Document

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



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	o

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, there were 44,502,223 shares of common stock, $0.01 par value, outstanding.

MAMMOTH ENERGY SERVICES, INC.

TABLE OF CONTENTS





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

PART I. FINANCIAL INFORMATION		1
Item 1.	Condensed Consolidated Financial Statements (Unaudited)	1
	Condensed Consolidated Balance Sheets	1
	Condensed Consolidated Statements of Comprehensive Loss	2
	Condensed Consolidated Statements of Changes in Equity	3
	Condensed Consolidated Statements of Cash Flows	4
	Notes to Unaudited Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	49
Item 4.	Controls and Procedures	50

PART II. OTHER INFORMATION		51
Item 1.	Legal Proceedings	51
Item 1A.	Risk Factors	51
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	52
Item 4.	Mine Safety Disclosures	52
Item 5.	Other Information	53
Item 6.	Exhibits	54

SIGNATURES		55

GLOSSARY OF OIL AND NATURAL GAS TERMS



The following is a glossary of certain oil and natural gas industry terms used in this report:
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 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, 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.
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.
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.
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 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.

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 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 report, are forward-looking statements. In some cases, you can identify forward-looking statements by terminology such as “may,” "will," “could,” “should,” “expect,” “plan,” “project,” “budget,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “seek,” “objective” or “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. 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.

iii

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,
CURRENT ASSETS	2017 (a)			2016 (b)
Cash and cash equivalents	$	8,549,290		$	29,238,618
Accounts receivable, net	30,414,421			21,169,579
Receivables from related parties	45,686,985			27,589,283
Inventories	10,316,700			6,124,201
Prepaid expenses	3,647,227			4,425,872
Other current assets	341,555			391,599
Total current assets	98,956,178			88,939,152

Property, plant and equipment, net	327,080,164			242,119,663
Sand reserves	75,892,824			55,367,295
Intangible assets, net - customer relationships	13,962,772			15,949,772
Intangible assets, net - trade names	6,641,557			5,617,057
Goodwill	99,562,761			88,726,875
Other non-current assets	4,821,319			5,642,661
Total assets	$	626,917,575		$	502,362,475
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	53,864,660		$	20,469,542
Payables to related parties	120,183			203,209
Accrued expenses and other current liabilities	10,190,094			8,546,198
Income taxes payable	—			28,156
Total current liabilities	64,174,937			29,247,105

Long-term debt	65,000,000			—
Deferred income taxes	52,307,148			47,670,789
Asset retirement obligation	2,006,294			259,804
Other liabilities	3,018,937			2,404,422
Total liabilities	186,507,316			79,582,120

COMMITMENTS AND CONTINGENCIES (Note 14)

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.
Additional paid in capital	505,245,742			400,205,921
Member's equity	—			81,738,675
Accumulated deficit	(62,473,672		)	(56,322,878		)
Accumulated other comprehensive loss	(2,806,811		)	(3,216,363		)
Total equity	440,410,259			422,780,355
Total liabilities and equity	$	626,917,575		$	502,362,475

(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 (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			—

(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.

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

(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,
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 of Presentation

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 Inc." or "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 in the exploration and development of North American onshore unconventional oil and natural gas reserves. The Company was incorporated in Delaware in June 2016 as a wholly-owned subsidiary of Mammoth Energy Partners LP, a Delaware limited partnership (the "Partnership" or the "Predecessor"). The Partnership was originally formed by Wexford Capital LP (“Wexford”) in February 2014 as a holding company under the name Redback Inc. and was converted to a Delaware limited partnership in August 2014. On November 24, 2014, Gulfport Energy Corporation (“Gulfport”), Rhino Resource Partners LP (“Rhino”) and Mammoth Energy Holdings LLC (“Mammoth Holdings”), an entity controlled by Wexford, contributed their interest in certain of the entities presented below to the Partnership in exchange for 20 million limited partner units. Mammoth Energy Partners GP, LLC (the “General Partner”) held a non-economic general partner interest.

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"), 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.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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



	At June 30, 2017			At December 31, 2016
	Share Count	% Ownership		Share Count	% Ownership
Mammoth Holdings	25,009,319	56.2	%	20,443,903	54.5	%
Gulfport	11,171,887	25.1	%	9,073,750	24.2	%
Rhino	568,794	1.3	%	232,347	0.6	%
Outstanding shares owned by related parties	36,750,000	82.6	%	29,750,000	79.3	%
Total outstanding	44,500,000	100.0	%	37,500,000	100.0	%

Operations

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 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 vertical and horizontal drilling of oil and natural gas wells. The Company also provides other energy services, which have historically consisted of remote accommodations for people working in the oil sands located in Northern Alberta, Canada, but recently have been expanded to include energy infrastructure services.

All of the Company’s operations are in North America. The Company operates in the Permian Basin, the Utica Shale, the Eagle Ford Shale, the Marcellus Shale, the Granite Wash, the Cana-Woodford Shale, the Cleveland Sand and the oil sands located in Northern Alberta, Canada. The Company's 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.


2.	Summary of Significant Accounting Policies

(a) Principles of Consolidation

The condensed consolidated financial statements are prepared in accordance with GAAP. All material intercompany accounts and transactions between the entities within the Company have been eliminated.

(b) Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include but are not limited to the Company's sand reserves and their impact on calculating the depletion expense, the allowance for doubtful accounts, 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.

All highly liquid investments with an original maturity of three months or less are considered cash equivalents. The Company maintains its cash accounts in financial institutions that are insured by the Federal Deposit Insurance Corporation, with the exception of cash held by Lodging in a Canadian financial institution. At June 30, 2017, the Company had $3.1 million, in Canadian dollars, of cash in Canadian accounts. Cash balances from time to time may exceed the insured amounts; however the Company has not experienced any losses in such accounts and does not believe it is exposed to any significant credit risks on such accounts.

(d) Accounts Receivable

Accounts receivable include amounts due from customers for services performed and are recorded as the work progresses. 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 of customers change, 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 final determination is made of their uncollectability.

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



Balance, January 1, 2016	$	4,011,882
Additions charged to expense	1,968,001
Deductions for uncollectible receivables written off	(602,967		)
Balance, December 31, 2016	5,376,916
Additions charged to expense	18,980
Additions other	178,871
Balance, June 30, 2017	$	5,574,767

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 of the oil and natural gas industry. The year ended December 31, 2016 contained such pricing conditions which may lead to enhanced risk of uncollectiblity on certain receivables. As such, the Company monitored its previously established reserves and adjusted upward. The Company will continue to pursue collection until such time as final determination is made consistent with Company policy.

