MAMMOTH ENERGY SERVICES, INC. - Quarter Report: 2017 March (Form 10-Q)

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 MARCH 31, 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 May 11, 2017, there were 37,500,000 shares of common stock, $0.01 par value, outstanding.

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 Partners' Interest	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	25
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	37
Item 4.	Controls and Procedures	38

PART II. OTHER INFORMATION		39
Item 1.	Legal Proceedings	39
Item 1A.	Risk Factors	39
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39
Item 5.	Other Information	40
Item 6.	Exhibits	41

SIGNATURES		42

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 and drill bits, including rotary steerable systems, and drill bits. The directional driller also exploits drilling parameters such as weight on bit and rotary speed to deflect the bit away from the axis of the existing wellbore. In some cases, such as drilling steeply dipping formations or unpredictable deviation in conventional drilling operations, directional-drilling techniques may be employed to ensure that the hole is drilled vertically. While many techniques can accomplish this, the general concept is simple: point the bit in the direction that one wants to drill. The most common way is through the use of a bend near the bit in a down-hole steerable mud motor. The bend points the bit in a direction different from the axis of the wellbore when the entire drillstring is not rotating. By pumping mud through the mud motor, the bit turns while the drillstring does not rotate, allowing the bit to drill in the direction it points. When a particular wellbore direction is achieved, that direction may be maintained by rotating the entire drillstring (including the bent section) so that the bit does not drill in a single direction off the wellbore axis, but instead sweeps around and its net direction coincides with the existing wellbore. Rotary steerable tools allow steering while rotating, usually with higher rates of penetration and ultimately smoother boreholes.
Down-hole	Pertaining to or in the wellbore (as opposed to being on the surface).
Down-hole motor	A drilling motor located in the drill string above the drilling bit powered by the flow of drilling mud. Down-hole motors are used to increase the speed and efficiency of the drill bit or can be used to steer the bit in directional drilling operations. Drilling motors have become very popular because of horizontal and directional drilling applications and the increase of day rates for drilling rigs.
Drilling rig	The machine used to drill a wellbore.
Drillpipe or Drill pipe	Tubular steel conduit fitted with special threaded ends called tool joints. The drillpipe connects the rig surface equipment with the bottomhole assembly and the bit, both to pump drilling fluid to the bit and to be able to raise, lower and rotate the bottomhole assembly and bit.
Drillstring or Drill string	The combination of the drillpipe, the bottomhole assembly and any other tools used to make the drill bit turn at the bottom of the wellbore.
Horizontal drilling	A subset of the more general term “directional drilling,” used where the departure of the wellbore from vertical exceeds about 80 degrees. Note that some horizontal wells are designed such that after reaching true 90-degree horizontal, the wellbore may actually start drilling upward. In such cases, the angle past 90 degrees is continued, as in 95 degrees, rather than reporting it as deviation from vertical, which would then be 85 degrees. Because a horizontal well typically penetrates a greater length of the reservoir, it can offer significant production improvement over a vertical well.
Hydraulic fracturing	A stimulation treatment routinely performed on oil and gas wells in low permeability reservoirs. Specially engineered fluids are pumped at high pressure and rate into the reservoir interval to be treated, causing a vertical fracture to open. The wings of the fracture extend away from the wellbore in opposing directions according to the natural stresses within the formation. Proppant, such as grains of sand of a particular size, is mixed with the treatment fluid to keep the fracture open when the treatment is complete. Hydraulic fracturing creates high-conductivity communication with a large area of formation and bypasses any damage that may exist in the near-wellbore area.
Hydrocarbon	A naturally occurring organic compound comprising hydrogen and carbon. Hydrocarbons can be as simple as methane, but many are highly complex molecules, and can occur as gases, liquids or solids. Petroleum is a complex mixture of hydrocarbons. The most common hydrocarbons are natural gas, oil and coal.
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.

MAMMOTH ENERGY SERVICES, INC.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

MAMMOTH ENERGY SERVICES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (unaudited)



ASSETS	March 31,			December 31,
	2017			2016
CURRENT ASSETS
Cash and cash equivalents	$	12,278,120		$	28,693,985
Accounts receivable, net	24,973,332			20,602,962
Receivables from related parties	33,141,299			28,059,565
Inventories	4,922,627			4,355,088
Prepaid expenses	3,402,022			4,254,148
Other current assets	1,182,058			391,599
Total current assets	79,899,458			86,357,347

Property, plant and equipment, net	244,021,697			221,247,228
Intangible assets, net - customer relationships	13,859,772			15,949,772
Intangible assets, net - trade names	5,439,307			5,617,057
Goodwill	86,043,148			86,043,148
Other non-current assets	5,239,582			5,339,283
Total assets	$	434,502,964		$	420,553,835

LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	37,237,976		$	18,480,325
Payables to related parties	4,921,129			2,434,031
Accrued expenses and other current liabilities	8,825,877			8,396,968
Income taxes payable	—			28,156
Total current liabilities	50,984,982			29,339,480

Long-term debt	—			—
Deferred income taxes	43,881,012			47,670,789
Other liabilities	2,733,863			2,501,886
Total liabilities	97,599,857			79,512,155

COMMITMENTS AND CONTINGENCIES (Note 13)

EQUITY
Equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 37,500,000	375,000			375,000
issued and outstanding at March 31, 2017 and December 31, 2016.
Additional paid in capital	400,775,752			400,205,921
Accumulated deficit	(61,259,392		)	(56,322,878		)
Accumulated other comprehensive loss	(2,988,253		)	(3,216,363		)
Total equity	336,903,107			341,041,680
Total liabilities and equity	$	434,502,964		$	420,553,835

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
	March 31,
	2017			2016
REVENUE
Services revenue	$	27,091,882		$	28,236,482
Services revenue - related parties	33,132,571			1,156,815
Product revenue	2,615,209			735,453
Product revenue - related parties	11,576,151			4,374,754
Total Revenue	74,415,813			34,503,504

COST AND EXPENSES
Services cost of revenue (1)	45,460,804			26,103,641
Services cost of revenue - related parties	494,345			2,835,402
Product cost of revenue (2)	5,376,897			3,158,632
Product cost of revenue - related parties	7,554,380			799,545
Selling, general and administrative	5,844,093			3,110,197
Selling, general and administrative - related parties	377,717			144,869
Depreciation and amortization	16,893,777			17,413,591
Total cost and expenses	82,002,013			53,565,877
Operating loss	(7,586,200		)	(19,062,373		)

OTHER (EXPENSE) INCOME
Interest expense	(286,338		)	(1,191,895		)
Other, net	(170,041		)	18,194
Total other expense	(456,379		)	(1,173,701		)
Loss before income taxes	(8,042,579		)	(20,236,074		)
(Benefit) provision for income taxes	(3,106,065		)	894,360
Net loss	$	(4,936,514	)	$	(21,130,434	)

OTHER COMPREHENSIVE LOSS
Foreign currency translation adjustment (3)	228,110			1,975,351
Comprehensive loss	$	(4,708,404	)	$	(19,155,083	)

Net loss per share (basic and diluted) (Note 9)	$	(0.13	)	$	(0.70	)
Weighted average number of shares outstanding (Note 9)	37,500,000			30,000,000

Pro Forma C Corporation Data (unaudited):
Net loss, as reported				(21,130,434		)
Pro forma benefit for income taxes				(944,584		)
Pro forma net loss				(20,185,850		)
Basic and Diluted (Note 9)				(0.54		)
Weighted average pro forma shares outstanding—basic and diluted (Note 9)				37,500,000

