~Condensed Consolidated Balance Sheets~~unaudited 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 ~~six months~~year ended ~~June 30,~~December 31, 2017, ~~$1.2~~$1.3 million of transaction related costs ~~was~~were 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)~~(f) Acquisition of ~~Higher Power~~Chieftain

On ~~April 21,~~March 27, 2017, as amended as of May 24, 2017, the Company ~~completed its acquisition of Higher Power~~entered into a Purchase Agreement with Chieftain Sand and Proppant, LLC and Chieftain Sand and Proppant Barron, LLC, unrelated third party sellers (the "Chieftain Sellers"), following the Company's successful bid in a bankruptcy court auction 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 June 30, 2017, $250,000 and $500,000substantially all of the ~~contingent consideration are~~assets of the

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~reflected in the accrued expenses and other current liabilities and other liabilities, respectively.~~Chieftain Sellers (the "Chieftain Assets"). This transaction (the "Chieftain Acquisition") closed on May 26, 2017. Mammoth funded the purchase price for ~~Higher Power~~the Chieftain Assets with cash on hand and borrowings under its revolving credit facility. The ~~acquisition of Higher Power~~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 ~~Company's other energy segment. This acquisition created a new energy infrastructure component~~Union Pacific railroad, which affords access to both the Mid-Continent and Permian basins in support of ~~our other energy services segment, which diversifies our service offerings.~~

~~For~~ the ~~six months ended June 30, 2017 there were $0.1 million transaction related costs expensed.~~Company’s pressure pumping services.

The following table summarizes the fair value of ~~Higher Power~~the Chieftain Acquisition as of ~~April 21, 2017:~~May 26, 2017 (in thousands):

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



	Total
Property, plant and equipment ^(a)	$	23,373
Sand reserves ^(b)	20,910
Total assets acquired	$	44,283

Asset retirement obligation	1,732
Total liabilities assumed	$	1,732
Total allocation of purchase price	$	42,551
Bargain purchase price ^(c,d)	(6,231		)
Total purchase price	$	36,320


a.	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.


b.	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.


c.	Amount reflected in unaudited condensed consolidated statements of comprehensive income (loss) reflected net of income taxes of $2.2 million.


d.	The fair value of the business was determined based on the excess cash flow method, a form of the income approach.

From the acquisition date through June 30, 2018, the Chieftain Assets provided the following activity (in thousands):



	2018		2017
Revenues^(a)	$	35,128	$	22,847
Net income^(b)	10,694		5,520

a.Includes intercompany revenues of $9.6 million and $12.3 million, respectively, for 2018 and 2017

b.Includes depreciation, depletion, amortization and accretion of $2.3 million and $2.8 million, respectively, for 2018 and 2017

The following table presents unaudited pro forma information as if the acquisition of the Chieftain Assets had occurred as of January 1, 2017 (in thousands):



	Six Months Ended June 30, 2017
Revenues	$	1,312
Net loss	(72		)

The Company's historical financial information was adjusted to give pro forma effect to the events that were directly attributable to the Chieftain Acquisition. The Company recognized $0.8 million of transaction related costs during the year ended December 31, 2017 related to this acquisition.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(g) Acquisition of Stingray

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, 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, through its wholly-owned subsidiary Mammoth LLC, all outstanding membership interests in Stingray Cementing LLC ("Cementing") and Stingray Energy Services LLC ("SR Energy") (the “2017 Stingray Acquisition”). 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 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 $25.8 million.

The following tables summarize the fair values of Cementing and SR Energy as of June 5, 2017 (in thousands):



Consideration attributable to Cementing^(a)	$	12,975
Consideration attributable to SR Energy^(a)	12,787
Total consideration transferred	$	25,762

a. See Summary of acquired assets and liabilities below



	SR Energy		Cementing		Total
	(in thousands)
Cash and cash equivalents	$	1,611	$	1,060	$	2,671
Accounts receivable, net	3,913		495		4,408
Receivables from related parties	3,684		1,418		5,102
Inventories	—		306		306
Prepaid expenses	35		32		67
Property, plant and equipment^(a)	13,061		7,459		20,520
Identifiable intangible assets - customer relationships^(b)	—		1,140		1,140
Identifiable intangible assets - trade names^(b)	550		270		820
Goodwill^(c)	3,929		6,264		10,193
Other assets	7		—		7
Total assets acquired	$	26,790	$	18,444	$	45,234

Accounts payable and accrued liabilities	$	5,890	$	2,063	$	7,953
Long-term debt^(d)	5,074		2,000		7,074
Deferred tax liability	3,039		1,406		4,445
Total liabilities assumed	$	14,003	$	5,469	$	19,472
Net assets acquired	$	12,787	$	12,975	$	25,762


a.	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.


b.	⁽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.

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 the assembled workforces and future profitability expected to arise from the acquired ~~entity.~~entities.


d.	Long-term debt assumed was paid off subsequent to the acquisitions.

~~Since~~

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

From the acquisition date ~~Higher Power has~~through June 30, 2018, SR Energy and Cementing provided the following ~~activity:~~activity (in thousands):


	2017			2018						2017
	Higher Power			SR Energy			Cementing			SR Energy			Cementing
Revenues(a)	$	1,709,277		$	16,034		$	5,131		$	11,572		$	7,500
Net loss^(a)(b)	(286,959		)	(1,586		)	(806		)	(1,626		)	(1,963		)


a.	Includes intercompany revenues of $1.6 million and $0.6 million for SR Energy in 2018 and 2017.


b.	a.Includes ~~$340,333 in~~ depreciation and amortization expense of $2.8 million and $1.0 million, respectively, for SR Energy and Cementing in 2018 and $3.4 million and $4.1 million, respectively, for SR Energy and Cementing in 2017.

The following table presents unaudited pro forma information ~~for the Company~~ as if the acquisition of ~~Higher Power~~SR Energy and Cementing had occurred ~~as of~~on January 1, ~~2016:~~2017 (in thousands):


	Six Months Ended June 30, 2017			Year Ended December 31, 2016			Six Months Ended June 30, 2017
Revenues	$	4,481,260		$	10,038,825		$	18,333
Net loss	(411,237		)	(1,189,496		)	(1,612		)

The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the 2017 Stingray Acquisition. 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. The Company recognized $0.2 million of transaction related costs during the year ended December 31, 2017 related to this acquisition.


4.5.	Inventories

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


	June 30,		December 31,		June 30,		December 31,
	2017		2016		2018		2017
Supplies	$	6,592,239	$	4,020,670	$	7,264	$	9,437
Raw materials	149,845		75,971		321		219
Work in process	—		205,450		1,326		2,370
Finished goods	3,574,616		1,822,110		3,806		5,788
Total inventory	$	10,316,700	$	6,124,201	$	12,717	$	17,814

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


5.6.	Property, Plant and Equipment

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


		June 30,		December 31,			June 30,		December 31,
	Useful Life	2017		2016		Useful Life	2018		2017
Pressure pumping equipment						3-5 years	$	199,333	$	190,211
Drilling rigs and related equipment						3-15 years	137,075		132,260
Machinery and equipment^(a)						7-20 years	140,308		97,569
Buildings						15-39 years	47,593		45,992
Vehicles, trucks and trailers^(b)						5-10 years	91,680		54,055
Coil tubing equipment						4-10 years	28,068		28,053
Land		$	11,316,910	$	5,040,482	N/A	14,183		11,317
Land improvements	15 years or life of lease	9,324,179		3,640,976		15 years or life of lease	9,614		9,614
Buildings	15-20 years	44,796,429		42,191,745
Buildings - dry plant facility	39 years	7,872,137		7,806,128
Buildings - wash plant facility	39 years	4,835,148		4,835,148
Drilling rigs and related equipment	3-15 years	149,676,740		138,526,519
Pressure pumping equipment	3-5 years	138,792,153		96,500,592
Coil tubing equipment	4-10 years	28,006,153		28,019,217
Rail improvements	10-20 years	5,962,779		4,276,928		10-20 years	13,101		5,540
Vehicles, trucks and trailers	5-10 years	43,233,579		33,140,599
Machinery and equipment	7-20 years	51,745,514		35,548,357
Other property and equipment	3-12 years	12,424,178		11,461,839		3-12 years	15,006		12,687
		507,985,899		410,988,530			695,961		587,298
Deposits on equipment and equipment in process of assembly		26,817,262		9,427,307			33,349		20,348
		534,803,161		420,415,837			729,310		607,646
Less: accumulated depreciation		207,722,997		178,296,174
Less: accumulated depreciation^(c)							305,995		256,629
Property, plant and equipment, net		$	327,080,164	$	242,119,663		$	423,315	$	351,017


a.	Included in machinery and equipment are assets under capital leases totaling $1.8 million and $1.8 million, respectively, at June 30, 2018 and December 31, 2017.


b.	Included in vehicles, trucks and trailers are assets under capital leases totaling $3.8 million and $1.0 million, respectively, at June 30, 2018 and December 31, 2017.


c.	Accumulated depreciation for assets under capital leases totaled $0.9 million and $0.8 million, respectively, at June 30, 2018 and December 31, 2017.

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 statement of cash flows. For the six months ended June 30, 2018 and 2017, proceeds from the sale of equipment damaged or lost down-hole were ~~$347,844~~$0.6 million and ~~gain~~$0.3 million, respectively, and gains on sales of equipment damaged or lost down-hole ~~was $221,779. There~~ were ~~no proceeds from the sale of equipment damaged or lost down-hole for the six months ended June 30, 2016.~~$0.5 million and $0.2 million, respectively.

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

Three Months Ended June 30, Six Months Ended June 30,
2017 2016 2017 2016
Depreciation expense $ 17,229,471
$ 16,323,309
$ 32,196,269
$ 31,806,631
Accretion expense (see Note 2) 13,976
329
14,409
329
Depletion expense (see Note 2) 382,202
219,227
384,472
219,227
Amortization expense (see Note 6) 2,267,750
2,267,750
4,535,500
4,535,500
Depreciation, depletion, accretion and amortization $ 19,893,399
$ 18,810,615
$ 37,130,650
$ 36,561,687



	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Depreciation expense^(a)	$	27,058	$	17,229	$	51,456	$	32,196
Depletion expense	1,340		382		1,427		384
Amortization expense	2,382		2,268		4,790		4,536
Accretion expense	15		14		30		14
Depreciation, depletion, amortization and accretion	$	30,795	$	19,893	$	57,703	$	37,130


a.	Includes depreciation expense for assets under capital leases totaling $0.4 million and $0.2 million, respectively, for the six months ended June 30, 2018 and 2017.

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


6.7.	~~Goodwill and~~ Intangible Assets and Goodwill

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


	June 30,		December 31,		June 30,			December 31,
	2017		2016		2018			2017
Customer relationships	$	35,798,000	$	33,605,000	$	36,725		$	35,795
Trade names	8,490,000		7,110,000		9,443			8,793
Less: accumulated amortization - customer relationships	21,835,228		17,655,228		(30,521		)	(26,172		)
Less: accumulated amortization - trade names	1,848,443		1,492,943		(2,717		)	(2,277		)
Intangible assets, net	$	20,604,329	$	21,566,829	$	12,930		$	16,139

Amortization expense for intangible assets was ~~$4,535,500~~$4.8 million and ~~$4,535,500~~$4.5 million, respectively, for the six months ended June 30, ~~2017~~2018 and ~~2016, respectively.~~2017. The original life of customer relationships ~~range~~ranges from 4 to 10 years with a remaining average useful life of ~~4.56~~3.9 years. ~~Trade~~The original life of trade names ~~are amortized over~~ranges from 10 to 20 years with a ~~10 year~~remaining average useful life ~~and as~~ of ~~June 30, 2017 the remaining useful life was 8.78~~9.1 years.

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


Year ended December 31:	Amount
Remainder of 2017	$	4,694,216
2018	8,541,434
			Amount
Remainder of 2018			$	3,969
2019	1,055,932		1,293
2020	1,055,932		1,293
2021	1,050,180		1,288
2022			1,266
Thereafter	4,206,635		3,821
	$	20,604,329	$	12,930

Goodwill was ~~$99,562,761~~$101.5 million and ~~$88,726,875~~$99.8 million, respectively, at June 30, ~~2017~~2018 and December 31, ~~2016, respectively.~~2017. Changes in the goodwill for the year ended December 31, ~~2016~~2017 and the six months ended June 30, ~~2017~~2018 are set forth ~~below:~~below (in thousands):

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
Balance, June 30, 2017 $ 99,562,761



Balance, January 1, 2017	$	88,727
Additions - 2017 Stingray Acquisition (Note 4)	10,193
Additions - Higher Power Acquisition (Note 4)	643
Additions - 5 Star Acquisition (Note 4)	248
Balance, December 31, 2017	99,811
Additions - WTL Acquisition (Note 4)	1,567
Additions - RTS Acquisition (Note 4)	133
Balance, June 30, 2018	$	101,511

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


7.8.	Accrued Expenses and Other Current Liabilities

Accrued expense and other current liabilities included the ~~following:~~following (in thousands):

June 30, December 31,
2017 2016
Accrued compensation, benefits and related taxes $ 3,670,536
$ 2,432,093
Financed insurance premiums 978,122
3,293,859
State & local taxes payable 920,566
319,597
Insurance reserves 1,491,300
971,351
Other 3,129,570
1,529,298
Total $ 10,190,094
$ 8,546,198

~~MAMMOTH ENERGY SERVICES, INC.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~



	June 30,		December 31,
	2018		2017
Deferred revenue	15,100		15,210
Accrued compensation, benefits and related taxes	19,917		11,552
Financed insurance premiums	1,638		4,876
Insurance reserves	4,183		2,942
State and local taxes payable	8,205		2,126
Other	5,658		4,189
Total	$	54,701	$	40,895

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. As of June 30, 2018 and December 31, 2017, the applicable interest rate associated with financed insurance premiums was 2.75%.


8.9.	Debt

Mammoth Credit Facility

On November 25, 2014, Mammoth entered into a revolving credit and security agreement with a syndicate of banks that provides for maximum borrowings 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.~~$0.5 million. 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 the line as a percentage of the maximum credit limit. The deferred loan costs associated with this facility are classified in other non-current assets.

At June 30, 2018, there were no outstanding borrowings under the credit facility and $162.7 million of available borrowing capacity, after giving effect to $6.5 million of outstanding letters of credit. At December 31, 2017, ~~$57,000,000~~there were outstanding borrowings under the credit facility of ~~the $65,000,000 outstanding balance~~$99.9 million, leaving an aggregate of $62.8 million of borrowing capacity under the facility, ~~was in a one month LIBOR rate option tranche with an interest rate~~after giving effect to $6.5 million of ~~3.72% and $8,000,000~~outstanding letters of ~~the outstanding balance was at the base rate with an interest rate of 5.75%. As of June 30, 2017, Mammoth had availability of $104,664,874.~~

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

The Mammoth facility also contains various customary affirmative 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 June 30, ~~2017~~2018 and December 31, ~~2016,~~2017, the Company was in compliance with ~~its~~the financial covenants under the facility.


9.	~~Income Taxes~~

As discussed in Note 1, the Partnership was converted into a limited liability company on October 12, 2016 and the membership interests in the limited liability company were contributed to the Company. As a result, the Company will file a consolidated return 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.Sturgeon Credit Facility

~~The components of income tax (benefit) expense attributable to the Company for the six months ended~~On June 30, ~~2017~~2015, Sturgeon entered in to a three-year $25.0 million revolving line of credit secured by substantially all of the assets of Sturgeon (“the Sturgeon revolver”). Advances under the Sturgeon revolver bore interest at 2% plus the greater of (a) the Base Rate as set by the lender's commercial lending group, (b) the sum of the Federal Funds Open Rate plus one half of one percent and ~~2016, are as follows:~~

Three Months Ended June 30, Six Months Ended June 30,
2017 2016 2017 2016
U.S. current income tax (benefit) expense $ —
$ (12,880 ) $ —
$ (12,880 )
U.S. deferred income tax (benefit) expense (2,810,993 ) 9,786
(6,496,374 ) 9,786
Foreign current income tax expense 21,089
759,824
606,556
1,654,184
Foreign deferred income tax (benefit) expense (14,173 ) 32,645
(20,324 ) 32,645
Total $ (2,804,077 ) $ 789,375
$ (5,910,142 ) $ 1,683,735
(c) the sum of the Daily LIBOR rate. Additionally, at Sturgeon’s request, advances could be obtained at LIBOR plus 3%. The LIBOR rate option allowed Sturgeon to select interest periods from one, two, three or six month LIBOR futures spot rates. The Sturgeon revolver was terminated on June 6, 2017.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


10.	Other Liabilities

~~A reconciliation of~~

Other liabilities included the ~~statutory federal income tax amount to the recorded expense is as follows:~~following (in thousands):

Six Months Ended June 30,
2017 2016
Loss before income taxes, as reported $ (12,060,936 ) $ (30,084,571 )
Bargain purchase gain (4,011,512 ) —
Loss before income taxes, as taxed (16,072,448 ) (30,084,571 )
Statutory income tax rate 35 % 35 %
Expected income tax benefit (5,625,357 ) (10,529,600 )
Non-taxable entity —
12,685,647
Other permanent differences 60,231
21,535
State tax benefit (807,139 ) (3,301 )
Foreign tax credit (907,171 ) —
Foreign earnings not in book income 1,542,732
—
Foreign income tax rate differential (173,438 ) (497,438 )
Other —
6,892
Total $ (5,910,142 ) $ 1,683,735



	June 30,			December 31,
	2018			2017
Capital lease obligations	$	4,253		$	2,015
Equipment financing arrangement	1,436			1,605
Other	250			500
Total	5,939			4,120
Less: Current portion of capital lease and equipment financing obligations included in accrued expenses and other current liabilities	(1,839		)	(831		)
Total Other Liabilities	$	4,100		$	3,289

~~Deferred tax assets~~The Company leases vehicles and ~~liabilities attributable to~~other equipment under capital leases with varying terms and expiration dates through 2020. The weighted average implied interest rate under our capital leases as of June 30, 2018 and December 31, 2017 was 14.2% and 19.1%, respectively. Additionally, the Company ~~consisted~~entered into a five-year equipment financing arrangement maturing in 2022 that bears interest at 4.6% as of June 30, 2018. Principal and interest on capital leases and the ~~following:~~equipment financing arrangement are paid monthly. Aggregate future payments under the Company's non-cancelable capital leases and equipment financing arrangement as of June 30, 2018 are as follows (in thousands):

June 30, December 31,
2017 2016
Deferred tax assets:
Allowance for doubtful accounts $ 1,975,186
$ 1,892,761
Net operating loss carryforward 8,060,506
—
Deferred stock compensation 1,716,754
1,686,671
Accrued liabilities 1,654,190
746,132
Other 1,331,091
1,785,999
Deferred tax assets 14,737,727
6,111,563

Deferred tax liabilities:
Property and equipment $ (55,624,122 ) $ (42,525,793 )
Intangible assets (6,784,966 ) (7,662,590 )
Unrepatriated foreign earnings (4,575,485 ) (3,451,110 )
Other (60,302 ) (142,859 )
Deferred tax liabilities (67,044,875 ) (53,782,352 )
Net deferred tax liability $ (52,307,148 ) $ (47,670,789 )

Reflected in accompanying balance sheet as:
Deferred income taxes $ (52,307,148 ) $ (47,670,789 )



2018	$	890
2019	2,593
2020	1,696
2021	664
2022	360
Total future minimum payments	6,203
Less interest payments	(514		)
Present value of future minimum payments	$	5,689


~~10.~~11.	~~Earnings Per Share~~Variable Interest Entity

~~Common Stock Offering~~

On April 6, 2018, Dire Wolf Energy Services LLC ("Dire Wolf"), a wholly owned subsidiary of the Company, entered into a Voting Trust Agreement with TVPX Aircraft Solutions Inc. (the "Voting Trustee"). Under the Voting Trust Agreement, Dire Wolf transferred 100% of its membership interest in Cobra Aviation Services LLC ("Cobra Aviation") to the Voting Trustee in exchange for Voting Trust Certificates. Dire Wolf retained the obligation to absorb all expected returns or losses of Cobra Aviation. Prior to the transfer of membership interest to the Voting Trustee, Cobra Aviation was a wholly owned subsidiary of Dire Wolf. Cobra Aviation owns and operates a helicopter primarily for services provided to Cobra Acquisitions, a wholly owned subsidiary of the Company. Dire Wolf entered into the Voting Trust Agreement in order to meet certain registration requirements.

~~On October 14, 2016, Mammoth Inc.’s common stock began trading~~Dire Wolf's voting rights are not proportional to its obligation to absorb expected returns or losses of Cobra Aviation and all of Cobra Aviation's activities are conducted on ~~The Nasdaq Global Select Market under~~behalf of Dire Wolf, which has disproportionately fewer voting rights; therefore, Cobra Aviation meets the ~~symbol “TUSK.” On October 19, 2016,~~criteria of a VIE. Cobra Aviation's operational activities are directed by Dire Wolf's officers and Dire Wolf has the option to terminate the Voting Trust Agreement at any time. Therefore, the Company, ~~closed~~through Dire Wolf, is considered the ~~IPO~~primary beneficiary of ~~7,750,000 shares of common stock~~the VIE and consolidates Cobra Aviation at ~~$15.00 per share. Net proceeds to Mammoth Inc. from its sale of 7,500,000 shares of common stock were approximately $103.1 million.~~June 30, 2018.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


12.	Selling, General and Administrative Expense

~~The authorized capital stock~~

Selling, general and administrative ("SG&A") expense includes of the ~~Company consists~~following (in thousands):



	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Cash expenses:
Compensation and benefits	$	10,978	$	2,966	$	18,677	$	5,381
Professional services	2,981		1,652		5,568		3,581
Other^(a)	3,935		2,015		5,542		3,880
Total cash SG&A expense	17,894		6,633		29,787		12,842
Non-cash expenses:
Bad debt provision	28,263		17		53,790		(25		)
Equity based compensation^(b)	17,487		—		17,487		—
Stock based compensation	1,483		1,050		2,574		1,620
Total non-cash SG&A expense	47,233		1,067		73,851		1,595
Total SG&A expense	$	65,127	$	7,700	$	103,638	$	14,437


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


b.	Represents compensation expense for non-employee awards, which were issued and are payable by certain affiliates of Wexford (the sponsor level). See Note 15 for additional detail.