(e) Inventory

Inventory consists of raw sand and processed sand available for sale, 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.

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 stockpiles based on the number of tons in the stockpile. Inventory transported for sale at the Company’s terminal facility includes the cost of purchased or manufactured sand, plus transportation related charges.

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 $962,302 for the six months ended June 30, 2017 and 2016, respectively.

(f) Prepaid Expenses

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

(g) Property and Equipment

Property and equipment, including renewals and betterments, are capitalized and stated at cost, while maintenance and repairs that do not increase the capacity, improve the efficiency or safety, or improve or extend the useful life are charged to operations as incurred. Disposals are removed at cost, less accumulated depreciation, and any resulting gain or loss is recorded in 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:



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

(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 to related parties. The carrying amount of cash and cash equivalents, trade receivables, receivables from related parties and trade payables approximates fair value because of the short-term nature of the instruments. The fair value of long-term debt approximates its carrying value because the cost of borrowing fluctuates based upon market conditions.

(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.

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


3.	Acquisitions

(a) Description of Stingray Acquisition

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

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

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



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

(1)See Summary of acquired assets and liabilities below

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



	SR 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


⁽¹⁾	Property, plant and equipment fair value measurements were prepared by utilizing a combined fair market value and cost approach. The market approach relies on comparability of assets using market data information. The cost approach places emphasis on the physical components and characteristics of the asset. It places reliance on estimated replacement cost, depreciation and economic obsolescence.


⁽²⁾	Identifiable intangible assets were measured using a combination of income approaches. Trade names were valued using a "Relief-from-Royalty" method. Non-contractual customer relationships were valued using a "Multi-period excess earnings" method. Identifiable intangible assets will be amortized over 5-10 years.

⁽³⁾

Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill recorded in connection with the acquisition is attributable to assembled workforces and future profitability based on the synergies expected to arise from the acquired entities.


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

Since the acquisition date, the businesses acquired have provided the following activity:



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

a.Includes $503,997 and $512,656 in depreciation and amortization for SR Energy and Cementing, respectively.

The following table presents unaudited pro forma information for the Company as if the acquisition of SR Energy and Cementing had occurred on January 1, 2016:



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

The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the 2017 Stingray Acquisition. For the six months ended June 30, 2017, there were $0.2 million transaction related costs expensed. The unaudited pro forma consolidated results are not necessarily indicative of what the consolidated results of operations actually would have been had the 2017 Stingray Acquisition been completed on January 1, 2017. In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations of the Company.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(b) Description of Chieftain Acquisition

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

On the acquisition date, the $36,320,187 in cash consideration consisted of the following components:



	Total
Property, plant and equipment ⁽¹⁾	$	23,372,800
Sand reserves ⁽²⁾	20,910,000
Total assets acquired	$	44,282,800

Asset retirement obligation	1,732,081
Total liabilities assumed	$	1,732,081
Total allocation of purchase price	$	42,550,719
Bargain purchase price ^{(3, 4)}	(6,230,532		)
Total purchase price	$	36,320,187


⁽¹⁾	Property, plant and equipment fair value measurements were prepared by utilizing a combined fair market value and cost approach. The market approach relies on comparability of assets using market data information. The cost approach places emphasis on the physical components and characteristics of the asset. It places reliance on estimated replacement cost, depreciation and economic obsolescence.


⁽²⁾	The fair value of the sand reserves was determined based on the excess cash flow method, a form of the income approach. The method provides a value based on the estimated remaining life of sand reserves, projected financial information and industry projections.


⁽³⁾	Amount reflected in Condensed Consolidated Statements of Comprehensive Loss reflected net of income taxes of $2,219,020.


⁽⁴⁾	The fair value of the business was determined based on the excess cash flow method, a form of the income approach.

Since the acquisition date, the Chieftain Assets have provided the following activity:



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

a.Includes $429,821 in depreciation and amortization

The following table presents unaudited pro forma information for the Company as if the acquisition of the Chieftain Assets had occurred as of January 1, 2016:



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

The Company's historical financial information was adjusted to give pro forma effect to the events that were directly attributable to the Chieftain Acquisition. For the six months ended June 30, 2017, $0.7 million of transaction related costs was expensed.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

For the six months ended June 30, 2017, $1.2 million of transaction related costs was expensed.

The following table summarizes the carrying value of Sturgeon as of September 13, 2014, the date at which Sturgeon commenced operations with the acquisition of the Sturgeon subsidiaries:



	Sturgeon
Cash and cash equivalents	$	705,638
Accounts receivable	7,587,298
Inventories	2,221,073
Other current assets	555,939
Property, plant and equipment	20,424,087
Sand reserves	57,420,000
Goodwill	2,683,727
Total assets acquired	$	91,597,762

Accounts payable and accrued liabilities	$	2,878,072
Total liabilities assumed	$	2,878,072
Net assets acquired	$	88,719,690

Allocation of purchase price
Carrying value of sponsor's non-controlling interest prior to Sturgeon contribution	$	81,738,675
Deferred tax liability assumed	(4,010,885		)
Members' equity conveyed	$	77,727,790

(d) Acquisition of Higher Power

On April 21, 2017, the Company completed its acquisition of Higher Power for total consideration of $3,250,000 in cash to the sellers plus up to $750,000 in contingent consideration to be paid in equal annual installments over the next three years subject to contractual conditions. As of June 30, 2017, $250,000 and $500,000 of the contingent consideration are

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

reflected in the accrued expenses and other current liabilities and other liabilities, respectively. Mammoth funded the purchase price for Higher Power with cash on hand and borrowings under its credit facility. The acquisition of Higher Power added to the Company's other energy segment. This acquisition created a new energy infrastructure component 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.

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



	Higher Power
Property, plant and equipment	$	1,743,600
Identifiable intangible assets - customer relationships	1,613,000
Goodwill ⁽¹⁾	643,400
Total assets acquired	$	4,000,000

Long-term debt and other liabilities	$	750,000
Total liabilities assumed	$	750,000
Net assets acquired	$	3,250,000


⁽¹⁾	Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill recorded in connection with the acquisition is attributable to assembled workforces and future profitability expected to arise from the acquired entity.