(1) Exclusive of depreciation and amortization	15,837,735			16,348,075
(2) Exclusive of depreciation and amortization	1,018,241			1,029,201
(3) Net of tax	20,143			—

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			Accumulated			Paid-In
	Shares	Amount		Partners			Deficit			Capital		AOCL			Total
Balance at January 1, 2016	—	$	—	$	329,090,230		$	—		$	—	$	(5,926,968	)	$	323,163,262
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 subsequent to LLC conversion	—	—		—			(56,322,878		)	—		—			(56,322,878		)
Other comprehensive income	—	—		—			—			—		2,710,605			2,710,605
Balance at December 31, 2016	37,500,000	375,000		—			(56,322,878		)	400,205,921		(3,216,363		)	341,041,680
Net loss	—	—		—			(4,936,514		)	—		—			(4,936,514		)
Equity based compensation	—	—		—			—			569,831		—			569,831
Other comprehensive income	—	—		—			—			—		228,110			228,110
Balance at March 31, 2017	37,500,000	$	375,000	$	—		$	(61,259,392	)	$	400,775,752	$	(2,988,253	)	$	336,903,107

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

MAMMOTH ENERGY SERVICES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)



	Three Months Ended
	March 31,
	2017			2016
Cash flows from operating activities
Net loss	$	(4,936,514	)	$	(21,130,434	)
Adjustments to reconcile net loss to cash provided by operating activities:
Equity based compensation	569,831			—
Depreciation and amortization	16,893,777			17,413,591
Amortization of coil tubing strings	492,409			551,300
Amortization of debt origination costs	99,701			99,701
Bad debt expense	(40,446		)	23,543
Gain disposal of property and equipment	(79,408		)	(21,000		)
Deferred income taxes	(3,801,212		)	93,451
Changes in assets and liabilities:
Accounts receivable, net	(4,282,133		)	(1,854,385		)
Receivables from related parties	(5,081,734		)	19,802,936
Inventories	(1,059,948		)	(162,003		)
Prepaid expenses and other assets	62,571			(4,530,288		)
Accounts payable	12,185,209			(3,123,148		)
Payables to related parties	2,487,033			1,393,117
Accrued expenses and other liabilities	658,419			12,100,124
Income taxes payable	(28,156		)	(26,912		)
Net cash provided by operating activities	14,139,399			20,629,593

Cash flows from investing activities:
Purchases of property and equipment	(30,935,179		)	(534,525		)
Proceeds from disposal of property and equipment	369,258			34,863
Net cash used in investing activities	(30,565,921		)	(499,662		)

Cash flows from financing activities:
Borrowings from lines of credit	—			4,800,000
Repayments of lines of credit	—			(14,299,772		)
Net cash used in financing activities	—			(9,499,772		)
Effect of foreign exchange rate on cash	10,657			260,074
Net (decrease) increase in cash and cash equivalents	(16,415,865		)	10,890,233
Cash and cash equivalents at beginning of period	28,693,985			3,074,072
Cash and cash equivalents at end of period	$	12,278,120		$	13,964,305

Supplemental disclosure of cash flow information:
Cash paid for interest	$	186,584		$	1,138,550
Cash paid for income taxes	$	700,825		$	934,262
Supplemental disclosure of non-cash transactions:
Purchases of property and equipment included in trade accounts payable	$	9,346,077		$	597,885

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 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, Mammoth Energy Holdings, LLC (“Mammoth Holdings”), an entity controlled by Wexford, Gulfport Energy Corporation (“Gulfport”) and Rhino Resource Partners LP (“Rhino”) 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, formed January 9, 2017; and Cobra T&D LLC, formed January 24, 2017.

The contribution to the Partnership on November 24, 2014 of all Operating Entities, except Pressure Pumping, Logistics and entities created 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.

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 intends to use the remaining net proceeds for general corporate purposes, which may include the acquisition of additional equipment and complementary businesses that enhance its existing service offerings, broaden its service offerings or expand its customer relationships.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

At March 31, 2017 and December 31, 2016, Mammoth Holdings, Gulfport and Rhino owned the following share of outstanding common stock of Mammoth Inc:



	At March 31, 2017			At December 31, 2016
	Share Count	% Ownership		Share Count	% Ownership
Mammoth Holdings	20,443,903	54.5	%	20,443,903	54.5	%
Gulfport	9,073,750	24.2	%	9,073,750	24.2	%
Rhino	232,347	0.6	%	232,347	0.6	%
Outstanding shares owned by related parties	29,750,000	79.3	%	29,750,000	79.3	%
Total outstanding	37,500,000	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, currently primarily consisting of remote accommodations for people working in the oil sands located in Northern Alberta, Canada.

The acquisition of the Stingray Entities added to the Company's completion and production portfolio. Specifically, by adding hydraulic fracturing and proppant hauling logistics services, the Company has developed a diverse offering of operations that can participate in nearly all phases of the oilfield services industry.

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 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 consolidated financial statements are prepared in accordance with Generally Accepted Accounting Principles ("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 allowance for doubtful accounts, reserves for self-insurance, depreciation and amortization of property and equipment, 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 March 31, 2017, the Company had $5.7 million, in Canadian dollars, of cash in Canadian accounts. Cash balances from time to time may

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 30^th 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 three months ended March 31, 2017 and year ended December 31, 2016:



Balance, January 1, 2016	$	3,947,432
Additions charged to expense	1,968,001
Deductions for uncollectible receivables written off	(602,967		)
Balance, December 31, 2016	5,312,466
Additions charged (credited) to expense	(40,446		)
Balance, March 31, 2017	$	5,272,020

As discussed in Note 1, prolonged declines in pricing can impact the overall health of the oil and natural gas industry. The three months ended March 31, 2017 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, consistent with Company policy, it reduced a portion of the allowance for doubtful accounts. 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 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 $492,409 and $551,300 for the three months ended March 31, 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.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(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.

(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 three months ended March 31, 2017 and 2016, no impairment losses were recognized.

(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 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 three months ended March 31, 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 7) and sales tax receivables.

(k) 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 three months ended March 31, 2017 and 2016, no impairment losses were recognized.

(l) Fair Value of Financial Instruments

The Company's financial instruments consist of cash and cash equivalents, trade receivables, trade payables and amounts receivable or payable 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.

(m) 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 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.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 three months ended March 31, 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.

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 $2,756,150 and $2,732,993 of unbilled revenue included in accounts receivable, net in the Condensed Consolidated Balance Sheets at March 31, 2017 and December 31, 2016, respectively. The Company had $11,466,592 and $10,506,958 of unbilled revenue included in receivables from related parties in the Condensed Consolidated Balance Sheets at March 31, 2017 and December 31, 2016, respectively.

(n) Earnings per Share

Earnings per share is computed by dividing net loss by the weighted average number of outstanding shares. See Note 9.

(o) 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 IPO was outstanding for the three months ended March 31, 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 9.

(p) 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 10.

(q) 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 11.

(r) 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

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 38.7% for the three months ended March 31, 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 9. 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 three months ended March 31, 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.

(s) 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.

(t) Comprehensive Loss

Comprehensive loss consists of net loss and other comprehensive loss. Other comprehensive 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.

(u) 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 March 31, 2017, no third-party customer accounted for more than 10% of the Company's trade accounts receivable and receivables from related parties balance combined. At March 31, 2017 and December 31, 2016, related party customers accounted for 57% and 58%, respectively, of the Company’s trade accounts receivable and receivables from related parties balance combined. At March 31, 2017 and December 31, 2016, one related party customer accounted for 52% and 53%, respectively, of the Company's trade accounts receivable and receivables from related parties balance

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

combined. During the three months ended March 31, 2017 and 2016, one related party customer accounted for 59% and 7%, respectively, of the Company's total revenue. Two third-party customers accounted for greater than 10% of the Company's total revenue for three months ended March 31, 2016, at 35% and 17%, respectively. No third-party customer accounted for greater than 10% of the Company's total revenue for three months ended March 31, 2017.