13.	Income Taxes

The components of ~~200 million shares of common stock, par value $0.01 per share, and 20 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 conversion of the Partnership into Mammoth LLC, a limited liability company, in October 2016, the common units were converted into an equal number of membership interests in Mammoth LLC. Finally, when Mammoth Holdings, Gulfport and Rhino contributed their 30,000,000 membership interests in Mammoth LLCincome tax expense (benefit) attributable to the Company ~~in connection with~~for the IPO, the Company issued to them an aggregate of 30,000,000 shares of the Company's common stock. Accordingly, for purposes of comparability of earnings per equity security, the amount of outstanding equity was the same for all periods presented.three and six months ended June 30, 2018 and 2017, are as follows (in thousands):

Three Months Ended June 30, Six Months Ended June 30,
2017 2016 2017 2016
Basic loss per share:
Allocation of earnings:
Net loss $ (1,169,515 ) $ (8,403,337 ) $ (6,150,794 ) $ (31,768,306 )
Weighted average common shares outstanding 39,500,000
30,000,000
38,505,525
30,000,000
Basic loss per share $ (0.03 ) $ (0.28 ) $ (0.16 ) $ (1.06 )

Diluted loss per share:
Allocation of earnings:
Net loss $ (1,169,515 ) $ (8,403,337 ) $ (6,150,794 ) $ (31,768,306 )
Weighted average common shares, including dilutive effect^(a)
39,500,000
30,000,000
38,505,525
30,000,000
Diluted loss per share $ (0.03 ) $ (0.28 ) $ (0.16 ) $ (1.06 )



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Foreign current income tax expense	$	67,665		$	21		$	125,712		$	606
Foreign deferred income tax benefit	(15,266		)	(14		)	(25,386		)	(20		)
U.S. current income tax expense	1,636			—			1,624			—
U.S. deferred income tax benefit	(523		)	(2,811		)	(2,520		)	(6,496		)
Total	$	53,512		$	(2,804	)	$	99,430		$	(5,910	)

The Company's effective tax rate was 50% and 37%, respectively, for the six months ended June 30, 2018 and 2017. The increase in the effective tax rate is primarily due to the equity based compensation expense recognized during the six months ended June 30, 2018 as well as a higher tax rate in Puerto Rico, where most of our income was generated during the six months ended June 30, 2018, compared to the United States tax rate. No income was generated in Puerto Rico during the six months ended June 30, 2017. Additionally, the Company's effective tax rate can fluctuate as a result of, among other things, discrete items, state income taxes, permanent differences and changes in pre-tax income.

A valuation allowance for deferred tax assets is recognized when it is more likely than not that the benefit of deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgments regarding future taxable income, as well as the jurisdiction in which such taxable income is generated, to determine whether a valuation allowance is required. During the six months ended June 30, 2018, the Company recorded a change in valuation allowance of $9.2 million related to foreign tax credits that are not expected to be utilized.

On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act (the “Tax Act”). As a result, the Company recorded a provisional amount for effects of the Tax Act totaling $31.0 million during the fourth quarter of 2017. The Company continues to evaluate the impact of the Tax Act and no revisions were recorded to the provisional amount during the six months ended June 30, 2018. The Company expects to complete its detailed analysis of the effects of the Tax Act no later than the fourth quarter of 2018.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


14.	Earnings (Loss) Per Share

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



	Three Months Ended June 30,					Six Months Ended June 30,
	2018		2017			2018		2017
Basic earnings (loss) per share:
Allocation of earnings:
Net income (loss)	$	42,700	$	(1,170	)	$	98,246	$	(6,151	)
Weighted average common shares outstanding	44,737		39,500			44,700		38,506
Basic earnings (loss) per share	$	0.95	$	(0.03	)	$	2.20	$	(0.16	)

Diluted earnings (loss) per share:
Allocation of earnings (loss):
Net income (loss)	$	42,700	$	(1,170	)	$	98,246	$	(6,151	)
Weighted average common shares, including dilutive effect^(a)	45,059		39,500			44,977		38,506
Diluted earnings (loss) per share	$	0.95	$	(0.03	)	$	2.18	$	(0.16	)


^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~~

The Company’s pro forma basic and diluted earnings per share amounts have been computed based on the weighted-average number 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:

~~MAMMOTH ENERGY SERVICES, INC.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

Three Months Ended Six Months Ended
June 30, 2016 June 30, 2016
Pro Forma C Corporation Data (unaudited):
Net loss, as reported $ (7,613,962 ) $ (30,084,571 )
Pro forma benefit for income taxes (2,342,467 ) (3,287,051 )
Pro forma net loss $ (5,271,495 ) $ (26,797,520 )

Basic loss per share:
Allocation of earnings:
Net loss $ (5,271,495 ) $ (26,797,520 )
Weighted average common shares outstanding 37,500,000
37,500,000
Basic loss per share $ (0.14 ) $ (0.71 )

Diluted loss per share:
Allocation of earnings:
Net loss $ (5,271,495 ) $ (26,797,520 )
Weighted average common shares, including dilutive effect ^(a)
37,500,000
37,500,000
Diluted loss per share $ (0.14 ) $ (0.71 )


^(a)	~~No incremental shares of potentially dilutive restricted stock awards were included for periods presented~~three and six months ended June 30, 2017 as their effect was antidulitive under the treasury stock method.


~~11.~~15.	Equity Based Compensation

Upon formation of certain ~~Operating Entities (including the acquired Stingray Entities),~~operating entities by Wexford, Gulfport and Rhino, 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 Entities~~operating entities to Mammoth. ~~Awards are~~These awards were not granted in limited or general partner units. ~~Agreements~~The awards are for ~~interest~~interests in the distributable earnings of ~~Mammoth Holdings,~~the members of MEH Sub, Mammoth’s majority equity holder.

On the IPO closing date, ~~Mammoth Holdings~~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~~

On June 29, 2018, as part of an underwritten secondary public offering, MEH Sub sold 2,764,400 shares of the Company’s common stock at a purchase price to ~~recover outstanding unreturned capital remain not probable.~~MEH Sub of $38.01 per share. MEH Sub received the proceeds from this offering. As a result, a portion of the Non-Employee Member awards reached Payout. During the three months ended June 30, 2018, the Company recognized equity compensation expense totaling $17.5 million related to these non-employee awards. These awards are at the sponsor level and this transaction had no dilutive impact or cash impact to the Company.

Payout for the remaining awards is expected to occur following ~~the sale~~additional sales by ~~Mammoth Holding's~~MEH Sub of its shares of the Company's common stock, which is 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-Employees~~Non-Employee Member awards, the unrecognized ~~cost,~~amount, which represents the fair value of the awards as of June 30, ~~2017~~2018 was ~~$47,168,561.~~$43.1 million.


~~12.~~16.	Stock Based Compensation

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

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'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 Shares		Weighted Average Grant-Date Fair Value			Number of Unvested Restricted Shares		Weighted Average Grant-Date Fair Value
Unvested shares as of January 1, 2017	282,780		$	14.98
Unvested shares as of January 1, 2018						640,632		$	19.44
Granted	390,587		21.19			93,556		26.83
Vested	(2,233	)	(17.42		)	(149,098	)	21.29
Forfeited	(8,888	)	(15.00		)	—		—
Unvested shares as of June 30, 2017	662,246		$	18.63
Unvested shares as of June 30, 2018						585,090		$	21.07

As of June 30, ~~2017,~~2018, there was ~~$10,326,977~~$9.2 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 ~~2.5~~1.8 years.

Included in cost of revenue and selling, general and administrative expenses is ~~stock-based~~stock based compensation expense of ~~$1,050,062~~$1.7 million and ~~$1,619,893~~$1.1 million, respectively, for the three months ended June 30, 2018 and 2017 and $2.9 million and $1.6 million, respectively, for the six months ended June 30, ~~2017, respectively.~~2018 and 2017.

~~MAMMOTH ENERGY SERVICES, INC.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~


~~13.~~17.	Related Party Transactions

Transactions between the subsidiaries of the Company and 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"~~Toro”); Cementing and SR Energy (collectively, prior to the 2017 Stingray Acquisition, the ~~"2017~~“2017 Stingray ~~Companies"~~Companies”); Everest Operations Management LLC ~~("Everest"~~(“Everest”); Elk City Yard LLC ("(“Elk City ~~Yard"~~Yard”); Double Barrel Downhole Technologies LLC ~~("DBDHT"); Orange Leaf Holdings LLC ("Orange Leaf"~~(“DBDHT”); Caliber Investment Group LLC ~~("Caliber"~~(“Caliber”); ~~and~~ Dunvegan North Oilfield Services ULC (“Dunvegan”); Predator Drilling LLC (“Predator”); and T&E Flow Services LLC (“T&E”).

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


		REVENUES								ACCOUNTS RECEIVABLE					REVENUES								ACCOUNTS RECEIVABLE
		Three Months Ended June 30,				Six Months Ended June 30,				At June 30,		At December 31,			Three Months Ended June 30,				Six Months Ended June 30,				At June 30,			At December 31,
		2017		2016		2017		2016		2017		2016			2018		2017		2018		2017		2018			2017
Pressure Pumping and Gulfport	(a)	$	41,099,441	$	38,165,558	$	72,845,391	$	38,165,558	$	28,596,696	$	19,094,509	(a)	$	33,831	$	41,100	$	72,377	$	72,845	$	20,127		$	25,054
Muskie and Gulfport	(b)	13,605,124		9,313,266		25,145,543		11,231,344		8,151,536		5,373,007		(b)	9,730		13,605		21,192		25,145		4,428			1,947
Panther Drilling and Gulfport	(c)	951,439		769,147		1,993,816		1,221,022		1,016,589		1,434,036		(c)	—		952		56		1,994		12			872
Cementing and Gulfport	(d)	903,317		—		903,317		—		1,767,432		—		(d)	2,048		903		4,876		903		1,739			2,255
SR Energy and Gulfport	(e)	1,565,211		—		1,565,211		—		6,011,500		—		(e)	4,626		1,565		11,579		1,565		4,292			3,348
Lodging and Grizzly	(f)	261		17		525		572		283		274
Bison Drilling and El Toro	(g)	—		—		—		371,873		—		—
Panther Drilling and El Toro	(g)	—		1,449		—		171,619		—		—		(f)	—		—		345		—		—			—
Bison Trucking and El Toro	(g)	—		—		—		130,000		—		—
White Wing and El Toro	(g)	—		—		—		20,431		—		—
Energy Services and El Toro	(h)	34,100		249,193		157,745		249,193		35,853		108,386
White Wing and Diamondback	(i)	—		—		—		1,650		—		—
Redback Energy and El Toro														(g)	92		34		92		158		—			—
Coil Tubing and El Toro	(j)	—		318,694		—		318,694		—		—		(h)	—		—		360		—		(2		)	—
Panther and DBDHT	(k)	8,474		—		13,689		—		11,972		100,450
Consolidated and 2017 Stingray Companies	(l)	40,516		—		84,722		—		—		1,363,056
Bison Drilling and Predator														(i)	—		—		—		—		—			234
Other Relationships		—		—		—		—		95,124		115,565			14		49		14		100		78			78
		$	58,207,883	$	48,817,324	$	102,709,959	$	51,881,956	$	45,686,985	$	27,589,283		$	50,341	$	58,208	$	110,891	$	102,710	$	30,674		$	33,788


a.	Pressure Pumping provides pressure pumping, stimulation and related completion services to ~~Gulfport, dedicating two spreads and related equipment for the performance of these services.~~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~~Panther provides services for El Toro, an entity controlled by Wexford, pursuant to a master service agreement.


h.g.	Redback 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.h.	Coil Tubing provides to El Toro services in connection with completion and drilling activities.


k.i.	~~Panther~~Bison Drilling provides ~~services and materials~~equipment rentals to ~~DBDHT.~~


l.	~~The Company provided certain services to the 2017 Stingray Companies.~~Predator, an entity in which Wexford owns a minority interest.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

COST OF REVENUE ACCOUNTS PAYABLE
Three Months Ended June 30, Six Months Ended June 30, At June 30, At December 31,
2017 2016 2017 2016 2017 2016
Panther and DBDHT (a) $ 58
$ 2,444
$ 127,778
$ 48,998
$ —
$ —
Bison Trucking and Diamondback (b) 28,390
42,331
66,522
83,958
—
—
Energy Services and Elk City Yard (c) 26,700
26,700
53,400
53,400
—
—
Lodging and Dunvegan (d) —
2,453
—
2,453
—
3,199
Bison Trucking and El Toro (e) —
5,000
—
5,000
—
—
Consolidated and 2017 Stingray Companies (f) 207,044
1,563
444,409
3,728
—
174,145
$ 262,192
$ 80,491
$ 692,109
$ 197,537
$ —
$ 177,344

SELLING, GENERAL AND ADMINISTRATIVE COSTS
Consolidated and Everest (g) $ 49,804
$ 63,431
$ 108,117
$ 135,755
$ 23,818
$ 12,668
Consolidated and Wexford (h) 164,414
100,336
398,294
136,257
50,185
13,197
Mammoth and Orange Leaf (i) 16,276
53,331
45,786
53,331
—
—
Mammoth and Caliber (j) 71,998
—
71,998
—
43,608
—
Sand Tiger and Grizzly (k) 4,047
—
4,047
—
1,820
—
Lodging and Dunvegan (d) 91
—
2,642
—
752
—
$ 306,630
$ 217,098
$ 630,884
$ 325,343
$ 120,183
$ 25,865
$ 120,183
$ 203,209



		Three Months Ended June 30,					Six Months Ended June 30,				At June 30,		At December 31,
		2018			2017		2018		2017		2018		2017
		COST OF REVENUE					COST OF REVENUE				ACCOUNTS PAYABLE
Cobra and T&E	(a)	$	1,486		$	—	$	2,762	$	—	$	289	$	457
Higher Power and T&E	(a)	950			—		1,458		—		576		3
Panther and DBDHT	(b)	—			—		—		128		—		77
The Company and 2017 Stingray Companies	(c)	—			207		—		444		—		—
Other		(8		)	55		—		120		—		218
		$	2,428		$	262	$	4,220	$	692	$	865	$	755

		SELLING, GENERAL AND ADMINISTRATIVE COSTS					SELLING, GENERAL AND ADMINISTRATIVE COSTS
The Company and Everest	(d)	$	55		$	50	$	86	$	108	$	6	$	19
The Company and Wexford	(e)	290			165		473		398		78		150
The Company and Caliber	(f)	145			72		346		72		47		1
Other		42			20		56		53		—		2
		$	532		$	307	$	961	$	631	$	131	$	172

		CAPITAL EXPENDITURES					CAPITAL EXPENDITURES
Cobra and T&E	(a)	$	757		$	—	$	1,131	$	—	$	170	$	66
Higher Power and T&E	(a)	1,575			—		2,773		—		750		385
		$	2,332		$	—	$	3,904	$	—	$	920	$	451
											$	1,916	$	1,378


a.	Cobra and Higher Power purchase materials and services from T&E, an entity in which a member of management's family owns a minority interest.


b.	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.d.	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.e.	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.f.	Caliber leases office space to Mammoth.


k.	~~Grizzly provides certain administrative and analytical services to the Company.~~

On June 29, 2018, Gulfport and certain entities controlled by Wexford (the "Selling Stockholders") completed an underwritten secondary public offering of 4,000,000 shares of the Company’s common stock at a purchase price to the Selling Stockholders of $38.01 per share. The Selling Stockholders received all proceeds from this offering. The Company incurred costs of approximately $0.7 million related to the secondary public offering during the three months ended June 30, 2018.


~~14.~~18.	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.~~2062.

Minimum Purchase Commitments

~~We have~~The Company has entered into agreements with ~~sand~~ suppliers that contain minimum purchase obligations. ~~Our failure~~Failure to purchase the minimum ~~tonnage would~~amounts may require usthe Company 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

The Company has entered into agreements with suppliers to acquire capital equipment.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Aggregate future minimum payments under these obligations in effect at June 30, ~~2017~~2018 are as ~~follows:~~follows (in thousands):


Year ended December 31:	Operating Leases		Capital Spend Commitments		Minimum Purchase Commitments		Operating Leases		Capital Spend Commitments		Minimum Purchase Commitments
Remainder of 2017	$	5,486,024	$	22,730,189	$	6,689,581
2018	9,177,272		—		10,866,000
Remainder of 2018							$	12,148	$	16,393	$	19,254
2019	8,075,402		—		10,866,000		18,091		—		12,125
2020	5,597,885		—		—		15,622		—		400
2021	2,645,182		—		—		12,029		—		165
2022							8,995		—		—
Thereafter	3,721,249		—		—		6,057		—		—
	$	34,703,014	$	22,730,189	$	28,421,581	$	72,942	$	16,393	$	31,944

For the six months ended June 30, ~~2017~~2018 and ~~2016,~~2017, the Company recognized rent expense of~~$4,247,896~~ $10.2 million and ~~$4,079,662,~~$4.2 million, respectively.

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



	June 30,		December 31,
	2018		2017
Environmental remediation	$	3,582	$	3,582
Insurance programs	2,486		2,486
Rail car commitments	455		455
Total letters of credit	$	6,523	$	6,523

The Company has insurance coverage for physical partial loss to its assets, employer’s liability, automobile liability, commercial general liability, workers’ compensation and insurance for other specific risks. The Company has also elected in some cases to accept a greater amount of risk through increased deductibles on certain insurance policies. As of June 30, ~~2017~~2018 and December 31, ~~2016,~~2017, the ~~policy requires~~policies require a ~~per~~ deductible per occurrence of ~~$250,000.~~up to $0.3 million. The Company establishes liabilities for the unpaid deductible portion of claims incurred relating to physical loss to its assets, employer's liability, automobile liability, commercial general liability and workers’ compensation ~~and auto liability~~ based on estimates. As of June 30, ~~2017~~2018 and December 31, ~~2016,~~2017, the policies contained an aggregate stop loss of ~~$2,000,000.~~$2.0 million. 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.~~2018. These estimates may change in the near term as actual claims continue to develop. As of June 30, ~~2017~~2018 and December 31, ~~2016,~~2017, accrued insurance claims were ~~$1,491,300~~$4.2 million and ~~$971,351,~~$2.9 million, respectively. ~~In connection with~~

Pursuant to certain customer contracts in our infrastructure services segment, the ~~insurance programs, letters~~Company warrants equipment and labor performed under the contracts for a specified period following substantial completion of ~~credit of $1,636,000 and $1,285,000~~the work. Generally, the warranty is for one year or less. No liabilities were accrued as of June 30, ~~2017~~2018 and December 31, ~~2016, respectively, have been issued supporting~~2017 and no expense was recognized during the ~~retained risk exposure.~~six months ended June 30, 2018 or 2017 related to warranty claims. However, if warranty claims occur, the Company could be required to repair or replace warrantied items, which in most cases are covered by warranties extended from the manufacturer of the equipment. In the event the manufacturer of equipment failed to perform on a warranty obligation or denied a warranty claim made by the Company, the Company could be required to pay for the cost of the repair or replacement.

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

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

incurs. As of June 30, ~~2017, in connection with environmental remediation programs, letters~~2018, outstanding bid bonds and performance and payment bonds totaled $1.1 million and $1.6 million, respectively. The estimated the cost to complete projects secured by the performance and payment bonds totaled $0.6 million as of ~~credit of $3,363,627 have been issued supporting the retained risk exposure.~~June 30, 2018. As of ~~both June 30, 2017 and~~ December 31, ~~2016, these letters of credit were collateralized by substantially all of~~2017, the ~~assets of the Company.~~Company did not have any outstanding bid bonds or performance and payment bonds.

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 deferred~~Ohio. The Company is appealing the ~~hearing until 2017. While the Company~~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 ~~financial position or results of operations of the Company.~~

On June 3, 2015, a putative class and collective action lawsuit alleging 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, LLC in the U.S. District Court Southern District of Ohio Eastern Division. The parties have reached a settlement of this matter which received preliminary approval from the court in February 2017. This settlement, if it receives final approval at a fairness hearing in August 2017, will not have a material impact on the Company’s financial position, results of operations or cash flows.

On December 2, 2015, 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 filed titled John Talamantez, 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.

~~MAMMOTH ENERGY SERVICES, INC.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

On June 22, 2016, a putative, Title VII discrimination, and Oklahoma anti-discrimination lawsuit alleging that Redback 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. 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’sCompany's financial position, results of operations or cash flows.

On August 1, 2016, a putative class and collective action lawsuit alleging that Redback Energy ~~Services~~ 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 able to predict the outcome~~parties reached a settlement of this ~~lawsuit or whether it will~~matter in April 2017. The settlement was paid and did not 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 al in the U.S. District Court Western District of Texas. The Company is evaluating the background facts at this time. The parties have agreed to stay discovery while they engage in settlement discussions. The Company is not able to predict the outcome of this lawsuit or whether it will have a material impact on the Company’sCompany's financial position, results of operations or cash flows.

On January 26, 2017, a collective action lawsuit alleging that Stingray Pressure Pumping LLC ("Pressure Pumping") failed to pay a class of workers in compliance with the Fair Labor Standards Act was filed titled Ryan Crosby vs. Stingray Pressure Pumping LLC, 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.~~

On May 4, 2017, a complaint alleging a former employee was not paid a yearly bonus was filed titled Lawrence Dehoff v. Redback Coil Tubing, L.L.C. in the Judicial District Court at Law 2 for 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.

On May 8, 2017, a complaint alleging breach of contract was filed titled Philadelphia Indemnity Insurance Co. vs. Stingray Energy Services, LLC in the Commonwealth Pleas Court Belmont County, Ohio. 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.