Since the acquisition date, Higher Power has provided the following activity:



	2017
	Higher Power
Revenues	$	1,709,277
Net loss^(a)	(286,959		)

a.Includes $340,333 in depreciation and amortization

The following table presents unaudited pro forma information for the Company as if the acquisition of Higher Power had occurred as of January 1, 2016:



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


4.	Inventories

A summary of the Company's inventories is shown below:



	June 30,		December 31,
	2017		2016
Supplies	$	6,592,239	$	4,020,670
Raw materials	149,845		75,971
Work in process	—		205,450
Finished goods	3,574,616		1,822,110
Total inventory	$	10,316,700	$	6,124,201

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


5.	Property, Plant and Equipment

Property, plant and equipment include the following:



		June 30,		December 31,
	Useful Life	2017		2016
Land		$	11,316,910	$	5,040,482
Land improvements	15 years or life of lease	9,324,179		3,640,976
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
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
		507,985,899		410,988,530
Deposits on equipment and equipment in process of assembly		26,817,262		9,427,307
		534,803,161		420,415,837
Less: accumulated depreciation		207,722,997		178,296,174
Property, plant and equipment, net		$	327,080,164	$	242,119,663

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, 2017, proceeds from the sale of equipment damaged or lost down-hole were $347,844 and gain 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.

A summary of depreciation, depletion, accretion and amortization expense is outlined below:



	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

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

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


6.	Goodwill and Intangible Assets

The Company had the following definite lived intangible assets recorded:



	June 30,		December 31,
	2017		2016
Customer relationships	$	35,798,000	$	33,605,000
Trade names	8,490,000		7,110,000
Less: accumulated amortization - customer relationships	21,835,228		17,655,228
Less: accumulated amortization - trade names	1,848,443		1,492,943
Intangible assets, net	$	20,604,329	$	21,566,829

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

Aggregated expected amortization expense for the future periods is expected to be as follows:



Year ended December 31:	Amount
Remainder of 2017	$	4,694,216
2018	8,541,434
2019	1,055,932
2020	1,055,932
2021	1,050,180
Thereafter	4,206,635
	$	20,604,329

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



Balance, January 1, 2016	$	88,726,875
Additions	—
Balance, December 31, 2016	88,726,875
Additions - 2017 Stingray Acquisition (Note 3)	10,192,486
Additions - Higher Power Acquisition (Note 3)	643,400
Balance, June 30, 2017	$	99,562,761


7.	Accrued Expenses and Other Current Liabilities

Accrued expense and other current liabilities included the following:



	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

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


8.	Debt

Mammoth Credit Facility

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. 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, 2017, $57,000,000 of the $65,000,000 outstanding balance of the facility was in a one month LIBOR rate option tranche with an interest rate of 3.72% and $8,000,000 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.

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 and December 31, 2016, the Company was in compliance with its covenants under the facility.


9.	Income Taxes

As discussed in Note 1, the Partnership was converted into a limited liability company on October 12, 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.

The components of income tax (benefit) expense attributable to the Company for the six months ended June 30, 2017 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

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

A reconciliation of the statutory federal income tax amount to the recorded expense is as follows:



	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

Deferred tax assets and liabilities attributable to the Company consisted of the following:



	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	)


10.	Earnings Per Share

Common Stock Offering

On October 14, 2016, Mammoth Inc.’s common stock began trading on The Nasdaq Global Select Market under the symbol “TUSK.” On October 19, 2016, the Company closed the IPO of 7,750,000 shares of common stock 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.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The authorized capital stock of the Company consists 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 LLC to the Company in connection with 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 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	)


^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 as their effect was antidulitive under the treasury stock method.


11.	Equity Based Compensation

Upon formation of certain Operating Entities (including the acquired Stingray Entities), specified members of management (“Specified Members”) were granted the right to receive distributions from their respective Operating Entity, 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 to Mammoth. Awards are not granted in limited or general partner units. Agreements are for interest in the distributable earnings of Mammoth Holdings, Mammoth’s majority equity holder.

On the IPO closing date, Mammoth Holdings unreturned capital balance was not fully recovered from its sale of common stock in the IPO. As a result, Payout did not occur and no compensation cost was recorded. Future offerings or sales of common stock to recover outstanding unreturned capital remain not probable.

Payout is expected to occur following the sale by Mammoth Holding's 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. For the Non-Employees Member awards, the unrecognized cost, which represents the fair value of the awards as of June 30, 2017 was $47,168,561.


12.	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
Unvested shares as of January 1, 2017	282,780		$	14.98
Granted	390,587		21.19
Vested	(2,233	)	(17.42		)
Forfeited	(8,888	)	(15.00		)
Unvested shares as of June 30, 2017	662,246		$	18.63

As of June 30, 2017, there was $10,326,977 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 years.

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

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


13.	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 ("El Toro"); Diamondback E&P, LLC ("Diamondback"); Cementing and SR Energy (collectively, prior to the 2017 Stingray Acquisition, the "2017 Stingray Companies"); Everest Operations Management, LLC ("Everest"); Elk City Yard, LLC ("Elk City Yard"); Double Barrel Downhole Technologies, LLC ("DBDHT"); Orange Leaf Holdings LLC ("Orange Leaf"); Caliber Investment Group, LLC ("Caliber"); and Dunvegan North Oilfield Services ULC (“Dunvegan”).



		REVENUES								ACCOUNTS RECEIVABLE
		Three Months Ended June 30,				Six Months Ended June 30,				At June 30,		At December 31,
		2017		2016		2017		2016		2017		2016
Pressure Pumping and Gulfport	(a)	$	41,099,441	$	38,165,558	$	72,845,391	$	38,165,558	$	28,596,696	$	19,094,509
Muskie and Gulfport	(b)	13,605,124		9,313,266		25,145,543		11,231,344		8,151,536		5,373,007
Panther Drilling and Gulfport	(c)	951,439		769,147		1,993,816		1,221,022		1,016,589		1,434,036
Cementing and Gulfport	(d)	903,317		—		903,317		—		1,767,432		—
SR Energy and Gulfport	(e)	1,565,211		—		1,565,211		—		6,011,500		—
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		—		—
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		—		—
Coil Tubing and El Toro	(j)	—		318,694		—		318,694		—		—
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
Other Relationships		—		—		—		—		95,124		115,565
		$	58,207,883	$	48,817,324	$	102,709,959	$	51,881,956	$	45,686,985	$	27,589,283


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.


b.	Muskie has agreed to sell and deliver, and Gulfport has agreed to purchase, specified annual and monthly amounts of natural sand proppant, subject to certain exceptions specified in the agreement, and pay certain costs and expenses.


c.	Panther Drilling performs drilling services for Gulfport pursuant to a master service agreement.


d.	Cementing performs well cementing services for Gulfport.


e.	SR Energy performs rental services for Gulfport.


f.	Lodging provides remote accommodation and food services to Grizzly, an entity owned approximately 75% by affiliates of Wexford and approximately 25% by Gulfport.