(v) 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 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.

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.	Inventory

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



	March 31,		December 31,
	2017		2016
Supplies	$	3,638,587	$	4,020,670
Raw materials	149,455		75,971
Work in process	—		205,450
Finished goods	1,134,585		52,997
Total inventory	$	4,922,627	$	4,355,088

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


4.	Property, Plant and Equipment

Property, plant and equipment include the following:



		March 31,		December 31,
	Useful Life	2017		2016
Land		$	2,010,555	$	2,010,555
Land improvements	15 years or life of lease	3,640,976		3,640,976
Buildings	15-20 years	42,461,037		42,191,745
Drilling rigs and related equipment	3-15 years	139,101,541		138,526,519
Pressure pumping equipment	3-5 years	101,580,322		96,500,592
Coil tubing equipment	4-10 years	28,006,153		28,019,217
Other machinery and equipment	7-20 years	36,171,379		35,548,357
Vehicles, trucks and trailers	5-10 years	30,041,893		29,964,148
Other property and equipment	3-12 years	11,437,020		11,416,334
		394,450,876		387,818,443
Deposits on equipment and equipment in process of assembly		39,144,915		8,701,725
		433,595,791		396,520,168
Less: accumulated depreciation		189,574,094		175,272,940
Property, plant and equipment, net		$	244,021,697	$	221,247,228

Depreciation expense was $14,626,027 and $15,145,841 for the three months ended March 31, 2017 and 2016, respectively.

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 three months ended March 31, 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 $242,723. There were no proceeds from the sale of equipment damaged or lost down-hole for the three months ended March 31, 2016.

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.


5.	Goodwill and Intangible Assets

The Company had the following definite lived intangible assets recorded:

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



	March 31,		December 31,
	2017		2016
Customer relationships	$	33,605,000	$	33,605,000
Trade names	7,110,000		7,110,000
Less: accumulated amortization - customer relationships	19,745,228		17,655,228
Less: accumulated amortization - trade names	1,670,693		1,492,943
Intangible assets, net	$	19,299,079	$	21,566,829

Amortization expense for intangible assets was $2,267,750 and $2,267,750 for the three months ended March 31, 2017 and 2016, respectively. The original life of customer relationships range from 4 to 10 years with a remaining average useful life of 3.10 years. Trade names are amortized over a 10 year useful life and as of March 31, 2017 the remaining useful life was 7.65 years.

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



Year ended December 31:	Amount
Remainder of 2017	$	6,803,254
2018	8,224,005
2019	738,504
2020	738,504
2021	732,752
Thereafter	2,062,060
	$	19,299,079

Goodwill was $86,043,148 at March 31, 2017 and December 31, 2016.


6.	Accrued Expenses and Other Current Liabilities

Accrued expense and other current liabilities included the following:



	March 31,		December 31,
	2017		2016
Accrued compensation, benefits and related taxes	$	2,702,648	$	2,368,143
Financed insurance premiums	3,022,422		3,293,859
State and local taxes payable	319,868		319,597
Insurance reserves	1,173,705		971,351
Other	1,607,234		1,444,018
Total	$	8,825,877	$	8,396,968

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.


7.	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 institution’s commercial lending group plus an applicable

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 March 31, 2017, the facility was undrawn and had borrowing base availability of $144,149,393.

At 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 March 31, 2017 and December 31, 2016, the Company was in compliance with its covenants under the facility.


8.	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 expense (benefit) attributable to the Company for the three months ended March 31, 2017 and 2016, are as follows:



	Three Months Ended March 31,
	2017			2016
U.S. deferred income tax benefit	$	(3,685,381	)	$	—
Foreign current income tax expense	585,467			894,360
Foreign deferred income tax benefit	(6,151		)	—
Total	$	(3,106,065	)	$	894,360

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



	Three Months Ended March 31,
	2017			2016
Loss before income taxes	$	(8,042,579	)	$	(20,236,074	)
Statutory income tax rate	35		%	35		%
Expected income tax benefit	(2,814,903		)	(7,082,626		)
Non-taxable entity	—			8,260,791
Other permanent differences	14,063			6,793
State tax benefit	(452,372		)	(2,055		)
Foreign tax credit	(698,289		)	—
Foreign earnings not in book income	1,046,248			—
Foreign income tax rate differential	(174,511		)	(270,813		)
Other	(26,301		)	(17,730		)
Total	$	(3,106,065	)	$	894,360

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

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



	March 31,			December 31,
	2017			2016
Deferred tax assets:
Allowance for doubtful accounts	$	1,891,392		$	1,892,761
Net operating loss carryforward	2,280,696			—
Deferred stock compensation	1,697,536			1,686,671
Accrued liabilities	601,449			746,132
Other	1,765,362			1,785,999
Deferred tax assets	8,236,435			6,111,563

Deferred tax liabilities:
Property and equipment	$	(40,901,822	)	$	(42,525,793	)
Intangible assets	(6,890,355		)	(7,662,590		)
Unrepatriated foreign earnings	(4,244,437		)	(3,451,110		)
Other	(80,833		)	(142,859		)
Deferred tax liabilities	(52,117,447		)	(53,782,352		)
Net deferred tax liability	$	(43,881,012	)	$	(47,670,789	)

Reflected in accompanying balance sheet as:
Deferred income taxes	$	(43,881,012	)	$	(47,670,789	)


9.	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.

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.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



	Three Months Ended March 31,
	2017			2016
Basic loss per share:
Allocation of earnings:
Net loss	$	(4,936,514	)	$	(21,130,434	)
Weighted average common shares outstanding	37,500,000			30,000,000
Basic loss per share	$	(0.13	)	$	(0.70	)

Diluted loss per share:
Allocation of earnings:
Net loss	$	(4,936,514	)	$	(21,130,434	)
Weighted average common shares, including dilutive effect ^(a)	37,500,000			30,000,000
Diluted loss per share	$	(0.13	)	$	(0.70	)


^(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 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:



	Three Months Ended
	March 31, 2016
Pro Forma C Corporation Data (unaudited):
Net loss, as reported	(21,130,434		)
Pro forma benefit for income taxes	(944,584		)
Pro forma net loss	(20,185,850		)

Basic loss per share:
Allocation of earnings:
Net loss	$	(20,185,850	)
Weighted average common shares outstanding	37,500,000
Basic loss per share	$	(0.54	)

Diluted loss per share:
Allocation of earnings:
Net loss	$	(20,185,850	)
Weighted average common shares, including dilutive effect ^(a)	37,500,000
Diluted loss per share	$	(0.54	)


^(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.

Pro forma basic and diluted loss per share has been computed by dividing pro forma net loss attributable to the Company by the number of shares of common stock determined as if the shares of common stock issued were outstanding for all periods presented. Management believes that these assumptions provide a reasonable basis for presenting the pro forma effects.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


10.	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 March 31, 2017 was $48,061,841.


11.	Stock Based Compensation

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

Restricted Stock Units

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

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	379,444		21.13
Vested	—		—
Forfeited	(4,444	)	15.00
Unvested shares as of March 31, 2017	657,780		$	18.53

As of March 31, 2017, there was $11,324,218 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 thirty-three months.