On June 27, 2017, a complaint alleging negligence, as a result 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. This matter is covered by insurance and did not have a material impact on the Company’s financial position, results of operations or cash flows.

On June 27, 2018, the Company's registered agent notified the Company that it had been served with a putative class action lawsuit titled Wendco of Puerto Rico Inc.; Multisystem Restaurant Inc.; Restaurant Operators Inc.; Apple Caribe, Inc.; on their own behalf and in representation of all businesses that conduct business in the Commonwealth of Puerto Rico vs. Mammoth Energy Services Inc.; Cobra Acquisitions, LLC; D. Grimm Puerto Rico, LLC; Aseguradoras A, B & C; John Doe; Richard Doe, in the Commonwealth of Puerto Rico Superior Court of San Juan. The plaintiffs allege negligent acts by the defendants caused an electrical failure in Puerto Rico resulting in damages of at least $300 million. The Company believes this claim is ~~evaluating~~without merit and will vigorously defend the action. However, the Company continues to evaluate 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~~Company's financial position, results of operations or cash flows.

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

Defined contribution plan

The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at their date of hire. The plan allows eligible employees to contribute up to 92% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes discretionary matching contributions of up to 4%3% of an employee’s compensation and may make additional discretionary contributions for eligible employees. For the three and six months ended June 30, ~~2017 and 2016,~~2018, the Company paid $0$1.8 million and ~~$102,230,~~$3.4 million, respectively, in contributions to the plan.

The Company did not make contributions to the plan during the three and six months ended June 30, 2017.


~~15.~~19.	~~Operating~~Reporting Segments

~~MAMMOTH ENERGY SERVICES, INC.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~The Company is organized into five~~As of June 30, 2018, our 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.~~segments. The Company principally provides ~~oilfield~~energy services in connection with on-shore drilling of oil and natural gas wells for small to large domestic independent oil and ~~nature~~natural gas ~~producers. The Company’s five segments consist of pressure pumping~~producers and electric infrastructure services ~~("Pressure Pumping Services"), well services ("Well Services"), natural sand proppant ("Sand"), contract land~~to government-funded utilities, private utilities, public investor-owned utilities and ~~directional drilling services ("Drilling") and other energy services ("Other Energy Services").~~co-operative utilities.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The Company's Chief Executive Officer and Chief Financial Officer comprise the Company's Chief Operating Decision Maker function ("CODM"). Segment information is prepared on the same basis that the CODM manages the segments, evaluates the segment financial statements and makes key operating and resource utilization decisions. Segment evaluation is determined on a quantitative basis based on a function of ~~revenue and earnings before interest, other expense (income)~~operating income (loss), ~~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 on~~As of June 30, 2018, the ~~CODM's assessment, effective December 31, 2016, the Company reorganized the~~Company’s four reportable segments ~~to align with its new management reporting structure~~include pressure pumping services ("Pressure Pumping"), infrastructure services ("Infrastructure"), natural sand proppant services ("Sand") and ~~business activities. Prior to this reorganization, the existing reportable segments were comprised of four segments for financial reporting purposes:~~contract land and directional drilling services ~~completion~~("Drilling").

The pressure pumping services segment provides hydraulic fracturing services primarily in the Utica Shale of Eastern Ohio, Marcellus Shale in Pennsylvania, Permian Basin in Texas and ~~production~~the mid-continent region in Oklahoma. The infrastructure services ~~completion~~segment provides electric utility infrastructure services to government-funded utilities, private utilities, public investor-owned utilities and ~~production - natural~~co-operative utilities in Puerto Rico and the northeast, southwest and midwest portions of the United States. The sand ~~proppant~~segment mines, processes and sells sand for use in hydraulic fracturing. The sand segment primarily services the Utica Shale, Permian Basin, SCOOP, STACK and Montney Shale in British Columbia and Alberta, Canada. The contract land and directional drilling services segment provides vertical, horizontal and directional drilling services primarily in the Permian Basin in West Texas.

The Company also provides coil tubing services, pressure control services, flowback services, cementing services, equipment rental services, crude oil hauling services and remote accommodation services. AsThe 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 ~~result~~reporting segment and do not meet the aggregation criteria set forth in ASC 280 Segment Reporting. Therefore, results for these operating segments are included in the column labeled "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 LLC, which holds these corporate assets, meets one of ~~this change, there~~the quantitative thresholds of a reporting segment, it does not engage in business activities from which it may earn revenues and its results are ~~five~~not regularly reviewed by the Company's CODM when making key operating and resource utilization decisions. Therefore, the Company does not include it as a reportable ~~segments for financial reporting purposes as described above. Historical information in this Note to the financial statements has been revised to reflect the new reportable~~ segment.

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

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Completion and Production
Six Months Ended June 30, 2017 Pressure Pumping Services Well Services Sand Drilling Other Energy Services Total
Revenue from external customers $ 17,508,098
$ 8,796,654
$ 13,767,088
$ 21,215,222
$ 9,231,059
$ 70,518,121
Revenue from related parties $ 72,868,938
$ 2,687,448
$ 25,145,543
$ 2,007,505
$ 525
$ 102,709,959
Cost of revenue $ 64,533,809
$ 10,436,065
$ 32,581,324
$ 22,986,579
$ 5,300,163
$ 135,837,940
Selling, general and administrative expenses $ 4,179,665
$ 1,698,503
$ 4,473,436
$ 2,728,778
$ 1,356,122
$ 14,436,504
Earnings before interest, other expense (income), impairment, taxes and depreciation and amortization $ 21,663,562
$ (650,466 ) $ 1,857,871
$ (2,492,630 ) $ 2,575,299
$ 22,953,636
Other expense (income) $ 6,389
$ (1,991 ) $ 153,776
$ 224,236
$ 4,232
$ 386,642
Bargain purchase gain $ —
$ —
$ (4,011,512 ) $ —
$ —
$ (4,011,512 )
Interest expense (income) $ 431,795
$ (108,376 ) $ 485,239
$ 657,058
$ 43,076
$ 1,508,792
Depreciation, depletion, accretion and amortization $ 18,784,446
$ 3,428,162
$ 3,568,659
$ 9,942,310
$ 1,407,073
$ 37,130,650
Income tax (benefit) provision $ —
$ (6,500,514 ) $ 8,502
$ —
$ 581,870
$ (5,910,142 )
Net income (loss) $ 2,440,932
$ 2,532,253
$ 1,653,207
$ (13,316,234 ) $ 539,048
$ (6,150,794 )
Total expenditures for property, plant and equipment $ 53,401,909
$ 344,474
$ 2,969,883
$ 5,900,817
$ 3,958,636
$ 66,575,719
Three Months Ended June 30, 2017
Revenue from external customers $ 8,816,451
$ 5,606,522
$ 10,395,025
$ 11,511,825
$ 3,724,353
$ 40,054,176
Revenue from related parties $ 41,108,032
$ 2,534,553
$ 13,605,124
$ 959,913
$ 261
$ 58,207,883
Cost of revenue $ 35,826,369
$ 6,636,289
$ 19,974,059
$ 12,033,156
$ 2,870,081
$ 77,339,954
Selling, general and administrative expenses $ 2,404,739
$ 726,098
$ 2,415,883
$ 1,433,754
$ 719,232
$ 7,699,706
Earnings before interest, other expense (income), impairment, taxes and depreciation and amortization $ 11,693,375
$ 778,688
$ 1,610,207
$ (995,172 ) $ 135,301
$ 13,222,399
Other expense (income) $ 3,758
$ (3,173 ) $ 139,569
$ 60,451
$ 1,891
$ 202,496
Bargain purchase gain $ —
$ —
$ (4,011,512 ) $ —
$ —
$ (4,011,512 )
Interest expense (income) $ 303,351
$ (2,474 ) $ 352,600
$ 439,876
$ 18,255
$ 1,111,608
Depreciation, depletion, accretion and amortization $ 9,626,553
$ 2,219,921
$ 2,205,694
$ 4,973,682
$ 867,549
$ 19,893,399
Income tax (benefit) provision $ —
$ (2,808,982 ) $ 8,502
$ —
$ (3,597 ) $ (2,804,077 )
Net income (loss) $ 1,759,713
$ 1,373,396
$ 2,915,354
$ (6,469,181 ) $ (748,797 ) $ (1,169,515 )
Total expenditures for property, plant and equipment $ 24,736,600
$ 344,474
$ 2,795,370
$ 3,631,540
$ 3,958,043
$ 35,466,027
At June 30, 2017
Goodwill $ 86,043,147
$ 10,192,486
$ 2,683,727
$ —
$ 643,400
$ 99,562,761
Intangible assets, net $ 16,913,308
$ 2,078,021
$ —
$ —
$ 1,613,000
$ 20,604,329
Total assets $ 244,665,648
$ 83,026,472
$ 163,911,495
$ 98,203,014
$ 37,110,946
$ 626,917,575



Three months ended June 30, 2018	Pressure Pumping			Infrastructure		Sand		Drilling			All Other			Eliminations			Total
Revenue from external customers	$	100,333		$	360,250	$	37,439	$	17,126		$	18,446		$	—		$	533,594
Intersegment revenues	1,073			—		15,406		84			1,721			(18,284		)	—
Total revenue	101,406			360,250		52,845		17,210			20,167			(18,284		)	533,594
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion	61,593			210,189		35,117		15,280			17,649			—			339,828
Intersegment cost of revenues	16,174			754		1,019		(40		)	129			(18,036		)	—
Total cost of revenue	77,767			210,943		36,136		15,240			17,778			(18,036		)	339,828
Selling, general and administrative	20,822			39,786		1,787		1,591			1,141			—			65,127
Depreciation, depletion, amortization and accretion	13,829			4,094		3,881		5,349			3,642			—			30,795
Impairment of long-lived assets	—			—		—		187			—			—			187
Operating income (loss)	(11,012		)	105,427		11,041		(5,157		)	(2,394		)	(248		)	97,657
Interest expense, net	341			106		76		265			171			—			959
Other expense	80			330		36		32			8			—			486
Income (loss) before income taxes	$	(11,433	)	$	104,991	$	10,929	$	(5,454	)	$	(2,573	)	$	(248	)	$	96,212



Three months ended June 30, 2017	Pressure Pumping		Infrastructure			Sand			Drilling			All Other			Eliminations			Total
Revenue from external customers	$	49,924	$	1,709		$	24,000		$	12,472		$	10,157		$	—		$	98,262
Intersegment revenues	272		—			762			—			85			(1,119		)	—
Total revenue	50,196		1,709			24,762			12,472			10,242			(1,119		)	98,262
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion	35,826		1,626			19,974			12,033			7,881			—			77,340
Intersegment cost of revenues	847		—			267			—			5			(1,119		)	—
Total cost of revenue	36,673		1,626			20,241			12,033			7,886			(1,119		)	77,340
Selling, general and administrative	2,403		307			2,416			1,435			1,139			—			7,700
Depreciation, depletion, amortization and accretion	9,626		340			2,206			4,974			2,747			—			19,893
Operating income (loss)	1,494		(564		)	(101		)	(5,970		)	(1,530		)	—			(6,671		)
Interest expense, net	303		4			353			440			12			—			1,112
Bargain purchase gain	—		—			(4,012		)	—			—			—			(4,012		)
Other expense	4		—			140			60			(1		)	—			203
Income (loss) before income taxes	$	1,187	$	(568	)	$	3,418		$	(6,470	)	$	(1,541	)	$	—		$	(3,974	)



Six months ended June 30, 2018	Pressure Pumping			Infrastructure		Sand		Drilling			All Other			Eliminations			Total
Revenue from external customers	$	196,912		$	685,709	$	73,942	$	32,354		$	38,926		$	—		$	1,027,843
Intersegment revenues	5,632			—		29,918		86			4,136			(39,772		)	—
Total revenue	202,544			685,709		103,860		32,440			43,062			(39,772		)	1,027,843
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion	128,205			404,265		68,447		29,755			35,257			—			665,929
Intersegment cost of revenues	31,576			2,545		5,305		122			234			(39,782		)	—
Total cost of revenue	159,781			406,810		73,752		29,877			35,491			(39,782		)	665,929
Selling, general and administrative	23,485			71,637		3,431		2,844			2,241			—			103,638
Depreciation, depletion, amortization and accretion	27,815			6,501		6,197		9,704			7,486			—			57,703
Impairment of long-lived assets	—			—		—		187			—			—			187
Operating income (loss)	(8,537		)	200,761		20,480		(10,172		)	(2,156		)	10			200,386
Interest expense, net	845			182		156		660			353			—			2,196
Other expense	92			332		23		72			(5		)	—			514
Income (loss) before income taxes	$	(9,474	)	$	200,247	$	20,301	$	(10,904	)	$	(2,504	)	$	10		$	197,676

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Completion and Production
Six Months Ended June 30, 2016 Pressure Pumping Services Well Services Sand Drilling Other Energy Services Total
Revenue from external customers $ 18,157,113
$ 4,360,611
$ 2,976,443
$ 9,715,833
$ 14,653,537
$ 49,863,537
Revenue from related parties $ 38,165,558
$ 567,887
$ 11,231,344
$ 1,916,595
$ 572
$ 51,881,956
Cost of revenue $ 40,083,680
$ 6,962,055
$ 16,432,367
$ 12,968,054
$ 6,448,663
$ 82,894,819
Selling, general and administrative expenses $ 2,065,542
$ 1,013,478
$ 2,109,803
$ 2,567,237
$ 1,063,952
$ 8,820,012
Earnings before interest, other expense (income), impairment, taxes and depreciation and amortization $ 14,173,449
$ (3,047,035 ) $ (4,334,383 ) $ (3,902,863 ) $ 7,141,494
$ 10,030,662
Other expense (income) $ 23,825
$ (673,145 ) $ 72,985
$ (57,574 ) $ 8,183
$ (625,726 )
Interest expense (income) $ 368,764
$ 149,095
$ 211,111
$ 1,554,207
$ 25,210
$ 2,308,387
Depreciation, depletion, accretion and amortization $ 18,913,487
$ 2,670,222
$ 2,949,851
$ 10,945,932
$ 1,082,195
$ 36,561,687
Impairment of long-lived assets $ 138,587
$ 1,384,751
$ —
$ 347,547
$ —
$ 1,870,885
Income tax (benefit) provision $ —
$ (3,094 ) $ —
$ —
$ 1,686,829
$ 1,683,735
Net (loss) income $ (5,271,214 ) $ (6,574,864 ) $ (7,568,330 ) $ (16,692,975 ) $ 4,339,077
$ (31,768,306 )
Total expenditures for property, plant and equipment $ 927,542
$ 247,829
$ 157,726
$ 423,095
$ 418,017
$ 2,174,209
Three Months Ended June 30, 2016
Revenue from external customers $ 5,862,584
$ 1,662,019
$ 1,694,698
$ 4,458,095
$ 6,667,914
$ 20,345,310
Revenue from related parties $ 38,165,558
$ 567,887
$ 9,313,266
$ 770,596
$ 17
$ 48,817,324
Cost of revenue $ 28,551,790
$ 3,034,349
$ 10,251,613
$ 5,759,398
$ 2,906,493
$ 50,503,643
Selling, general and administrative expenses $ 1,539,371
$ 440,182
$ 1,508,533
$ 1,264,763
$ 453,289
$ 5,206,138
Earnings before interest, other expense (income), impairment, taxes and depreciation and amortization $ 13,936,981
$ (1,244,625 ) $ (752,182 ) $ (1,795,470 ) $ 3,308,149
$ 13,452,853
Other expense (income) $ 43,033
$ (682,545 ) $ 53,803
$ (47,500 ) $ 6,493
$ (626,716 )
Interest expense (income) $ 131,709
$ 50,776
$ 106,650
$ 701,633
$ 21,263
$ 1,012,031
Depreciation, depletion, accretion and amortization $ 9,958,270
$ 1,272,715
$ 1,581,334
$ 5,438,551
$ 559,745
$ 18,810,615
Impairment of long-lived assets $ 138,587
$ 1,384,751
$ —
$ 347,547
$ —
$ 1,870,885
Income tax (benefit) provision $ —
$ (3,094 ) $ —
$ —
$ 792,469
$ 789,375
Net income (loss) $ 3,665,382
$ (3,267,228 ) $ (2,493,969 ) $ (8,235,701 ) $ 1,928,179
$ (8,403,337 )
Total expenditures for property, plant and equipment $ 896,847
$ 247,829
$ 65,184
$ 158,924
$ 270,386
$ 1,639,170
At June 30, 2016
Goodwill $ 86,043,148
$ —
$ 2,683,727
$ —
$ —
$ 88,726,875
Intangible assets, net $ 25,956,808
$ 145,521
$ —
$ —
$ —
$ 26,102,329
Total assets $ 209,357,385
$ 41,178,159
$ 114,090,998
$ 105,556,115
$ 35,639,200
$ 505,821,857



Six months ended June 30, 2017	Pressure Pumping		Infrastructure			Sand			Drilling			All Other			Eliminations			Total
Revenue from external customers	$	90,377	$	1,709		$	38,912		$	23,223		$	19,007		$	—		$	173,228
Intersegment revenues	459		—			1,447			—			85			(1,991		)	—
Total revenue	90,836		1,709			40,359			23,223			19,092			(1,991		)	173,228
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion	64,533		1,712			32,582			22,986			14,025			—			135,838
Intersegment cost of revenues	1,532		—			454			—			5			(1,991		)	—
Total cost of revenue	66,065		1,712			33,036			22,986			14,030			(1,991		)	135,838
Selling, general and administrative	4,180		355			4,474			2,728			2,700			—			14,437
Depreciation, depletion, amortization and accretion	18,784		340			3,569			9,942			4,495			—			37,130
Operating income (loss)	1,807		(698		)	(720		)	(12,433		)	(2,133		)	—			(14,177		)
Interest expense, net	431		4			486			657			(69		)	—			1,509
Bargain purchase gain	—		—			(4,012		)	—			—			—			(4,012		)
Other expense	7		—			154			224			2			—			387
Income (loss) before income taxes	$	1,369	$	(702	)	$	2,652		$	(13,314	)	$	(2,066	)	$	—		$	(12,061	)

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 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.



	Pressure Pumping		Infrastructure		Sand		Drilling		All Other		Eliminations			Total
As of June 30, 2018:
Total assets^(a)	$	277,895	$	341,171	$	199,421	$	92,578	$	150,579	$	(32,521	)	$	1,029,123
Goodwill	$	86,043	$	891	$	2,684	$	—	$	11,893	$	—		$	101,511
As of December 31, 2017:
Total assets^(a)	$	297,140	$	205,275	$	190,859	$	88,527	$	243,767	$	(158,325	)	$	867,243
Goodwill	$	86,043	$	891	$	2,684	$	—	$	10,193	$	—		$	99,811


a.	Total assets included in the All Other column include Mammoth LLC corporate assets totaling $34.3 million and $148.8 million, respectively, as of June 30, 2018 and December 31, 2017, of which $16.9 million and $137.4 million are inter-segment accounts receivable which are eliminated in consolidation.


~~16.~~20.	Subsequent Events

On July ~~7, 2017,~~9, 2018, the Company ~~acquired an energy service company from an unrelated~~and certain of its direct and indirect subsidiaries entered into a third amendment to Mammoth's revolving credit facility with the lenders party ~~seller~~thereto and PNC Bank, National Association, as a lender and agent for ~~$2.3 million~~the lenders (the "Third Amendment"). Among other things, the Third Amendment permits (i) the declaration of quarterly cash distributions on the shares representing equity of Mammoth if, among other things, after giving effect to the payment of such dividend or distributions contemplated by the declaration, pro forma excess availability would be no less than 22.5% of the maximum available credit and no default or event of default exists, (ii) the payment of the declared dividends or distributions if (x) such dividends or distributions are made within sixty (60) days after the declaration thereof and (y) on the date such dividends or distributions are made, (1) after giving effect to the payment of such dividend or distribution, pro forma excess availability would be no less than 22.5% of the maximum available credit and (2) no material default or material event of default shall have occurred, or would result therefrom, and (iii) the issuance of third-party surety bonds in ~~cash consideration~~favor of Mammoth and its subsidiaries in relation with their bonded contracts, in each case subject to the ~~assumption of $1.8 million~~additional limitations described in ~~debt.~~the Third Amendment.

~~Effective~~On July 10, 2018, the Company's wholly owned subsidiary, Pressure Pumping and Gulfport entered into Amendment No. 2 to that certain Amended & Restated Master Services Agreement for Pressure Pumping Services, effective as of October 1, 2014, as amended effective January 1, 2016 (the “Existing Pressure Pumping Agreement”). Under the Existing Pressure Pumping Agreement, Pressure Pumping provides hydraulic fracturing, stimulation and related completion and rework services to Gulfport with two dedicated frac spreads and related equipment. The amendment extended the term of the existing pressure pumping agreement until December 31, 2021, unless it is terminated earlier in accordance with its terms, and expanded the service area to include both Ohio and Oklahoma. The amendment also provides that Gulfport has the right to suspend pressure pumping services for up to one crew by upon a minimum of 90 days prior written notice to Pressure Pumping, with no further payment or other obligation to Pressure Pumping for such suspended crew. Pressure Pumping will be obligated to resume any such suspended pressure pumping services upon 90 days prior written notice by

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Gulfport, unless such notice is waived by Pressure Pumping. The amendment also provides for the initial suspension of pressure pumping services to Gulfport for a period July ~~12, 2017,~~1, 2018 through September 30, 2018, during which period Pressure Pumping may use the ~~Company~~dedicated frac spreads for other customers. If during the initial suspension period Pressure Pumping’s use of the dedicated frac spreads for other customers does not reach a certain level, then Gulfport will pay agreed costs to Pressure Pumping and Pressure Pumping will perform services for Gulfport with respect to such amount. In addition, if during such initial suspension period Pressure Pumping is unable to utilize the dedicated frac spreads for other customers, Gulfport will pay agreed recoupment costs to Pressure Pumping during the period of October 1, 2018 to December 31, 2018.