g.	The contract land and directional drilling segment provides services for El Toro, an entity controlled by Wexford, pursuant to a master service agreement.


h.	Energy Services performs completion and production services for El Toro pursuant to a master service agreement.


i.	White Wing provides rental services to Diamondback.


j.	Coil Tubing provides to El Toro services in connection with completion and drilling activities.


k.	Panther provides services and materials to DBDHT.


l.	The Company provided certain services to the 2017 Stingray Companies.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



		COST OF REVENUE								ACCOUNTS PAYABLE
		Three Months Ended 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


a.	Panther rents rotary steerable equipment in connection with its directional drilling services from DBDHT.


b.	Bison Trucking leased office space from Diamondback in Midland, Texas.


c.	Energy Services leases property from Elk City Yard.


d.	Dunvegan provides technical and administrative services and pays for goods and services on behalf of the Company.


e.	Bison Trucking leases space from El Toro for storage of a rig.


f.	Prior to the 2017 Stingray Acquisition, the 2017 Stingray Companies provided certain services to the Company and, from time to time, the 2017 Stingray Companies paid for goods and services on behalf of the Company.


g.	Everest has historically provided office space and certain technical, administrative and payroll services to the Company and the Company has reimbursed Everest in amounts determined by Everest based on estimates of the amount of office space provided and the amount of employees’ time spent performing services for the Company.


h.	Wexford provides certain administrative and analytical services to the Company and, from time to time, the Company pays for goods and services on behalf of Wexford.


i.	Orange Leaf leases office space to Mammoth.


j.	Caliber leases office space to Mammoth.


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


14.	Commitments and Contingencies

Lease Obligations

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

Minimum Purchase Commitments

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

Capital Spend Commitments

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 are as follows:



Year ended December 31:	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
2019	8,075,402		—		10,866,000
2020	5,597,885		—		—
2021	2,645,182		—		—
Thereafter	3,721,249		—		—
	$	34,703,014	$	22,730,189	$	28,421,581

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

The Company has various letters of credit totaling $454,560 to secure rail car lease payments. These letters of credit were issued under the Company's revolving credit agreement and are collateralized by substantially all of the assets of the Company.

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 and December 31, 2016, the policy requires a per deductible per occurrence of $250,000. The Company establishes liabilities for the unpaid deductible portion of claims incurred relating to workers’ compensation and auto liability based on estimates. As of June 30, 2017 and December 31, 2016, the policies contained an aggregate stop loss of $2,000,000. 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 per participant and an aggregate stop-loss of $5,799,991 for the calendar year ending December 31, 2017. These estimates may change in the near term as actual claims continue to develop. As of June 30, 2017 and December 31, 2016, accrued insurance claims were $1,491,300 and $971,351, respectively. In connection with the insurance programs, letters of credit of $1,636,000 and $1,285,000 as of June 30, 2017 and December 31, 2016, respectively, have been issued supporting the retained risk exposure. As of June 30, 2017, in connection with environmental remediation programs, letters of credit of $3,363,627 have been issued supporting the retained risk exposure. As of both June 30, 2017 and December 31, 2016, these letters of credit were collateralized by substantially all of the assets of the Company.

The Company is routinely involved in state and local tax audits. During the year ended December 31, 2016, 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 the Company 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’s financial position, results of operations or cash flows.

On August 1, 2016, a putative class and collective action lawsuit alleging that 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 of this lawsuit or whether it will have a material impact on the Company’s financial position, results of operations or cash flows.

On September 27, 2016, a putative lawsuit alleging that Energy Services failed to pay a class of workers in compliance with the Fair Labor Standards Act was filed titled Michael Drake vs. Redback Coil Tubing LLC, et 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’s financial position, results of operations or cash flows.

On January 26, 2017, a collective action lawsuit alleging that 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, 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. 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.

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% of an employee’s compensation and may make additional discretionary contributions for eligible employees. For the six months ended June 30, 2017 and 2016, the Company paid $0 and $102,230, respectively, in contributions to the plan.


15.	Operating Segments

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The Company is organized into five reportable segments based on the nature of services provided and the basis in which management makes business and operating decisions. The Company principally provides oilfield services in connection with on-shore drilling of oil and natural gas wells for small to large domestic independent oil and nature gas producers. The Company’s five segments consist of pressure pumping services ("Pressure Pumping Services"), well services ("Well Services"), natural sand proppant ("Sand"), contract land and directional drilling services ("Drilling") and other energy services ("Other Energy Services").

The Company's Chief Executive Officer and Chief Financial Officer comprise the Company'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), impairment, taxes and depreciation and amortization as well as a qualitative basis, such as nature of the product and service offerings, types of customers.

Based on the CODM's assessment, effective December 31, 2016, the Company reorganized the reportable segments to align with its new management reporting structure and business activities. Prior to this reorganization, the existing reportable segments were comprised of four segments for financial reporting purposes: land and directional drilling services, completion and production services, completion and production - natural sand proppant and remote accommodation services. As a result of this change, there are five 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.

The following table sets forth certain financial information with respect to the Company’s reportable segments:

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

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

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.


16.	Subsequent Events

On July 7, 2017, the Company acquired an energy service company from an unrelated third party seller for $2.3 million in cash consideration and the assumption of $1.8 million in debt.

Effective as of July 12, 2017, the Company entered into a Second Amendment to Revolving Credit and Security Agreement, among the Company and certain of its subsidiaries, as borrowers, certain financial institutions party thereto, as lenders, and PNC Bank, National Association, as agent for the lenders (the “Amendment”). The Amendment provided the borrowers with greater flexibility for permitted acquisitions and permitted indebtedness, increased the maximum

amount credited to the borrowing base for sand inventory and for in-transit inventory and increased certain cross-default thresholds from $5 million to $15 million.

Subsequent to June 30, 2017, the Company entered into a lease agreement for capital equipment with aggregate commitments of $1.5 million.

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

The following discussion should be read in conjunction with the unaudited condensed consolidated financial statements and related notes thereto presented in this quarterly report and the consolidated financial statements and related notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2016, filed with the Securities and Exchange Commission, or the SEC, on February 24, 2017.

Overview

We are an integrated, growth-oriented oilfield service company serving companies engaged in the exploration and development of North American onshore unconventional oil and natural gas reserves. 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 services, natural sand proppant services, contract land and directional drilling services and other energy services. Our pressure pumping services division provides hydraulic fracturing services. Our well services division provides pressure control services, flowback services and equipment rentals. Our natural sand proppant services division sells, distributes and produces proppant 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 services division has historically provided housing, kitchen 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. 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. 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 Report 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 2017 Highlights

Acquisition of Stingray Energy, Stingray Cementing and Sturgeon

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 Services 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 entered into a definitive asset purchase agreement, which we refer to as the Purchase Agreement, with Chieftain Sand and Proppant, LLC and Chieftain Sand and Proppant Barron, LLC, unrelated third party sellers, following our successful bid 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. The assets subject to the Chieftain Acquisition include a wet and dry plant and sand mine located on approximately 600 acres 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.