Included in cost of revenue and selling, general and administrative expenses is stock-based compensation expense of $569,831 for the three months ended March 31, 2017.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


12.	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”); Taylor Frac LLC (“Taylor”); El Toro ("El Toro"); Stingray Cementing, LLC ("Cementing"); Diamondback E&P, LLC ("Diamondback"); Stingray Energy Services, LLC ("SR Energy"); 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 March 31,				At March 31,		At December 31,
		2017		2016		2017		2016
Pressure Pumping and Gulfport	(a)	$	31,745,950	$	—	$	20,470,158	$	19,094,509
Muskie and Gulfport	(b)	11,540,419		1,918,078		8,109,288		5,373,007
Muskie and Taylor	(c)	35,732		2,456,676		20,193		70,470
Panther Drilling and Gulfport	(d)	1,042,377		451,875		1,732,263		1,434,036
Lodging and Grizzly	(e)	264		555		263		274
Bison Drilling and El Toro	(f)	—		371,873		—		—
Panther Drilling and El Toro	(f)	—		170,170		—		—
Bison Trucking and El Toro	(f)	—		130,000		—		—
White Wing and El Toro	(f)	—		20,431		—		—
Energy Services and El Toro	(g)	123,645		—		64,646		108,386
Barracuda and Taylor	(h)	170,914		10,261		58,227		199,413
MRI and Cementing	(i)	4,790		—		5,610		820
White Wing and Diamondback	(j)	—		1,650		—		—
Coil Tubing and SR Energy	(k)	29,250		—		47,850		—
Pressure Pumping and Cementing	(l)	9,970		—		26,593		950,678
Silverback and SR Energy	(m)	196		—		17,124		12,181
Panther and DBDHT	(n)	5,215		—		86,015		100,450
Other Relationships		—		—		2,503,069		715,341
		$	44,708,722	$	5,531,569	$	33,141,299	$	28,059,565


a.	Pressure Pumping provides pressure pumping, stimulation and related completion services to Gulfport.


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


c.	Taylor, an entity under common ownership with the Company and managed by the Company, has purchased natural sand proppant from Muskie.

Natural sand proppant is sold to Taylor at a market-based per ton arrangement on an as-needed basis.


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


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


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

agreement.


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


h.	Barracuda receives fees from Taylor for the usage of its rail transloading facility.


i.	MRI provides iron inspection services to Cementing.


j.	White Wing provides rental services to Diamondback.


k.	Coil Tubing provides rental services to SR Energy.


l.	Pressure Pumping provides services and materials to Cementing.


m.	Silverback provides services and materials to SR Energy.


n.	Panther provides services and materials to DBDHT.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



		COST OF REVENUE				ACCOUNTS PAYABLE
		Three Months Ended March 31,				At March 31,		At December 31,
		2017		2016		2017		2016
Pressure Pumping and Taylor	(a)	$	—	$	2,665,992	$	—	$	—
Muskie and Taylor	(a)	7,554,380		799,545		4,056,830		2,119,084
Barracuda and Taylor	(b)	64,428		52,364		203,165		111,738
Panther and DBDHT	(c)	127,720		46,554		115,661		—
Bison Trucking and Diamondback	(d)	38,132		41,627		10,187		—
Energy Services and Elk City Yard	(e)	26,700		26,700		—		—
Barracuda and SR Energy	(f)	14,983		2,165		—		6,279
Stingray Entities and SR Energy	(g)	222,382		—		408,458		167,866
Lodging and Dunvegan	(h)	—		—		—		3,199
Bison Trucking and El Toro	(i)	—		—		79		—
		$	8,048,725	$	3,634,947	$	4,794,380	$	2,408,166

		SELLING, GENERAL AND ADMINISTRATIVE COSTS
Consolidated and Everest	(j)	$	55,367	$	72,324	$	16,798	$	12,668
Consolidated and Taylor	(k)	62,550		37,840		—		—
Consolidated and Wexford	(l)	227,739		34,705		109,065		13,197
Mammoth and Orange Leaf	(m)	29,510		—		—		—
Lodging and Dunvegan	(h)	2,551		—		886		—
		$	377,717	$	144,869	$	126,749	$	25,865
						$	4,921,129	$	2,434,031


a.	Taylor, an entity under common ownership with the Company and managed by the Company, sells natural sand proppant to Muskie and Pressure

Pumping. Natural sand proppant is sold to Muskie at a market-based per ton arrangement on an as-needed basis to supplement sand provided

by its facility (when in operation) if any orders placed by its customers are not able to be readily fulfilled, either because of volume or specific

grades of sand requested.


b.	From time to time, Barracuda pays for goods and services on behalf of Taylor.


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


d.	Bison Trucking leases office space from Diamondback in Midland, Texas. The office space is leased through early 2017.


e.	Energy Services leases property from Elk City Yard.


f.	From time to time, Barracuda rents equipment from SR Energy.


g.	Stingray entities rent equipment from SR Energy.


h.	Dunvegan provides technical and administrative services and pays for goods and services on behalf of Lodging.


i.	Bison Drilling leases space from El Toro for storage of a rig.


j.	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. In 2014, Everest provided personnel to support operational functions in addition

to significant technical and advisory support.


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


l.	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.


m.	Orange Leaf leases office space to Mammoth Inc.


13.	Commitments and Contingencies

The Company leases real estate, rail cars and other equipment under long-term operating leases with varying terms and expiration dates through 2025. Aggregate future minimum lease payments under these non-cancelable operating leases in effect at March 31, 2017 are as follows:

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



Year ended December 31:	Amount
Remainder of 2017	$	4,344,826
2018	5,400,861
2019	4,980,266
2020	3,516,479
2021	2,280,974
Thereafter	4,244,036
	$	24,767,442

For the three months ended March 31, 2017 and 2016, the Company recognized rent expense of $910,119 and $960,918, respectively.

The Company entered into a purchase agreement in 2014 with a sand supplier to begin January 1, 2015 and end December 31, 2016. The Company is subject to an annual commitment of 200,000 tons of sand. During June 2016, the Company paid a deposit of $600,000 to the sand supplier to be netted against future purchases of sand under this contract and deferred the commitment until June 2017. The Company has one additional unilateral option to extend for one additional year with a further deposit of $600,000. As of March 31, 2017, the future commitment for 2017 under this agreement is $2,110,848.

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.

On March 31, 2017, the Company entered into a five year office lease agreement with Caliber Investment Group LLC, an affiliate of Wexford. The aggregate minimum lease payments under this agreement are $2.6 million.

In the fourth quarter of 2016 and first quarter of 2017, we entered into agreements to acquire new high pressure fracturing units and other capital equipment. The future commitments under these agreements were $21.0 million as of March 31, 2017.

The Company has insurance coverage for physical 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 March 31, 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 March 31, 2017 and December 31, 2016, the policies contained an aggregate stop loss of $2,000,000. As of March 31, 2017 and December 31, 2016, accrued claims were $1,173,705 and $971,351, respectively. 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 and an aggregate stop-loss of $5,799,991 per calendar year. In connection with the insurance programs, letters of credit of $1,636,000 as of March 31, 2017 and December 31, 2016, have been issued supporting the retained risk exposure. As of both March 31, 2017 and December 31, 2016, these letters of credit were collateralized by substantially all of the assets of the Company.

On March 20, 2017, as amended and restated on May 12, 2017, the Company entered into definitive agreements (the "Contribution Agreements") with affiliates of Wexford, Gulfport and Rhino to acquire Sturgeon Acquisitions LLC (which owns Taylor, Taylor Real Estate Investments, LLC and South River Road, LLC), SR Energy and Cementing (collectively, the "Targets") for 7,000,000 of its common stock. Based upon the closing price of Mammoth's common stock of $19.06 per share on March 20, 2017, the total purchase price was valued at approximately $133.4 million. The acquisition is expected to close in the second quarter of 2017.