On August 6, 2018, the Company's wholly owned subsidiary, Muskie Proppant LLC ("Muskie Proppant") and Gulfport entered into a Second Amendment to ~~Revolving Credit and Security~~the Sand Supply Agreement, ~~among~~effective as of October 1, 2014, as amended effective November 15, 2015. The amendment extends the ~~Company and certain~~term of ~~its subsidiaries,~~the agreement until December 31, 2021.

The Company's unsatisfied performance obligations increased approximately $88.8 million as ~~borrowers, certain financial institutions party thereto, as lenders, and PNC Bank, National Association, as agent for~~a result of the ~~lenders (the “Amendment”). The Amendment provided the borrowers with greater flexibility for permitted acquisitions and permitted indebtedness, increased the maximum~~

~~amount credited~~amendments to the ~~borrowing base for~~pressure pumping and sand ~~inventory~~supply agreements with Gulfport.

On July 16, 2018, the Company's Board of Directors initiated a quarterly dividend policy and ~~for in-transit inventory and increased certain cross-default thresholds from $5 million~~declared the Company's first quarterly cash dividend of $0.125 per share of common stock, to ~~$15~~be paid on August 14, 2018 to stockholders of record as of the close of business on August 7, 2018. Based on the number of shares outstanding at June 30, 2018, the total dividend payable to stockholders on August 14, 2018 will be approximately $5.6 million.

Subsequent to June 30, ~~2017,~~2018, the Company entered into arail car and property lease ~~agreement for~~agreements with aggregate commitments of $2.4 million.

Subsequent to June 30, 2018, the Company ordered additional capital equipment with aggregate commitments of ~~$1.5~~$9.6 million.

Subsequent to June 30, 2018, subsidiaries in the Company's infrastructure segment entered into an air chart agreement, barge chartering agreement and other service agreements with aggregate commitments of $2.5 million, $2.1 million and $0.6 million, respectively.

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

The following discussion should be read in conjunction with the unaudited condensed consolidated financial statements and related notes thereto presented in this ~~quarterly report~~Quarterly Report and the consolidated financial statements and related notes thereto included in our Annual Report on Form 10-K. This discussion contains forward-looking statements reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in Item 1A. "Risk Factors” in this Quarterly Report and in our Form 10-K for the year ended December 31, ~~2016,~~2017, filed with the Securities and Exchange Commission, or the SEC, on February ~~24, 2017.~~28, 2018 and the section entitled “Forward-Looking Statements” appearing elsewhere in this Quarterly Report.

Overview

We are an integrated, growth-oriented ~~oilfield service~~ company serving ~~companies engaged in~~both the ~~exploration and development of North American onshore unconventional~~ oil and ~~natural~~ gas ~~reserves.~~and the electric utility industry in North America and US territories. Our primary business objective is to grow our operations and create value for stockholders through organic opportunities and accretive acquisitions. Our suite of services includes pressure pumping services, ~~well~~infrastructure services, natural sand proppant services, contract land and directional drilling services and other energy ~~services.~~services, including coil tubing, flowback, cementing, acidizing, equipment rental, crude oil hauling, water transfer and remote accommodations. Our pressure pumping services division provides hydraulic fracturing services. Our ~~well~~infrastructure services division provides ~~pressure control~~construction, upgrade, maintenance and repair services ~~flowback services and equipment rentals.~~to the electrical infrastructure industry. Our natural sand proppant services division mines, processes and sells ~~distributes and produces~~ proppant used for hydraulic fracturing. Our contract land and directional drilling services division 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 energy~~In addition to these service divisions, we also provide coil tubing services, ~~division has historically provided housing, kitchen~~pressure control services, flowback services, cementing services, acidizing services, equipment rentals, crude oil hauling services, water transfer and ~~dining, and recreational service facilities for oilfield workers located in~~ remote ~~areas away from readily available lodging and recentlywas expanded to include energy infrastructure services.~~accommodations. 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 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, and Rhino Exploration LLC, or Rhino, contributed to Mammoth Energy Partners LP, or the Partnership, their respective interests in the following entities: Bison Drilling 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; 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, 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, 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 results with our financial results as if the acquisition had been effective since Sturgeon commenced operations.

Second Quarter 2018 Highlights and Recent Developments

~~Second Quarter 2017 Highlights~~

~~Acquisition of Stingray Energy, Stingray Cementing and Sturgeon~~Executed New $900 million Contract with PREPA

On ~~March 20, 2017, as amended and restated on~~ May 12, 2017, we entered into three definitive contribution agreements, one with Gulfport, Rhino, affiliates of Wexford and Mammoth LLC, and two others with Gulfport, affiliates of Wexford and Mammoth LLC, which we collectively refer to as the Contribution Agreements. Under the Contribution Agreements, we agreed to acquire all outstanding membership interests in Sturgeon (which owns Taylor Frac, LLC, Taylor Real Estate Investments, LLC and South River Road, LLC, which are collectively referred to as Taylor Frac), Stingray Energy Services26, 2018, our wholly owned subsidiary Cobra Acquisitions LLC, or Stingray Energy, and Stingray Cementing LLC, or Stingray Cementing, respectively, for an aggregate of 7.0 million shares of our common stock. Taylor Frac owns a sand mine and processing plant. Once the expansion of the Taylor facility to 1.75 million tons per annum (Mmtpa) of capacity is completed, which we currently anticipate will occur in the fourth quarter of 2017, our processing capacity will increase to approximately 4 Mmtpa of high quality frac sand. Stingray Energy and Stingray Cementing, combined, offer services in fresh water transfer, equipment rental, re-fueling as well as cementing and operate primarily in the Appalachian basin. We have provided certain management, administrative and treasury functions to Taylor Frac, Stingray Energy and Stingray Cementing since 2014. We closed this acquisition on June 5, 2017. The inclusion of these businesses for 25 days of the second quarter of 2017 added $2.6 million in revenue during this period.

~~Chieftain Acquisition~~

~~On March 27, 2017, we~~Cobra, entered into a ~~definitive asset purchase~~new master services agreement with the Puerto Rico Electric Power Authority, or PREPA, to complete the restoration of the electrical transmission and distribution system components damaged by Hurricane Maria and to support the initial phase of reconstruction of the electrical power system in Puerto Rico, which we refer to as the ~~Purchase Agreement, with Chieftain Sand~~New PREPA Contract. Cobra has agreed to provide the labor, supervision, tools and ~~Proppant, LLC~~materials necessary to provide the restoration and ~~Chieftain Sand~~reconstruction services under the New PREPA Contract, which has a one-year term ending May 25, 2019 and ~~Proppant Barron, LLC, unrelated third party sellers, following our successful~~provides for total payments not to exceed $900.0 million. The New PREPA Contract was awarded at the conclusion of a request for proposal (RFP) bid process that began in ~~a bankruptcy court auction for substantially all of the assets of the sellers for $35.25 million, which we refer to as the Chieftain Acquisition.~~February 2018. The ~~assets subject~~New PREPA Contract is in addition to the ~~Chieftain Acquisition include a wet and dry plant and sand mine located on approximately 600 acres~~contract that Cobra entered into in New Auburn, Wisconsin. The sellers’ facilities are located on the Union Pacific Railroad with unit train capability on site. The Chieftain Acquisition closed on May 26, 2017. We funded the purchase price for the Chieftain Acquisition with cash on hand and borrowings under our revolving credit facility.October 2017, as subsequently amended, to provide restoration services to PREPA.

~~Expansion~~Acquisition of WTL Oil and RTS Energy Services

During the second quarter of ~~2017,~~2018, we ~~expanded~~completed the acquisitions of WTL Oil LLC, or WTL, and RTS Energy Services LLC, or RTS, for $6.1 million and $8.1 million, respectively. WTL provides crude oil hauling services in the Permian Basin and mid-continent region. RTS provides cementing and acidizing services in the Permian Basin.

Completed Underwritten Secondary Offering of Common Stock

On June 29, 2018, Gulfport and certain entities controlled by Wexford Capital LP, as the selling stockholders, completed an underwritten secondary public offering of 4,000,000 shares of the Company’s common stock at a purchase price to the selling stockholders of $38.01 per share. The selling stockholders received all proceeds from this offering. The selling stockholders also granted the underwriters an option to purchase up to an aggregate of 600,000 additional shares of our common stock at the same purchase price. This option was exercised, in part, and on July 30, 2018, the underwriters purchased an additional 385,000 shares of common stock from the selling stockholders at the same price per share.

Extended Pressure Pumping Services and Sand Supply Agreements with Gulfport

On July 10, 2018, we amended our existing agreement with Gulfport pursuant to which we, through our subsidiary Pressure Pumping, provide hydraulic fracturing, stimulation and related completion and rework services to Gulfport with two dedicated frac spreads and related equipment. The amendment extended the term of the existing pressure pumping ~~sand deliveries~~agreement until December 31, 2021, unless it is terminated earlier in accordance with its terms, and ~~last-mile trucking services into~~expanded the ~~SCOOP/STACK with the startup of our fourth~~service area to include both Ohio and Oklahoma. The pressure pumping ~~fleet in June 2017.~~ amendment also provides that Gulfport has the right to suspend pressure pumping services for up to one crew by upon a minimum of 90 days prior written notice to Pressure Pumping, with no further payment or other obligation to Pressure Pumping for such suspended crew. Pressure Pumping will be obligated to resume any such suspended pressure pumping services upon 90 days prior written notice by Gulfport, unless such notice is waived by Pressure Pumping.

The ~~startup~~pressure pumping amendment also provides for the initial suspension of ~~our fifth fleet in~~pressure pumping services to Gulfport for a period July 1, 2018 through September 30, 2018, during which period Pressure Pumping may use the ~~mid-continent is scheduled~~dedicated frac spreads for ~~August 8, 2017,~~other customers. If during the initial suspension period Pressure Pumping’s use of the dedicated frac spreads for other customers does not reach a certain level, then Gulfport will pay agreed costs to Pressure Pumping and Pressure Pumping will perform services for Gulfport with ~~our sixth fleet expected~~respect to ~~commence operations in October 2017.~~such amount. In addition, ~~on July 7, 2017, we acquired an energy service company from an unrelated third party seller~~if during such initial suspension period Pressure Pumping is unable to utilize the dedicated frac spreads for ~~$2.3 million in cash and~~other customers, Gulfport will pay agreed recoupment costs to Pressure Pumping during the ~~assumption~~period of ~~$1.8 million in debt. This acquisition expands the infrastructure services of our other energy services division.~~October 1, 2018 to December 31, 2018.

~~Long Term Take-or- Pay Sand Contracts~~On August 6, 2018, we amended our existing agreement with Gulfport pursuant to which we, through our subsidiary Muskie Proppant, sell and deliver specified amounts of sand to Gulfport. The amendment extends the term of the existing sand supply agreement until December 31, 2021.

During the second quarter of 2017, we signed a take-or-pay sand contract with an unrelated third-party service company covering approximately 0.7 Mmtpa across several grades (20/40, 30/50 and 40/70) of sand. This contract has a three-year term commencing on October 1, 2017.

Industry Overview

Oil and Natural Gas Industry

The oil and natural gas industry has traditionally been volatile and is influenced by a combination of long-term, short-term and cyclical trends, including the domestic and international supply and demand for oil and natural gas, current and expected future prices for oil and natural gas and the perceived stability and sustainability of those prices, production depletion rates and the resultant levels of cash flows generated and allocated by exploration and production companies to their drilling, completion and related services and products budget. 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 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 decline in~~levels of capital expenditures of our customers are predominantly driven by the oil and natural gas prices. Over the past several years, commodity prices, ~~that began in the third quarter~~particularly oil, has seen significant volatility with pricing ranging from a high of ~~2014 continued into February 2016, when the closing price of oil reached~~$110.53 per barrel on September 6, 2013 to a ~~12-year~~ low of $26.19 per barrel on February 11, 2016. ~~The low commodity price environment caused~~During early 2017, oil prices stabilized around the $50 per barrel level and started a ~~reduction in~~gradual upward trend which continued into the ~~drilling, completion and other production activities~~second quarter of ~~most of our customers and their spending on our products and services.~~2018, where oil prices averaged $67.85.

~~The reduction in~~We anticipate demand ~~during the first part of 2016,~~for our oil and ~~the resulting oversupply of many of the~~natural gas services and products will continue to be dependent on commodity prices. If commodity prices stabilize at current levels or continue to increase, we ~~provide, substantially reduced the prices we could charge our customers~~expect to experience further increases in demand for our ~~products and~~ services and had a negative impact on the utilization of our services. This overall trend with respect to our customers’ activities and spending reversed in late 2016 as oil prices started 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. During the first six months of 2017, oil traded between a low of $42.53 per barrel on June 21, 2017 and a high of $54.45 per barrel on February 23, 2017, and closed at $46.04 per barrel on June 30, 2017. This increase in commodity prices from 2016 levels has spurred a significant increase in the land rig count with 919 rigs operating on June 30, 2017, up approximately 45% from the 635 rigs operating at year-end 2016. As the rig count increased, we experienced an increase in activity and pricing, mainlyproducts, particularly in our ~~pressure pumping, other well services,~~completion and production, natural sand proppant and contract land and directional drilling businesses. ~~If near term~~Decreases in commodity prices, ~~stablize at current levels~~however, may result in a reduction in the demand for our drilling, completion and other products and services.

Energy Infrastructure Industry

In 2017, we expanded into the electric infrastructure business, offering both commercial and storm restoration services to government-funded utilities, private utilities, public investor owned utilities and cooperatives. Since we commenced operations in this line of business, substantially all of our infrastructure revenues has been generated from storm restoration work, primarily from PREPA due to damage caused by Hurricane Maria. On October 19, 2017, Cobra and PREPA entered into an emergency master services agreement for repairs to PREPA’s electrical grid. The one-year contract, as amended, provides for payments of up to $945.4 million. On May 26, 2018, Cobra and PREPA entered into a new one-year, $900.0 million master services agreement to provide additional repair services and begin the initial phase of reconstruction of the electrical power system in Puerto Rico. 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 ~~increase,~~other sources. In the event PREPA does not have or does not obtain the funds necessary to satisfy its obligations to Cobra under the contracts, terminates the contracts or curtails our services prior to the end of the contract terms, our financial condition, results of operations and cash flows could be materially and adversely affected. In addition, government contracts are subject to various uncertainties, restrictions and regulations, including oversight audits by government representatives and profit and cost controls, which could result in withholding or delayed payments to us or efforts to recover payments already made.

The demand for our infrastructure services in the continental United States has steadily increased since we ~~expect~~expanded in to the infrastructure business. Our infrastructure teams are working for multiple utilities across the northeastern, midwestern and southwestern portions of the United States. We believe we will be able to continue to ~~experience an~~grow our customer base in the continental United States and increase the backlog of work over the coming years.

Natural Sand Proppant Industry

In the natural sand proppant industry, demand growth for frac sand and other proppants is primarily driven by advancements in oil and natural gas drilling and well completion technology and techniques, such as horizontal drilling and hydraulic fracturing, as well as overall industry activity growth. Demand for proppant declined in 2015 and throughout most of 2016 with reduced well completion activity; however, we believe that demand for proppant will continue to grow over the long-term, as it did throughout 2017 and the first half of 2018. Over the past 18 months, several new and existing suppliers announced planned capacity additions of frac sand supply, particularly in the Permian Basin. We expect frac sand supply to exceed growth in demand over the coming months and quarters in the Permian Basin. While planned capacity may exceed the expectations for frac sand demand in the Permian Basin, the collectively available industry capacity is constrained due to (i)

availability of the grades of sand that are currently in demand, (ii) general operating conditions and normal downtime and (iii) logistics constraints. The industry is expected to add significant capacity over the next 12 to 18 months, particularly in the Permian Basin. We believe that the coarseness, conductivity, sphericity, acid-solubility and crush-resistant properties of our ~~services~~Northern White sand reserves and ~~products. Our other energy services revenue declined~~our transportation infrastructure afford us an advantage over many of our competitors and make us one of a select group of sand producers capable of delivering high volumes of frac sand that is optimal for oil and natural gas production to all major unconventional resource basins currently producing throughout North America.

During the first half of 2018, constraints in the rail system adversely impacted frac sand deliveries from our Taylor sand facility in Jackson County, Wisconsin. As a result, we estimate production at our Taylor facility was 23% lower during the ~~second quarter~~first half of ~~2017 as a major construction project~~2018 than it would have been in the ~~area serviced~~absence of these constraints. We anticipate that these rail system constraints will be alleviated later in 2018. Production at our Piranha facility was not impacted by ~~our remote accommodation division was substantially completed in March 2017.~~

these rail constraints.

Results of Operations

Three Months Ended June 30, ~~2017~~2018 Compared to Three Months Ended June 30, ~~2016~~2017


							Three Months Ended
	Three Months Ended						June 30, 2018			June 30, 2017
	June 30, 2017			June 30, 2016			(in thousands)
Revenue:
Pressure pumping services	$	49,924,483		$	44,028,142		$	101,406		$	50,196
Well services	8,141,075			2,229,906
Infrastructure services							360,250			1,709
Natural sand proppant services	24,000,149			11,007,964			52,845			24,762
Contract land and directional drilling services	12,471,738			5,228,691			17,210			12,472
Other energy services	3,724,614			6,667,931
Other services							20,167			10,242
Eliminations							(18,284		)	(1,119		)
Total revenue	98,262,059			69,162,634			533,594			98,262

Cost of revenue:
Pressure pumping services	35,826,369			28,551,790
Well services	6,636,289			3,034,349
Natural sand proppant services	19,974,059			10,251,613
Contract land and directional drilling services	12,033,156			5,759,398
Other energy services	2,870,081			2,906,493
Pressure pumping services (exclusive of depreciation and amortization of $13,841 and $9,597, respectively, for the three months ended June 30, 2018 and 2017)							77,767			36,673
Infrastructure services (exclusive of depreciation and amortization of $4,088 and $340, respectively, for the three months ended June 30, 2018 and 2017)							210,943			1,626
Natural sand proppant services (exclusive of depreciation, depletion and accretion of $3,879 and $2,204, respectively, for the three months ended June 30, 2018 and 2017)							36,136			20,241
Contract land and directional drilling services (exclusive of depreciation of $5,349 and $4,970, respectively, for the three months ended June 30, 2018 and 2017)							15,240			12,033
Other services (exclusive of depreciation and amortization of $3,620 and $2,744, respectively, for the three months ended June 30, 2018 and 2017)							17,778			7,886
Eliminations							(18,036		)	(1,119		)
Total cost of revenue	77,339,954			50,503,643			339,828			77,340
Selling, general and administrative expenses	7,699,706			5,206,138			65,127			7,700
Depreciation and amortization	19,893,399			18,810,615
Depreciation, depletion, amortization and accretion							30,795			19,893
Impairment of long-lived assets	—			1,870,885			187			—
Operating (loss) income	(6,671,000		)	(7,228,647		)
Operating income (loss)							97,657			(6,671		)
Interest expense, net	(1,111,608		)	(1,012,031		)	(959		)	(1,112		)
Bargain purchase gain, net of tax	4,011,512			—
Other (expense) income, net	(202,496		)	626,716
Bargain purchase gain							—			4,012
Other expense, net							(486		)	(203		)
Income (loss) before income taxes	(3,973,592		)	(7,613,962		)	96,212			(3,974		)
(Benefit) provision for income taxes	(2,804,077		)	789,375
Net loss	$	(1,169,515	)	$	(8,403,337	)
Provision (benefit) for income taxes							53,512			(2,804		)
Net income (loss)							$	42,700		$	(1,170	)

Revenue. Revenue for the three months ended June 30, ~~2017~~2018 increased ~~$29.1~~$436 million, or ~~42%~~443%, to ~~$98.3~~$534 million from ~~$69.2~~$98 million for the three months ended June 30, ~~2016.~~2017. The increase in total revenues is primarily attributable to a $359 million increase in infrastructure services revenue during the three months ended June 30, 2018, representing 82% of the overall increase. Additionally, pressure pumping services revenue and natural sand proppant revenue increased $51 million and $28 million, respectively, representing 12% and 6% of the overall increase.

Revenue derived from related parties was $50 million, or 9% of our total revenues, for the three months ended June 30, 2018 and $58 million, or 59% of our total revenues, for the three months ended June 30, 2017. Substantially all of our related party revenue is derived from Gulfport under pressure pumping and sand contracts. On July 10, 2018, we executed an

amendment with Gulfport to extend the term of our pressure pumping contract through December 2021. While the terms of the contract amendment provide Gulfport the right to suspend our services under certain conditions, we do not believe that any such suspension would have a material adverse effect on our operations or financial condition based on current utilization and pricing. Additionally, on August 6, 2018, we executed an amendment with Gulfport to extend the term of our sand supply agreement through December 2021. Revenue by operating division was as follows:

Pressure Pumping Services. Pressure pumping services division revenue increased ~~$5.9~~$51 million, or ~~13%~~102%, to ~~$49.9~~$101 million for the three months ended June 30, ~~2017~~2018 from ~~$44.0~~$50 million for the three months ended June 30, ~~2016. The increase~~2017. Revenue derived from related parties was ~~primarily driven by an increase in fleet utilization~~$34 million, or 33% of ~~76%, on an average of two active fleets, from 76%~~total pressure pumping revenues, for the three months ended June 30, ~~2016~~2018 compared to ~~77%, on an average~~$41 million, or 82% of ~~three active fleets~~total pressure pumping revenues, for the three months ended June 30, 2017. ~~Our~~Substantially all of our related party revenue is derived from Gulfport. Inter-segment revenues, consisting primarily of revenue derived from our sand segment, totaled $1 million and $0.3 million, respectively, for the three months ended June 30, 2018 and 2017.

The increase in our pressure pumping services revenue was primarily driven by the startup of our fourth, ~~fleet began working~~fifth and sixth pressure pumping fleets in June, ~~2017.~~August and October 2017, respectively, in the SCOOP/STACK and Permian Basin, which contributed revenues of $51 million during the three months ended June 30, 2018. Additionally, the number of stages completed increased to 1,815 for the three months ended June 30, 2018 from 1,287 for the three months ended June 30, ~~2017 from 963 for the three months ended June 30, 2016.~~2017.