Expansion of Services

During the second quarter of 2017, we expanded our pressure pumping, sand deliveries and last-mile trucking services into the SCOOP/STACK with the startup of our fourth pressure pumping fleet in June 2017. The startup of our fifth fleet in the mid-continent is scheduled for August 8, 2017, with our sixth fleet expected to commence operations in October 2017. In addition, on July 7, 2017, we acquired an energy service company from an unrelated third party seller for $2.3 million in cash and the assumption of $1.8 million in debt. This acquisition expands the infrastructure services of our other energy services division.

Long Term Take-or- Pay Sand Contracts

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

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 products and services depends substantially on the level of expenditures by companies in the oil and natural gas industry. The significant decline in oil and natural gas prices that began in the third quarter of 2014 continued into February 2016, when the closing price of oil reached a 12-year low of $26.19 per barrel on February 11, 2016. The low commodity price environment caused a reduction in the drilling, completion and other production activities of most of our customers and their spending on our products and services.

The reduction in demand during the first part of 2016, and the resulting oversupply of many of the services and products we provide, substantially reduced the prices we could charge our customers for our 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, mainly in our pressure pumping, other well services, natural sand proppant and contract land and directional drilling businesses. If near term commodity prices stablize at current levels or increase, we expect to continue to experience an increase in demand for our services and products. Our other energy services revenue declined during the second quarter of 2017 as a major construction project in the area serviced by our remote accommodation division was substantially completed in March 2017.

Results of Operations

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



	Three Months Ended
	June 30, 2017			June 30, 2016
Revenue:
Pressure pumping services	$	49,924,483		$	44,028,142
Well services	8,141,075			2,229,906
Natural sand proppant services	24,000,149			11,007,964
Contract land and directional drilling services	12,471,738			5,228,691
Other energy services	3,724,614			6,667,931
Total revenue	98,262,059			69,162,634

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
Total cost of revenue	77,339,954			50,503,643
Selling, general and administrative expenses	7,699,706			5,206,138
Depreciation and amortization	19,893,399			18,810,615
Impairment of long-lived assets	—			1,870,885
Operating (loss) income	(6,671,000		)	(7,228,647		)
Interest expense, net	(1,111,608		)	(1,012,031		)
Bargain purchase gain, net of tax	4,011,512			—
Other (expense) income, net	(202,496		)	626,716
Income (loss) before income taxes	(3,973,592		)	(7,613,962		)
(Benefit) provision for income taxes	(2,804,077		)	789,375
Net loss	$	(1,169,515	)	$	(8,403,337	)

Revenue. Revenue for the three months ended June 30, 2017 increased $29.1 million, or 42%, to $98.3 million from $69.2 million for the three months ended June 30, 2016. Revenue by operating division was as follows:

Pressure Pumping Services. Pressure pumping services division revenue increased $5.9 million, or 13%, to $49.9 million for the three months ended June 30, 2017 from $44.0 million for the three months ended June 30, 2016. The increase was primarily driven by an increase in fleet utilization of 76%, on an average of two active fleets, from 76% for the three months ended June 30, 2016 to 77%, on an average of three active fleets for the three months ended June 30, 2017. Our fourth fleet began working in June 2017. Additionally, the number of stages completed increased to 1,287 for the three months ended June 30, 2017 from 963 for the three months ended June 30, 2016.

Well Services. Well services division revenue increased $5.9 million, or 268%, to $8.1 million for the three months ended June 30, 2017 from $2.2 million for the three months ended June 30, 2016. Cementing and energy services accounted for $2.6 million of the increase as a result of our Stingray Cementing and Stingray Energy acquisitions. Our coil tubing 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.

Natural Sand Proppant Services. Natural sand proppant services division revenue increased $13.0 million, or 118%, to $24.0 million for the three months ended June 30, 2017, from $11.0 million for the three months ended June 30, 2016. The increase was primarily attributable to an increase in tons of sand sold from 197,529 for the three

months ended June 30, 2016 to 350,710 for the three months ended June 30, 2017. In addition, the price per ton of sand delivered increased from $56 to $68, from the three months ended June 30, 2016 to the three months ended June 30, 2017.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division revenue increased $7.3 million, or 140%, from $5.2 million for the three months ended June 30, 2016 to $12.5 million for the three months ended June 30, 2017. The increase was primarily attributable to our land drilling services, which accounted for $4.5 million, or 62%, of the operating division increase as a result of a increase in average active rigs from four for the three months ended June 30, 2016 to 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% for the three months ended June 30, 2016 to 26% for the three months ended June 30, 2017. Our rig moving services accounted for $1.6 million, or 22%, of the operating division increase. The increase in our rig moving services was driven by the increase in drilling activity.

Other Energy Services. Other energy services division revenue, which has historically included only remote accommodation services but was recently expanded to include energy infrastructure services, decreased $3.0 million, or 45%, to $3.7 million for the three months ended June 30, 2017 from $6.7 million for the three months ended June 30, 2016. The decrease was a result of a decrease in total rooms nights rented from 47,532 to 15,100 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 three months ended June 30, 2016 to $180 for the three months ended June 30, 2017. The decrease in remote accommodations revenue was partially offset by revenue of $1.7 million from our energy infrastructure services.

Cost of Revenue. Cost of revenue increased $26.8 million from $50.5 million, or 73% of total revenue, for the three months ended June 30, 2016 to $77.3 million, or 79% of total revenue, for 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 increased $7.2 million, or 26%, to $35.8 million for the three months ended June 30, 2017 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 million for the three months ended June 30, 2017. The increase was primarily due to increases in labor-related costs and the acquisition of Stingray Cementing and Stingray Energy. As a percentage of revenue, our well services division cost of revenue was 82% and 136% for the three months ended June 30, 2017 and June 30, 2016, respectively. The decrease in cost of revenue as a percentage of revenue was primarily due to the increase in utilization.