On March 27, 2017, the Company, as purchaser, entered into a definitive asset purchase agreement with Chieftain Sand and Proppant, LLC and Chieftain Sand and Proppant Barron, LLC, unrelated third party sellers (the “Sellers”), following the Company’s successful bid in a bankruptcy court auction for substantially all of the assets of the Sellers for $35.3 million (the “Chieftain Acquisition”). The Chieftain Acquisition was approved by the bankruptcy court at a hearing on March 27, 2017, but remains subject to agreed closing conditions. The Chieftain Acquisition is expected to close in the

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

second quarter of 2017. The Company intends to fund the purchase price for the Chieftain Acquisition with cash on hand and borrowings under its revolving credit facility.

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 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 March 16, 2016, a putative and collective action lawsuit alleging that Coil Tubing failed to pay a class of workers in compliance with the Fair Labor Standards Act was filed titled Rusty Hale, 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 Oklahoma. On March 28, 2017, the Company settled this matter. This resolution did not have a material impact on the Company’s financial position, results of operations or cash flows.

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 October 12, 2015, 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 Oklahoma law was filed titled William Reynolds, 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 Oklahoma. In March 2017, the parties reached a settlement of this matter and filed a joint motion with the court to approve this settlement, which was granted. This settlement 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 Talamentez, 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.

On February 12, 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 Brian Croniser vs. Redback Energy Services LLC in the U.S. District Court Southern District of Ohio. On February 17, 2017, the Company settled this matter and the lawsuit has been dismissed. This resolution did not have a material impact on the Company’s financial position, results of operations or cash flows.

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

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

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 three months ended March 31, 2017 and 2016, the Company paid $0 and $67,171, respectively, in contributions to the plan.


14.	Operating Segments

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
Three Months Ended March 31, 2017	Pressure Pumping Services		Well Services			Sand			Drilling			Other Energy Services		Total
Revenue from external customers...	$	8,691,647	$	3,190,132		$	2,615,209		$	9,703,397		$	5,506,706	$	29,707,091
Revenue from related parties..........	$	31,931,820	$	152,895		$	11,576,151		$	1,047,592		$	264	$	44,708,722
Cost of revenue..............................	$	28,771,868	$	3,799,776		$	12,931,277		$	10,953,423		$	2,430,082	$	58,886,426
Selling, general and administrative expenses...............................................	$	1,774,926	$	972,405		$	1,542,565		$	1,295,024		$	636,890	$	6,221,810
Earnings before interest, other expense, taxes and depreciation and amortization............	$	10,076,673	$	(1,429,154	)	$	(282,482	)	$	(1,497,458	)	$	2,439,998	$	9,307,577
Other expense .......................	$	2,631	$	1,182		$	102		$	163,785		$	2,341	$	170,041
Interest expense..............................	$	128,444	$	(105,902	)	$	21,793		$	217,182		$	24,821	$	286,338
Depreciation and amortization.......	$	9,157,893	$	1,208,241		$	1,019,491		$	4,968,628		$	539,524	$	16,893,777
Income tax provision.....................	$	—	$	(3,691,532	)	$	—		$	—		$	585,467	$	(3,106,065	)
Net income (loss)..........................	$	787,705	$	1,158,857		$	(1,323,868	)	$	(6,847,053	)	$	1,287,845	$	(4,936,514	)
Total expenditures for property, plant and equipment.................	$	28,665,309	$	—		$	—		$	2,269,277		$	593	$	30,935,179
At March 31, 2017
Goodwill.......................................	$	86,043,148	$	—		$	—		$	—		$	—	$	86,043,148
Intangible assets, net.....................	$	19,174,183	$	124,896		$	—		$	—		$	—	$	19,299,079
Total Assets...................................	$	228,689,765	$	47,734,021		$	29,421,704		$	97,838,858		$	30,818,616	$	434,502,964



	Completion and Production
Three Months Ended March 31, 2016	Pressure Pumping Services			Well Services			Sand			Drilling			Other Energy Services		Total
Revenue from external customers...	$	12,294,529		$	2,698,592		$	735,453		$	5,257,738		$	7,985,623	$	28,971,935
Revenue from related parties..........	$	10,261		$	—		$	4,374,754		$	1,145,999		$	555	$	5,531,569
Cost of revenue..............................	$	14,260,507		$	3,927,709		$	3,958,177		$	7,208,657		$	3,542,170	$	32,897,220
Selling, general and administrative expenses...............................................	$	526,171		$	573,296		$	242,463		$	1,302,473		$	610,663	$	3,255,066
Earnings before interest, other (income) expense, taxes and depreciation and amortization.......	$	(2,481,888	)	$	(1,802,413	)	$	909,567		$	(2,107,393	)	$	3,833,345	$	(1,648,782	)
Other (income) expense .......................	$	(19,208	)	$	9,400		$	(2	)	$	(10,074	)	$	1,690	$	(18,194	)
Interest expense..............................	$	237,055		$	98,319		$	—		$	852,574		$	3,947	$	1,191,895
Depreciation and amortization.......	$	8,955,217		$	1,397,507		$	1,031,036		$	5,507,381		$	522,450	$	17,413,591
Income tax provision.....................	$	—		$	—		$	—		$	—		$	894,360	$	894,360
Net (loss) income..........................	$	(11,654,952	)	$	(3,307,639	)	$	(121,467	)	$	(8,457,274	)	$	2,410,898	$	(21,130,434	)
Total expenditures for property, plant and equipment.................	$	30,695		$	—		$	92,028		$	264,171		$	147,631	$	534,525
At March 31, 2016
Goodwill.......................................	$	86,043,148		$	—		$	—		$	—		$	—	$	86,043,148
Intangible assets, net.....................	$	28,217,683		$	152,396		$	—		$	—		$	—	$	28,370,079
Total Assets...................................	$	198,457,528		$	60,191,891		$	28,112,951		$	110,148,572		$	35,713,736	$	432,624,678

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 primarily provides housing, kitchen and dining, and recreational service facilities for oilfield workers that are located in remote areas away from readily available lodging. 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 primarily in Canada.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


15.	Subsequent Events

Subsequent to March 31, 2017, the Company entered into lease agreements with aggregate commitments of $0.5 million.

On April 21, 2017, the Company acquired an energy service provider and related equipment from an unrelated third party seller for $4.0 million.

On May 10, 2017, the Company acquired oilfield service equipment and related real property from an unrelated third party seller for $3.8 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 primarily provides housing, kitchen and dining, and recreational service facilities for oilfield workers located in remote areas away from readily available lodging. 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 October 19, 2016, Mammoth Energy Services, Inc., or Mammoth Inc., closed its IPO of 7,750,000 shares of common stock, of which 7,500,000 shares were sold by Mammoth Inc. and the remaining 250,000 shares were sold by certain selling stockholders, at a price to the public of $15.00 per share. Mammoth Inc.’s 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 Mammoth Energy Partners, LP, or 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 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 below 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 November 24, 2014, Mammoth Energy Holdings LLC, or Mammoth Holdings, Gulfport Energy Corporation, or Gulfport, and Rhino Exploration LLC, or Rhino, contributed to 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. Subsequently, the Partnership formed Redback Pumpdown Services LLC, or Pumpdown, Mr. Inspections LLC, or Mr. Inspections, Silverback Energy Services LLC, or Silverback, and Mammoth Inc. as wholly-owned subsidiaries.

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.