~~Well Services~~Infrastructure Services.~~. Well~~ Infrastructure services division revenue increased ~~$5.9~~$358 million ~~or 268%,~~ to ~~$8.1~~$360 million for the three months ended June 30, ~~2017~~2018 from ~~$2.2~~$2 million for the three months ended June 30, ~~2016. Cementing and energy~~2017. We generated $347 million, or 96% of total infrastructure services ~~accounted~~revenue, from our contract with PREPA for ~~$2.6 million of the increase~~repairs to Puerto Rico's electrical grid as a result of Hurricane Maria. For additional information regarding our ~~Stingray Cementing~~contracts with PREPA and ~~Stingray Energy acquisitions. Our coil tubing~~our infrastructure services, accounted for $3.1 million of our operating division increase, as a result of an increase in average day rates from approximately $17,100 for the three months ended June 30, 2016 to approximately $29,400 for the three months ended June 30, 2017. Our flowback services accounted for $0.2 million of our operating division increase, as a result of an increase in utilization.see "Industry Overview - Electrical Infrastructure Industry" above.

Natural Sand Proppant Services. Natural sand proppant services division revenue increased ~~$13.0~~$28 million, or ~~118%~~113%, to ~~$24.0~~$53 million for the three months ended June 30, ~~2017,~~2018, from ~~$11.0~~$25 million for the three months ended June 30, ~~2016. The increase~~2017. Revenue derived from related parties was ~~primarily attributable to an increase in tons~~$10 million, or 18% of total sand ~~sold from 197,529~~revenues, for the three

months ended June 30, ~~2016 to 350,710~~2018 and $14 million, or 55% of total sand revenues, for the three months ended June 30, 2017. ~~In addition, the price per ton~~Inter-segment revenues, consisting primarily of revenue derived from our pressure pumping segment, totaled $15 million, or 29% of total sand ~~delivered increased from $56 to $68, from~~revenues, for the three months ended June 30, ~~2016~~2018 and $1 million, or 3% of total sand revenues, for the three months ended June 30, 2017.

The increase in our natural sand proppant services revenue was primarily attributable to a 117% increase in tons of sand sold from approximately 359,053 tons for the three months ended June 30, 2017 to 777,850 tons for the three months ended June 30, 2018. We completed the expansion of our Taylor sand facility in March 2018. In May 2017, we acquired a wet and dry plant and sand mine located on approximately 600 acres in New Auburn, Wisconsin through our purchase of the assets of Chieftain. These assets contributed revenues of $14.6 million to our natural sand proppant division for the three months ended June 30, 2018 compared to $0.2 million for the three months ended June 30, 2017.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division revenue increased ~~$7.3~~$5 million, or ~~140%~~38%, from ~~$5.2~~$12 million for the three months ended June 30, ~~2016~~2017 to ~~$12.5~~$17 million for the three months ended June 30, 2018. Revenue derived from related parties, consisting primarily of directional drilling revenue from Gulfport, was a nominal amount for the three months ended June 30, 2018 and $1 million, or 8% of total drilling revenues, for the three months ended June 30, 2017.

The increase in contract land and directional drilling revenue was primarily attributable to our ~~land~~directional drilling services, which accounted for ~~$4.5~~$4 million, or ~~62%~~76% of the total increase as a result of increased utilization from 26% for the three months ended June 30, 2017 to 47% for the three months ended June 30, 2018. Our rig moving services accounted for $1 million, or 22%, of the operating division increase primarily due to increased activity. Our land drilling services accounted for $0.1 million, or 2%, of the operating division increase as a result of aan increase in average ~~active rigs~~day rates from ~~four~~approximately $14,100 for the three months ended June 30, ~~2016~~2017 to approximately $17,229 for the three months ended June 30, 2018, partially offset by a decrease in average active rigs from six for the three months ended June 30, 2017 ~~as well as an increase in average day rates from approximately $12,400~~ to ~~approximately $14,100 during those same periods. Our directional drilling services accounted for $1.2 million, or 16%, of the operating division increase as a result of utilization increasing from 15%~~four for the three months ended June 30, ~~2016~~2018.

$10 million, or 97%, to ~~26%~~$20 million for the three months ended June 30, 2018 from $10 million for the three months ended June 30, 2017. ~~Our rig moving services accounted for $1.6~~Revenue derived from related parties, consisting primarily of equipment rental and cementing revenue from Gulfport, was $7 million, or ~~22%,~~34% of total other revenues, for the ~~operating division increase. The increase in~~three months ended June 30, 2018 and $3 million, or 25% of total other revenues, for the three months ended June 30, 2017. Inter-segment revenues, consisting primarily of revenue derived from our ~~rig moving services was driven by~~infrastructure and pressure pumping segments, totaled $2 million and $0.1 million, respectively, for the ~~increase in drilling activity.~~three months ended June 30, 2018 and 2017.

~~Other~~Stingray Cementing and Stingray Energy, ~~Services. Other energy services division revenue,~~ which ~~has historically included only remote accommodation services but was recently expanded to include energy infrastructure services, decreased $3.0 million, or 45%, to $3.7~~we acquired in June 2017, contributed revenues of $9 million for the three months ended June 30, ~~2017 from $6.7~~2018 compared to $3 million for the three months ended June 30, ~~2016. The decrease was a result of a decrease in total rooms nights rented~~2017. Revenues from ~~47,532 to 15,100~~our coil tubing, pressure control and flowback services increased $3 million for the three months ended June 30, ~~2016 and 2017, respectively, partially offset by an increase in revenue per room night, in Canadian dollars, from $179 for the~~2018 compared to three months ended June 30, ~~2016~~2017 primarily due to ~~$180 for the three months ended June 30, 2017. The decrease~~increases in ~~remote accommodations revenue was~~utilization. These increases were partially offset by a decrease in revenue ~~of $1.7 million~~ from our ~~energy infrastructure services.~~remote accommodations business due to a decline in utilization.

Cost of Revenue (exclusive of depreciation, depletion, amortization and accretion expense). Cost of revenue, exclusive of depreciation, depletion, amortization and accretion expense, increased ~~$26.8~~$263 million from ~~$50.5~~$77 million, or ~~73%~~79% of total revenue, for the three months ended June 30, ~~2016~~2017 to ~~$77.3~~$340 million, or ~~79%~~64% of total revenue, for the three months ended June 30, 2018. The increase was primarily due to an expansion of our infrastructure services business, which represented a $209 million increase in cost of revenue, as well as an increase in pressure pumping division costs of $41 million, primarily related to the addition of three new fleets in 2017, and an increase in natural sand proppant division costs of $16 million, primarily due to an increase in tons of sand sold during the three months ended June 30, 2018 compared to the three months ended June 30, 2017. Cost of revenue by operating division was as follows:

Pressure Pumping Services. Pressure pumping services division cost of revenue, exclusive of depreciation and amortization expense, increased ~~$7.2~~$41 million, or ~~26%~~112%, to ~~$35.8~~$78 million for the three months ended June 30, ~~2017~~2018 from $28.6 million for the three months ended June 30, 2016. The increase was primarily due to increases in proppant costs, repairs and maintenance expense and labor-related costs. The labor-related costs were primarily as a result of staffing our third and fourth pressure pumping fleets during 2017. As a percentage of revenue, our pressure pumping services division cost of revenue was 72% and 65% for the three months ended June 30, 2017 and June 30, 2016, respectively.

~~Well Services. Well services division cost of revenue increased $3.6 million, or 120%, from $3.0 million for the three months ended June 30, 2016 to $6.6~~$37 million for the three months ended June 30, 2017. The increase was primarily due to ~~increases in labor-related costs~~the expansion of services into the SCOOP/STACK and Permian Basin with the ~~acquisition~~addition of ~~Stingray Cementing and Stingray Energy.~~three fleets. As a percentage of revenue, our ~~well~~pressure pumping services division cost of revenue, ~~was 82%~~exclusive of depreciation and ~~136%~~amortization expense of $14 million and $10 million for the three months ended June 30, 2018 and 2017, was 77% and 73%, respectively, for the three months ended June 30, ~~2016, respectively.~~2018 and 2017. The ~~decrease~~increase in ~~cost of revenue~~costs as a percentage of revenue was primarily due to ~~the~~an increase in ~~utilization.~~cost of goods sold as a result of selling sand with our service package to customers in the mid-continent region.

Infrastructure Services. Infrastructure services division cost of revenue, exclusive of depreciation and amortization expense, was $211 million and $2 million, respectively, for the three months ended June 30, 2018 and 2017. The increase is due to the expansion of our infrastructure business in late 2017 and 2018. The largest components of our cost of revenue include labor-related costs, including contract labor, and travel, meals and lodging expense. As a percentage of revenue, cost of revenue, exclusive of depreciation and amortization expense of $4 million and $0.3 million for the three months ended June 30, 2018 and 2017, was 59% and 95%, respectively, for the three months ended June 30, 2018 and 2017.

Natural Sand Proppant Services. Natural sand proppant services division cost of revenue, exclusive of depreciation, depletion and accretion expense, increased ~~$9.7~~$16 million, or ~~94%~~79%, from ~~$10.3 million for the three months ended June 30, 2016 to $20.0~~$20 million for the three months ended June 30, 2017 to $36 million for the three months ended June 30, 2018, primarily due to an increase in cost of goods sold as a result of a 117% increase in tons of sand ~~sold.~~sold in the 2018 period. As a percentage of revenue, cost of revenue, ~~was 83%~~exclusive of depreciation, depletion and ~~93%~~accretion expense of $4 million and $2 million for the three months ended June 30, 2018 and 2017, was 68% and 82%, respectively, for the three months ended June 30, ~~2016, respectively.~~2018 and 2017. The decrease ~~was~~is primarily due to ~~an increase~~startup costs incurred for our Piranha plant, which was acquired in ~~the price per ton of sand delivered.~~May 2017.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division cost of revenue, exclusive of depreciation expense, increased ~~$6.2~~$3 million, or ~~107%~~27%, from ~~$5.8 million for the three months ended June 30, 2016 to $12.0~~$12 million for the three months ended June 30, 2017 to $15 million for the three months ended June 30, 2018, 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, exclusive of depreciation expense of $5 million for both the three months ended June 30, 2018 and 2017, was ~~96%~~89% and ~~110%~~96%, respectively, for the three months ended June 30, 2018 and June 30, 2017. The decrease was primarily due to increased utilization and dayrates.

Other Services. Other services division cost of revenue, exclusive of depreciation and amortization expense, increased $10 million, or 125%, from $8 million for the three months ended June 30, 2017 ~~and June 30, 2016, respectively. The decrease was primarily due~~ to ~~higher day rates and utilization.~~$18 million for the three

~~Other Energy Services. Other energy services division cost of revenues remained consistent at $2.9 million for each of the three~~ months ended June 30, ~~2016~~2018, primarily due to the acquisition of Stingray Cementing and ~~2017.~~Stingray Energy in June 2017 and an increase in utilization for our other businesses. As a percentage of revenue, cost of revenue, ~~was 77%~~exclusive of depreciation and ~~44%~~amortization expense of $4 million and $2 million for the three months ended June 30, 2018 and 2017, was 88% and ~~2016, respectively.~~77%, respectively, for the three months ended June 30, 2018 and 2017. The ~~decrease in~~increase is primarily the result of increased equipment rental expense and labor-related costs ~~attributable to our remote accommodation services was partially offset by $1.5 million~~as a percentage of ~~costs attribubable to our energy infrastructure services.~~revenue.

Selling, General and Administrative Expenses. Selling, general and administrative expenses, or SG&A, represent the costs associated with managing and supporting our operations. These expenses increased ~~$2.5~~$57 million, or ~~48%~~746%, to ~~$7.7~~$65 million for the three months ended June 30, 2018, from $8 million for the three months ended June 30, 2017, ~~from $5.2~~primarily related to costs incurred for the expansion of our infrastructure business, an increase in the provision for bad debt and an increase in equity based compensation. The equity based compensation represents compensation expense for awards issued by certain Wexford affiliates and had no cash impact to the Company and no dilutive impact relative to the number of shares outstanding. Following is a breakout of SG&A expenses for the periods indicated (in thousands):



	Three Months Ended
	June 30, 2018		June 30, 2017
Cash expenses:
Compensation and benefits	$	10,978	$	2,966
Professional services	2,981		1,652
Other^(a)	3,935		2,015
Total cash SG&A expense	17,894		6,633
Non-cash expenses:
Bad debt provision	28,263		17
Equity based compensation^(b)	17,487		—
Stock based compensation	1,483		1,050
Total non-cash SG&A expense	47,233		1,067
Total SG&A expense	$	65,127	$	7,700


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


b.	Represents compensation expense for non-employee awards, which were issued and are payable by certain affiliates of Wexford (the sponsor level).

Depreciation, Depletion, Amortization and Accretion. Depreciation, depletion, amortization and accretion increased $11 million, or 55%, to $31 million for the three months ended June 30, 2016. The increase in expenses was primarily attributable to a $2.8 million increase in compensation, a $0.8 million increase in professional fees and services and a $1.1 million reduction in bad debt expense for the three months ended June 30, 2017, compared to the three months ended June 30, 2016.

~~Depreciation and Amortization. Depreciation and amortization increased $1.1 million, or 6%, to $19.9~~2018 from $20 million for the three months ended June 30, 2017. The increase is primarily attributable to an increase in property and equipment purchases in the second half of 2017 ~~from $18.8~~and first half of 2018, resulting in increased depreciation expense.

Operating Income (Loss). Operating income increased $105 million to $98 million for the three months ended June 30, ~~2016. The increase was primarily attributable~~2018 compared to ~~placing in service~~an operating loss of ~~$105.9~~$7 million ~~of capital additions~~ for the three months ended June 30, ~~2017~~2017. The increase was primarily the result of an expansion of our infrastructure services business, which recognized operating income of $106 million and an increase in natural sand proppant operating income of $11 million. These were partially offset by ~~$26.2~~a $13 million ~~of assets that fully depreciated~~decrease in operating income in our pressure pumping segment due to an increase in non-cash equity compensation expense during ~~2016.~~

~~Impairment of Long-lived Assets.~~ ~~The~~the three months ended June 30, 2016 included impairment charges of $1.9 million attributable to various fixed assets in the amount of $0.3 million, $0.1 million and $1.4 million for the contract land and directional drilling services, pressure pumping and well service segments, respectively.2018.

Interest Expense, Net. Interest expense, ~~increased $0.1~~net was $1 million ~~or 10%, to $1.1 million during~~for both the three months ended June 30, ~~2017, from $1.0 million during~~2018 and 2017. Average outstanding borrowings remained relatively flat for the three months ended June 30, ~~2016. The increase in interest expense was attributable~~2018 compared to ~~an increase in average borrowings during~~ the three months ended June 30, 2017.

~~Bargain Purchase Gain~~Other Expense, Net. .~~Bargain purchase~~Non-operating charges, net resulted in ~~a gain~~expense of ~~$4.0~~$0.5 million and $0.2 million, respectively, for the three months ended June 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 $0.2 million for the three months ended June 30, 2017, compared to other income, net, of $0.6 million for the three months ended June 30, 2016.~~2018 and 2017. Both periods were primarily comprised of ~~income/~~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 June 30, 2017, we recognized income tax benefit of $2.8 million compared to anWe recorded income tax expense of ~~$0.8~~$54 million on pre-tax income of $96 million for the three months ended June 30, ~~2016. The provision~~2018 compared to an income tax benefit of $3 million on pre-tax loss of $4 million for the three months ended June 30, ~~2016~~2017. Our effective tax rate was 56% for the three months ended June 30, 2018 compared to 35% for the three months ended June 30, 2017. The increase in effective tax rate is primarily ~~attributable~~due to the equity based compensation expense recognized during the three months ending June 30, 2018 as well as a higher tax rate in Puerto Rico, where most of our ~~subsidiary, Lodging, which provides our remote accommodation services.~~income was

generated during the three months ended June 30, 2018, compared to the United States tax rate. No income was generated in Puerto Rico during the three months ended June 30, 2017.

Results of Operations

Six Months Ended June 30, ~~2017~~2018 Compared to Six Months Ended June 30, ~~2016~~2017


							Six Months Ended
	Six Months Ended June 30,						June 30, 2018			June 30, 2017
	2017			2016			(in thousands)
Revenue:
Pressure pumping services	$	90,377,036		$	56,322,671		$	202,544		$	90,836
Well services	11,484,102			4,928,498
Infrastructure services							685,709			1,709
Natural sand proppant services	38,912,631			14,207,787			103,860			40,359
Contract land and directional drilling services	23,222,727			11,632,428			32,440			23,223
Other energy services	9,231,584			14,654,109
Other services							43,062			19,092
Eliminations							(39,772		)	(1,991		)
Total revenue	173,228,080			101,745,493			1,027,843			173,228

Cost of revenue:
Pressure pumping services	64,533,809			40,083,680
Well services	10,436,065			6,962,055
Natural sand proppant services	32,581,324			16,432,367
Contract land and directional drilling services	22,986,579			12,968,054
Other energy services	5,300,163			6,448,663
Pressure pumping services (exclusive of depreciation and amortization of $27,818 and $18,725, respectively, for the six months ended June 30, 2018 and 2017)							159,781			66,065
Infrastructure services (exclusive of depreciation and amortization of $6,489 and $340, respectively, for the six months ended June 30, 2018 and 2017)							406,810			1,712
Natural sand proppant services (exclusive of depreciation, depletion and accretion of $6,193 and $3,566, respectively, for the six months ended June 30, 2018 and 2017)							73,752			33,036
Contract land and directional drilling services (exclusive of depreciation of $9,703 and $9,934, respectively, for the six months ended June 30, 2018 and 2017)							29,877			22,986
Other services (exclusive of depreciation and amortization of $7,463 and $4,490, respectively, for the six months ended June 30, 2018 and 2017)							35,491			14,030
Eliminations							(39,782		)	(1,991		)
Total cost of revenue	135,837,940			82,894,819			665,929			135,838
Selling, general and administrative expenses	14,436,504			8,820,012			103,638			14,437
Depreciation and amortization	37,130,650			36,561,687
Depreciation, depletion, amortization and accretion							57,703			37,130
Impairment of long-lived assets	—			1,870,885			187			—
Operating loss	(14,177,014		)	(28,401,910		)
Operating income (loss)							200,386			(14,177		)
Interest expense, net	(1,508,792		)	(2,308,387		)	(2,196		)	(1,509		)
Bargain purchase gain, net of tax	4,011,512			—
Other (expense) income, net	(386,642		)	625,726
Loss before income taxes	(12,060,936		)	(30,084,571		)
(Benefit) provision for income taxes	(5,910,142		)	1,683,735
Net loss	$	(6,150,794	)	$	(31,768,306	)
Bargain purchase gain							—			4,012
Other expense, net							(514		)	(387		)
Income (loss) before income taxes							197,676			(12,061		)
Provision (benefit) for income taxes							99,430			(5,910		)
Net income (loss)							$	98,246		$	(6,151	)

Revenue. Revenue for the six months ended June 30, ~~2017~~2018 increased ~~$71.5~~$855 million, or ~~70%~~493%, to ~~$173.2 million~~$1 billion from ~~$101.7~~$173 million for the six months ended June 30, ~~2016.~~2017. The increase in total revenues is primarily attributable to a $684 million increase in infrastructure services revenue, representing 80% of the overall increase. Additionally, pressure pumping services revenue and natural sand proppant revenue increased $112 million and $64 million, respectively, representing 13% and 7% of the overall increase.

Revenue derived from related parties was $111 million, or 11% of our total revenues, for the six months ended June 30, 2018 and $103 million, or 59% of our total revenues, for the six months ended June 30, 2017. Substantially all of our related party revenue is derived from Gulfport under pressure pumping and sand contracts. On July 10, 2018, we executed an amendment with Gulfport to extend the term of our pressure pumping contract through December 2021. While the terms of the contract amendment provide Gulfport the right to suspend our services under certain conditions, we do not believe that any such suspension would have a material adverse effect on our operations or financial condition based on current utilization and pricing. Additionally, on August 6, 2018, we executed an amendment with Gulfport to extend the term of our sand supply agreement through December 2021. Revenue by operating division was as follows:

Pressure Pumping Services. Pressure pumping services division revenue increased ~~$34.1~~$112 million, or ~~61%~~123%, to ~~$90.4~~$203 million for the six months ended June 30, 2018 from $91 million for the six months ended June 30, 2017. Revenue derived from related parties was $72 million, or 36% of total pressure pumping revenues, for the six months ended June 30, 2018 compared to $73 million, or 80% of total pressure pumping revenues, for the six months ended June 30, 2017. Substantially all of our related party revenue is derived from Gulfport. Inter-segment revenues, consisting primarily of revenue derived from our sand segment, totaled $6 million and $0 million, respectively, for the six months ended June 30, 2018 and 2017.

The increase in our pressure pumping services revenue was primarily driven by the startup of our fourth, fifth and sixth pressure pumping fleets in June, August and October 2017, respectively, in the SCOOP/STACK and Permian Basin, which contributed revenues of $92 million during the six months ended June 30, 2018. Additionally, the number of stages completed increased to 3,487 for the six months ended June 30, 2018 from 2,147 for the six months ended June 30, 2017.

Infrastructure Services. Infrastructure services division revenue increased $684 million from $2 million for the six months ended June 30, 2017 ~~from $56.3~~to $686 million for the six months ended June 30, 2016. The increase was primarily driven by an increase in fleet utilization of 49%, on an average of two active fleets, for the six months ended June 30, 2016 to 85%, on an average of three active fleets, for the six months ended June 30, 2017. Additionally, the number of stages completed increased to 2,147 for the six months ended June 30, 2017 from 1,167 for the six months ended June 30, 2016.