Natural Sand Proppant Services. Natural sand proppant services division cost of revenue increased $9.7 million, or 94%, from $10.3 million for the three months ended June 30, 2016 to $20.0 million for the three months ended June 30, 2017, primarily due to an increase in tons of sand sold. As a percentage of revenue, cost of revenue was 83% and 93% for the three months ended June 30, 2017 and June 30, 2016, respectively. The decrease was primarily due to an increase in the price per ton of sand delivered.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division cost of revenue increased $6.2 million, or 107%, from $5.8 million for the three months ended June 30, 2016 to $12.0 million for the three months ended June 30, 2017, primarily due to an increase in labor-related costs, repairs and maintenance and increased utilization. As a percentage of revenue, our contract land and directional drilling services division cost of revenue was 96% and 110% for the three months ended June 30, 2017 and June 30, 2016, respectively. The decrease was primarily due to higher day rates and utilization.

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 and 2017. As a percentage of revenue, cost of revenue was 77% and 44% for the three months ended June 30, 2017 and 2016, respectively. The decrease in costs attributable to our remote accommodation services was partially offset by $1.5 million of costs attribubable to our energy infrastructure services.

Selling, General and Administrative Expenses. Selling, general and administrative expenses represent the costs associated with managing and supporting our operations. These expenses increased $2.5 million, or 48%, to $7.7 million for the three months ended June 30, 2017, from $5.2 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 million for the three months ended June 30, 2017 from $18.8 million for the three months ended June 30, 2016. The increase was primarily attributable to placing in service of $105.9 million of capital additions for the three months ended June 30, 2017 partially offset by $26.2 million of assets that fully depreciated during 2016.

Impairment of Long-lived Assets. 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.

Interest Expense, Net. Interest expense increased $0.1 million, or 10%, to $1.1 million during the three months ended June 30, 2017, from $1.0 million during the three months ended June 30, 2016. The increase in interest expense was attributable to an increase in average borrowings during the three months ended June 30, 2017.

Bargain Purchase Gain. Bargain purchase resulted in a gain of $4.0 million 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. 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 an income tax expense of $0.8 million for the three months ended June 30, 2016. The provision for the three months ended June 30, 2016 was primarily attributable to our subsidiary, Lodging, which provides our remote accommodation services.

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



	Six Months Ended June 30,
	2017			2016
Revenue:
Pressure pumping services	$	90,377,036		$	56,322,671
Well services	11,484,102			4,928,498
Natural sand proppant services	38,912,631			14,207,787
Contract land and directional drilling services	23,222,727			11,632,428
Other energy services	9,231,584			14,654,109
Total revenue	173,228,080			101,745,493

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
Total cost of revenue	135,837,940			82,894,819
Selling, general and administrative expenses	14,436,504			8,820,012
Depreciation and amortization	37,130,650			36,561,687
Impairment of long-lived assets	—			1,870,885
Operating loss	(14,177,014		)	(28,401,910		)
Interest expense, net	(1,508,792		)	(2,308,387		)
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	)

Revenue. Revenue for the six months ended June 30, 2017 increased $71.5 million, or 70%, to $173.2 million from $101.7 million for the six months ended June 30, 2016. Revenue by operating division was as follows:

Pressure Pumping Services. Pressure pumping services division revenue increased $34.1 million, or 61%, to $90.4 million for the six months ended June 30, 2017 from $56.3 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 million, or 135%, 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 as a result of our Stingray Cementing and Stingray Energy acquisitions. Our coil tubing 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.

Natural Sand Proppant Services. Natural sand proppant services division revenue increased $24.7 million, or 174%, to $38.9 million for the six months ended June 30, 2017, from $14.2 million for the six months ended June 30, 2016. The increase was primarily attributable to an increase in tons delivered from approximately 259,890 for

the six months ended June 30, 2016 to approximately 596,706 in the six months ended June 30, 2017, in addition to an increase in price per ton of of sand delivered from $55 to $65, for the six months ended June 30, 2016 and 2017, respectively.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division revenue increased $11.6 million, or 100%, from $11.6 million for the six months ended June 30, 2016 to $23.2 million for the six months ended June 30, 2017. The increase was primarily attributable to our land drilling services, which accounted for $7.0 million, or 60%, of the operating division increase. The increase in our land drilling services was driven by a increase in average active rigs from four for the six months ended June 30, 2016 to six for the six months ended June 30, 2017 as well as a increase in average day rates from approximately $12,900 to approximately $14,250 during those same periods. Our directional drilling services accounted for $2.6 million, or 22%, of the operating division increase as a result of utilization declining from 15% for the six months ended June 30, 2016 to 26% for the six months ended June 30, 2017. Our rig moving services accounted for $2.2 million, or 19%, of the operating division increase primarily driven by the increase in drilling activity. Our drill pipe inspection services accounted for a decline of $0.2 million, or (1)%, of the operating division.

Other Energy Services. Other energy services division revenue decreased $5.5 million, or 37%, to $9.2 million for the six months ended June 30, 2017 from $14.7 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 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 for the six months ended June 30, 2017. The decreases were partially offset by approximately $0.9 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 six months ended June 30, 2017. We did not not provide infrastructure services during the same period in 2016.

Cost of revenue. Cost of revenue increased $52.9 million from $82.9 million, or 81% of total revenue, for the six months ended June 30, 2016 to $135.8 million, or 78% of total revenue for 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 increased $24.4 million, or 61%, to $64.5 million for the six months ended June 30, 2017 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 million for the six months ended June 30, 2017. The increase was primarily due to an increase in labor-related costs. As a percentage of revenue, our well services division cost of revenue was 91% and 141% for the six months ended June 30, 2017 and June 30, 2016, respectively. The decrease in cost of revenue as a percentage of revenue was primarily due to increases in utilization as well as pricing.

Natural Sand Proppant Services. Natural sand proppant services division cost of revenue increased $16.2 million, or 99%, from $16.4 million for the six months ended June 30, 2016 to $32.6 million for the six months ended June 30, 2017, primarily due to an increase in tons sold. As a percentage of revenue, cost of revenue was 84% and 116% for the six months ended June 30, 2017 and 2016, respectively. The decrease in cost of revenue as a percentage of revenue was primarily due to an increase in price per ton sold.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division cost of revenue increased $10.0 million, or 77%, from $13.0 million for the six months ended June 30, 2016 to $23.0 million for the six months ended June 30, 2017, primarily due to an increase in labor-related costs, repairs and maintenance and increased utilization. As a percentage of revenue, our contract land and directional drilling services division cost of revenue was 99% and 111% for the six months ended June 30, 2017 and 2016, respectively. The decrease was primarily due to higher day rates and utilization.