First Quarter 2017 Highlights

Pending 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 affiliates of Wexford, Gulfport, Rhino and Mammoth LLC, and two others with affiliates of Wexford, Gulfport 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 Acquisitions LLC (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, and, together with Sturgeon Acquisitions, LLC and Stingray Energy, the Target Companies), respectively, for an aggregate of 7.0 million shares of our common stock valued at approximately $133.4 million based on the closing price of $19.06 per share for our common stock on March 20, 2017. As of February 28, 2017, the Target Companies had $7.3 million in debt and a positive working capital balance of $6.9 million. Taylor Frac owns a 0.7 million ton per year sand mine and processing plant with an estimated 37.1 million tons of recoverable reserves, 73% of which is more highly valued fine sand grades. 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 anticipate closing this acquisition in the second quarter of 2017, subject to agreed closing conditions.

Pending 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 located on approximately 600 acres in New Auburn, Wisconsin and a sand mine with estimated reserves of 30 million tons of Northern White Jordan Substrate frac sand which meets or exceeds API standards including solubility, turbidity, roundness, sphericity and crush resistance. The nameplate capacity of the dry plant, which is not operating today, is 1.8 million tons per annum, or Mtpa, with an expected capacity of 1.5 Mtpa once it is operational. The sellers’ facilities are located on the Union Pacific Railroad with unit train capability on site. The Chieftain Acquisition was approved by the bankruptcy court at a hearing on March 27, 2017, but remains subject to agreed closing conditions. The Chieftain Acquisition is expected to close in the second quarter of 2017. We intend to fund the purchase price for the Chieftain Acquisition with cash on hand and borrowings under our revolving credit facility.

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 continued in 2016. However, oil prices have increased since the 12-year low recorded on February 11, 2016, reaching a high of $54.06 per barrel on December 28, 2016. During the first three months of 2017, oil traded between a low of $47.70 per barrel recorded on March 23, 2017 and a high of $54.45 per barrel on February 23, 2017. As commodity prices have begun to recover, we have experienced an increase in activity. If near term commodity prices remain at current levels and recover further, we expect to continue to experience an increase in demand for our services and products, particularly in our completion and production, natural sand proppant and contract land and directional drilling businesses. Our other energy services revenue, which are currently only attributable to our remote accommodations business, declined during the first quarter of 2017 as a major construction project in the area we service was substantially completed in March 2017. We currently anticipate that our other energy services revenues will continue to decrease in the second quarter of 2017 if we are unable to replace the revenue attributable to this project.

Results of Operations

Three Months Ended March 31, 2017 Compared to Three Months Ended March 31, 2016



	Three Months Ended
	March 31, 2017			March 31, 2016
Revenue:
Pressure pumping services	$	40,623,467		$	12,304,790
Well services	3,343,027			2,698,592
Natural sand proppant services	14,191,360			5,110,207
Contract land and directional drilling services	10,750,989			6,403,737
Other energy services	5,506,970			7,986,178
Total revenue	74,415,813			34,503,504

Cost of Revenue:
Pressure pumping services	28,771,868			14,260,507
Well services	3,799,776			3,927,709
Natural sand proppant services	12,931,277			3,958,177
Contract land and directional drilling services	10,953,423			7,208,657
Other energy services	2,430,082			3,542,170
Total cost of revenue	58,886,426			32,897,220
Selling, general and administrative expenses	6,221,810			3,255,066
Depreciation and amortization	16,893,777			17,413,591
Operating loss	(7,586,200		)	(19,062,373		)
Interest expense, net	(286,338		)	(1,191,895		)
Other (expense) income	(170,041		)	18,194
Loss before income taxes	(8,042,579		)	(20,236,074		)
(Benefit) provision for income taxes	(3,106,065		)	894,360
Net loss	$	(4,936,514	)	$	(21,130,434	)

Revenue. Revenue for the three months ended March 31, 2017 increased $39.9 million, or 116%, to $74.4 million from $34.5 million for the three months ended March 31, 2016. Revenue by operating division was as follows:

Pressure Pumping Services. Pressure pumping services division revenue increased $28.3 million, or 230%, to $40.6 million for the three months ended March 31, 2017 from $12.3 million for the three months ended March 31, 2016. The increase was primarily driven by an increase in fleet utilization, on two active fleets, from 21% for the three months ended March 31, 2016 to 63%, on three active fleets, for the three months ended March 31, 2017. Additionally, the number of stages completed increased to 860 for the three months ended March 31, 2017 from 204 for the three months ended March 31, 2016.

Well Services. Well services division revenue increased $0.6 million, or 24%, to $3.3 million for the three months ended March 31, 2017 from $2.7 million for the three months ended March 31, 2016. Our coil tubing services accounted for $0.6 million, or 100% of our operating division increase, as a result of an increase in average day rates from approximately $19,900 for the three months ended March 31, 2016 to approximately $22,100 for the three months ended March 31, 2017. Our flowback services remained consistent period over period.

Natural Sand Proppant Services. Natural sand proppant services division revenue increased $9.1 million, or 178%, to $14.2 million for the three months ended March 31, 2017, from $5.1 million for the three months ended March 31, 2016. The increase was primarily attributable to an increase in tons of sand sold from approximately 66,500 for the three months ended March 31, 2016 to approximately 227,840 for the three months ended March 31, 2017, partially offset by a decrease in the average sales price per ton of sand from $77 to $62 for the three months ended March 31, 2016 and 2017, respectively.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division revenue increased $4.4 million, or 68%, from $6.4 million for the three months ended March 31, 2016 to $10.8 million for the three months ended March 31, 2017. The increase was primarily attributable to our land drilling services, which accounted for $2.5 million, or 57%, of the operating division increase as a result of an increase in average day rates from approximately $13,400 for the three months ended March 31, 2016 to approximately $14,400 for the three months ended March 31, 2017. Active rig count remained consistent at four during those same periods. Our directional drilling services accounted for $1.4 million, or 31%, of the operating division increase as a result of utilization increasing from 14% for the three months ended March 31, 2016 to 26% for the three months ended March 31, 2017. Our rig moving services accounted for $0.6 million, or 15%, of the operating division increase. The increase in our rig moving services was driven by the increase in drilling activity. Our drill pipe inspection services reflected a decrease of $0.1 million, or (3)%, of the operating division activity.

Other Energy Services. Other energy services division revenue decreased $2.5 million, or 31%, to $5.5 million for the three months ended March 31, 2017 from $8.0 million for the three months ended March 31, 2016. The decrease was the result of a decrease in total rooms nights rented from 61,697 to 34,338 for the three months ended March 31, 2016 and 2017, respectively, in addition to a decrease in revenue per room night, in Canadian dollars, from $178 for the three months ended March 31, 2016 to $175 for the three months ended March 31, 2017, partially offset by approximately $0.9 million of business interruption insurance proceeds we collected and recognized for the three months ended March 31, 2017.

Cost of Revenue. Cost of revenue increased $26.0 million from $32.9 million, or 95% of total revenue, for the three months ended March 31, 2016 to $58.9 million, or 79% of total revenue, for the three months ended March 31, 2017. Cost of revenue by operating division was as follows:

Pressure Pumping Services. Pressure pumping services division cost of revenue increased $14.5 million, or 102%, from $14.3 million for the three months ended March 31, 2016 to $28.8 million for the three months ended March 31, 2017. The increase was primarily due to increases in proppant costs, repairs and maintenance expense and labor-related costs from bringing our third pressure pumping fleet on line during 2017. As a percentage of revenues, our pressure pumping services division cost of revenue was 71% and 116% for the three months ended March 31, 2017 and 2016, respectively. The decrease in cost of revenue as a percentage of revenue was primarily due to an increase in utilization.