~~Well Services. Well services division revenue increased $6.6~~2018. We generated $665 million, or ~~135%,~~97% of total infrastructure services revenue, from our contract with PREPA for repairs to ~~$11.5 million for the six months ended June 30, 2017 from $4.9 million for the six months ended June 30, 2016. The cementing and energy services division accounted for $2.6 million of the increase~~Puerto Rico's electrical grid as a result of Hurricane Maria. For additional information regarding our ~~Stingray Cementing~~contracts with PREPA and ~~Stingray Energy acquisitions. Our coil tubing~~our infrastructure services, accounted for $3.8 million of our operating division increase, as a result of an increase in average day rates from approximately $18,500 for the six months ended June 30, 2016 to approximately $25,300 for the six months ended June 30, 2017. Our flowback services accounted for $0.2 million of our operating division increase, as a result of an increased utilization.see "Industry Overview - Electrical Infrastructure Industry" above.

Natural Sand Proppant Services. Natural sand proppant services division revenue increased ~~$24.7~~$64 million, or ~~174%~~157%, to ~~$38.9~~$104 million for the six months ended June 30, ~~2017,~~2018, from ~~$14.2~~$40 million for the six months ended June 30, ~~2016. The increase~~2017. Revenue derived from related parties was ~~primarily attributable to an increase in tons delivered from approximately 259,890~~$21 million, or 20% of total sand revenues, for

the six months ended June 30, ~~2016~~2018 and $25 million, or 62% of total sand revenues, for the six months ended June 30, 2017. Inter-segment revenues, consisting primarily of revenue derived from our pressure pumping segment, totaled $30 million, or 29% of total sand revenues, for the six months ended June 30, 2018 and $1 million, or 4% of total sand revenues, for the six months ended June 30, 2017.

The increase in our natural sand proppant services revenue was primarily attributable to a 146% increase in tons of sand sold from approximately ~~596,706 in~~614,918 tons for the six months ended June 30, 2017 ~~in addition~~ to ~~an increase in price per ton of of sand delivered from $55 to $65,~~1,513,434 tons for the six months ended June 30, ~~2016~~2018. We completed the expansion of our Taylor sand facility in March 2018. In May 2017, we acquired a wet and ~~2017, respectively.~~dry plant and sand mine located on approximately 600 acres in New Auburn, Wisconsin through our purchase of the assets of Chieftain. These assets contributed revenues of $26 million to our natural sand proppant division for the six months ended June 30, 2018 compared to $0.2 million for the six months ended June 30, 2017.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division revenue increased ~~$11.6~~$9 million, or ~~100%~~40%, from ~~$11.6~~$23 million for the six months ended June 30, ~~2016~~2017 to ~~$23.2~~$32 million for the six months ended June 30, ~~2017. The increase~~2018. Revenue derived from related parties, consisting primarily of directional drilling revenue from Gulfport and El Toro Resources LLC, was ~~primarily attributable to our land drilling services, which accounted for $7.0~~$0.4 million, or ~~60%,~~1% of ~~the operating division increase. The increase in our land~~total drilling ~~services was driven by a increase in average active rigs from four~~revenues, for the six months ended June 30, ~~2016~~2018 compared to $2 million, or 9% of total drilling revenues, for the six months ended June 30, 2017.

The increase in contract land and directional drilling revenue was primarily attributable to our directional drilling services, which accounted for $6 million, or 61% of the total increase as a result of increased utilization from 26% for the six months ended June 30, 2017 ~~as well as a~~to 46% for the six months ended June 30, 2018. Our rig moving services accounted for $2 million, or 24%, of the operating division increase ~~in average day rates from approximately $12,900~~primarily due to ~~approximately $14,250 during those same periods.~~increased activity. Our ~~directional~~land drilling services accounted for ~~$2.6~~$1 million, or ~~22%~~16%, of the operating division increase as a result of ~~utilization declining~~an increase in average day rates from ~~15%~~approximately $14,250 for the six months ended June 30, ~~2016~~2017 to ~~26%~~approximately $16,882 for

the six months ended June 30, 2018, partially offset by a decrease in average active rigs from six for the six months ended June 30, 2017 to five rigs for the six months ended June 30, 2018.

Other Services. Other revenue, consisting of revenue derived from our coil tubing, pressure control, flowback, cementing, acidizing, equipment rental, crude oil hauling and remote accommodations businesses, increased $24 million, or 126%, to $43 million for the six months ended June 30, 2018 from $19 million for the six months ended June 30, 2017. ~~Our rig moving services accounted for $2.2~~Revenue derived from related parties, consisting primarily of equipment rental and cementing revenue from Gulfport, was $17 million, or ~~19%,~~39% of total other revenues, for the ~~operating division increase primarily driven by the increase in drilling activity. Our drill pipe inspection services accounted for a decline of $0.2~~six months ended June 30, 2018 and $3 million, or ~~(1)%,~~14% of total other revenues, for the ~~operating division.~~

~~Other Energy Services. Other energy services division~~six months ended June 30, 2017. Inter-segment revenues, consisting primarily of revenue ~~decreased $5.5~~derived from our infrastructure and pressure pumping segments, totaled $4 million ~~or 37%, to $9.2~~and $0.1 million for the six months ended June 30, 2018 and 2017.

Stingray Cementing and Stingray Energy, which we acquired in June 2017, ~~from $14.7~~contributed revenues of $21 million for the six months ended June 30, ~~2016. The decrease was a result of a decrease in total room nights rented from 109,229 for the six months ended June 30, 2016~~2018 compared to ~~49,438 for the six months ended June 30, 2017 in addition to a decrease in revenue per room night, in Canadian dollars, from $178 for the six months ended June 30, 2016 to $177~~$3 million for the six months ended June 30, 2017. ~~The decreases were partially offset by approximately $0.9~~Revenues from our coil tubing, pressure control and flowback services increased $7 million ~~of business interruption insurance proceeds we collected and recognized~~ for the six months ended June 30, ~~2017. The decrease in remote accommodations revenue was partially offset by $1.7 million of revenue from our energy infrastructure services during the~~2018 compared to six months ended June 30, ~~2017. We did not not provide infrastructure services during the same period~~2017 primarily due to increases in ~~2016.~~utilization.

Cost of ~~revenue~~Revenue (exclusive of depreciation, depletion, amortization and accretion expense). Cost of revenue, exclusive of depreciation, depletion, amortization and accretion expense, increased ~~$52.9~~$530 million from ~~$82.9~~$136 million, or ~~81%~~78% of total revenue, for the six months ended June 30, ~~2016~~2017 to ~~$135.8~~$666 million, or ~~78%~~65% of total revenue, for the six months ended June 30, 2018. The increase was primarily due to the expansion of our infrastructure services business, which represented a $405 million increase in cost of revenue, as well as an increase in pressure pumping division costs of $94 million, primarily related to the addition of three new fleets during 2017, and an increase in natural sand proppant division costs of $41 million, primarily due to an increase in tons of sand sold during the six months ended June 30, 2018 compared to the six months ended June 30, 2017. Cost of revenue by operating division was as follows:

Pressure Pumping Services. Pressure pumping services division cost of revenue, exclusive of depreciation and amortization expense, increased ~~$24.4~~$94 million, or ~~61%~~142%, to ~~$64.5~~$160 million for the six months ended June 30, ~~2017~~2018 from $40.1 million for the six months ended June 30, 2016. The increase was primarily due to 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 and fourth pressure pumping fleet online during 2017. As a percentage of revenue, our pressure pumping services division cost of revenue was 71% for both the six months ended June 30, 2017 and June 30, 2016.

~~Well Services. Well services division cost of revenue increased $3.4 million, or 49%, from $7.0 million for the six months ended June 30, 2016 to $10.4~~$66 million for the six months ended June 30, 2017. The increase was primarily due to ~~an increase in labor-related costs.~~the expansion of services into the SCOOP/STACK and Permian Basin with the addition of three fleets during 2017, which accounted for $83 million, or 88%, of the increase. As a percentage of revenue, our ~~well~~pressure pumping services division cost of revenue, ~~was 91%~~exclusive of depreciation and ~~141%~~amortization expense of $28 million and $19 million for the six months ended June 30, 2018 and 2017, was 79% and 73%, respectively, for the six months ended June 30, 2018 and June 30, ~~2016, respectively.~~2017. The ~~decrease~~increase in ~~cost of revenue~~costs as a percentage of revenue was primarily due to ~~increases~~an increase in ~~utilization~~cost of goods sold as ~~well as pricing.~~a result of selling sand with our service package to customers in the mid-continent region.

Infrastructure Services. Infrastructure services division cost of revenue, exclusive of depreciation and amortization expense, was $407 million and $2 million, respectively, for the six months ended June 30, 2018 and 2017. The increase is due to the expansion of our infrastructure business in late 2017 and 2018. The largest components of our cost of revenue include labor-related costs, including contract labor, and travel, meals and lodging expense. As a percentage of revenue, cost of revenue, exclusive of depreciation and amortization expense of $7 million and $0.3 million for the six months ended June 30, 2018 and 2017, was 59% and 100%, respectively, for the six months ended June 30, 2018 and 2017.

Natural Sand Proppant Services. Natural sand proppant services division cost of revenue, exclusive of depreciation, depletion and accretion expense, increased ~~$16.2~~$41 million, or ~~99%~~123%, from ~~$16.4 million for the six months ended June 30, 2016 to $32.6~~$33 million for the six months ended June 30, 2017 to $74 million for the six months ended June 30, 2018, primarily due to an increase in cost of goods sold as a result of a 146% increase in tons ~~sold.~~of sand sold in the 2018 period. As a percentage of revenue, cost of revenue, ~~was 84%~~exclusive of depreciation, depletion and ~~116%~~accretion expense of $6 million and $4 million for the six months ended June 30, 2018 and 2017, was 71% and ~~2016, respectively.~~82%, respectively, for the six months ended June 30, 2018 and June 30, 2017. The decrease ~~in cost of revenue as a percentage of revenue was~~is primarily due to ~~an increase~~startup costs incurred for our Piranha plant, which was acquired in ~~price per ton sold.~~May 2017.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division cost of revenue, exclusive of depreciation expense, increased ~~$10.0~~$7 million, or ~~77%~~30%, from ~~$13.0 million for the six months ended June 30, 2016 to $23.0~~$23 million for the six months ended June 30, 2017 to $30 million for the six months ended June 30, 2018, 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, exclusive of depreciation expense of $10 million for both the six months ended June 30, 2018 and 2017, was ~~99%~~92% and ~~111%~~99%, respectively, for the six months ended June 30, ~~2017~~2018 and ~~2016, respectively.~~June 30, 2017. The decrease was primarily due to higher day rates and ~~utilization.~~a decrease in compensation and benefits expense as a percentage of revenue.

Other ~~Energy~~ Services. Other ~~energy~~ services division cost of revenue, ~~decreased $1.1~~exclusive of depreciation and amortization expense, increased $21 million, or ~~17%~~153%, from ~~$6.4 million the six months ended June 30, 2016 to $5.3~~$14 million for the six months ended June 30, 2017 to $35 million for the six months ended June 30, 2018, primarily due to ~~a decline~~the acquisition of Stingray Cementing and Stingray Energy in ~~contracted labor-related costs.~~June 2017. As a percentage of revenue, cost of revenue, ~~was 57%~~exclusive of depreciation and ~~44% for the six~~

~~months ended June 30, 2017~~amortization expense of $7 million and ~~2016, respectively. The increase was primarily due to the decrease in total room nights rented from 109,229~~$4 million for the six months ended June 30, ~~2016 to 49,438~~2018 and 2017, was 82% and 73%, respectively, for the six months ended June 30, 2018 and 2017. The ~~decrease in~~increase is primarily the result of increased equipment rental expense and labor-related costs ~~associated with our remote accommodation services was partially offset by $1.5 million~~as a percentage of ~~costs associated with our energy infrastructure services.~~revenue.

Selling, General and Administrative ~~expenses~~Expenses. Selling, general and administrative expenses represent the costs associated with managing and supporting our operations. These expenses increased ~~$5.6~~$89 million, or ~~64%~~618%, to ~~$14.4~~$104 million for the six months ended June 30, 2018, from $14 million for the six months ended June 30, 2017 ~~from $8.8~~primarily related to costs incurred for the expansion of our infrastructure business, an increase in provisions for bad debt and an increase in equity based compensation. The equity based compensation represents compensation expense for awards issued by certain Wexford affiliates and had no cash impact to the Company and no dilutive impact relative to the number of shares outstanding. Following is a breakout of SG&A expenses for the periods indicated (in thousands):



	Six Months Ended
	June 30, 2018		June 30, 2017
Cash expenses:
Compensation and benefits	$	18,677	$	5,381
Professional services	5,568		3,581
Other^(a)	5,542		3,880
Total cash SG&A expense	29,787		12,842
Non-cash expenses:
Bad debt provision	53,790		(25		)
Equity based compensation^(b)	17,487		—
Stock based compensation	2,574		1,620
Total non-cash SG&A expense	73,851		1,595
Total SG&A expense	$	103,638	$	14,437


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


b.	Represents compensation expense for non-employee awards, which were issued and are payable by certain affiliates of Wexford (the sponsor level).

Depreciation, Depletion, Amortization and Accretion. Depreciation, depletion, amortization and accretion increased $21 million, or 55%, to $58 million for the six months ended June 30, 2016. The increase in expenses was primarily attributable to a $5.0 million increase in compensation and benefits and a $1.7 million increase in professional fees, partially offset by a decrease in bad debt expense of $1.1 million.

~~Depreciation and Amortization. Depreciation and amortization increased $0.5 million, or 1%, to $37.1~~2018 from $37 million for the six months ended June 30, 2017. The increase is primarily attributable to an increase in property and equipment purchases in the second half of 2017 ~~from $36.6~~and first half of 2018, resulting in increased depreciation expense.

Operating Income (Loss). Operating income increased $215 million to $200 million for the six months ended June 30, ~~2016. The increase was primarily attributable~~2018 compared to ~~placing in service~~an operating loss of ~~$112.4~~$14 million ~~of capital additions~~ for the six months ended June 30, ~~2017, with $105.9~~2017. The increase was primarily the result of an expansion of our infrastructure services business, which accounted for 93%, or $201 million, of the ~~$112.4~~overall increase in operating income and a $21 million ~~of assets placed~~increase in ~~service for the three months ended June 30, 2017,~~natural sand proppant operating income. These were partially offset by ~~$26.2~~a $10 million ~~of assets that fully depreciated~~decrease in pressure pumping operating income due to an increase in non-cash equity compensation expense during ~~2016.~~

~~Impairment of Long-lived Assets.~~ ~~The~~the six months ended June 30, 2016 included impairment charges of $1.9 million attributable to various fixed assets in the amount of $0.3 million, $0.1 million and $1.4 million for the contract land and directional drilling services, pressure pumping and well service segments, respectively.2018.

Interest Expense, Net. Interest expense, ~~decreased $0.8~~net increased $1 million, or ~~35%~~46%, ~~to $1.5 million~~ during the six months ended June 30, ~~2017, from $2.3 million~~2018 primarily due to an increase in average borrowings outstanding during the six months ended June 30, ~~2016. The decrease in interest expense was attributable~~2018 compared to ~~a decrease in average borrowings during~~ the six months ended June 30, 2017.

Other ~~(Expense) Income,~~Expense, Net. Non-operating ~~(charges) income~~charges, net resulted in expense of $1 million and $0.4 million for the six months ended June 30, ~~2017, compared to other income, net of $0.6 million for the six months ended June 30, 2016.~~2018 and 2017. Both periods were primarily comprised of ~~income/~~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 six months ended June 30, 2017, we recognized income tax benefit of $5.9 million compared to anWe recorded income tax expense of ~~$1.7~~$99 million ~~for the three months ended June 30, 2016. The provision~~on pre-tax income of $198 million for the six months ended June 30, ~~2016~~2018 compared to an income tax benefit of $6 million on pre-tax loss of $12 million for the six months ended

June 30, 2017. Our effective tax rate was 50% for the six months ended June 30, 2018 compared to 37% for the six months ended June 30, 2017. The increase in effective tax rate is primarily ~~attributable~~due to the equity based compensation expense recognized during the six months ended June 30, 2018 as well as a higher tax rate in Puerto Rico, where most of our ~~subsidiary, Lodging, which provides our remote accommodation services.~~income was generated during the six months ended June 30, 2018, compared to the United States tax rate. No income was generated in Puerto Rico during the six months ended June 30, 2017.

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, accretion and amortization, ~~impairment of long-lived assets,~~ acquisition related costs, public offering costs, equity based compensation, stock based compensation, bargain purchase gain, interest expense, net, other (income) expense, net (which is comprised of the (gain) or loss on disposal of long-lived assets)~~, bargain purchase gain~~ and provision (benefit) for income taxes. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our ~~industry~~industries depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (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 ~~measure~~measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

The following tables ~~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						Six Months Ended						Three Months Ended					Six Months Ended
	June 30,						June 30,						June 30,					June 30,
Reconciliation of Adjusted EBITDA to net income (loss):	2017			2016			2017			2016			2018		2017			2018		2017
Net income (loss)	$	(1,169,515	)	$	(8,403,337	)	$	(6,150,794	)	$	(31,768,306	)	$	42,700	$	(1,170	)	$	98,246	$	(6,151	)
Depreciation and amortization expense	19,893,399			18,810,615			37,130,650			36,561,687
Depreciation, depletion, accretion and amortization expense													30,795		19,893			57,703		37,130
Impairment of long-lived assets	—			1,870,885			—			1,870,885			187		—			187		—
Acquisition related costs	961,237			—			2,190,749			—			77		961			31		2,208
Public offering costs													731		—			731		—
Equity based compensation	1,050,062			—			1,619,893			—			17,487		—			17,487		—
Stock based compensation													1,660		1,050			2,916		1,620
Bargain purchase gain	(4,011,512		)	—			(4,011,512		)	—			—		(4,012		)	—		(4,012		)
Interest expense	1,111,608			1,012,031			1,508,792			2,308,387
Other expense (income), net	202,496			(626,716		)	386,642			(625,726		)
(Benefit) provision for income taxes	(2,804,077		)	789,375			(5,910,142		)	1,683,735
Interest expense, net													959		1,112			2,196		1,509
Other expense, net													486		203			514		387
Provision (benefit) for income taxes													53,512		(2,804		)	99,430		(5,910		)
Adjusted EBITDA	$	15,233,698		$	13,452,853		$	26,764,278		$	10,030,662		$	148,594	$	15,233		$	279,441	$	26,781

Pressure Pumping Services


	Three Months Ended				Six Months Ended					Three Months Ended					Six Months Ended
	June 30,				June 30,					June 30,					June 30,
Reconciliation of Adjusted EBITDA to net income (loss):	2017		2016		2017		2016			2018			2017		2018			2017
Net income (loss)	$	1,759,713	$	3,665,382	$	2,440,932	$	(5,271,214	)
Net income										$	(11,433	)	$	1,187	$	(9,474	)	$	1,369
Depreciation and amortization expense	9,626,553		9,958,270		18,784,446		18,913,487			13,829			9,626		27,815			18,784
Impairment of long-lived assets	—		138,587		—		138,587
Acquisition related costs										33			—		33			—
Public offering costs										202			—		202			—
Equity based compensation	502,901		—		774,289		—			17,487			—		17,487			—
Stock based compensation										453			503		871			774
Interest expense	303,351		131,709		431,795		368,764			341			303		845			431
Other (income) expense, net	3,758		43,033		6,389		23,825
Other expense, net										80			4		92			7
Adjusted EBITDA	$	12,196,276	$	13,936,981	$	22,437,851	$	14,173,449		$	20,992		$	11,623	$	37,871		$	21,365

~~Other Well~~Infrastructure Services


	Three Months Ended						Six Months Ended						Three Months Ended					Six Months Ended
	June 30,						June 30,						June 30,					June 30,
Reconciliation of Adjusted EBITDA to net income (loss):	2017			2016			2017			2016			2018		2017			2018			2017
Net income (loss)	$	1,373,396		$	(3,267,228	)	$	2,532,253		$	(6,574,864	)	$	52,359	$	(568	)	$	99,658		$	(702	)
Depreciation and amortization expense	2,219,921			1,272,715			3,428,162			2,670,222			4,094		340			6,501			340
Impairment of long-lived assets	—			1,384,751			—			1,384,751
Acquisition related costs	—			—			170,132			—			4		42			(4		)	42
Equity based compensation	90,461			—			137,450			—
Public offering costs													360		—			360			—
Stock based compensation													606		—			1,063			—
Interest expense	(2,474		)	50,776			(108,376		)	149,095			106		4			182			4
Other (income) expense, net	(3,173		)	(682,545		)	(1,991		)	(673,145		)
Provision (benefit) for income taxes	(2,808,982		)	(3,094		)	(6,500,514		)	(3,094		)
Other expense, net													330		—			332			—
Provision for income taxes													52,632		—			100,589			—
Adjusted EBITDA	$	869,149		$	(1,244,625	)	$	(342,884	)	$	(3,047,035	)	$	110,491	$	(182	)	$	208,681		$	(316	)

Natural Sand Proppant Services


	Three Months Ended						Six Months Ended						Three Months Ended					Six Months Ended
	June 30,						June 30,						June 30,					June 30,
Reconciliation of Adjusted EBITDA to net income (loss):	2017			2016			2017			2016			2018		2017			2018			2017
Net income (loss)	$	2,915,354		$	(2,493,969	)	$	1,653,207		$	(7,568,330	)
Depreciation and amortization expense	2,205,694			1,581,334			3,568,659			2,949,851
Net income													$	10,929	$	3,409		$	20,301		$	2,643
Depreciation, depletion, accretion and amortization expense													3,881		2,206			6,197			3,569
Acquisition related costs	916,214			—			1,954,079			—			—		916			(38		)	1,954
Equity based compensation	182,337			—			252,461			—
Public offering costs													95		—			95			—
Stock based compensation													205		182			391			252
Bargain purchase gain	(4,011,512		)	—			(4,011,512		)	—			—		(4,012		)	—			(4,012		)
Interest expense	352,600			106,650			485,239			211,111			76		353			156			486
Other (income) expense, net	139,569			53,803			153,776			72,985
Other expense, net													36		140			23			154
Provision for income taxes	8,502			—			8,502			—			—		9			—			9
Adjusted EBITDA	$	2,708,758		$	(752,182	)	$	4,064,411		$	(4,334,383	)	$	15,222	$	3,203		$	27,125		$	5,055

Contract Land and Directional Drilling Services


	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
Reconciliation of Adjusted EBITDA to net income (loss):	2017			2016			2017			2016			2018			2017			2018			2017
Net loss	$	(6,469,181	)	$	(8,235,701	)	$	(13,316,234	)	$	(16,692,975	)	$	(5,454	)	$	(6,470	)	$	(10,904	)	$	(13,314	)
Depreciation and amortization expense	4,973,682			5,438,551			9,942,310			10,945,932			5,349			4,974			9,704			9,942
Impairment of long-lived assets	—			347,547			—			347,547			187			—			187			—
Acquisition related costs	3,000			—			24,515			—			—			3			—			25
Equity based compensation	180,394			—			292,264			—
Interest expense	439,876			701,633			657,058			1,554,207
Other expense (income), net	60,451			(47,500		)	224,236			(57,574		)
Public offering costs													34			—			34			—
Stock based compensation													301			180			408			292
Interest expense, net													265			440			660			657
Other expense, net													32			60			72			224
Adjusted EBITDA	$	(811,778	)	$	(1,795,470	)	$	(2,175,851	)	$	(3,902,863	)	$	714		$	(813	)	$	161		$	(2,174	)

Other Services^(a)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
Reconciliation of Adjusted EBITDA to net income (loss):	2018			2017			2018			2017
Net (loss) income	$	(3,453	)	$	1,272		$	(1,346	)	$	3,853
Depreciation and amortization expense	3,642			2,747			7,486			4,495
Acquisition related costs	40			—			40			187
Public offering costs	40			—			40			—
Stock based compensation	94			184			183			301
Interest expense, net	171			12			353			(69		)
Other expense, net	8			(1		)	(5		)	2
(Benefit) provision for income taxes	880			(2,813		)	(1,158		)	(5,919		)
Adjusted EBITDA	$	1,422		$	1,401		$	5,593		$	2,850

(a) Includes results for our coil tubing, pressure control, flowback, cementing, acidizing, equipment rentals, crude oil hauling and remote accommodations services and corporate related activities. Our corporate related activities do not generate revenue.