Other Energy Services. Other energy services division cost of revenue decreased $1.1 million, or 17%, from $6.4 million the six months ended June 30, 2016 to $5.3 million for the six months ended June 30, 2017, primarily due to a decline in contracted labor-related costs. As a percentage of revenue, cost of revenue was 57% and 44% for the six

months ended June 30, 2017 and 2016, respectively. The increase was primarily due to the decrease in total room nights rented from 109,229 for the six months ended June 30, 2016 to 49,438 for the six months ended June 30, 2017. The decrease in costs associated with our remote accommodation services was partially offset by $1.5 million of costs associated with our energy infrastructure services.

Selling, General and Administrative expenses. Selling, general and administrative expenses represent the costs associated with managing and supporting our operations. These expenses increased $5.6 million, or 64%, to $14.4 million for the six months ended June 30, 2017, from $8.8 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 million for the six months ended June 30, 2017 from $36.6 million for the six months ended June 30, 2016. The increase was primarily attributable to placing in service of $112.4 million of capital additions for the six months ended June 30, 2017, with $105.9 million, of the $112.4 million, of assets placed in service for the three months ended June 30, 2017, partially offset by $26.2 million of assets that fully depreciated during 2016.

Impairment of Long-lived Assets. 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.

Interest Expense, Net. Interest expense decreased $0.8 million, or 35%, to $1.5 million during the six months ended June 30, 2017, from $2.3 million during the six months ended June 30, 2016. The decrease in interest expense was attributable to a decrease in average borrowings during the six months ended June 30, 2017.

Other (Expense) Income, Net. Non-operating (charges) income resulted in expense of $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. Both periods were primarily comprised of income/loss recognition on assets disposed during the period.

Income Taxes. Prior to our initial public offering in October 2016, we were treated as a pass-through entity for federal income tax and most state income tax purposes. For the six months ended June 30, 2017, we recognized income tax benefit of $5.9 million compared to an income tax expense of $1.7 million for the three months ended June 30, 2016. The provision for the six months ended June 30, 2016 was primarily attributable to our subsidiary, Lodging, which provides our remote accommodation services.

Non-GAAP Financial Measures

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 and amortization, impairment of long-lived assets, acquisition related costs, equity based compensation, interest expense, 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 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 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.

Consolidated



	Three Months Ended						Six Months Ended
	June 30,						June 30,
Reconciliation of Adjusted EBITDA to net income (loss):	2017			2016			2017			2016
Net income (loss)	$	(1,169,515	)	$	(8,403,337	)	$	(6,150,794	)	$	(31,768,306	)
Depreciation and amortization expense	19,893,399			18,810,615			37,130,650			36,561,687
Impairment of long-lived assets	—			1,870,885			—			1,870,885
Acquisition related costs	961,237			—			2,190,749			—
Equity based compensation	1,050,062			—			1,619,893			—
Bargain purchase gain	(4,011,512		)	—			(4,011,512		)	—
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
Adjusted EBITDA	$	15,233,698		$	13,452,853		$	26,764,278		$	10,030,662

Pressure Pumping Services



	Three Months Ended				Six Months Ended
	June 30,				June 30,
Reconciliation of Adjusted EBITDA to net income (loss):	2017		2016		2017		2016
Net income (loss)	$	1,759,713	$	3,665,382	$	2,440,932	$	(5,271,214	)
Depreciation and amortization expense	9,626,553		9,958,270		18,784,446		18,913,487
Impairment of long-lived assets	—		138,587		—		138,587
Equity based compensation	502,901		—		774,289		—
Interest expense	303,351		131,709		431,795		368,764
Other (income) expense, net	3,758		43,033		6,389		23,825
Adjusted EBITDA	$	12,196,276	$	13,936,981	$	22,437,851	$	14,173,449

Other Well Services



	Three Months Ended						Six Months Ended
	June 30,						June 30,
Reconciliation of Adjusted EBITDA to net income (loss):	2017			2016			2017			2016
Net income (loss)	$	1,373,396		$	(3,267,228	)	$	2,532,253		$	(6,574,864	)
Depreciation and amortization expense	2,219,921			1,272,715			3,428,162			2,670,222
Impairment of long-lived assets	—			1,384,751			—			1,384,751
Acquisition related costs	—			—			170,132			—
Equity based compensation	90,461			—			137,450			—
Interest expense	(2,474		)	50,776			(108,376		)	149,095
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		)
Adjusted EBITDA	$	869,149		$	(1,244,625	)	$	(342,884	)	$	(3,047,035	)

Natural Sand Proppant Services



	Three Months Ended						Six Months Ended
	June 30,						June 30,
Reconciliation of Adjusted EBITDA to net income (loss):	2017			2016			2017			2016
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
Acquisition related costs	916,214			—			1,954,079			—
Equity based compensation	182,337			—			252,461			—
Bargain purchase gain	(4,011,512		)	—			(4,011,512		)	—
Interest expense	352,600			106,650			485,239			211,111
Other (income) expense, net	139,569			53,803			153,776			72,985
Provision for income taxes	8,502			—			8,502			—
Adjusted EBITDA	$	2,708,758		$	(752,182	)	$	4,064,411		$	(4,334,383	)

Contract Land and Directional Drilling 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	$	(6,469,181	)	$	(8,235,701	)	$	(13,316,234	)	$	(16,692,975	)
Depreciation and amortization expense	4,973,682			5,438,551			9,942,310			10,945,932
Impairment of long-lived assets	—			347,547			—			347,547
Acquisition related costs	3,000			—			24,515			—
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		)
Adjusted EBITDA	$	(811,778	)	$	(1,795,470	)	$	(2,175,851	)	$	(3,902,863	)

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

Liquidity and Capital Resources

We require capital to fund ongoing operations, including maintenance expenditures on our existing fleet and 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. Our primary use of capital has been for investing in property and equipment used to provide our services and to acquire complimentary businesses.

As of June 30, 2017, we had an aggregate of $65.0 million in borrowings outstanding under our revolving credit facility, leaving an aggregate of $104.7 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 of $92.2 million in borrowings outstanding under our revolving credit facility, leaving an aggregate of $77.5 million of available borrowing capacity under this facility.

Liquidity and Cash Flows

The following table sets forth our cash flows at the dates indicated:



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
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 (used in) financing activities	57,926,146			(5,102,744		)	57,926,146			(14,602,516		)
Effect of foreign exchange rate on cash	62,288			(126,397		)	72,943			54,163
Net change in cash	$	(4,377,952	)	$	(13,241,979	)	$	(20,689,328	)	$	(2,610,926	)

Operating Activities

Net cash provided by operating activities was $24.0 million for the six months ended June 30, 2017, compared to $10.9 million for the six months ended June 30, 2016. 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 the three months ended June 30, 2017, compared to cash used of $9.5 million for the three months ended June 30, 2016. The increase in operating cash flows was primarily attributable to timing of receivable collections with related parties.