Well Services. Well services division cost of revenue decreased $0.1 million, or 3%, from $3.9 million for the three months ended March 31, 2016 to $3.8 million for the three months ended March 31, 2017. The decrease was primarily due to decreases in labor-related costs. As a percentage of revenues, our well services division cost of revenue was 114% and 146% for the three months ended March 31, 2017 and 2016, respectively. The decrease in cost of revenue as a percentage of revenue was primarily due to an increase in utilization.

Natural Sand Proppant Services. Natural sand proppant services division cost of revenue increased $8.9 million, or 227%, from $4.0 million for the three months ended March 31, 2016 to $12.9 million for the three months ended March 31, 2017, primarily due to an increase in product costs. As a percentage of revenue, cost of revenue was 91% and 77% for the three months ended March 31, 2017 and 2016, respectively. The increase was primarily due to an increase in per-ton product costs.

Contract Land and Directional / Drilling Services. Contract land and directional drilling services division cost of revenue increased $3.8 million, or 52%, from $7.2 million for the three months ended March 31, 2016 to $11.0 million for the three months ended March 31, 2017, primarily due to an increase in labor-related costs and higher utilization. As a percentage of revenue, our contract land and directional drilling services division cost of revenue was 102% and 113% for the three months ended March 31, 2017 and 2016, respectively. The decrease was primarily due to lower compensation and repairs and maintenance as a percentage of revenue.

Other Energy Services. Other energy services division cost of revenues decreased $1.1 million, or 31%, from $3.5 million the three months ended March 31, 2016 to $2.4 million for the three months ended March 31, 2017, primarily due to declines in contracted labor-related costs in our remote accommodation services. As a percentage of revenues, cost of revenues was 44% for each of the three month periods ended March 31, 2017 and 2016.

Selling, General and Administrative Expenses. Selling, general and administrative expenses represent the costs associated with managing and supporting our operations. These expenses increased $2.9 million, or 91%, to $6.2 million for the three months ended March 31, 2017, from $3.3 million for the three months ended March 31, 2016. The increase in expenses

was primarily attributable to a $2.1 million increase in compensation-related cost, a $0.7 million increase in professional fees and services and a $0.1 million reduction in bad debt expense for the three months ended March 31, 2017, compared to the three months ended March 31, 2016.

Depreciation and Amortization. Depreciation and amortization decreased $0.5 million, or 3%, to $16.9 million for the three months ended March 31, 2017 from $17.4 million for the three months ended March 31, 2016. The decrease was primarily attributable to $26.2 million of assets that fully depreciated during 2016 and was partially offset by placing in service of $6.6 million of capital additions for the three months ended March 31, 2017.

Interest Expense. Interest expense decreased $0.9 million, or 76%, to $0.3 million during the three months ended March 31, 2017, from $1.2 million during the three months ended March 31, 2016. The decrease in interest expense was attributable to a decrease in average borrowings during 2016 and the repayment of all outstanding borrowings in October 2016 with a portion of the net proceeds from the IPO.

Other (expense) income, net. Non-operating charges (income) resulted in expense of $0.2 million for the three months ended March 31, 2017, compared to other income, net of $18.2 thousand for the three months ended March 31, 2016. The three months ended March 31, 2017 included $0.1 million in 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 March 31, 2017, we recognized income tax benefit of $3.1 million compared to an income tax expense of $0.9 million for the three months ended March 31, 2016. The provision for the three months ended March 31, 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, 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) 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 March 31,
Reconciliation of Adjusted EBITDA to net income (loss):	2017			2016
Net loss	$	(4,936,514	)	$	(21,130,434	)
Depreciation and amortization expense	16,893,777			17,413,591
Acquisition related costs	1,246,564			—
Equity based compensation	569,831			—
Interest expense	286,338			1,191,895
Other (income) expense, net	170,041			(18,194		)
Provision (benefit) for income taxes	(3,106,065		)	894,360
Adjusted EBITDA	$	11,123,972		$	(1,648,782	)

Pressure Pumping Services



	Three Months Ended March 31,
Reconciliation of Adjusted EBITDA to net income (loss):	2017		2016
Net income (loss)	$	787,705	$	(11,654,952	)
Depreciation and amortization expense	9,157,893		8,955,217
Equity based compensation	271,388		—
Interest expense	128,444		237,055
Other (income) expense, net	2,631		(19,208		)
Provision (benefit) for income taxes	—		—
Adjusted EBITDA	$	10,348,061	$	(2,481,888	)

Well Services



	Three Months Ended March 31,
Reconciliation of Adjusted EBITDA to net income (loss):	2017			2016
Net income (loss)	$	1,158,857		$	(3,307,639	)
Depreciation and amortization expense	1,208,241			1,397,507
Acquisition related costs	187,184			—
Equity based compensation	46,989			—
Interest expense	(105,902		)	98,319
Other (income) expense, net	1,182			9,400
Provision (benefit) for income taxes	(3,691,532		)	—
Adjusted EBITDA	$	(1,194,981	)	$	(1,802,413	)

Natural Sand Proppant Services



	Three Months Ended March 31,
Reconciliation of Adjusted EBITDA to net income (loss):	2017			2016
Net loss	$	(1,323,868	)	$	(121,467	)
Depreciation and amortization expense	1,019,491			1,031,036
Acquisition related costs	1,037,865			—
Equity based compensation	70,124			—
Interest expense	21,793			—
Other (income) expense, net	102			(2		)
Provision (benefit) for income taxes	—			—
Adjusted EBITDA	$	825,507		$	909,567

Contract Land and Directional Drilling Services



	Three Months Ended March 31,
Reconciliation of Adjusted EBITDA to net income (loss):	2017			2016
Net income (loss)	$	(6,847,053	)	$	(8,457,274	)
Depreciation and amortization expense	4,968,628			5,507,381
Acquisition related costs	21,515			—
Equity based compensation	111,870			—
Interest expense	217,182			852,574
Other (income) expense, net	163,785			(10,074		)
Provision for income taxes	—			—
Adjusted EBITDA	$	(1,364,073	)	$	(2,107,393	)

Other Energy Services



	Three Months Ended March 31,
Reconciliation of Adjusted EBITDA to net income (loss):	2017		2016
Net income	$	1,287,845	$	2,410,898
Depreciation and amortization expense	539,524		522,450
Equity based compensation	69,460		—
Interest expense	24,821		3,947
Other (income) expense, net	2,341		1,690
Provision (benefit) for income taxes	585,467		894,360
Adjusted EBITDA	$	2,509,458	$	3,833,345

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 in addition to the net proceeds from our initial public offering. Our primary use of capital has been for investing in property and equipment used to provide our services.

As of March 31, 2017, our revolving credit facility was undrawn, leaving an aggregate of $144.1 million of available borrowing capacity under this facility.

The following table summarizes our liquidity for the periods indicated:



	March 31,			December 31,
	2017			2016
Cash and cash equivalents	$	12,278,120		$	28,693,985
Revolving credit facilities availability	144,149,393			146,181,002
Less borrowings	—			—
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		)
Net working capital (less cash)	16,636,356			28,323,882
Total	$	170,973,309		$	199,823,309

We used a portion of the net proceeds from our IPO to repay all borrowings outstanding under our revolving credit facility and, at May 11, 2017, this facility was undrawn with $141.2 million available borrowing capacity.