Adjusted Net Income and Adjusted Earnings per Share

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

~~Other Energy Services~~

Three Months Ended Six Months Ended
June 30, June 30,
Reconciliation of Adjusted EBITDA to net income (loss): 2017 2016 2017 2016
Net (loss) income $ (748,797 ) $ 1,928,179
$ 539,048
$ 4,339,077
Depreciation and amortization expense 867,549
559,745
1,407,073
1,082,195
Impairment of long-lived assets —
—
—
—
Acquisition related costs 42,023
—
42,023
—
Equity based compensation 93,969
—
163,429
—
Interest expense 18,255
21,263
43,076
25,210
Other expense (income), net 1,891
6,493
4,232
8,183
Provision (benefit) for income taxes (3,597 ) 792,469
581,870
1,686,829
Adjusted EBITDA $ 271,293
$ 3,308,149
$ 2,780,751
$ 7,141,494



	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2018		2017			2018		2017
	(in thousands, except per share amounts)
Net income, as reported	$	42,700	$	(1,170	)	$	98,246	$	(6,151	)
Equity based compensation	17,487		—			17,487		—
Adjusted net income	$	60,187	$	(1,170	)	$	115,733	$	(6,151	)

Basic earnings per share, as reported	$	0.95	$	(0.03	)	$	2.20	$	(0.16	)
Equity based compensation	0.40		—			0.40		—
Adjusted basic earnings per share	$	1.35	$	(0.03	)	$	2.60	$	(0.16	)

Diluted earnings per share, as reported	$	0.95	$	(0.03	)	$	2.18	$	(0.16	)
Equity based compensation	0.39		—			0.39		—
Adjusted diluted earnings per share	$	1.34	$	(0.03	)	$	2.57	$	(0.16	)

Liquidity and Capital Resources

We require capital to fund ongoing operations, including maintenance expenditures on our existing fleet ~~and~~of equipment, organic growth initiatives, investments and acquisitions. Since November 2014, our primary sources of liquidity have been cash on hand, borrowings under our revolving credit facility, ~~and~~ cash flows from ~~operations.~~operations and proceeds from our initial public offering. Our primary use of capital has been for investing in property and equipment used to provide our services and to acquire ~~complimentary~~complementary businesses. On July 16, 2018, we initiated a quarterly dividend policy a declared our first quarterly cash dividend to be paid in August 2018. Future declaration of cash dividends are subject to approval by our Board of Directors and may be adjusted at their discretion based on market conditions and capital availability.

As of June 30, ~~2017,~~2018, we had ~~an aggregate~~no borrowings outstanding under our revolving credit facility and $163 million of ~~$65.0~~available borrowing capacity under this facility, after giving effect to $7 million inof outstanding letters of credit.

The following table summarizes our liquidity for the periods indicated (in thousands):



	June 30,			December 31,
	2018			2017
Cash and cash equivalents	$	10,702		$	5,637
Revolving credit facility availability	169,233			169,233
Less long-term debt	—			(99,900		)
Less letter of credit facilities (environmental remediation)	(3,582		)	(3,582		)
Less letter of credit facilities (insurance programs)	(2,486		)	(2,486		)
Less letter of credit facilities (rail car commitments)	(455		)	(455		)
Net working capital (less cash)^(a)	5,688			88,798
Total	$	179,100		$	157,245

Net working capital (less cash) is a non-GAAP measure and is calculated by subtracting total current liabilities of $365 million and cash and cash equivalents of $11 million from total current assets of $382 million as of June 30, 2018. As of December 31, 2017, net working capital (less cash) is calculated by subtracting total current liabilities of $220 million and cash and cash equivalents of $6 million from total current assets of $314 million.

At August 3, 2018, we had no borrowings outstanding under our revolving credit facility, leaving an aggregate of ~~$104.7~~$163 million of available borrowing capacity under this ~~facility.~~

~~The following table summarizes our liquidity for the periods indicated:~~

June 30, December 31,
2017 2016
Cash and cash equivalents $ 8,549,290
$ 29,238,618
Revolving credit facilities availability 169,664,874
146,181,002
Less long-term debt (65,000,000 ) —
Less letter of credit facilities (rail car commitments) (454,560 ) (2,090,560 )
Less letter of credit facilities (insurance programs) (1,636,000 ) (1,285,000 )
Less letter of credit facilities (environmental remediation) (3,363,627 ) —
Net working capital (less cash) 26,231,951
30,453,429
Total $ 133,991,928
$ 202,497,489

~~At August 2, 2017, we had an aggregate~~facility, which is net of ~~$92.2 million in borrowings outstanding under our revolving~~letters of credit ~~facility, leaving an aggregate~~ of ~~$77.5 million of available borrowing capacity under this facility.~~$7 million.

Liquidity and Cash Flows

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


	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Net cash provided by (used in) operating activities	$	9,586,596		$	(9,504,324	)	$	24,004,999		$	10,946,117
Net cash (used in) provided by investing activities	(71,952,982		)	1,491,486			(102,693,416		)	991,310
Net cash provided by operating activities													$	125,128		$	9,586		$	226,451		$	24,004
Net cash used in investing activities													(85,755		)	(71,952		)	(121,243		)	(102,693		)
Net cash provided by (used in) financing activities	57,926,146			(5,102,744		)	57,926,146			(14,602,516		)	(39,073		)	57,926			(100,045		)	57,926
Effect of foreign exchange rate on cash	62,288			(126,397		)	72,943			54,163			(45		)	62			(98		)	73
Net change in cash	$	(4,377,952	)	$	(13,241,979	)	$	(20,689,328	)	$	(2,610,926	)	$	255		$	(4,378	)	$	5,065		$	(20,690	)

Operating Activities

Net cash provided by operating activities was ~~$24.0~~$226 million for the six months ended June 30, ~~2017,~~2018, compared to ~~$10.9~~$24 million for the six months ended June 30, ~~2016.~~2017. Net cash provided by operating activities was $125 million for the three months ended June 30, 2018 compared to $10 million for the three months ended June 30, 2017. The increase in operating cash flows was primarily attributable to the increase in ~~revenue.~~

~~Net cash provided by operating activities was $9.6 million for~~net income as a result of the ~~three months ended June 30, 2017, compared to cash used~~expansion of ~~$9.5 million for the three months ended June 30, 2016. The increase~~our infrastructure services business and improvements in ~~operating cash flows was primarily attributable to timing of receivable collections with related parties.~~our pressure pumping and sand businesses.

Investing Activities

Net cash used in investing activities was ~~$102.7~~$121 million for the six months ended June 30, ~~2017,~~2018, compared to ~~net cash provided by investing activities of $1.0~~$103 million for the six months ended June 30, ~~2016.~~2017. Net cash used in investing activities was ~~$72.0~~$86 million for the three months ended June 30, ~~2017,~~2018, compared to ~~net cash provided by investing activities of $1.5~~

$72 million for the three months ended June 30, ~~2016. With the exception of the businesses acquired, substantially all cash~~2017. Cash used in investing activities was used to purchase property and equipment that is utilized to provide our ~~services.~~services and to acquire complementary businesses.

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

Three Months Ended Six Months Ended
June 30, June 30,
2017 2016 2017 2016
Pressure pumping services (a) $ 24,736,600
$ 896,847
$ 53,401,909
$ 927,542
Well services (b) 344,474
247,829
344,474
247,829
Natural sand proppant production (c) 2,795,370
65,184
2,969,883
157,726
Contract and directional drilling services (d) 3,631,540
158,924
5,900,817
423,095
Other energy services (e) 3,958,043
270,386
3,958,636
418,017
Net change in cash $ 35,466,027
$ 1,639,170
$ 66,575,719
$ 2,174,209



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2018		2017		2018		2017
Pressure pumping services^(a)	$	8,233	$	24,737	$	16,099	$	53,402
Infrastructure services^(b)	40,778		3,958		56,556		3,958
Natural sand proppant services^(c)	6,958		2,795		12,658		2,970
Contract and directional drilling services^(d)	7,083		3,632		10,701		5,901
Other^(e)	9,959		344		12,771		344
Total capital expenditures	$	73,011	$	35,466	$	108,785	$	66,575

~~(a).~~

a. Capital expenditures primarily for pressure pumping equipment for the six months ended June 30, 2018 and 2017.

b. Capital expenditures primarily for trucks and other equipment for the six months ended June 30, 2018 and 2017.

c. Capital expenditures primarily for plant upgrades for the six months ended June 30, 2018 and 2017.


d.	Capital expenditures primarily for upgrades to our rig fleet and real estate purchases for the six months ended June 30, ~~2017~~2018 and ~~2016.~~


~~(b).~~	~~Capital expenditures primarily for equipment upgrades for the six months ended June 30, 2017 and 2016.~~


~~(c).~~	~~Capital expenditures included a conveyor for the six months ended June 30, 2017 and plant additions for the six months ended June 30, 2016.~~


~~(d).~~	~~Capital expenditures primarily for~~ upgrades to our rig fleet for the six months ended June 30, ~~2017 and 2016.~~2017.


~~(e).~~	Capital expenditures primarily for an intersection upgrade for the six months ended June 30, 2016. Capital expenditures for the six months ended June 30, 2017 represent property and equipment for energy infrastructure services.

e. Capital expenditures primarily for equipment for our rental and crude oil hauling businesses for the six months ended June 30, 2018.

Financing Activities

Net cash ~~provided by~~used in financing activities was ~~$57.9~~$100 million for the six months ended June 30, ~~2017,~~2018, compared to net cash ~~used in~~provided by financing activities of ~~$14.6~~$58 million for the six months ended June 30, ~~2016.~~2017. Net cash ~~provided by~~used in financing activities was ~~$57.9~~$39 million for the three months ended June 30, ~~2017,~~2018, compared to net cash ~~used in~~provided by financing activities of ~~$5.1~~$58 million for the three months ended June 30, 2016. For the six months ended June 30, 2017, cash provided by financing activities were used to fund the Chieftain and Higher Power Electrical, LLC acquisitions and to purchase property and equipment. For the six months ended June 30, 2016, substantially all2017. Net cash used in financing activities was ~~used~~primarily attributable to ~~pay down~~net repayments under our revolving credit facility of $39 million and $99 million, respectively for the three and six months ended June 30, 2018. Net cash provided by financing activities was primarily attributable to net borrowings under our revolving credit ~~facility.~~facility of $65 million for the three and six months ended June 30, 2017.

Effect of Foreign Exchange Rate on Cash

The effect of foreign exchange rate on cash was ($0.1) million and $0.1 million, respectively, for ~~each of~~ the six months ended June 30, ~~2017~~2018 and ~~2016.~~2017. The ~~effect of foreign rate on cash was $0.1 million for the three months ended June 30, 2017, compared to $(0.1) million for the three months ended June 30, 2016. The year-over-year effect~~change was driven primarily by a favorable (unfavorable) shift in the weakness (strength) of the Canadian dollar relative to the U.S. dollar for the cash held in Canadian accounts.

Working Capital

Our working capital totaled ~~$34.8~~$16 million and ~~$59.7~~$94 million, respectively, at June 30, ~~2017~~2018 and December 31, ~~2016, respectively.~~2017. Our cash balances ~~totaled $8.5~~were $11 million and ~~$29.2~~$6 million, respectively, at June 30, ~~2017~~2018 and December 31, ~~2016, respectively.~~2017.

Our Revolving Credit Facility

~~On November 25, 2014, we entered into~~We are party to a ~~$170.0~~$170 million revolving credit and security agreement, dated as of November 25, 2014 as subsequently amended, with PNC Capital Markets LLC, as lead arranger, PNC Bank, National Association, as 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 future borrowings under our revolving credit facility is 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 credited to the borrowing base for sand inventory and for in-transit inventory and increasing certain default thresholds from $5 million to $15 million.

Effective as of July 9, 2018, our revolving credit facility was again amended to, among other things, permit (i) the declaration of quarterly cash distributions on the shares representing equity of Mammoth if, among other things, after giving effect to the payment of such dividend or distributions contemplated by the declaration, pro forma excess availability would be no less than 22.5% of the maximum available credit and no default or event of default exists, (ii) the payment of the declared dividends or distributions if (x) such dividends or distributions are made within sixty (60) days after the declaration thereof and (y) on the date such dividends or distributions are made, (1) after giving effect to the payment of such dividend or distribution, pro forma excess availability would be no less than 22.5% of the maximum available credit and (2) no material default or material event of default shall have occurred, or would result therefrom, and (iii) the issuance of third-party surety bonds in favor of Mammoth and its subsidiaries in relation with their bonded contracts, in each case subject to the additional limitations described in the Third Amendment.

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, and 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 June 30, ~~2017, $57.0 million of the total~~2018, we had no outstanding ~~balance of $65.0 million~~borrowings under ~~the facility was in a one month LIBOR rate option tranche with an interest rate of 3.72%. As of~~our credit facility. At June 30, ~~2017,~~2018, we had availability of ~~$104.7~~$163 million under our revolving credit ~~facility. We used a portion of the net proceeds from our IPO~~facility, after giving effect to repay all borrowings outstanding under our revolving credit facility and at August 2, 2017, had an aggregate of $92.2 million in borrowings outstanding under our revolving credit facility, leaving an aggregate of $77.5$7 million of ~~available borrowing capacity under this facility.~~outstanding letters of credit.

Our revolving credit facility contains various customary affirmative and restrictive covenants. Among the covenants are two financial covenants, including a minimum interest coverage ratio (3.0 to 1.0), and a maximum leverage ratio (4.0 to 1.0), and minimum availability ($10.0 million). As of June 30, ~~2017~~2018 and December 31, ~~2016,~~2017, we were in compliance with these financial covenants.

Capital Requirements and Sources of Liquidity

~~With commodity prices beginning to increase in the second half of 2016 and then stabilizing within their current range,~~During 2018, we ~~have seen an increase in customer demand, particularly~~currently estimate that our aggregate capital expenditures will be approximately $205 million. These capital expenditures include $98 million in our ~~pressure pumping and~~infrastructure services segment for assets for additional crews, $25 million in our 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 $64.0segment primarily related to expansion projects, $21 million in our pressure pumping ~~services division~~segment for ~~the acquisition of 132,500 horsepower of new high~~various pressure ~~hydraulic pumps and related~~pumping equipment, ~~$8.0~~$14 million in our ~~pressure pumping service division for tractors, pneumatic trailers to enhance our last mile solutions, $25.0 million in our sand~~contract land and directional drilling services segment ~~for plant capacity expansion projects, and $33.0 million~~primarily for rig upgrades and ~~additional~~real estate, $17 million for expansion of our rental equipment business in Ohio and into Oklahoma, $10 million for the expansion of our ~~well services, contract~~water transfer business, $8 million for the expansion of our crude hauling business, $6 million for coil tubing equipment and ~~direction drilling services and~~$6 million for other ~~energy services divisions.~~capital expenditures. During the first ~~six months ended June 30, 2017, we spent approximately $66.6 million on such~~half of 2018, our capital expenditures ~~including $35.5 million during the second quarter of 2017, and an additional $39.6 million to complete business acquisitions.~~totaled $109 million.

We believe that our cash on hand, operating cash flow and available borrowings under our revolving credit facility will be sufficient to fund our operations for at least the next twelve months. However, future cash flows are subject to a number of variables, and significant additional capital expenditures could be required to conduct our operations. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, we continue to pursue our previously announced acquisition strategy to enhance our portfolio of products and services, market positioning and/or geographic ~~presence. We~~presence in both other existing and new industries. In doing so, we regularly evaluate acquisition ~~opportunities, and the number of opportunities coming to our attention has increased substantially since the IPO.~~opportunities. However, we do not have a specific acquisition budget for ~~2017~~2018 since the timing and size of acquisitions cannot be accurately forecasted. 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 that or other reasons, we may do so through borrowings under our revolving credit facility, joint venture partnerships, asset sales, offerings of debt or equity securities or other means. We cannot assure you that this additional capital will be available on acceptable terms or at all. If we are unable to obtain funds we need, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to conduct our operations.

Off-Balance Sheet Arrangements

Lease Obligations

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

2062.

Minimum Purchase Commitments

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

Capital Spend Commitments

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

Aggregate future minimum lease payments under these agreements in effect at June 30, ~~2017~~2018 are as ~~follows:~~follows (in thousands):


Year ended December 31:	Operating Leases		Capital Spend Commitments		Minimum Purchase Commitments		Operating Leases		Capital Spend Commitments		Minimum Purchase Commitments
Remainder of 2017	$	5,486,024	$	22,730,189	$	6,689,581
2018	9,177,272		—		10,866,000
Remainder of 2018							$	12,148	$	16,393	$	19,254
2019	8,075,402		—		10,866,000		18,091		—		12,125
2020	5,597,885		—		—		15,622		—		400
2021	2,645,182		—		—		12,029		—		165
2022							8,995		—		—
Thereafter	3,721,249		—		—		6,057		—		—
	$	34,703,014	$	22,730,189	$	28,421,581	$	72,942	$	16,393	$	31,944

Other Commitments

Subsequent to June 30, ~~2017,~~2018, we entered into arail car and property lease ~~agreement for~~agreements with aggregate commitments of $2.4 million.

Subsequent to June 30, 2018, we ordered additional capital equipment with aggregate commitments of ~~$1.5~~$9.6 million.

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~~." The Company expects to adopt this new revenue guidance utilizing the full retrospective method of adoption in the first quarter of 2018, and because the Company is still evaluating the portion of its revenues that may be subject to the new leasing guidance discussed below, it is unable to quantify the impact that the new revenue standard will have on the Company’s consolidated financial statements upon adoption. Remaining implementation matters include establishing new policies, procedures, and controls and quantifying any adoption date adjustments.

In February 2016, the FASB issued ASU No, 2016-2 “~~Leases~~”“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 expects~~We plan to adopt this ~~updated leasing guidance at~~ASU effective January 1, 2019 utilizing the ~~same time its adopts the new revenue standard discussed above, utilizing the~~modified retrospective method of adoption. This new leasing guidance will ~~also~~ impact ~~the Company~~us in situations where ~~it is~~we are the lessee, and in certain circumstances itwe will have a right-of-use asset and lease liability on ~~its~~our consolidated financial statements. We are currently evaluating the effect the new guidance ~~will~~may have on our consolidated financial statements and results of operations.

In June 2018, the FASB issued ASU No. 2018-07, “Compensation - Stock Compensation (Topic 718): Improvements to Non-employee Share-Based Accounting,” which simplifies the accounting for share-based payments granted to non-employees by aligning the accounting with requirements for employee share-based compensation. Upon transition, this ASU requires non-employee awards to be measured at fair value as of the adoption date. This ASU is effective for fiscal years beginning after December 15, 2018, and interim periods within that fiscal year. Early adoption is permitted. Currently, we have not elected to early adopt this ASU and are evaluating the impact it will have on our consolidated financial statements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The demand, pricing and terms for ~~oil~~our 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; the level of 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; available~~reserves and frac sand reserves meeting industry specifications and consisting of the mesh size in demand; access to pipeline, transloading and other transportation facilities and their capacity; weather conditions; domestic and worldwide economic conditions; political instability in oil-producing countries; environmental regulations; technical advances affecting energy consumption; the price and availability of alternative fuels; the ability of oil and natural gas producers and other users of our services to raise equity capital and debt financing; and merger and divestiture activity ~~among oil and natural gas producers.~~in industries in which we operate.