Investing Activities

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

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

The following table summarizes our capital expenditures by operating division for the periods indicated:



	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


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


(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.

Financing Activities

Net cash provided by financing activities was $57.9 million for the six months ended June 30, 2017, compared to cash used in financing activities of $14.6 million for the six months ended June 30, 2016. Net cash provided by financing activities was $57.9 million for the three months ended June 30, 2017, compared to cash used in financing activities of $5.1 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 all cash used in financing activities was used to pay down net borrowings under our credit facility.

Effect of Foreign Exchange Rate on Cash

The effect of foreign exchange rate on cash was $0.1 million, for each of the six months ended June 30, 2017 and 2016. 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 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 million and $59.7 million at June 30, 2017 and December 31, 2016, respectively. Our cash balances totaled $8.5 million and $29.2 million at June 30, 2017 and December 31, 2016, respectively.

Our Revolving Credit Facility

On November 25, 2014, we entered into a $170.0 million revolving credit and security agreement 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.

Interest is payable monthly at a base rate set by the lead institution’s commercial lending group plus an applicable margin. Additionally, at our request, outstanding balances are permitted to be converted to LIBOR rate plus applicable margin tranches at set increments of $500,000. The LIBOR rate option allows us to select interest periods from one, two, three or six months. The applicable margin for either the base rate or the LIBOR rate option can vary from 1.5% to 3.0%, based upon a calculation of the excess availability of the line as a percentage of the maximum credit limit.

At June 30, 2017, $57.0 million of the total outstanding balance of $65.0 million under the facility was in a one month LIBOR rate option tranche with an interest rate of 3.72%. As of June 30, 2017, we had availability of $104.7 million under our revolving credit facility. We used a portion of the net proceeds from our IPO 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 million of available borrowing capacity under this facility.

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 and December 31, 2016, we were in compliance with these 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, we have seen an increase in customer demand, particularly in our pressure pumping and natural sand proppant services divisions. Our capital budget for 2017 increased substantially from our 2016 capital budget of approximately $11.3 million. Our expected 2017 full-year capital budget currently includes expenditures of $64.0 million in our pressure pumping services division for the acquisition of 132,500 horsepower of new high pressure hydraulic pumps and related equipment, $8.0 million in our pressure pumping service division for tractors, pneumatic trailers to enhance our last mile solutions, $25.0 million in our sand segment for plant capacity expansion projects, and $33.0 million for rig upgrades and additional equipment for our well services, contract and direction drilling services and other energy services divisions. During the first six months ended June 30, 2017, we spent approximately $66.6 million on such capital expenditures, including $35.5 million during the second quarter of 2017, and an additional $39.6 million to complete business acquisitions.

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 regularly evaluate acquisition opportunities, and the number of opportunities coming to our attention has increased substantially since the IPO. However, we do not have a specific acquisition budget for 2017 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 real estate, rail cars and other equipment under long-term operating leases with varying terms and expiration dates through 2025.

Minimum Purchase Commitments

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

Capital Spend Commitments

The Company has 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 are as follows:



Year ended December 31:	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
2019	8,075,402		—		10,866,000
2020	5,597,885		—		—
2021	2,645,182		—		—
Thereafter	3,721,249		—		—
	$	34,703,014	$	22,730,189	$	28,421,581

Other Commitments

Subsequent to June 30, 2017, we entered into a lease agreement for capital equipment with aggregate commitments of $1.5 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 February 2016, the FASB issued ASU No, 2016-2 “Leases” amending the current accounting for leases. Under the new provisions, all lessees will report a right-of-use asset and a liability for the obligation to make payments for all leases with the exception of those leases with a term of 12 months or less. All other leases will fall into one of two categories: (i) a financing lease or (ii) an operating lease. Lessor accounting remains substantially unchanged with the exception that no leases entered into after the effective date will be classified as leveraged leases. For sale leaseback transactions, a sale will only be recognized if the criteria in the new revenue recognition standard are met. ASU 2016-2 is effective for fiscal years beginning after December 15, 2018, and interim periods within that fiscal year. Early adoption is permitted. Since a portion of the Company’s revenue may be subject to this new leasing guidance, it expects to adopt this updated leasing guidance at the same time its adopts the new revenue standard discussed above, utilizing the retrospective method of adoption. This new leasing guidance will also impact the Company in situations where it is the lessee, and in certain circumstances it will have a right-of-use asset and lease liability on its consolidated financial statements. We are currently evaluating the effect the new guidance will have on our consolidated financial statements and results of operations.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The demand, pricing and terms for oil and gas services provided by us are largely dependent upon the level of activity for the U.S. oil and natural gas 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; the level of prices, and expectations about future prices of oil and natural gas; 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 pipeline and other transportation 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 to raise equity capital and debt financing; and merger and divestiture activity among oil and natural gas producers.

The level of activity in the U.S. oil and natural gas exploration and production industry is volatile. Expected trends in oil and natural gas production activities may not continue and demand for our services may not reflect the level of activity in the industry. Any prolonged substantial reduction in oil and natural gas prices would likely affect oil and natural gas production levels and therefore affect demand for our services. A material decline in oil and natural gas prices 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 million at June 30, 2017. 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.

At June 30, 2017, we had $65.0 million outstanding under this facility with weighted average interest rate of 3.91%. A 1% increase or decrease in the interest rate at that time would have increased or decreased our interest expense by approximately $0.7 million per year. We do not currently hedge our interest rate exposure.

Foreign Currency Risk

Our remote accommodation business, which is included in our other energy services segment, 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, we had $3.1 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 million as of June 30, 2017. 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 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 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 in Ohio, Oklahoma, Wisconsin, Minnesota, and Alberta, Canada. For the six months ended June 30, 2017 and 2016, we generated approximately 81% and 85%, respectively, of our revenue from our operations in Ohio, Wisconsin, Minnesota, Pennsylvania, West Virginia and Canada where weather conditions may be severe. As a result, our operations may be limited or disrupted, particularly during winter and spring months, in these geographic regions, which would have a material adverse effect on our financial condition and results of operations. Our operations in Oklahoma and Texas are generally not affected by seasonal weather conditions.

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, 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, 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 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 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 have a material adverse effect on our financial condition, cash flows or results of operations.

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

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 in this Report and other reports and materials we file 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 or on our behalf.

Inaccuracies 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.

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 offering

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.

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.


#	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	By:	/s/ Arty Straehla
			Arty Straehla
			Chief Executive Officer

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