Liquidity and Cash Flows

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



	Three Months Ended
	March 31,
	2017			2016
Net cash provided by operating activities	$	14,139,399		$	20,629,593
Net cash used in investing activities	(30,565,921		)	(499,662		)
Net cash used in financing activities	—			(9,499,772		)
Effect of foreign exchange rate on cash	10,657			260,074
Net change in cash	$	(16,415,865	)	$	10,890,233

Operating Activities

Net cash provided by operating activities was $14.1 million for the three months ended March 31, 2017, compared to net cash provided of $20.6 million for the three months ended March 31, 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 $30.6 million for the three months ended March 31, 2017, compared to net cash used of $0.5 million for the three months ended March 31, 2016. 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
	March 31,
	2017		2016
Pressure pumping services (a)	$	28,665,309	$	30,695
Well services	—		—
Natural sand proppant production (b)	—		92,028
Contract and directional drilling services (c)	2,269,277		264,171
Other energy services (d)	593		147,631
Net change in cash	$	30,935,179	$	534,525


(a).	Capital expenditures primarily for for pressure pumping equipment for the three months ended March 31, 2017 and 2016.


(b).	Capital expenditures included a conveyor for the three months ended March 31, 2016.


(c).	Capital expenditures primarily for upgrades to our rig fleet for the three months ended March 31, 2017 and 2016.


(d).	Capital expenditures included primarily for an intersection upgrade for the three months ended March 31, 2016.

Financing Activities

Net cash used in financing activities for the three months ended March 31, 2016 was $9.5 million. During 2016, substantially all of which was used to pay down net borrowings under our credit facility. There was no net cash used in financing activities for the three months ended March 31, 2017.

Effect of Foreign Exchange Rate on Cash

The effect of foreign exchange rate on cash was $0.1 million, for the three months ended March 31, 2017, compared to net cash used of $0.3 million for the three months ended March 31, 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 $28.9 million and $57.0 million at March 31, 2017 and December 31, 2016 respectively. Our cash balances totaled $12.3 million and $28.7 million at March 31, 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. Concurrent with our entry into our revolving credit facility, we repaid all of our then existing subordinate debt with the initial advance under our revolving credit facility.

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

We used a portion of the net proceeds from the IPO to repay all borrowings outstanding under our revolving credit facility and at March 31, 2017 our credit facility remained undrawn with availability of $144.1 million, net of outstanding letters of credit. At May 11, 2017, this facility was undrawn with $141.2 million available borrowing capacity.

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 March 31, 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 at their current range, we have seen an increase in customer demand, particularly in our pressure pumping and natural sand proppant services divisions. We have increased our capital budget accordingly and, during 2017, we currently estimate that our aggregate capital expenditures will be approximately $143.0 million. These capital expenditures include $66.0 million in our pressure pumping services division for the acquisition of an additional 132,500 horsepower of new high pressure hydraulic pumps and related equipment, $29.0 million in our pressure pumping service division for tractors, pneumatic trailers and transload facilities to enhance our last mile solutions, $23.0 million in our sand segment for plant capacity expansion projects, $9.0 million in our contract land and directional drilling services division for an upgrade to two of our horizontal rigs and $16.0 million in our well services and other energy services divisions, primarily to maintain our coil tubing and flowback services lines and add new service offerings. We spent approximately $31.0 million on capital expenditures during the first quarter of 2017. We also intend to spend $35.3 million to complete the Chieftain Acquisition.

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 and fund the Chieftain Acquisition. 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, as previously announced, we intend to actively pursue an 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. We do not have a specific acquisition budget for 2017 since the timing and size of acquisitions cannot be accurately forecasted, however, we continue to evaluate opportunities. Our acquisitions may be undertaken with cash (as in the case of the Chieftain Acquisition), our common stock (as in the case of the pending acquisitions of the Target companies) or a combination of cash, common stock and/or other consideration. In the event we make one or more acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures and/or seek additional capital. If we seek additional capital for that or other reasons, we may do so through borrowings under our revolving credit facility, joint venture partnerships, 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

Operating Leases

An Operating Entity leases real estate, rail cars and other equipment under long-term operating leases with varying terms and expiration dates through 2025. Aggregate future minimum lease payments under these non-cancelable operating leases in effect at March 31, 2017, are as follows:



Year ended December 31:	Amount
Remainder of 2017	$	4,344,826
2018	5,400,861
2019	4,980,266
2020	3,516,479
2021	2,280,974
Thereafter	4,244,036
	$	24,767,442

Other Commitments

We entered into a purchase agreement in 2014 with a sand supplier to begin January 1, 2015 and end December 31, 2016. We are subject to an annual commitment of 200,000 tons of sand. During June 2016, we paid a deposit of $0.6 million to the

sand supplier to be netted against future purchases of sand under this contract and deferred the commitment until June 2017. We have one additional unilateral option to extend for one additional year with a further deposit of $0.6 million. As of March 31, 2017, the future commitment for 2017 under this agreement was $2.1 million.

On March 31, 2017, we entered into a five year office lease agreement with Caliber Investment Group LLC, an affiliate of Wexford. The aggregate minimum lease payments under this agreement are $2.6 million.

Subsequent to March 31, 2017, we entered into lease agreements with aggregate commitments of $0.5 million.

On March 20, 2017, as amended and restated on May 12, 2017, we entered into the Contribution Agreements in which we agreed to acquire all outstanding membership interests in the Target Companies for an aggregate of 7.0 million shares of our common stock. We anticipate closing these acquisitions in the second quarter of 2017, subject to agreed closing conditions. See “——First Quarter 2017 Highlights” above.

On March 27, 2017, we entered into 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 $35.3 million. The Chieftain Acquisition was approved by the bankruptcy court at a hearing on March 27, 2017, but remains subject to agreed closing conditions. The Chieftain Acquisition is expected to close in the second quarter of 2017. We intend to fund the purchase price for the Chieftain Acquisition with cash on hand and borrowings under our revolving credit facility. See “——First Quarter 2017 Highlights” above.

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 $12.3 million at March 31, 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 March 31, 2017, our revolving credit facility was undrawn and no borrowings were outstanding. On October 19, 2016, immediately prior to the closing of the IPO, we had $78.1 million outstanding under this facility with weighted average interest rate of 3.51%. A 1% increase or decrease in the interest rate at that time would have increased or decreased our interest expense by approximately $0.8 million per year. We do not currently hedge our interest rate exposure.

Foreign Currency Risk

Our remote accommodation business, which is included in our other 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 March 31, 2017, we had $5.7 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 March 31, 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 three months ended March 31, 2017 and 2016, we generated approximately 84% and 74%, 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 March 31, 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 March 31, 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 March 31, 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

See risk factors previously in our Annual Report on Form 10-K for the year ended December 31, 2016.

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

On March 20, 2017 as amended and restated on May 12, 2017, we entered into the Contribution Agreements, pursuant to which we agreed to issue 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 the Target Companies. We anticipate closing this acquisition in the second quarter of 2017, subject to agreed closing conditions. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations —— First Quarter 2017 Highlights.” At the closing of this acquisition, we intend to issue these shares of our common stock 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 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

DEF14C

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

DEF14C

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

DEF14C

001-37917

5/15/2017

A-3

2.4 #

Purchase and Sale Agreement, dated as of March 27, 2017, by and between Mammoth Energy Services, Inc., as purchaser, and Chieftain Sand and Proppant, LLC and Chieftain Sand and Proppant Barron, LLC, as sellers.

8-K

001-37917

3/29/2017

2.1

10.1

Office Lease Agreement, dated as of March 31, 2017, by and between the Company and Caliber Investment Group LLC.

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.

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:	May 15, 2017	By:	/s/ Arty Straehla
			Arty Straehla
			Chief Executive Officer

Date:	May 15, 2017	By:	/s/ Mark Layton
			Mark Layton
			Chief Financial Officer