The level of activity in the U.S. oil and natural gas exploration and production, ~~industry~~energy infrastructure and natural sand proppant industries is volatile. Expected trends ~~in oil and natural gas production activities~~ may not continue and demand for our products and services may not reflect the level of activity in ~~the industry.~~these industries. Any prolonged substantial reduction in ~~oil and natural gas prices~~pricing environment would likely ~~affect oil and natural gas production levels and therefore~~ affect demand for our services. A material decline in ~~oil and natural gas prices~~pricing levels or U.S. activity levels could have a material adverse effect on our business, financial condition, results of operations 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.~~

Interest Rate Risk

We had a cash and cash equivalents balance of ~~$8.5~~$11 million at June 30, ~~2017.~~2018. We do not enter into investments for trading or speculative purposes. We do not believe that we have any material exposure to changes in the fair value of these investments as a result of changes in interest rates. Declines in interest rates, however, will reduce future income.

Interest under our credit facility is payable at a base rate plus an applicable margin. Additionally, at our request, outstanding balances are permitted to be converted to LIBOR rate plus applicable margin tranches. The applicable margin for either the base rate or the LIBOR rate option can vary from 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 June 30, ~~2017,~~2018, we had ~~$65.0 million~~no outstanding borrowings under ~~this~~our revolving credit facility. As of June 28, 2018, the last day on which we had outstanding borrowings under our revolving credit facility, ~~with weighted average interest rate of 3.91%. A~~a 1% increase or decrease in the interest rate ~~at that time~~ would have increased or decreased our interest expense by approximately ~~$0.7~~$0.2 million per ~~year.~~year, based on $20 million outstanding and a weighted average interest rate of 4.55%. 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, 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 June 30, ~~2017,~~2018, we had ~~$3.1~~$3 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 June 30, ~~2017.~~2018. Conversely, a corresponding decrease in the strength of the Canadian dollar would have resulted in a comparable decrease in pre-tax income. We have not hedged our exposure to changes in foreign currency exchange rates and, as a result, could incur unanticipated translation gains and losses.

Seasonality

We provide completion and production services as well as contract land and drilling services primarily in the Utica, Permian Basin, Eagle Ford, Marcellus, Granite Wash, Cana Woodford and Cleveland sand resource plays located in the continental U.S. We ~~also~~provide infrastructure services in the northeast, southwest and midwest portions of the United States and in Puerto Rico. We provide remote accommodation services in the oil sands in Alberta, Canada. We serve these markets through our facilities and service centers that are strategically located to serve ~~resource plays~~our customers in Ohio, Texas, Oklahoma, Wisconsin, Minnesota, Kentucky, Puerto Rico and Alberta, Canada. ~~For the six months ended June 30, 2017 and 2016, we generated approximately 81% and 85%, respectively,~~A portion of our ~~revenue from our operations~~revenues are generated in Ohio, Wisconsin, Minnesota, North Dakota, Pennsylvania, West Virginia and Canada where weather conditions may be severe. As a result, our

operations may be limited or disrupted, particularly during winter and spring months, in these geographic regions, which would have a material adverse effect on our financial condition and results of operations. Our operations in Oklahoma and Texas are generally not affected by seasonal weather conditions.

Item 4. Controls and Procedures

Evaluation of Disclosure Control and Procedures

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

As of June 30, ~~2017,~~2018, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that as of June 30, ~~2017,~~2018, 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 June 30, ~~2017~~2018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

The Company is routinely involved in state and local tax audits. During 2015, the State of Ohio assessed taxes on the purchase of equipment the Company believes is exempt under state law. The Company has appealed the assessment and a hearing was scheduled for November 30, 2016. In November 2016, the State of Ohio deferred the hearing until 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 the financial position or results of operations of the Company.

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. In the opinion of our management, none of the pending litigation, disputes or claims against us ~~if decided adversely, will~~is expected to have a material adverse effect on our financial condition, cash flows or results of operations.

See ~~Part I, Item 1.~~ Note 1318 "Commitments and Contingencies," of ~~this Report.~~the Notes to Unaudited Condensed Consolidated Financial Statements for additional information.

Item 1A. Risk Factors

Security holders and potential investors in our securities should carefully consider the risk factors ~~set forth below and~~ in our Annual Report on Form 10-K (Commission File No. 001-37917) filed with the SEC on February ~~24, 2017, together with other information~~28, 2018 and in ~~this Report~~our Rule 424(b)(5) prospectus summary and ~~other reports and materials we file~~related base prospectus filed with the SEC. We have identified these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us orSEC on ~~our behalf.~~June 26, 2018.

~~Inaccuracies~~There have been no material changes to the Risk Factors previously disclosed in ~~estimates of volumes and qualities of~~ our ~~sand reserves could result in lower than expected sales and higher than expected production costs.~~

Estimates of sand reserves are by nature imprecise and depend to some extent on statistical inferences drawn from available data, which may prove unreliable. There are numerous uncertainties inherent in estimating quantities and qualities of sand reserves and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically recoverable sand reserves necessarily depend on a number of factors and assumptions, all of which may vary considerably from actual results, such as:

~~geological and mining conditions and/or effects from prior mining that may not be fully identified by available data or that may differ from experience;~~

~~assumptions concerning future prices of frac sand, operating costs, mining technology improvements, development costs and reclamation costs; and~~

~~assumptions concerning future effects of regulation, including the issuance of required permits and taxes by governmental agencies.~~

Any inaccuracy in the estimates related to our sand reserves could result in lower than expected sales and higher than expected costs. For example, these estimates assume that our revenue and cost structure will remain relatively constant over the life of our reserves. If these assumptions prove to be inaccurate, some or all of our reserves may not be economically mineable, which could have a material adverse effect on our results of operations and cash flows. In addition, we pay a fixed price per ton of sand excavated regardless of the quality of the frac sand, and our current customer contracts require us to deliver frac sand that meets certain specifications. If the estimates of the quality of our sand reserves, including the volumes of the various specifications of those reserves, prove to be inaccurate, we may incur significantly higher excavation costs without corresponding increases in revenues, we may not be able to meet our contractual obligations, or our facilities may have a shorter than expected reserve life, which could have a material adverse effect on our results of operations and cash flows.

Our operations are dependent on our rights and ability to mine our properties and on our having renewed or received the required permits and approvals from governmental authorities and other third parties.

We hold numerous governmental, environmental, mining, and other permits, water rights, and approvals authorizing operations at our production facilities. For our extraction and processing in Wisconsin, the permitting process is subject to federal, state and local authority. For example, on the federal level, a Mine Identification Request (MSHA Form 7000-51) must be filed and obtained before mining commences. If wetlands are implicated, a U.S. Army Corps of Engineers Wetland Permit is required. At the state level, a series of permits are required related to air quality, wetlands, water quality (waste water, storm water), grading

~~MAMMOTH ENERGY SERVICES, INC.~~

permits, endangered species, archaeological assessments and high capacity wells in addition to others depending upon site specific factors and operational detail. At the local level, zoning, building, storm water, erosion control, wellhead protection, road usage and access are all regulated and require permitting to some degree. A non-metallic mining reclamation permit is required. A decision by a governmental agency or other third party to deny or delay issuing a new or renewed permit or approval, or to revoke or substantially modify an existing permit or approval, could have a material adverse effect on our ability to continue operations.

Title to, and the area of, mineral properties and water rights may also be disputed. Mineral properties sometimes contain claims or transfer histories that examiners cannot verify. A successful claim that we do not have title to our property or lack appropriate water rights could cause us to lose any rights to explore, develop and extract minerals, without compensation for our prior expenditures relating to such property. Our business may suffer a material adverse effect in the event we have title deficiencies.

In some instances, we have received access rights or easements from third parties, which allow for a more efficient operation than would exist without the access or easement. A third party could take action to suspend the access or easement, and any such action could be materially adverse to our business, results of operations or financial condition.Prospectus Summary dated July 26, 2018.

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

On June 5, 2017, we issued an aggregate of 7.0 million shares of our common stock 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 reliance upon the exemption from the registration requirements of the Securities Act provided by Section 4(2) of the Securities Act as sales by an issuer not involving any public offeringNot applicable.

Item 4. Mine Safety Disclosures

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

Item 5. Other Information

Not applicable.

MAMMOTH ENERGY SERVICES, INC.

Item 6. Exhibits

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

Incorporated By Reference
Exhibit Number Exhibit Description Form Commission File No. Filing Date Exhibit No. Filed Herewith Furnished Herewith
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
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.

Incorporated By Reference

Exhibit Number

Exhibit Description

Form

Commission File No.

Filing Date

Exhibit No.

Filed Herewith

Furnished Herewith

3.1

Amended and Restated Certificate of Incorporation of the Company

8-K

001-37917

11/15/2016

3.1

3.2

Amended and Restated Bylaws of the Company

8-K

001-37917

11/15/2016

3.2

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

Master Service Contract for PREPA's Electrical Grid Repairs Hurricane Maria, executed on May 26, 2018, by the Puerto Rico Electric Power Authority (PREPA) and Cobra Acquisitions LLC.

8-K

001-37917

5/31/2018

10.1

10.2

Third Amendment to Revolving Credit and Security Agreement, dated as of July 9, 2018, by and among Mammoth Energy Services, Inc., and certain of its direct and indirect subsidiaries, the lenders party to the Revolving Credit and Security Agreement from time to time and PNC Bank, National Association, as a lender and agent for the lenders.

8-K

001-37917

7/13/2018

10.1

10.3#

Amendment No. 2, dated as of July 10, 2018, between Stingray Pressure Pumping, LLC and Gulfport Energy Corporation to that certain Amended & Restated Master Services Agreement for Pressure Pumping Services, effective as of October 1, 2014, as amended effective January 1, 2016.

10.4

Second Amendment to Sand Supply Agreement, dated as of August 6, 2018, between Muskie Proppant LLC and Gulfport Energy Corporation

31.1

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

31.2

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

32.1

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

32.2

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

95.1

Mine Safety Disclosure Exhibit

101.1

Interactive data files pursuant to Rule 405 of Regulation S-T.

Confidential treatment requested as to certain portions, which portions have been omitted and filed separately with the Securities and Exchange Commission.


#	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:	August ~~4, 2017~~7, 2018	By:	/s/ Arty Straehla
			Arty Straehla
			Chief Executive Officer

Date:	August ~~4, 2017~~7, 2018	By:	/s/ Mark Layton
			Mark Layton
			Chief Financial Officer

5557




													Additional
	Common Stock			Common			Members'			Accumulated			Paid-In
	Shares	Amount		Partners			Equity			Deficit			Capital		AOCL			Total
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 costs	37,500,000	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	—	—		—			—			(6,150,794		)	—		—			(6,150,794		)
Stingray acquisition	1,392,548	13,925		—			—			—			25,748,213		—			25,762,138
Sturgeon acquisition	5,607,452	56,075		—			(81,738,675		)	—			77,671,715		—			(4,010,885		)
Equity based compensation	—	—		—			—			—			1,619,893		—			1,619,893
Other comprehensive income	—	—		—			—			—			—		409,552			409,552
Balance at June 30, 2017	44,500,000	$	445,000	$	—		$	—		$	(62,473,672	)	$	505,245,742	$	(2,806,811	)	$	440,410,259



	Six Months Ended
	June 30,
Cash flows from operating activities	2017 (a)			2016 (b)
Net loss	$	(6,150,794	)	$	(31,768,306	)
Adjustments to reconcile net loss to cash provided by operating activities:
Equity based compensation	1,619,893			—
Depreciation, depletion, accretion and amortization	37,130,650			36,561,687
Amortization of coil tubing strings	1,045,233			962,302
Amortization of debt origination costs	199,403			199,403
Bad debt expense	18,980			1,764,218
(Gain) loss on disposal of property and equipment	127,153			(710,046		)
Gain on bargain purchase	(4,011,512		)	—
Impairment of long-lived assets	—			1,870,885
Deferred income taxes	(6,529,406		)	41,292
Changes in assets and liabilities, net of acquisitions of businesses:
Accounts receivable, net	(4,792,555		)	(2,562,425		)
Receivables from related parties	(12,995,194		)	(7,803,381		)
Inventories	(4,931,651		)	30,615
Prepaid expenses and other assets	1,528,346			(1,092,731		)
Accounts payable	20,557,001			8,008,632
Payables to related parties	(83,079		)	(199,694		)
Accrued expenses and other liabilities	1,300,687			5,659,053
Income taxes payable	(28,156		)	(15,387		)
Net cash provided by operating activities	24,004,999			10,946,117

Cash flows from investing activities:
Purchases of property and equipment	(66,575,719		)	(2,174,209		)
Business acquisitions	(39,570,187		)	—
Proceeds from disposal of property and equipment	780,932			3,165,519
Business combination cash acquired (Note 3)	2,671,558			—
Net cash (used in) provided by investing activities	(102,693,416		)	991,310

Cash flows from financing activities:
Borrowings from lines of credit	79,150,000			11,150,000
Repayments of lines of credit	(14,150,000		)	(25,752,516		)
Repayment of Stingray acquisition long-term debt	(7,073,854		)	—
Net cash provided by (used in) financing activities	57,926,146			(14,602,516		)
Effect of foreign exchange rate on cash	72,943			54,163
Net decrease in cash and cash equivalents	(20,689,328		)	(2,610,926		)
Cash and cash equivalents at beginning of period	29,238,618			4,038,899
Cash and cash equivalents at end of period	$	8,549,290		$	1,427,973

Supplemental disclosure of cash flow information:
Cash paid for interest	$	1,085,851		$	2,056,581
Cash paid for income taxes	$	911,700		$	2,035,015
Supplemental disclosure of non-cash transactions:
Purchases of property and equipment included in trade accounts payable	$	7,835,614		$	414,795
Acquisition of Sturgeon, Stingray Cementing LLC and Stingray Energy Services LLC and (Note 3)	$	23,090,580		$	—



Balance, January 1, 2016	$	94,904
Accretion expense	164,900
Balance, December 31, 2016	259,804
Accretion expense	14,409
Additions - Chieftain Acquisition (Note 3)	1,732,081
Balance, June 30, 2017	$	2,006,294



Consideration attributable to Cementing⁽¹⁾	$	12,975,123
Consideration attributable to SR Energy⁽¹⁾	12,787,015
Total consideration transferred	$	25,762,138



	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



	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



	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



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
Balance, June 30, 2017	$	99,562,761



	Completion and Production
Six Months Ended June 30, 2017	Pressure Pumping Services		Well Services			Sand			Drilling			Other Energy Services			Total
Revenue from external customers	$	17,508,098	$	8,796,654		$	13,767,088		$	21,215,222		$	9,231,059		$	70,518,121
Revenue from related parties	$	72,868,938	$	2,687,448		$	25,145,543		$	2,007,505		$	525		$	102,709,959
Cost of revenue	$	64,533,809	$	10,436,065		$	32,581,324		$	22,986,579		$	5,300,163		$	135,837,940
Selling, general and administrative expenses	$	4,179,665	$	1,698,503		$	4,473,436		$	2,728,778		$	1,356,122		$	14,436,504
Earnings before interest, other expense (income), impairment, taxes and depreciation and amortization	$	21,663,562	$	(650,466	)	$	1,857,871		$	(2,492,630	)	$	2,575,299		$	22,953,636
Other expense (income)	$	6,389	$	(1,991	)	$	153,776		$	224,236		$	4,232		$	386,642
Bargain purchase gain	$	—	$	—		$	(4,011,512	)	$	—		$	—		$	(4,011,512	)
Interest expense (income)	$	431,795	$	(108,376	)	$	485,239		$	657,058		$	43,076		$	1,508,792
Depreciation, depletion, accretion and amortization	$	18,784,446	$	3,428,162		$	3,568,659		$	9,942,310		$	1,407,073		$	37,130,650
Income tax (benefit) provision	$	—	$	(6,500,514	)	$	8,502		$	—		$	581,870		$	(5,910,142	)
Net income (loss)	$	2,440,932	$	2,532,253		$	1,653,207		$	(13,316,234	)	$	539,048		$	(6,150,794	)
Total expenditures for property, plant and equipment	$	53,401,909	$	344,474		$	2,969,883		$	5,900,817		$	3,958,636		$	66,575,719
Three Months Ended June 30, 2017
Revenue from external customers	$	8,816,451	$	5,606,522		$	10,395,025		$	11,511,825		$	3,724,353		$	40,054,176
Revenue from related parties	$	41,108,032	$	2,534,553		$	13,605,124		$	959,913		$	261		$	58,207,883
Cost of revenue	$	35,826,369	$	6,636,289		$	19,974,059		$	12,033,156		$	2,870,081		$	77,339,954
Selling, general and administrative expenses	$	2,404,739	$	726,098		$	2,415,883		$	1,433,754		$	719,232		$	7,699,706
Earnings before interest, other expense (income), impairment, taxes and depreciation and amortization	$	11,693,375	$	778,688		$	1,610,207		$	(995,172	)	$	135,301		$	13,222,399
Other expense (income)	$	3,758	$	(3,173	)	$	139,569		$	60,451		$	1,891		$	202,496
Bargain purchase gain	$	—	$	—		$	(4,011,512	)	$	—		$	—		$	(4,011,512	)
Interest expense (income)	$	303,351	$	(2,474	)	$	352,600		$	439,876		$	18,255		$	1,111,608
Depreciation, depletion, accretion and amortization	$	9,626,553	$	2,219,921		$	2,205,694		$	4,973,682		$	867,549		$	19,893,399
Income tax (benefit) provision	$	—	$	(2,808,982	)	$	8,502		$	—		$	(3,597	)	$	(2,804,077	)
Net income (loss)	$	1,759,713	$	1,373,396		$	2,915,354		$	(6,469,181	)	$	(748,797	)	$	(1,169,515	)
Total expenditures for property, plant and equipment	$	24,736,600	$	344,474		$	2,795,370		$	3,631,540		$	3,958,043		$	35,466,027
At June 30, 2017
Goodwill	$	86,043,147	$	10,192,486		$	2,683,727		$	—		$	643,400		$	99,562,761
Intangible assets, net	$	16,913,308	$	2,078,021		$	—		$	—		$	1,613,000		$	20,604,329
Total assets	$	244,665,648	$	83,026,472		$	163,911,495		$	98,203,014		$	37,110,946		$	626,917,575



	Completion and Production
Six Months Ended June 30, 2016	Pressure Pumping Services			Well Services			Sand			Drilling			Other Energy Services		Total
Revenue from external customers	$	18,157,113		$	4,360,611		$	2,976,443		$	9,715,833		$	14,653,537	$	49,863,537
Revenue from related parties	$	38,165,558		$	567,887		$	11,231,344		$	1,916,595		$	572	$	51,881,956
Cost of revenue	$	40,083,680		$	6,962,055		$	16,432,367		$	12,968,054		$	6,448,663	$	82,894,819
Selling, general and administrative expenses	$	2,065,542		$	1,013,478		$	2,109,803		$	2,567,237		$	1,063,952	$	8,820,012
Earnings before interest, other expense (income), impairment, taxes and depreciation and amortization	$	14,173,449		$	(3,047,035	)	$	(4,334,383	)	$	(3,902,863	)	$	7,141,494	$	10,030,662
Other expense (income)	$	23,825		$	(673,145	)	$	72,985		$	(57,574	)	$	8,183	$	(625,726	)
Interest expense (income)	$	368,764		$	149,095		$	211,111		$	1,554,207		$	25,210	$	2,308,387
Depreciation, depletion, accretion and amortization	$	18,913,487		$	2,670,222		$	2,949,851		$	10,945,932		$	1,082,195	$	36,561,687
Impairment of long-lived assets	$	138,587		$	1,384,751		$	—		$	347,547		$	—	$	1,870,885
Income tax (benefit) provision	$	—		$	(3,094	)	$	—		$	—		$	1,686,829	$	1,683,735
Net (loss) income	$	(5,271,214	)	$	(6,574,864	)	$	(7,568,330	)	$	(16,692,975	)	$	4,339,077	$	(31,768,306	)
Total expenditures for property, plant and equipment	$	927,542		$	247,829		$	157,726		$	423,095		$	418,017	$	2,174,209
Three Months Ended June 30, 2016
Revenue from external customers	$	5,862,584		$	1,662,019		$	1,694,698		$	4,458,095		$	6,667,914	$	20,345,310
Revenue from related parties	$	38,165,558		$	567,887		$	9,313,266		$	770,596		$	17	$	48,817,324
Cost of revenue	$	28,551,790		$	3,034,349		$	10,251,613		$	5,759,398		$	2,906,493	$	50,503,643
Selling, general and administrative expenses	$	1,539,371		$	440,182		$	1,508,533		$	1,264,763		$	453,289	$	5,206,138
Earnings before interest, other expense (income), impairment, taxes and depreciation and amortization	$	13,936,981		$	(1,244,625	)	$	(752,182	)	$	(1,795,470	)	$	3,308,149	$	13,452,853
Other expense (income)	$	43,033		$	(682,545	)	$	53,803		$	(47,500	)	$	6,493	$	(626,716	)
Interest expense (income)	$	131,709		$	50,776		$	106,650		$	701,633		$	21,263	$	1,012,031
Depreciation, depletion, accretion and amortization	$	9,958,270		$	1,272,715		$	1,581,334		$	5,438,551		$	559,745	$	18,810,615
Impairment of long-lived assets	$	138,587		$	1,384,751		$	—		$	347,547		$	—	$	1,870,885
Income tax (benefit) provision	$	—		$	(3,094	)	$	—		$	—		$	792,469	$	789,375
Net income (loss)	$	3,665,382		$	(3,267,228	)	$	(2,493,969	)	$	(8,235,701	)	$	1,928,179	$	(8,403,337	)
Total expenditures for property, plant and equipment	$	896,847		$	247,829		$	65,184		$	158,924		$	270,386	$	1,639,170
At June 30, 2016
Goodwill	$	86,043,148		$	—		$	2,683,727		$	—		$	—	$	88,726,875
Intangible assets, net	$	25,956,808		$	145,521		$	—		$	—		$	—	$	26,102,329
Total assets	$	209,357,385		$	41,178,159		$	114,090,998		$	105,556,115		$	35,639,200	$	505,821,857